Geopark Ltd
Annual Report 2023

Plain-text annual report

ANNUAL REPORT 2023 3 2 0 2 T R O P E R L A U N N A k r a P o e G EXPLORER OPERATOR CONSOLIDATOR Table of ContentsUNITED STATESSECURITIES AND EXCHANGE COMMISSIONWashington, D.C. 20549FORM 20-F(Mark One)☐ REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIESEXCHANGE ACT OF 1934OR☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACTOF 1934For the fiscal year ended December 31, 2023OR☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGEACT OF 1934For the transition period from ______________________ to ___________________________OR☐ SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIESEXCHANGE ACT OF 1934Date of event requiring this shell company reportCommission file number: 001-36298GEOPARK LIMITED(Exact name of Registrant as specified in its charter)Bermuda(Jurisdiction of incorporation)Calle 94 N° 11-30, 8o floorBogotá, Colombia(Address of principal executive offices)Mónica Jiménez GonzálezChief Strategy, Sustainability and Legal OfficerGeoPark LimitedCalle 94 N° 11-30, 8o floorBogotá, ColombiaPhone: +57 1 743 2337(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)Copies to:Maurice Blanco, Esq.Davis Polk & Wardwell LLP450 Lexington AvenueNew York, NY 10017Phone: (212 ) 450 4000Fax: (212) 701 5800Securities registered or to be registered pursuant to Section 12(b) of the Act:Title of each classTrading SymbolsName of each exchange on which registeredCommon shares, par value US$0.001per shareGPRKNew York Stock ExchangeSecurities registered or to be registered pursuant to Section 12(g) of the Act:NoneTable of Contents Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report. Common shares: 55,327,520 Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☐ No ☒ If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934. Yes ☐ No ☒ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☒ No ☐ Indicate by check mark whether the registrant has submitted electronically, every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☒ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or an emerging growth company. See definition of “large accelerated filer”, “accelerated filer”, and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☐ Emerging growth company ☐ Non-accelerated filer ☐ Accelerated filer ☒ If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards† provided pursuant to Section 13(a) of the Exchange Act. ☐ † The term “new or revised financial accounting standard” refers to any update issued by the Financial Accounting Standards Board to its Accounting Standards Codification after April 5, 2012. Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☒ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive- based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark which basis of accounting the registrant has used to prepare the financial statements included in this filing: US GAAP ☐ International Financial Reporting Standards as issued by the International Accounting Standards Board ☒ Other ☐ If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow. ☐ Item 17 ☐ Item 18 If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ☐ No ☒ Table of Contents GEOPARK LIMITED TABLE OF CONTENTS Glossary of oil and natural gas terms PRESENTATION OF FINANCIAL AND OTHER INFORMATION FORWARD-LOOKING STATEMENTS PART I ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS A. Directors and senior management B. Advisers C. Auditors ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE A. Offer statistics B. Method and expected timetable ITEM 3. KEY INFORMATION A. Reserved B. Capitalization and indebtedness C. Reasons for the offer and use of proceeds D. Risk factors ITEM 4. INFORMATION ON THE COMPANY A. History and development of the company B. Business Overview C. Organizational structure D. Property, plant and equipment ITEM 4A. UNRESOLVED STAFF COMMENTS ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS A. Operating results B. Liquidity and capital resources C. Research and development, patents and licenses, etc. D. Trend information E. Critical accounting policies and estimates ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and executive officers B. Compensation C. Board practices D. Employees E. Share ownership F. Disclosure of a registrant´s action to recover erroneously awarded compensation ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS A. Major shareholders B. Related party transactions C. Interests of Experts and Counsel ITEM 8. FINANCIAL INFORMATION A. Consolidated statements and other financial information B. Significant changes ITEM 9. THE OFFER AND LISTING A. Offering and listing details B. Plan of distribution C. Markets D. Selling shareholders E. Dilution i Page iii vii x 1 1 1 1 1 1 1 1 1 1 1 1 1 34 34 37 88 88 88 88 88 101 105 105 105 108 108 112 116 118 119 119 120 120 120 121 121 121 122 122 122 122 122 122 122 Table of Contents F. Expenses of the issue ITEM 10. ADDITIONAL INFORMATION A. Share capital B. Memorandum of association and bye-laws Enforcement of Judgments C. Material contracts D. Exchange controls E. Taxation F. Dividends and paying agents G. Statement by experts H. Documents on display I. Subsidiary information ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES A. Debt securities B. Warrants and rights C. Other securities D. American Depositary Shares PART II ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES A. Defaults B. Arrears and delinquencies ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures B. Management’s Annual Report on Internal Control over Financial Reporting C. Attestation Report of the Registered Public Accounting Firm D. Changes in Internal Control over Financial Reporting ITEM 16. RESERVED ITEM 16A. Audit committee financial expert ITEM 16B. Code of Conduct ITEM 16C. Principal Accountant Fees and Services ITEM 16D. Exemptions from the listing standards for audit committees ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers. ITEM 16F. Change in registrant’s certifying accountant ITEM 16G. Corporate governance ITEM 16H. Mine safety disclosure ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections ITEM 16J. Insider trading policies ITEM 16K. Cybersecurity PART III ITEM 17. Financial statements ITEM 18. Financial statements ITEM 19. Exhibits Index to Consolidated Financial Statements ii 122 122 122 122 130 131 131 131 135 135 135 135 135 135 135 135 136 136 136 136 136 136 136 136 136 136 138 138 138 138 138 138 139 139 140 141 142 142 142 142 144 144 144 144 F-1 Table of Contents GLOSSARY OF OIL AND NATURAL GAS TERMS The terms defined in this section are used throughout this annual report: “appraisal well” means a well drilled to further confirm and evaluate the presence of hydrocarbons in a reservoir that has been discovered. “API” means the American Petroleum Institute’s inverted scale for denoting the “light” or “heaviness” of crude oils and other liquid hydrocarbons. “bbl” means one stock tank barrel, of 42 U.S. gallons liquid volume, used herein in reference to crude oil, condensate or natural gas liquids. “bcf” means one billion cubic feet of natural gas. “bcm” means billion cubic meters. “boe” means barrels of oil equivalent, with 6,000 cubic feet of natural gas being equivalent to one barrel of oil. “boepd” means barrels of oil equivalent per day. “bopd” means barrels of oil per day. “British thermal unit” or “btu” means the heat required to raise the temperature of a one-pound mass of water from 58.5 to 59.5 degrees Fahrenheit. “basin” means a large natural depression on the earth’s surface in which sediments generally brought by water accumulate. “completion” means the process of treating a drilled well followed by the installation of permanent equipment for the production of natural gas or oil, or in the case of a dry hole, the reporting of abandonment to the appropriate agency. “developed acreage” means the number of acres that are allocated or assignable to productive wells or wells capable of production. “developed reserves” are expected quantities to be recovered from existing wells and facilities. Reserves are considered developed only after the necessary equipment has been installed or when the costs to do so are relatively minor compared to the cost of a well. Where required facilities become unavailable, it may be necessary to reclassify developed reserves as undeveloped. “development well” means a well drilled within the proved area of an oil or gas reservoir to the depth of a stratigraphic horizon known to be productive. “dry hole” means a well found to be incapable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of such production exceed production expenses and taxes. “E&P contract” means exploration and production contract. “economic interest” means an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires. “CEOP” (Contrato Especial de Operación) means a special operating contract the Chilean signs with a company or a consortium of companies for the exploration and exploitation of hydrocarbon wells. iii Table of Contents “economically producible” means a resource that generates revenue that exceeds, or is reasonably expected to exceed, the costs of the operation. “exploratory well” means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined below. “field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc. “formation” means a layer of rock which has distinct characteristics that differ from nearby rock. “mbbl” means one thousand barrels of crude oil, condensate, or natural gas liquids. “mboe” means one thousand barrels of oil equivalent. “mcf” means one thousand cubic feet of natural gas. “Measurements” include: ● “m” or “meter” means one meter, which equals approximately 3.28084 feet; ● “km” means one kilometer, which equals approximately 0.621371 miles; ● “sq. km” means one square kilometer, which equals approximately 247.1 acres; ● “bbl” “bo,” or “barrel of oil” means one stock tank barrel, which is equivalent to approximately 0.15898 cubic meters; ● “boe” means one barrel of oil equivalent, which equals approximately 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of natural gas to one barrel of oil; ● “cf” means one cubic foot; ● “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, respectively; ● “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, respectively; ● “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, respectively; and ● “pd” means per day. “metric ton” or “MT” means one thousand kilograms. Assuming standard quality oil, one metric ton equals 7.9 bbl. “mmbbl” means one million barrels of crude oil, condensate or natural gas liquids. “mmboe” means one million barrels of oil equivalent. iv Table of Contents “mmbtu” means one million British thermal units. “productive well” means a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes. “prospect” means a potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes. “proved developed reserves” means those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods. “proved reserves” means estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4 10(a)(2). “proved undeveloped reserves” means are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects. “reasonable certainty” means a high degree of confidence. “recompletion” means the process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production. “reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project. “reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs. “royalty” means a fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance. “service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for in-situ combustion. “shale” means a fine-grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps. “spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, and is often established by regulatory agencies). “stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to v Table of Contents hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area. “undeveloped reserves” are quantities expected to be recovered through future investments: (1) from new wells on undrilled acreage in known accumulation, (2) from deepening existing wells to a different (but known) reservoir, (3) from infill wells that will increase recovery, or (4) where a relatively large expenditure (e.g., when compared to the cost of drilling a new well) is required to (a) recomplete an existing well or (b) install production or transportation facilities for primary or improved recovery projects. “unit” means the joining of all or substantially all interests in a reservoir or field, rather than a single tract, to provide for development and operation without regard to separate property interests. Also, the area covered by a unitization agreement. “wellbore” means the hole drilled by the bit that is equipped for oil or gas production on a completed well. Also called well or borehole. “working interest” means the right granted to the lessee of a property to explore for and to produce and own oil, gas, or other minerals. The working interest owners bear the exploration, development, and operating costs on either a cash, penalty, or carried basis. “workover” means operations in a producing well to restore or increase production. vi Table of Contents Certain definitions PRESENTATION OF FINANCIAL AND OTHER INFORMATION Unless otherwise indicated or the context otherwise requires, all references in this annual report to: ● “GeoPark Limited,” “GeoPark,” “we,” “us,” “our,” the “Company” and words of a similar effect, are to GeoPark Limited, an exempted company incorporated under the laws of Bermuda, together with its consolidated subsidiaries; ● “Amerisur” are to Amerisur Resources Limited and its subsidiaries; ● “GeoPark Brazil” are to GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.; ● “YPF” are to YPF S.A.; ● “ONGC” are to ONGC Videsh Limited, international petroleum company of India; ● “Petroamazonas” are to Petroamazonas Ecuador S.A.; ● “Petroecuador” are to Empresa Pública de hidrocarburos del Ecuador; ● “MSCI” are to Morgan Stanley Capital International; ● “Notes due 2024” are to our 2017 issuance of US$425.0 million aggregate principal amount of 6.50% senior notes due 2024; ● “Notes due 2027” are to our 2020 issuance of US$350.0 million aggregate principal amount of 5.50% senior notes due 2027; ● “US$” and “U.S. dollar” are to the official currency of the United States of America; ● “Ch$” and “Chilean pesos” are to the official currency of Chile; ● “AR$” and “Argentine pesos” are to the official currency of Argentina; ● “real,” “reais” and “R$” are to the official currency of Brazil; ● “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); ● “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos); ● “ENAP” are to the Chilean National Petroleum Company (Empresa Nacional de Petróleo); ● “RODA” are to the Oil Pipeline Network of the Amazonian District (Red de Oleoductos del Distrito Amazónico); ● “SOTE” are to the Ecuadorian Oil Pipeline System (Sistema de Oleoducto Transecuatoriano); ● “IOGP” are to the International Association of Oil and Gas Producers; vii Table of Contents ● “IPIECA” are to the International Petroleum Industry Environmental Conservation Association; ● “IADC” are to the International Association of Drilling Contractors; ● “ARPEL” are to the Regional Association of Oil and Gas Companies, a non-profit association gathering oil, gas and biofuels sector companies and institutions in Latin America and the Caribbean; ● “UTA” are to Unidad Tributaria Anual; ● “economic interest” are to an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires; ● “ESG” are to Environmental, Social and Governance; and ● “IFC” are to International Finance Corporation. Financial statements Our historical financial data presented does not include any results or other financial information of any acquisitions, prior to their incorporation into our financial statements. Our consolidated financial statements This annual report includes our audited consolidated financial statements as of December 31, 2023 and 2022 and for each of the years ended December 31, 2023, 2022 and 2021 (hereinafter “Consolidated Financial Statements”). Our Consolidated Financial Statements are presented in US$ and have been prepared in accordance with International Financial Reporting Standards (“IFRS”), as issued by the International Accounting Standards Board (“IASB”). Our Consolidated Financial Statements for the year ended December 31, 2023, have been audited by Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited), an independent registered public accounting firm, as stated in their reports included elsewhere in this annual report. Our fiscal year ends December 31. References in this annual report to a fiscal year, such as “fiscal year 2023,” relate to our fiscal year ended on December 31 of that calendar year. Non IFRS financial measures Adjusted EBITDA Adjusted EBITDA is a supplemental non-IFRS financial measure that is used by management and external users of our financial statements, such as industry analysts, investors, lenders and rating agencies, to assess the performance of our Company and the operating segments. We define Adjusted EBITDA as profit (loss) for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Adjusted EBITDA is not a measure of profit or cash flows as determined by IFRS. We believe Adjusted EBITDA is useful because it allows us to more effectively evaluate our operating performance and compare the results of our operations from period to period without regard to our financing methods or capital structure. We exclude the items listed above from profit (loss) for the period in arriving at Adjusted EBITDA because viii Table of Contents these amounts can vary substantially from company to company within our industry depending upon accounting methods and book values of assets, capital structures and the method by which the assets were acquired. Adjusted EBITDA should not be considered as an alternative to, or more meaningful than, profit (loss) for the period or cash flows from operating activities as determined in accordance with IFRS or as an indicator of our operating performance or liquidity. Certain items excluded from Adjusted EBITDA are significant components in understanding and assessing a company’s financial performance, such as a company’s cost of capital and tax structure and significant and/or recurring write-offs, as well as the historic costs of depreciable assets, or unrealized results in commodity risk management contracts, none of which are components of Adjusted EBITDA. Our computation of Adjusted EBITDA may not be comparable to other similarly titled measures of other companies. For a reconciliation of Adjusted EBITDA to the IFRS financial measure of profit for the year, see Note 6 to our Consolidated Financial Statements as of and for the years ended 2023, 2022 and 2021. Oil and gas reserves and production information DeGolyer and MacNaughton 2023 Year-end Reserves Report The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia, Ecuador, Brazil and Chile is derived from estimates of the proved reserves as of December 31, 2023. The reserves estimates described herein are derived from the DeGolyer and MacNaughton Reserves Report (“D&M Reserves Report”), which was prepared for us by the independent reserves engineering team of DeGolyer and MacNaughton Corp. and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in various blocks in the Llanos and Putumayo Basins in Colombia, the Perico Block in the Oriente Basin in Ecuador, the BCAM-40 (Manati) Block in the Camamu-Almada Basin in Brazil and the Fell Block in the Magallanes Basin in Chile. Market share and other information Market data, other statistical information, information regarding recent developments in the countries in which we operate and certain industry forecast data used in this annual report were obtained from internal reports and studies, where appropriate, as well as estimates, market research, publicly available information and industry publications. Industry publications generally state that the information they include has been obtained from sources believed to be reliable, but that the accuracy and completeness of such information is not guaranteed. Similarly, internal reports and studies, estimates and market research, which we believe to be reliable and accurately extracted by us for use in this annual report, have not been independently verified. However, we believe such data is accurate and agree that we are responsible for the accurate extraction of such information from such sources and its correct reproduction in this annual report. In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms”. Rounding We have made rounding adjustments to some of the figures included elsewhere in this annual report. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that precede them. ix Table of Contents FORWARD-LOOKING STATEMENTS This annual report contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this annual report can be identified by the use of forward-looking words such as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” “estimate” and “potential,” among others. Forward-looking statements appear in a number of places in this annual report and include, but are not limited to, statements regarding our intent, belief or current expectations. Forward-looking statements are based on our management’s beliefs and assumptions and on information currently available to our management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors, including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to: ● the volatility of oil and natural gas prices; ● operating risks, including equipment failures and the amounts and timing of revenues and expenses; ● termination of, or intervention in, concessions, rights or authorizations granted by the Colombian, Ecuadorian, and Brazilian governments to us; ● uncertainties inherent in making estimates of our oil and natural gas data; ● environmental constraints on operations and environmental liabilities arising out of past or present operations; ● discovery and development of oil and natural gas reserves; ● climate change related risks; ● project delays or cancellations; ● financial market conditions and the results of financing efforts; ● political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which we operate; ● social and political unrest in many countries in which we operate; ● fluctuations in inflation and exchange rates in Colombia, Ecuador and Brazil and in other countries in which we may operate in the future; ● availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services; ● contract counterparty risk; ● projected and targeted capital expenditures and other cost commitments and revenues; ● pandemics, or the future outbreak of any highly infectious or contagious disease, including the COVID-19 pandemic; ● weather and other natural phenomena; ● armed conflicts, including the current armed conflicts in Ukraine and Israel; x Table of Contents ● the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations; ● current and future litigation; ● our ability to successfully identify, integrate and complete pending or future acquisitions and dispositions; ● our ability to retain key members of our senior management and key technical employees; ● competition from other similar oil and natural gas companies; ● market or business conditions and fluctuations in global and local demand for energy; ● the direct or indirect impact on our business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance; ● the adverse effect which a substantial or extended decline in oil and natural gas price may have on our business; ● material weaknesses in our internal control over financial reporting; ● the difficulty in integrating significant acquisitions or unexpected contingencies or changes in reserves estimates we discover following the completion of such acquisitions; and ● other factors discussed under “Item 3. Key Information—D. Risk factors” in this annual report. Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances or to reflect the occurrence of unanticipated events. xi Table of Contents ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS A. Directors and senior management PART I Not applicable. B. Advisers Not applicable. C. Auditors Not applicable. ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE A. Offer statistics Not applicable. B. Method and expected timetable Not applicable. ITEM 3. KEY INFORMATION A. Reserved B. Capitalization and indebtedness Not applicable. C. Reasons for the offer and use of proceeds Not applicable. D. Risk factors Our business, financial condition and results of operations could be materially and adversely affected if any of the risks described below occur. As a result, the market price of our common shares could decline, and you could lose all or part of your investment. This annual report also contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements.” The risks below are not the only ones facing our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. The following risk factors have been grouped as follows: a) Risks relating to our business; b) Risks relating to the countries in which we operate; and c) Risks relating to our common shares. 1 Table of Contents Summary of Key Risks Our business is subject to numerous risks and uncertainties, discussed in more detail below. These risks include, among others, the following key risks: ● A substantial or extended decline in oil and natural gas prices may materially adversely affect our business, financial condition, or results of operations. ● Low oil prices may impact our operations and corporate strategy. ● Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities. ● We derive a significant portion of our revenues from sales to a few key customers. ● Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates. ● There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas. ● Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. ● Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all. ● Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business. ● The development schedule of oil and natural gas projects is subject to cost overruns and delays. ● Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel. ● Our estimated oil and gas reserves are based on assumptions that may prove inaccurate. ● Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production. ● We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located. ● Under the terms of some of our various E&P contracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas. ● Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our E&P contracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances. ● We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets. 2 Table of Contents ● Acquisitions that we have completed, and any future acquisitions, strategic investments, partnerships, or alliances could be difficult to integrate and/or identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial results, including impairment of goodwill and other intangible assets. ● The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. ● The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced. ● We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations. ● Our operations are subject to operating hazards, including extreme weather events, which could expose us to potentially significant losses. ● We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified personnel. ● We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs. ● Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and limit our access to financing and insurance. ● Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations. ● Our indebtedness and other commercial obligations could adversely affect our financial health and our ability to raise additional capital and prevent us from fulfilling our obligations under our existing agreements and borrowing of additional funds. ● Our business could be negatively impacted by cybersecurity threats and related disruptions. ● The COVID-19 pandemic adversely impacted our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business. ● We operate in an industry with climate related risks. ● We operate in areas of significant biodiversity value. ● We operate in areas that have historical and current ties to indigenous peoples. ● Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk due to overlapping claims of rightful ownership. ● We have identified a material weakness in our internal control related to ineffective information technology general controls which could, if not remediated, result in material misstatements in our financial statements. ● Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future. 3 Table of Contents ● We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation. ● Oil and natural gas companies in Colombia, Ecuador and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries. ● Oil and gas operators are subject to extensive regulation in the countries in which we operate. ● Colombia has experienced and continues to experience internal security issues that have had or could have a negative effect on the Colombian economy. ● Our operations are subject to security and human rights risks. ● We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash. ● An active, liquid, and orderly trading market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell our common shares. ● Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. ● We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us. ● Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. ● Provisions of the Notes due 2027 could discourage an acquisition of us by a third party. ● Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control. ● Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price. ● As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it. ● There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make. ● We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. ● The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia. ● Legislation enacted in Bermuda as to Economic Substance may affect our operations. 4 Table of Contents Risks relating to our business A substantial or extended decline in oil and natural gas prices may materially adversely affect our business, financial condition, or results of operations. The prices that we receive for our oil and natural gas production heavily influence our revenues, profitability, access to capital and growth rate. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. International oil and natural gas prices have fluctuated widely in recent years and may continue to do so in the future. The prices that we will receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited, to the following: ● global economic conditions; ● changes in global supply and demand for oil and natural gas; ● the conflicts in Ukraine and Israel and other armed conflicts; ● the actions of the Organization of the Petroleum Exporting Countries (“OPEC”); ● political and economic conditions, including embargoes, in oil-producing countries or affecting other countries; ● the level of oil- and natural gas-producing activities, particularly in the Middle East, Africa, Russia, South America and the United States; ● the level of global oil and natural gas exploration and production activity; ● the level of global oil and natural gas inventories; ● availability of markets for natural gas; ● weather conditions and other natural disasters; ● technological advances affecting energy production or consumption; ● domestic and foreign governmental laws and regulations, including environmental, health and safety laws and regulations; ● proximity and capacity of oil and natural gas pipelines and other transportation facilities; ● the price and availability of competitors’ supplies of oil and natural gas in captive market areas; ● quality discounts for oil production based, among other things, on API, sulphur and mercury content; ● taxes and royalties under relevant laws and the terms of our contracts; ● our ability to enter into oil and natural gas sales contracts at fixed prices; ● the price and availability of alternative fuels, and possible regulations establishing costs for carbon emissions along the value chain; and 5 Table of Contents ● future changes to our hedging policies. These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements. For example, during the last four years, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel. Furthermore, oil and natural gas prices do not necessarily fluctuate in direct relationship to each other. After the oil crisis that resulted from the pandemic in 2020, the crude oil market normalized during early 2021 and shifted into an undersupply condition towards the end of that year. This condition was mainly driven by continued demand recovery while supply grew at a slower pace. OPEC and non-OPEC producers (sometimes referred to as OPEC+) paced output increase and capital discipline elsewhere, especially within the US Shale producers, were the key factors for moderate supply growth. In addition, natural gas prices spiked significantly during the last quarter of 2021, especially in Europe, pushing oil prices higher as well. These factors brought Brent prices up to US$78 per barrel at the end of 2021. The armed conflict between Russia and Ukraine during 2022, and the imposition of comprehensive sanctions against Russia (including in relation to the Russian energy sector), as well as the announcement of prohibitions on Russian oil and gas imports by certain members of the European Union, the United Kingdom, the United States, and other countries, led to volatility in the price of global oil and gas. For example, Brent spot price rose to a maximum of US$128 per barrel in March 2022. By the second half of 2022, sharply rising inflation led central banks to shift to a more restrictive policy stance, which historically is indicative of a potential economic recession. An economic recession could influence crude oil demand and, therefore, lead to a drop in crude oil prices, which dropped to US$86 per barrel by the end of 2022, 30% lower from the levels observed in June 2022. The year 2023 and the beginning of 2024 can be described as a consolidation period after a highly volatile 2022, where the much-anticipated Chinese economic recovery did not meet expectations, while the resilience of the U.S. economy positively surprised the macroeconomic environment. Despite the macro trend, countries like India and China took advantage of lower oil prices and their access to discounted barrels from Russia and Iran, and drove the world’s oil demand to an all- time-high of 103 million barrels a day, supporting Brent prices above $70/bbl. OPEC+ intervened the oil markets by cutting supply, especially Saudi Arabia and Russia, who pledged a combined voluntary cut of 1.3 million barrels a day until year-end. The group’s intervention resulted in the world’s oil inventories decreasing to a multi-year low and served as a catalyst for a sustained rally that supported a rise in Brent prices to approximately $100/bbl. Oil markets have currently shifted their focus to the evolution of the conflict between Israel and Hamas considering the potential impact on the crude oil supply from the region if the conflict extends beyond the region’s borders. For the year ended December 31, 2023, 97% of our revenues were derived from oil. Because we expect that our production mix will continue to be weighted towards oil, our financial results are more sensitive to movements in oil prices. For the year ended December 31, 2023, natural gas comprised 3% of our revenues. A decline in natural gas prices could negatively affect our future growth, particularly for future gas sales where we may not be able to secure or extend our current long-term contracts. Lower oil and natural gas prices may impact our revenues on a per unit basis and may also reduce the amount of oil and natural gas that can be produced economically. In addition, changes in oil and natural gas prices can impact the valuation of our reserves and, in periods of lower commodity prices, we may curtail production and capital spending or may defer or delay drilling wells because of lower cash generation. Lower oil and natural gas prices could also affect our growth, including future and pending acquisitions. A substantial or extended decline in oil or natural gas prices could adversely affect our business, financial condition, and results of operations. Continuing our hedging strategy, we entered into derivative financial instruments with the intent to partially mitigate our exposure to oil price risk. These derivatives were placed with major financial institutions and commodity traders, under ISDA Master Agreements and Credit Support Annexes. 6 Table of Contents To the extent that we engage in oil price risk management activities to partially protect ourselves from declines in oil price, we may be prevented from realizing the benefits of oil price increases above the levels of the zero-premium collars used to manage oil price risk. As market values of these derivatives fluctuate, we may post or receive variation cash collaterals with our counterparties. In the event of a significant decrease in the market value of the derivatives, we may have to post cash collateral, if they exceed our available credit lines. Even though cash collateral is returned to us upon reductions in the underlying Brent oil price, having to post cash collaterals could affect our near-term liquidity needs. As of the date of this annual report, we have no cash collateral posted related to our commodity risk management contracts. See Note 8 to our Consolidated Financial Statements for details regarding Commodity Risk Management Contracts. Low oil prices may impact our operations and corporate strategy. We face limitations on our ability to increase prices or improve margins on the oil and natural gas that we sell. As a consequence of the oil price crisis which started in the first half of 2020 (WTI and Brent, the main international oil price markers, fell by more than 45% between December 2019 and March 2020), we immediately took decisive measures to ensure our ability to both maximize ongoing projects and to preserve our cash, such as reducing our work program and made adjustments to our operating and administrative costs, with continuous monitoring to adjust further if necessary. While oil prices have rebounded since then, they may continue to be volatile and thus, we develop multiple scenarios for our capital expenditure plan. See “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook”. Funding our anticipated capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program, which would cause us to further decrease our work program and would harm our business outlook, investor confidence and our share price. In addition, actions taken by the company to maximize ongoing projects and to reduce expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives such as cost cutting may expose us to claims and contingencies from interested parties that may have a negative impact on our business, financial condition, results of operations and cash flows. If oil prices are lower than expected, we may be unable to meet our contractual obligations with oil and service contracts and suppliers. Equally, those third parties may be unable to meet their contractual obligations to us as a result of the oil price crisis, impacting on our operations. In budgeting for our future activities, we have relied on a number of assumptions, including, with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects and our ability to obtain needed financing with respect to any further acquisitions and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental, and competitive uncertainties, conditions in the financial markets, contingencies, and risks, all of which are difficult to predict and many of which are beyond our control. In addition, we opportunistically seek out new assets and acquisition targets to complement our existing operations and have financed such acquisitions in the past through the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority stakes in certain operations to our partners. We may need to raise additional funds more quickly if one or more of our assumptions prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. The ultimate amount of capital that we will expend may fluctuate materially based on market conditions, our continued production, decisions by the operators in blocks we do not operate, the success of our drilling results and future acquisitions. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made 7 Table of Contents and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production and the actual cost of exploration, appraisal and development of our oil and natural gas assets. Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities. Production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics. Accordingly, our current proved reserves will decline as these reserves are produced. As of December 31, 2023, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Ecuador and Brazil was 5.3 years. According to D&M estimates, if on January 1, 2024, we ceased all drilling and development activities, including recompletions, refracs and workovers, our proved developed producing reserves base in Colombia, Ecuador and Brazil would decline 26% during the first year. Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and using cost-effective methods to find or acquire additional recoverable reserves. While we have had success in identifying and developing commercially exploitable fields and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable fields or successfully drill, complete or produce more oil or gas reserves, and the wells which we have drilled, and currently plan to drill within our blocks or concession areas, may not discover or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be materially adversely affected. We derive a significant portion of our revenues from sales to a few key customers. In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. During 2023, the oil and gas production was sold to three clients which concentrate 96% of the Colombian subsidiaries’ revenue (accounting for 89% of the consolidated revenue). Delivery points include wellhead and other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the transport through the Ecuadorian pipeline system. We manage our counterparty credit risk associated to sales contracts by performing periodic evaluations of our counterparties’ credit profile and, in certain contracts, including early payment conditions to minimize the exposure. In Ecuador, oil is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of the sales are exported on a competitive basis to industry leading participants including traders and other producers. Sales of crude oil in Ecuador accounted for 3% of our consolidated revenue. In Brazil, the gas production from the Manati Field is sold to Petrobras, the Brazilian State-owned company, which is the operator of the Manati Field (accounting for 2% of our consolidated revenue). See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Brazil—Petrobras Natural Gas Purchase Agreement.” If any of our buyers were to decrease or cease purchasing oil or gas from us, or if any of them were to decide not to renew their contracts with us or to renew them at a lower sales price, this could have a material adverse effect on our business, financial condition, and results of operations. For example, see “Item 4. Information on the Company—B. Business Overview —Significant Agreements—Colombia”. Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates. Although most of our revenues are denominated in US$, unfavorable fluctuations in foreign currency exchange rates for certain of our expenses in Colombia, Ecuador and Brazil could have a material adverse effect on our results of operations. An appreciation of local currencies can increase our costs and negatively impact our results from operations. 8 Table of Contents Because our Consolidated Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities, into US$ at exchange rates in effect during or at the end of each reporting period. From time to time, we enter into derivative financial instruments in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. No currency risk management contracts were in place as of December 31, 2023, and onwards. In January 2023, we entered into derivative financial instruments (zero-premium collars) with local banks in Colombia, for an amount equivalent to US$38.0 million in order to anticipate any currency fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023. There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas. Our performance depends on the success of our exploration and production activities and on the existence of the infrastructure that will allow us to take advantage of our oil and gas reserves. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that exploration activities will not identify commercially viable quantities of oil or natural gas. Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of seismic and other data obtained through geophysical, geochemical and geological analysis, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations. Furthermore, the marketability of any oil and natural gas production from our projects may be affected by numerous factors beyond our control. These factors include, but are not limited to, proximity and capacity of pipelines and other means of transportation, the availability of upgrading and processing facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating to prices, sale restrictions, taxes, governmental stake, allowable production, importing and exporting of oil and natural gas, environmental protection and health and safety). The effect of these factors, individually or jointly, cannot be accurately predicted, but may have a material adverse effect on our business, financial condition, and results of operations. There can be no assurance that our drilling programs will produce oil and natural gas in the quantities or at the costs anticipated, or that our currently producing projects will not cease production, in part or entirely. Drilling programs may become uneconomic due to an increase in our operating costs or as a result of a decrease in market prices for oil and natural gas. Our actual operating costs or the actual prices we may receive for our oil and natural gas production may differ materially from current estimates. In addition, even if we are able to continue to produce oil and gas, there can be no assurance that we will have the ability to market our oil and gas production. See “—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production” below. Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. Our management team has specifically identified and scheduled certain potential drilling locations as an estimate of our future multi-year drilling activities on our existing acreage. These identified potential drilling locations, including those without proved undeveloped reserves, represent a significant part of our growth strategy. Our ability to drill and develop these identified potential drilling locations depends on a number of factors, including oil and natural gas prices, the availability and cost of capital, drilling and production costs, the availability of drilling services and equipment, drilling results, lease expirations, the availability of gathering systems, marketing and transportation constraints, refining capacity, regulatory approvals and other factors. Because of the uncertainty inherent in these factors, there can be no assurance that the numerous potential drilling locations we have identified will ever be drilled or, if they are, that we will be able to produce oil or natural gas from these or any other potential drilling locations. 9 Table of Contents Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all. Because the oil and natural gas industry is capital intensive, we expect to make substantial capital expenditures in our business and operations for the exploration and production of oil and natural gas reserves. See “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook.” We incurred capital expenditures of US$199.0 million and US$168.8 million during the years ended December 31, 2023 and 2022, respectively. See “Item 5. Operating and Financial Review and Prospects—A. Operating Results—Factors Affecting our Results of Operations—Discovery and exploitation of reserves.” The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other equipment and services, and regulatory, technological and competitive developments. In response to changes in commodity prices, we may increase or decrease our actual capital expenditures. For example, as a result of the oil price decline in 2020 we adjusted the capital expenditures program for that year to US$65-75 million, approximately a 60% reduction from prior preliminary estimates (approximately US$180-200 million). We intend to finance our future capital expenditures through cash generated by our operations and potential future financing arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets. If our capital requirements vary materially from our current plans, we may require further financing. In addition, we may incur significant financial indebtedness in the future, which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or financing on terms favorable to us, including as a result of financial institutions having lower capital availability or potentially higher interest rates. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results. Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business. Oil and gas exploration and production is uncertain and involves a high degree of risk and hazards. Our operations may be disrupted by risks and hazards that are beyond our control and that are common among oil and gas companies, including environmental hazards, blowouts, industrial accidents, occupational safety and health hazards, technical failures, labor disputes, nationwide or regional social protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and other accidents. While we believe that we maintain customary insurance coverage for companies engaged in similar operations, we are not fully insured against all risks in our business because certain risks, such as public order related issues or natural disasters, are not subject to insurance coverage because they are not under our control. In addition, insurance that we do, and plan to, carry may contain significant exclusions from and limitations on coverage. We may elect not to obtain certain non-mandatory types of insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of a significant event or a series of events against which we are not fully insured, and any losses or liabilities arising from uninsured or underinsured events could have a material adverse effect on our business, financial condition or results of operations. The development schedule of oil and natural gas projects is subject to cost overruns and delays. Oil and natural gas projects may experience capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel, and oil field services. The cost to execute projects may not be properly established and remains dependent upon a number of factors, including the 10 Table of Contents completion of detailed cost estimates and final engineering, contracting and procurement costs. The development of projects may be materially adversely affected by one or more of the following factors: ● shortages of equipment, materials and labor; ● fluctuations in the prices of construction materials; ● delays in delivery of equipment and materials; ● labor disputes; ● political events; ● title problems; ● obtaining easements and rights of way; ● blockades or embargoes; ● litigation; ● compliance with governmental laws and regulations, including environmental, health and safety laws and regulations; ● adverse weather conditions; ● unanticipated increases in costs; ● natural disasters; ● epidemics or pandemics; ● accidents; ● transportation; ● unforeseen engineering and drilling complications; ● delays during prior consultation processes; ● delays attributable to the operator of the project; ● environmental or geological uncertainties; and ● other unforeseen circumstances. Any of these events or other unanticipated events could give rise to delays in development and completion of our projects and cost overruns. For example, during 2023: 11 Table of Contents ● the Indico 6 and Indico 7 wells, which were drilled in the CPO-5 Block in late 2022, were shut-in from January to September 2023, following the ANH’s request that the operator suspend production until certain required surface facilities were completed; ● the environmental licensing processes in Putumayo (Colombia) were affected between April and November 2023, by the suspension of the public hearings due to lack of adequate security conditions, which affected the start of operations in the PUT-8 Block and caused delays in the planned drilling campaign; and ● the drilling and completion costs for the Tigana Norte 50 and Tigui 74 wells in our Llanos 34 Block in Colombia included delays and overruns of US$0.4 million and US$ 0.6 million, respectively, caused by local community blockades. Additionally, we may not be able to follow the development schedules we believe are optimal for blocks in which we are not the operator, such as the CPO-5 Block, which could adversely affect our financial condition and results of operations. Delays in the construction and commissioning of projects or other technical difficulties may result in future projected target dates for production being delayed or further capital expenditures being required. These projects may often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement and may not function as expected. Such uncertainties and operating risks associated with development projects could have a material adverse effect on our business, results of operations or financial condition. Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel. We compete with the major oil and gas companies engaged in the exploration and production sector, including state- owned exploration and production companies that possess greater financial and technical resources than we do for researching and developing exploration and production technologies and access to markets, equipment, labor and capital required to acquire, develop and operate our properties. We also compete for the acquisition of licenses and properties in the countries where we operate. Our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources allow. Our competitors may also be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not be able to successfully compete in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital, which could have a material adverse effect on our business, financial condition or results of operations. See “Item 4. Information on the Company—B. Business Overview—Our competition.” Our estimated oil and gas reserves are based on assumptions that may prove inaccurate. Our oil and gas reserves estimate in Colombia, Ecuador, Brazil and Chile as of December 31, 2023, is based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimate set forth in the D&M Reserves Reports is based on certain assumptions that may prove inaccurate. DeGolyer and MacNaughton’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us. Oil and gas reserves engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out herein. Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil and gas reserves, including projecting future rates of production, timing and amounts of development expenditures and prices of oil and gas, many of which are beyond our control. Post estimate drilling, testing and production results may require revisions. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate of our oil and gas reserves. Accordingly, reserves 12 Table of Contents estimates are often materially different from the quantities of oil and gas that are ultimately recovered, and if such recovered quantities are substantially lower than the initial reserves estimate, this could have a material adverse impact on our business, financial condition and results of operations. Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production. Our ability to market our oil and natural gas production depends substantially on the availability and capacity of processing facilities, transportation facilities (such as pipelines, crude oil unloading stations and trucks) and other necessary infrastructure, which may be owned and operated by third parties. Our failure to obtain such facilities on acceptable terms or on a timely basis could materially harm our business. We may be required to shut down oil and gas wells because access to transportation or processing facilities may be limited or unavailable when needed. If that were to occur, we would be unable to realize revenue from those wells until arrangements were made to deliver the production to the market, which could cause a material adverse effect on our business, financial condition and results of operations. In addition, the shutting down of wells can lead to mechanical problems upon bringing the production back on-line, potentially resulting in decreased production and increased remediation costs. The exploitation and sale of oil and natural gas and liquids will also be subject to timely commercial processing and marketing of these products, which depends on the contracting, financing, building and operating of infrastructure by us and third parties. In Colombia, producers of crude oil have historically suffered from trucking transportation logistics issues and limited pipeline and storage capacity, which cause delays in delivery and transfer of title of crude oil. To reduce this exposure, we and our partner in the Llanos 34 Block have constructed a flowline to evacuate crude oil from the Jacana field, reducing transportation costs, blockade risks and supporting our sustainable performance by reducing carbon emissions. Throughout 2023, we were impacted by repeated strikes carried out by communities requesting attention to their needs through the obstruction of routes we typically use for the evacuation of crude oil through tanker trucks. While we have been able to continue to evacuate our production through evacuation alternatives such as the Oleoducto del Casanare Pipeline (“ODCA”) pipeline, without significantly affecting the production of our fields, if both transportation alternatives are simultaneously affected and we are unable to evacuate our production, our access to the markets may be hindered and this could cause a material adverse effect on our business, financial condition and results of operation. In the case of our Putumayo Basin production, we have also reduced our exposure to trucking issues by implementing the use of flowlines alongside trucking to gather our production at the Platanillo Block and transport it via the Oleoducto Binacional Amerisur (“OBA”) pipeline that connects us to the Ecuador pipeline system. Trucking transportation was part of our crude delivery strategy during 2023 and will continue to be part of our strategy in the future. Although we were able to enable alternative delivery points and transport oil by trucks, avoiding any significant negative impact in our production during this period, we cannot assure we would be able to do so in the future. In Ecuador, our oil production is transported through the existing pipeline infrastructure. While the Ecuadorian pipeline system is well-developed and has operated reliably in the past, we cannot guarantee this will be the case in the future. Also, as production in Ecuador increases, available capacity may be limited. An inability to access transport capacity could adversely affect our production levels or the transport costs associated with getting our production to the market. While Brazil has a well-developed network of hydrocarbon pipelines, storage and loading facilities, we may not be able to access these facilities when needed. Pipeline facilities in Brazil are often full and seasonal capacity restrictions may occur, particularly in natural gas pipelines. Our gas production from the Manati Field is transported on Petrobras-operated pipelines. If those pipelines became unavailable, our overall production levels in the Manati Field would be negatively impaired. 13 Table of Contents We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located. Access to the sites where we operate requires agreements (including easements, rights-of-way and access authorizations), primarily with the owners of the lands on which we intend to develop our operational projects. If we are unable to negotiate easements with landowners, we may have to go to court to obtain access to the sites of our operations, which may delay the progress of our operations at such sites. In Colombia, although we have agreements with many landowners and ongoing negotiations with others, the economic expectations of landowners have generally increased concomitant with direct negotiations, which may result in delayed access to existing or future sites. Additionally, local communities and other stakeholders in the territory, such as workers' associations, trade unions and unions for activities related to the industry, are leading demands to the operators, beyond what is legally established, sometimes exerting pressures under de facto means or blockades to operational activities. Although oil and gas companies are managing these situations and stakeholder expectations in the territory, it ultimately becomes necessary to establish agreements for the viability of the operations, which on occasions translates into higher execution costs. Additionally, there are demands for improvements of transport infrastructure and the addressing of unsatisfied basic needs that have been historically ignored by the authorities and the fulfillment of such demands may be redirected towards the oil and gas companies. In Putumayo (Colombia), where we have operating sites, there is presence of illegal groups which may pressure farmers to oppose the control and eradication of illicit crops, and instrumentalize the oil and gas industry with blockades, seeking to draw the attention of the national government and prevent the eradication of these crops. As part of its international commitments, the Colombian government may seek to enhance the participatory phases of hydrocarbon projects, which could broaden the parameters of community participation and access to information and ultimately affect project timelines. Furthermore, local communities’ expectations may increase because of several reforms the government has announced. If the government reforms do not meet the communities’ expectations, the pressure to reform may shift to the oil and gas industry. The expectations and demands of local communities on oil and gas companies operating in Colombia may also increase. As a result, local communities have demanded that oil and gas companies invest in fixing and improving public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure which is commonly paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are now dealing with increasing difficulties resulting from instances of social unrest, temporary road blockades and conflicts with landowners. In addition, community and indigenous protests and blockades may arise near our operations, which could adversely affect our business, financial condition or results of operations. Other legal proceedings such as land restitution, a judicial process implemented because of the peace agreement in Colombia, focus on returning illegally held land to its rightful owners, may delay access to future sites. There can be no assurance that disputes with landowners and local communities or legal proceedings will not delay our operations or that any agreements we reach with such landowners and local communities or legal proceedings in the future will not require us to incur additional costs, thereby materially adversely affecting our business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected government to restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites. 14 Table of Contents Under the terms of some of our various E&P contracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas. To protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within periods specified in our various special operation contracts (E&P contracts, production sharing agreements and concession agreements), our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified under these contracts and agreements yield discoveries, we may face delays in drilling these prospects or be required to relinquish them. The costs to maintain or operate the E&P contracts, production sharing agreements and concession agreements over such areas may fluctuate and may increase significantly, and we may not be able to meet our commitments under such contracts and agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. For example, in 2023, we transferred commitments from certain blocks to others and asked for termination of certain E&P contracts. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Colombia.” Historically, a significant amount of our reserves or production have been derived from our operations in certain blocks, including various blocks in the Llanos and Putumayo Basins in Colombia, the Espejo and Perico Blocks in the Oriente Basin in Ecuador, the BCAM-40 Concession in the Camamu-Almada Basin in Brazil and the Fell Block in the Magallanes Basin in Chile. For the year ended December 31, 2023, the different blocks in the Llanos Basin contained 85.1% of our net proved reserves and generated 84.2% of our production, the Platanillo Block in the Putumayo Basin contained 4.8% of our net proved reserves and generated 5.8% of our production, the Espejo and Perico Blocks in the Oriente Basin contained 3.5% of our net proved reserves and generated 2.5% of our production, the BCAM-40 Concession in the Camamu-Almada Basin contained 2.3% of our net proved reserves and generated 2.8% of our production and the Fell Block in the Magallanes Basin contained 4.4% of our net proved reserves and generated 4.7% of our total production. While our continuing expansion with new exploratory blocks incorporated in our portfolio and the recent divestment of our operations in Chile mean that the above- mentioned blocks may be expected to be a less significant component of our overall business, we cannot be sure that we will be able to continue diversifying our reserves and production. Resulting from these, any government intervention, impairment, or disruption of our production due to factors outside of our control or any other material adverse event in our operations in such blocks would have a material adverse effect on our business, financial condition, and results of operations. Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our E&P contracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances. Under certain E&P contracts, production sharing contracts and concession agreements to which we are or may in the future become parties, we are or may become subject to guarantees to perform our commitments and/or to make payment for other obligations, and we may not be able to obtain financing for all such obligations as they arise. If such obligations are not complied with when due, in addition to any other remedies that may be available to other parties, this could result in cancelation of our E&P contracts, production sharing contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2023, the aggregate outstanding amount of this potential liability for guarantees was US$70.7 million, mainly related to capital commitments in the Llanos 34, Platanillo, Llanos 87, PUT-8, Llanos 86, and Llanos 104 Blocks in Colombia, the Espejo and Perico Blocks in Ecuador, and the Campanario Block in Chile. See “Item 4. Information on the Company—B. Business Overview—Our operations” and Note 33.2 to our Consolidated Financial Statements. Additionally, certain E&P contracts, production sharing contracts and concession agreements to which we are or may in the future become a party are subject to set expiration dates. Although we may want to extend some of these contracts beyond their original expiration dates, there is no assurance that we can do so on terms that are acceptable to us or at all, although some of these agreements contain provisions enabling exploration extensions. 15 Table of Contents In Colombia, our E&P contracts are subject to early termination for a breach by the parties, a default declaration, application of any of the contracts’ unilateral termination clauses or pursuant to termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH and/or a restriction on our ability to engage in contracts with the Colombian government during a certain period of time. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Colombia—E&P contracts.” To avoid the breach of an E&P contract due to unfulfillment of our exploration commitments, regulation gives us options such as the ability to transfer or credit those commitments to other E&P contracts, subject to meeting certain regulatory conditions. In Ecuador, our production sharing contracts may be subject to early termination in case of breach of the obligations under the contract, non-performance of the exploratory commitments or unjustified suspension of the operations, lack of remediation of environmental damages or unauthorized assignment of a working interest under the production sharing contracts, among others, as specified under the laws of the contract. The declaration of an early termination is subject to prior due process, which would allow us to remedy any hypothetical breach claimed against us, or to present our defense allegations. A declaration of early termination will cause forfeiture of equipment and facilities and enforcement of monetary guarantees. In Brazil, concession agreements in the production phase generally may be renewed at the ANP’s discretion for an additional period, provided that a renewal request is made at least 12 months prior to the termination of the concession agreement and there has not been a breach of the terms of the concession agreement. We expect that all our concession agreements will provide for early termination in the event of: (i) government expropriation for reasons of public interest; (ii) revocation of the concession pursuant to the terms of the concession agreement; or (iii) failure by us or our partners to fulfill all our respective obligations under the concession agreement (subject to a cure period). Administrative or monetary sanctions may also be applicable, as determined by the ANP, which shall be imposed based on applicable law and regulations. In the event of early termination of a concession agreement, the compensation to which we are entitled may not be sufficient to compensate us for the full value of our assets. Moreover, in the event of early termination of any concession agreement due to failure to fulfill obligations thereunder, we may be subject to fines and/or other penalties. Early termination or nonrenewal of any E&P contract, production sharing agreements or concession agreement could have a material adverse effect on our business, financial situation, or results of operations. We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets. We are not the operator or sole owner of all the blocks included in our portfolio. See “Item 4. Information on the Company—B. Business Overview—Operations in Colombia”, “—Operations in Ecuador”, “—Operations in Brazil” and “— Operations in Argentina”. Therefore, certain decisions are not under our sole discretion and need to be agreed to with our partners. Accordingly, our decision-making capabilities may be limited to the extent our partner operators or owners have any limitations with respect to any proposed action or plan. In addition, the terms of the joint operations agreements or association agreements governing our other partners’ interests in almost all of the blocks that are not wholly owned or operated by us require that certain actions be approved by supermajority vote. The terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over operations or prospects in the blocks operated by our partners, or in blocks that are not wholly owned or operated by us. A breach of contractual obligations by our partners who are the operators of such blocks could eventually affect our rights in exploration and production contracts in some of our blocks in Colombia, Ecuador and Brazil. Our dependence on our partners could prevent us from achieving our target returns for those discoveries or prospects. Moreover, as we are not the sole owner or operator of all our properties, we may not be able to control the timing of exploration or development activities or the amount of capital expenditures and may therefore not be able to carry out our key business strategies of minimizing the cycle time between discovery and initial production at such properties. The 16 Table of Contents success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including: ● the timing and amount of capital expenditures; ● the operator’s expertise and financial resources; ● approval of other block partners in drilling wells; ● the scheduling, pre-design, planning, design and approvals of activities and processes; ● selection of technology; and ● the rate of production of reserves, if any. This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations. For instance, we are not the operator of the CPO-5 Block, and do not control the execution of the development schedule. Any delays in the execution schedule of the CPO-5 Block could have a material adverse effect in our financial condition and results of operation. For example, the Indico 6 and Indico 7 wells, which were drilled in the CPO-5 Block in late 2022, were shut-in from January to September 2023, following the ANH’s request that the operator suspend production until certain required surface facilities were completed. Acquisitions that we have completed, and any future acquisitions, strategic investments, partnerships, or alliances could be difficult to integrate and/or identify, could divert the attention of key management personnel, disrupt our business, dilute stockholder value and adversely affect our financial results, including impairment of goodwill and other intangible assets. One of our principal business strategies includes acquisitions of properties, prospects, reserves and leaseholds and other strategic transactions, including in jurisdictions in which we do not currently operate. The successful acquisition and integration of producing properties requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices, development and operating costs, and potential environmental and other liabilities. The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review and the review of advisors and independent reserves engineers will not reveal all existing or potential problems, nor will it permit us or them to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental conditions are not necessarily observable even when an inspection is undertaken. We, advisors or independent reserves engineers may apply different assumptions when assessing the same field. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental liabilities and acquire properties on an “as is” basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller will not be able to fulfill its contractual obligations. There can be no assurance that problems related to the assets or management of the companies and operations we have acquired, or operations we may acquire or add to our portfolio in the future, will not arise in future, and these problems could have a material adverse effect on our business, financial condition, and results of operations. Significant acquisitions, and other strategic transactions may involve other risks, including: ● diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; 17 Table of Contents ● challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with ours while carrying on our ongoing business; ● contingencies and liabilities that could not be or were not identified during the due diligence process, including with respect to possible deficiencies in the internal controls of the acquired operations; and ● challenge of attracting and retaining personnel associated with acquired operations. It is also possible that we may not identify suitable acquisition targets or strategic investment, partnership, or alliance candidates. Our inability to identify suitable acquisition targets, strategic investments, partners or alliances, or our inability to complete such transactions, may negatively affect our competitiveness and growth opportunities. Moreover, if we fail to properly evaluate acquisitions, alliances, or investments, we may not achieve the anticipated benefits of any such transaction, and we may incur costs in excess of what we anticipate. Future acquisitions financed with our own cash could deplete the cash and working capital available to adequately fund our operations and return value to shareholders. We may also finance future transactions through debt financing, oil prepayment agreements, the issuance of our equity securities, existing cash, cash equivalents or investments, or a combination of the foregoing. Acquisitions financed with the issuance of our equity securities could be dilutive, which could affect the market price of our stock. Acquisitions financed with debt could require us to dedicate a substantial portion of our cash flow to principal and interest payments and could subject us to restrictive covenants. The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2023, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first day-of-the-month price for the preceding 12 months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as actual prices we receive for oil and natural gas, actual cost of development and production expenditures, the amount and timing of actual production, and changes in governmental regulations and taxation. The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general. The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced. As of December 31, 2023, 73% of our net proved reserves are developed. Development of our undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Additionally, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the standardized measure value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, and may result in some projects becoming uneconomic, causing the quantities associated with these uneconomic projects to no longer be classified as reserves. This was due to the uneconomic status of the reserves, given the proximity to the end of the concessions for these blocks, which does not allow for future capital investment in the blocks. There can be no assurance that we will not experience similar delays or increases in costs to drill and develop our reserves in the future, which could result in further reclassifications of our reserves. 18 Table of Contents We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations. Our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements. The combination of declining cash flows as a result of declines in commodity prices, a reduction in borrowing basis under reserves-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us. Some of our customers may be highly leveraged, and, in any event, are subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or curtail our customers’ future use of our products and services, which may have an adverse effect on our revenues and may lead to a reduction in reserves. Our operations are subject to operating hazards, including extreme weather events, which could expose us to potentially significant losses. Our operations are subject to potential operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic registration, exploration, production, development and transportation and storage of crude oil, such as explosions, fires, car and truck accidents, floods, labor disputes, social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures and spills and mechanical failure of equipment at our or third-party facilities. Any of these events could have a material adverse effect on our exploration and production operations or disrupt transportation or other process-related services provided by our third-party contractors. For example, during 2023, we incurred in higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified personnel. The ability, expertise, judgment and discretion of our management and our technical and engineering teams are key in discovering and developing oil and natural gas resources. Our performance and success are dependent to a large extent upon key members of our management and exploration team, and their loss or departure would be detrimental to our future success. In addition, our ability to manage our anticipated growth depends on our ability to recruit and retain qualified personnel. Our ability to retain our employees is influenced by the economic environment and the remote locations of our exploration blocks, which may enhance competition for human resources where we conduct our activities, thereby increasing our turnover rate. There is strong competition in our industry to hire employees in operational, technical, and other areas, and the supply of qualified employees is limited in the regions where we operate and throughout Latin America generally. The loss of any of our key management or other key employees of our technical team or our inability to hire and retain new qualified personnel could have a material adverse effect on us. We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs. We and our operations are subject to various international, foreign, federal, state, and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation and disposal of regulated materials; and human health and safety. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry, and which may arise unexpectedly and result in material adverse effects on our business, financial condition, and results of operations. Breach of environmental laws could result in environmental administrative investigations and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal or civil environmental 19 Table of Contents actions. For instance, non-governmental organizations may bring actions against us or other oil and gas companies in order to, among other things, halt our activities in any of the countries in which we operate or require us to pay fines. Additionally, in Colombia, environmental licenses are administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts on our E&P contracts. The Regional Agreement on Access to Information, Public Participation and Justice in Environmental Matters in Latin America and the Caribbean, also known as the Escazú Agreement, is an international human rights treaty that was signed by all the countries in which we operate and has been ratified by all, except for Brazil, where pressure has been growing for the government to ratify. We expect the countries where the agreement has been ratified will proceed to regulate the agreement and such regulations may include additional processes on participation and information, which could directly affect our operations as it could require additional processes that take time. Nonetheless, current Colombian processes require minor adjustments to comply with Escazú Agreement with regards to private involvement and we have extensive experience on such processes. The agreement also increases the protection of human rights and environmental activists, protection which we believe is much required in the countries where we operate and is aligned with our commitment to human rights. We are subject to national and regional environmental regulations and specific environmental requirements as part of the licenses and permits that we must obtain for our operations. We have mechanisms to assure the fulfillment of all those legal obligations such as a permanent external audit, a dedicated environmental team, and our environmental management system. The evidence of the fulfillment of such obligations is consolidated in the yearly environmental reports that are issued to the environmental authorities and correspond to public information. In addition, we are subject to yearly visits by the environmental national authority. Although we fulfill the requirements, sometimes we have not been and may not be at all times in complete compliance with some of them due to causes not attributable to us. This is the case of the offset obligations we have to implement to compensate the residual impacts that cannot be avoided, minimized or restored, in which we have to consider a concertation process with different stakeholders that could take more time than what the regulation provides. Nevertheless, we report the progress and we define action plans to demonstrate our diligence and reduce the possibility of sanctions, penalties or fines related to a delay in our fulfillment of the obligations, which could have a material adverse effect on our business, financial condition or results of operations. We have contracted with and intend to continue to hire third parties to perform services related to our operations. We could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors, predecessors, or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended, terminated, or otherwise adversely affected. Although we screen our contractors regarding their compliance on several issues, there is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. During 2023, we approved and adopted a Supplier Code of Conduct under which we define the minimum obligations and behaviors expected from our contractors and suppliers, aiming to address the risk. Releases of regulated substances may occur and can be significant. Under certain environmental laws and regulations applicable to us in the countries in which we operate, we could be held responsible for all the costs relating to any contamination at our past and current facilities and at any third-party waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species or sensitive environmental areas. We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in each of the countries in which we operate, which could result in substantial costs. In addition, we expect continued and increasing attention to climate change issues. Various countries and regions have agreed to regulate emissions of greenhouse gases including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation of greenhouse gases and the physical impacts of climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products. 20 Table of Contents We have set a target to reduce operational Scope 1 and 2 GHG emissions by 35-40 percent by year-end 2025 and by 40- 60 percent by year-end 2030 from a 2020 baseline. We also have a long-term ambition to achieve net zero Scope 1 and 2 GHG emissions from operations by 2050. Our ability to meet these targets is subject to numerous risks and uncertainties and actions taken in implementing such targets and ambition may also expose us to certain additional and/or heightened financial and operational risks, which is also dependent on how we grow. Furthermore, the long-term ambition of reaching net zero emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary to achieve this long-term ambition. A reduction in GHG emissions relies on, among other things, the ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technology and products, as well as our ability to participate in projects that capture carbon and reduce our footprint. If we are unable to implement these strategies and technologies as planned without negatively impacting expected operations or cost structures, or such strategies or technologies do not perform as expected, we may be unable to meet the 2025 and 2030 GHG reduction targets or the 2050 net zero emissions ambition on the current timelines, or at all. In addition, achieving the 2025 and 2030 GHG reduction targets and the 2050 net zero ambition relies on a stable regulatory framework and will require capital expenditures and resources, with the potential that actual costs may differ from the original estimates and the differences may be material. Furthermore, the cost of investing in emissions-reduction technologies, and the resultant change in the deployment of resources and focus, could have a negative impact on future operating and financial results, or could result in a differentiator for the company and our products. Environmental, health and safety laws and regulations are complex and change frequently, and our costs of complying with such laws and regulations may adversely affect our results of operations and financial condition. See “Item 4. Information on the Company—B. Business Overview—Health, safety and environmental matters” and “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework.” Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and limit our access to financing and insurance. A number of factors, including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and indigenous rights, have affected certain investors' sentiments towards investing in the oil and gas industry. As a result of these concerns, some institutional, retail, and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Although we have in place strong and robust social, environmental and governance practices, developing and implementing even broader policies and practices can involve significant costs and require a significant time commitment from our Board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in our Company or not investing in our Company at all. Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, our Company, may result in limiting our access to capital and insurance, increasing the cost of capital and insurance, and decreasing the price and liquidity of our common shares even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of our assets which may result in an impairment charge. Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations. Hydraulic fracturing of unconventional oil and gas resources is a process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to 21 Table of Contents facilitate a higher flow of hydrocarbons into the wellbore. We may eventually contemplate, after obtaining due environmental approvals, such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs. Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations. In Colombia, during the second half of 2022, the Council of State (the highest administrative court) issued a decision by which it denied the claims that were seeking nullity of the regulation for “non-conventional hydrocarbons”. Therefore, the regulation for unconventional oil and gas resources in Colombia is in force and with full effects. However, the government is seeking to prohibit fracking techniques in Colombia and, during the second half of 2022, a bill of law to forbid fracking and exploitation of unconventional hydrocarbons was filed in Congress. The bill of law is pending two debates in one of the chambers of Congress (house of representatives) and it is highly probable that the project is approved and sanctioned as a law. We currently are not aware of any proposals in Ecuador, Brazil or Chile to regulate hydraulic fracturing beyond the regulations already in place. However, various initiatives in other countries with substantial shale gas resources have been or may be proposed or implemented to, among other things, regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. If any of the countries in which we operate adopts similar laws or regulations, which is something we cannot predict right now, such adoption could significantly increase the cost of, impede or cause delays in the implementation of any plans to use hydraulic fracturing for unconventional oil and gas resources. Our indebtedness and other commercial obligations could adversely affect our financial health and our ability to raise additional capital and prevent us from fulfilling our obligations under our existing agreements and borrowing of additional funds. As of December 31, 2023, we had US$501.0 million outstanding amount of indebtedness on a consolidated basis, consisting of our Notes due 2027. Our indebtedness could: ● limit our capacity to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the agreements governing our indebtedness; ● require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, thereby reducing the availability of our cash flow to fund acquisitions, working capital, capital expenditures and other general corporate purposes; ● place us at a competitive disadvantage compared to certain of our competitors that have less debt; ● limit our ability to borrow additional funds; ● in the case of our secured indebtedness, if any, lose assets securing such indebtedness upon the exercise of security interests in connection with a default; ● make us more vulnerable to downturns in our business or the economy; and ● limit our flexibility in planning for, or reacting to, changes in our operations or business and the industry in which we operate. 22 Table of Contents The indenture governing our Notes due 2027 includes covenants restricting dividend payments and other shareholder distributions. For a description, see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources—Indebtedness.” As a result of these restrictive covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. We have in the past been unable to meet incurrence tests under the indenture governing our prior notes, which limited our ability to incur indebtedness. Failure to comply with the restrictive covenants included in our Notes due 2027 would not trigger an event of default. Similar restrictions could apply to us and our subsidiaries when we refinance or enter into new debt agreements which could intensify the risks described above. Our business could be negatively impacted by cybersecurity threats and related disruptions. We rely on information technology systems, including systems which are managed or provided by third-party providers, to conduct our business and support our exploration, development, and production activities. We increasingly depend on digital technologies, such as applications, a cloud environment, mobile platforms, computers, and telecommunications systems. We collect, use, transmit, store, and otherwise process data using information technology systems, including systems owned and maintained by us or our third-party providers. These data include confidential information and intellectual property belonging to us or our customers or other business partners. All information technology systems are subject to disruptions, outages, failures, and security breaches or incidents. A breach or failure of our digital infrastructure, control systems, or cyber defenses, or those of our third-party providers, as a result of negligence, intentional misconduct, or otherwise, could seriously disrupt our operations. We and our third-party providers have experienced, and expect to continue to experience, cybersecurity attacks. Cybersecurity attacks may range from employee or contractor error or misuse or unauthorized use of information technology systems or confidential information, to individual attempts to gain unauthorized access to these information systems, to sophisticated cybersecurity attacks, known as advanced persistent threats, any of which may target us directly or indirectly through our third-party providers. Despite employee training and other measures to mitigate vulnerabilities, our employees have been and will continue to be targeted by parties using fraudulent “spam”, “scam”, “phishing” and “spoofing” emails to misappropriate information or to introduce viruses or other malware programs to our technology environment. Cybersecurity attacks are increasing in number worldwide, and the attackers are increasingly organized and well-financed, or at times supported by state actors. Our industry is subject to fast-evolving risks from cyber-threat actors, including states, criminals, terrorists, hacktivists, and insiders. To the extent artificial intelligence capabilities improve and are increasingly adopted, they may be used to identify vulnerabilities and craft increasingly sophisticated cybersecurity attacks. Vulnerabilities may be introduced from the use of artificial intelligence by us, our customers, suppliers and other business partners and third-party providers. We continuously devote significant resources to network security, data loss prevention, and other measures to protect our systems and data from unauthorized access or misuse, and we may be required to expend greater resources in the future, especially in the face of evolving and increasingly sophisticated cybersecurity threats and laws, regulations, and other actual and asserted obligations to which we are or may become subject relating to privacy, data protection, and cybersecurity. We may be unable to anticipate, prevent, or remediate future attacks, vulnerabilities, breaches, or incidents, and in some instances, we may be unaware of vulnerabilities or cybersecurity breaches or incidents or their magnitude and effects, particularly as attackers are becoming increasingly able to circumvent controls and remove forensic evidence. Cybersecurity incidents may result in business disruption; delay in the development and delivery of our products; disruption of our production processes, internal communications, interactions with customers and suppliers and processing and reporting financial results; the theft or misappropriation of intellectual property; corruption, loss of, or inability to access (e.g., through ransomware or denial of service) confidential information, trade secrets, proprietary information, personal information, and other critical data (i.e., that of our company and our third-party providers and customers); reputational damage; private claims, demands, and litigation or regulatory investigations, enforcement actions, or other 23 Table of Contents proceedings related to contractual or regulatory privacy, cybersecurity, data protection, or other confidentiality obligations; diminution in the value of our investment in research, development and engineering; and increased costs associated with the implementation of cybersecurity measures to detect, deter, protect against, and recover from such incidents. Furthermore, the need for rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and coordinated means, presents a challenge we must face and any delay or failure to detect cyber incidents could compound potential harms. This could result in significant and compounding losses due to the cost of remediation and reputational consequences. Our efforts to comply with, and changes to, laws, regulations, and contractual and other actual and asserted obligations concerning privacy, cybersecurity, and data protection, including developing restrictions on cross-border data transfer and data localization, could result in significant expense, and any actual or alleged failure to comply could result in inquiries, investigations, and other proceedings against us by regulatory authorities or other third parties. Customers and third-party providers increasingly demand rigorous contractual provisions regarding privacy, cybersecurity, data protection, confidentiality, and intellectual property, which may increase our overall compliance burden. With respect to certain potential incidents, such as a cyber-attack or data breach, we are covered under a cybersecurity insurance. However, no assurances can be made as to whether the insurance policy is sufficient in coverage or amount to cover all our potential liability. The COVID-19 pandemic adversely impacted our business, financial condition, and results of our operations, the global economy, and the demand for and prices of oil and natural gas. The uncertainty of the impact an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business. The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic adversely impacted the global economy and created significant volatility in the global financial markets. The COVID-19 pandemic resulted in significant volatility in the financial and commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. In the event of a potential resurgence of the COVID-19 pandemic, responsive measures may be implemented and further disruptions to the global economy, demand, supply chain and others may occur. As of the date of this annual report, we believe we have implemented adequate operational measures (such as remote working procedures) to avoid or minimize major disruptions to our business. However, our operations rely on our workforce being able to access our wells, structures and facilities located upon or used in connection with our oil and gas blocks. The uncertainty of the impact that an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to an endemic or pandemic disease and we cannot assure if, and to what extent, our business, financial condition, cash flows or results of operations may be adversely impacted by any potential resurgence or outbreak of the COVID-19 pandemic, or any other regional or global outbreaks related to any other endemic or pandemic disease. The COVID-19 pandemic and its unprecedented consequences amplified, and may continue to amplify, the other risks identified in this annual report. We operate in an industry with climate related risks. The oil and gas industry, where we operate, is particularly exposed to risks arising from climate change and the energy transition, such as volatility of products prices, possible new regulations that may restrict our operations, and an increase in extreme weather events that affect our ability to operate. Moreover, our main assets are in countries like Colombia and Ecuador, where the risks related to the occurrence of natural hazards such as floods, landslides and droughts are high and expected to increase in the following years. For example, during 2023, we incurred in higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. 24 Table of Contents We operate in areas of significant biodiversity value. Some of our operations are in or adjacent to areas with significant biodiversity value, some of which are being considered for designation as conservation or protected areas. This could require modifications to our plans in order to adapt our projects to the environmental conditions and the allowed use of the land, which may increase viability costs and delay our timelines. We carry out detailed due diligence processes to mitigate the potential impacts derived from this risk, but there are factors outside of our control, such as local politics and political decisions. We operate in areas that have historical and current ties to indigenous peoples. We operate in highly culturally diverse areas, which brings us and our operations in close contact with different indigenous groups. This means we may need to carry out prior consultation processes aligned with local regulations. Such processes may cause delays in planned activities, thereby affecting our operations and may lead to claims from indigenous peoples, including those who have not been certified by the competent authorities, claims of alleged violations of human rights and may encourage requests for expansion of territories and precautionary measures to protect the rights of indigenous peoples, among others. During 2022 and 2023, as part of our exploration projects and based on certifications of the origin of prior consultation issued by the directorate of the national authority for prior consultation of the Ministry of the Interior, we have made advancements in the development of consultation processes in the department of Meta with the Resguardo, Turpial and La Victoria communities for the Golondrina development area project in the Llanos 86 and Llanos 104 Blocks. The agreements that resulted from the prior consultation process were documented and protocolized in August 2023. The prior consultation processes for the seismic acquisition program in those blocks is currently in the follow-up stage. In 2023, we made progress towards closing the prior consultation processes for the 2D and 3D seismic acquisition program in the Coati Block with indigenous communities from Santa Rosa del Guamuez, Yarinal, San Marcelino, Campo Alegre del Afilador and Parcialidad Nueva Palestina in the department of Putumayo. Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk due to overlapping claims of rightful ownership. Costs related to mitigation and offset measures to protect the habitat could be greater than currently anticipated due to the sensitivity of the biodiversity and the legal requirements imposed by the environmental authority. Nevertheless, we design our exploration and production projects while considering the conditions of the environment and avoiding any disruption to natural forest coverage and ecosystems connectivity. Several of the oil and gas development and exploration blocks in the Putumayo area in Colombia overlap with indigenous territories that are either formalized or are being considered for formal titling of tribal lands under the Colombian land restitution law. We have identified a material weakness in our internal control related to ineffective information technology general controls which could, if not remediated, result in material misstatements in our financial statements. In connection with the preparation of our financial statements as of December 31, 2023, we concluded there is a material weakness in our internal control related to ineffective information technology general controls (ITGCs). Notwithstanding, we have also concluded that the material weakness did not result in any identified misstatements to the consolidated financial statements, and there were no changes to previously released financial results. To remediate our material weakness, we have been implementing and will continue to implement measures designed to ensure that control deficiencies contributing to the material weakness are remediated, such that these controls are designed, implemented, and operating effectively. If our remedial measures are insufficient to address the material weakness, or if additional material weaknesses or significant deficiencies in our internal control over financial reporting are discovered or occur in the future, our financial statements may contain material misstatements and we could be required to restate our financial results. For further details on controls and remedial actions, see "Item 15. Controls and Procedures." 25 Table of Contents Risks relating to the countries in which we operate Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future. All of our current operations are located in South America. If local, regional or worldwide economic trends adversely affect the economy of any of the countries in which we have investments or operations, our financial condition and results from operations could be adversely affected. The Economic Commission for Latin America and the Caribbean (ECLAC) has forecasted a regional growth of 1.9% in 2024, after a 2.2% growth in 2023, indicating that the region would stay on a path of low growth, which means job creation would decelerate and informality and gender gaps would persist, among other effects. These projections reflect, in part, low dynamism in economic growth and global trade, which translates into a limited impetus from the global economy. Although inflation has declined, the interest rates of the main developed economies have not, which means that financing costs have remained at high levels throughout the year, and they are expected to stay that way in coming years. Furthermore, this low growth is also attributable to the limited domestic space for fiscal and monetary policy faced by the region’s countries. In this regard, it is emphasized that while public debt levels have declined, they remain high, and this, coupled with the increase in financing costs, restricts fiscal space. In the monetary arena, inflation continues to decline in the region, but monetary policy still has a restrictive bias, due to the effects that rate cuts could have on capital flows and the exchange rate, given that high interest rates are still in effect in developed countries. Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign-based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals from regulators, foreign exchange restrictions, price controls, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as to risks of loss due to civil strife, acts of war and community-based actions, such as protests or blockades, guerilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks are higher in developing countries, such as those in which we conduct our activities. The main economic risks we face and may face in the future because of our operations in the countries in which we operate include the following: ● difficulties incorporating movements in international prices of crude oil and exchange rates into domestic prices; ● the possibility that a deterioration in Colombia’s, Ecuador’s and Brazil’s relations with multilateral credit institutions, such as the International Monetary Fund, will impact negatively on capital controls, and result in a deterioration of the business climate; ● inflation, exchange rate movements (including devaluations), exchange control policies (including restrictions on remittance of dividends), price instability and fluctuations in interest rates; ● liquidity of domestic capital and lending markets; ● tax policies; and ● the possibility that we may become subject to restrictions on repatriation of earnings from the countries in which we operate in the future. In addition, our operations in these areas increase our exposure to risks of guerilla and other illegal armed group activities, social unrest, local economic conditions, political disruption, civil disturbance, community protests or 26 Table of Contents blockades, expropriation, tribal conflicts and governmental policies that may: disrupt our operations; require us to incur greater costs for security; restrict the movement of funds or limit repatriation of profits; lead to U.S. government or international sanctions; limit access to markets for periods of time; or influence the market’s perception of the risk associated with investments in these countries. Some countries where we operate have experienced, and may continue to experience, political instability, and losses caused by these disruptions may not be covered by insurance. During 2022, Colombia and Ecuador experienced social and political turmoil, including riots, nationwide protests, strikes and street demonstrations against their governments which led to acts of violence and social and political tensions. Future protests could adversely and materially affect the Colombian and Ecuadorian economies and our businesses in those countries. Consequently, our exploration, development and production activities may be substantially affected by factors which could have a material adverse effect on our results of operations and financial condition. We cannot guarantee that current programs and policies that apply to the oil and gas industry will remain in effect. Our operations may also be adversely affected by laws and policies of the jurisdictions in which we do business, that affect foreign trade and taxation, and by uncertainties in the application of, possible changes to (or to the application of) tax laws in these jurisdictions. For example, in 2022, the Colombian government enacted a tax reform that materially affected the oil producing companies. See Note 16 to our Consolidated Financial Statements. Changes in any of these laws or policies or the implementation thereof, and uncertainty over potential changes in policy or regulations affecting any of the factors mentioned above or other factors in the future may increase the volatility of domestic securities markets and securities issued abroad by companies operating in these countries, which could materially and adversely affect our financial position, results of operations and cash flows. Furthermore, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute. Changes in tax laws may result in increases in our tax payments, which could materially adversely affect our profitability, restrict our ability to do business in our existing and target markets and cause our results of operations to suffer. There can be no assurance that we will be able to maintain our projected cash flow and profitability following any increase in taxes applicable to us and to our operations. We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation. The success of our business and the effective operation of the fields in each of our countries of operation depend upon continued good relations and cooperation with applicable governmental authorities and agencies, including national oil companies such as Ecopetrol, Petroecuador and Petrobras. For instance, our Brazilian operations in BCAM-40 Concession provide us with a long-term off-take contract with Petrobras, the Brazilian state-owned company that covers 100% of net proved gas reserves in the Manati Field, one of the largest non-associated gas fields in Brazil. If we, the respective host governments and the national oil companies are not able to cooperate with one another, it could have an adverse impact on our business, operations and prospects. Oil and natural gas companies in Colombia, Ecuador and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries. Under Colombian, Ecuadorian and Brazilian law, all onshore and offshore hydrocarbon resources in these countries are owned by the respective sovereign. Although we are the operator of the majority of the blocks and concessions in which we have a working and/or economic interest and generally have the power to make decisions as how to market the hydrocarbons we produce, the Colombian, Ecuadorian and Brazilian governments have full authority to determine the rights, royalties or compensation to be paid by or to private investors for the exploration or production of any hydrocarbon reserves located in their respective countries. If these governments were to restrict or prevent concessionaires, including us, from exploiting oil and natural gas reserves, or otherwise interfered with our exploration through regulations with respect to restrictions on future exploration and production, price controls, export controls, foreign exchange controls, income taxes, expropriation of property, 27 Table of Contents environmental legislation or health and safety, this could have a material adverse effect on our business, financial condition and results of operations. Additionally, we are dependent on receipt of government approvals or permits to develop the concessions we hold in some countries. There can be no assurance that future political conditions in the countries in which we operate will not result in changes to policies with respect to foreign development and ownership of oil and gas, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities. Any delays in receiving government approvals in such countries may delay our operations or may affect the status of our contractual arrangements or our ability to meet contractual obligations. Oil and gas operators are subject to extensive regulation in the countries in which we operate. The Colombian, Ecuadorian and Brazilian hydrocarbons industries are subject to extensive regulation and supervision by their respective governments in matters such as the environment, social responsibility, tort liability, health and safety, labor, the award of exploration and production contracts, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls, export and import restrictions, capital expenditures and required divestments. In some countries in which we operate, such as Colombia, we are required to pay a percentage of our expected production to the government as royalties. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia” and see Note 33.1 to our Consolidated Financial Statements. For example, in Brazil there is potential liability for personal injury, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of operations or our being subjected to administrative, civil, and criminal penalties, which could have a material adverse effect on our financial condition and expected results of operations. We expect to also operate in a consortium in some of our concessions, which, under the Brazilian Petroleum Law, establishes joint and strict liability among consortium members, and failure to maintain the appropriate licenses may result in fines from the ANP, ranging from R$5 thousand to R$500 million. In addition, there is a contractual requirement in Brazilian concession agreements regarding local content, which has become a significant issue for oil and natural gas companies operating in Brazil given the penalties related with breaches thereof. The local content requirement will also apply to the production sharing contract regime. See “Item 4. Information on the Company—B. Business Overview—Our operations—Operations in Brazil.” Significant expenditures may be required to ensure our compliance with governmental regulations related to, among other things, licenses for drilling operations, environmental matters, drilling bonds, reports concerning operations, the spacing of wells, unitization of oil and natural gas accumulations, local content policy and taxation. Colombia has experienced and continues to experience internal security issues that have had or could have a negative effect on the Colombian economy. Despite the demobilization and disarmament that occurred because of the 2016 peace agreement, factors of instability persist in the territory, such as the presence of the Revolutionary Armed Forces of Colombia (FARC), the National Liberation Army (ELN) dissident forces and other illegal armed groups that seek to control drug trafficking and other illegal activities. The current government’s intention to solidify peace agreements with all criminal elements may cause an escalation of violent incidents, damage to infrastructure and social mobilizations that may have adverse effects on the country’s economy. The ELN has targeted crude oil pipelines in Colombia, including the Caño Limón-Coveñas pipeline, and other related infrastructure, disrupting the activities of certain oil and natural gas companies and resulting in unscheduled shutdowns of transportation systems. These activities, their possible escalation and the effects associated with them have had and may have in the future a negative impact on the Colombian economy or on our business, which may affect our employees or assets. The FARC has also historically attacked oil and gas infrastructure, bombing pipelines or attacking transport carrying oil and forcing drivers to spill it in Putumayo and our area of operations. For instance, in 2015, the content of 5 trucks of 28 Table of Contents Amerisur were spilled close to Puerto Asis, Putumayo. In 2023, the environmental licensing processes in Putumayo were affected as a result of the suspension of public hearings due to lack of adequate security conditions. Our operations are subject to security and human rights risks. Our operations can be affected by security related issues that may cause a halt or delay in production and exploration. The nature and magnitude of the risk may differ according to the area where operations are carried out. For example, our operations in Casanare and Meta may be affected by civil disturbances, including blockades. In Putumayo, the primary risk is the presence of illegal armed groups which control drug production and trafficking, and this situation can increase the perception of security risks, though the exact level of security risk depends on, among other factors, the location of the blocks and the time of crop production. Consequently, we develop security risk assessments on a yearly basis and constantly monitor specific security related issues. Moreover, since June 2022, we have strengthened our human rights and security risk management processes with our security contractors. As of December 2023, all our security contractors underwent training in security, human rights, and the voluntary principles (as determined by the United Nations Voluntary Principles on Security and Human Rights initiative). While we remain committed to strengthening our security processes and protocols, there is no guarantee that incidents of such nature will not occur in the future. We have also identified potential risks to our operations, neighboring communities, employees, and contractors and service providers, due to the presence of land mines around several of our blocks in Putumayo. The land mines around this area were primarily used by FARC to attack public security forces, but other illegal armed groups in the area, including FARC dissidents, have also been known to place land mines to attack public security forces or use them against their enemies in the fight for drug trafficking and production. In addition, our operations may be impacted by our adherence to national laws as well as all international human rights treaties ratified by the countries where we operate. As part of our commitment to respect human rights and engage in an open, respectful, and transparent manner with all our stakeholders, we always strive to resolve all issues with government authorities, especially following their lead with respect to guaranteeing human rights, through discussion and communication, which may result in delays to the advancement of our projects. We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash. We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash. Depending on our cash balance in any of our accounts at any given point in time, our balances may not be covered by government-backed deposit insurance programs in the event of default or failure of any bank with which we maintain a commercial relationship. The occurrence of any default or failure of any of the banks in which we have deposits could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, with regards to our accounts in the United States, while the U.S. Federal Deposit Insurance Corporation provides deposit insurance of US$250,000 per depositor, per insured bank, the amounts that we have in deposits in U.S. banks far exceed that insurance amount. Therefore, if the U.S. government does not impose measures to protect depositors in the event a bank in which our funds are held fails, we may lose all or a substantial portion of our deposits. As of December 31, 2023, we maintained 95% of our cash and cash equivalents in banks ranked within investment grade category. 29 Table of Contents Risks relating to our common shares An active, liquid, and orderly trading market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell our common shares. Our common shares began to trade on the New York Stock Exchange (the “NYSE”) on February 7, 2014, and as a result have a limited trading history. We cannot predict the extent to which investor interest in our company will maintain an active trading market on the NYSE, or how liquid that market will be in the future. The market price of our common shares may be volatile and may be influenced by many factors, some of which are beyond our control, including: ● our operating and financial performance and identified potential drilling locations, including reserve estimates; ● quarterly variations in the rate of growth of our financial indicators, such as net income per common share, net income and revenues; ● changes in revenue or earnings estimates or publication of reports by equity research analysts; ● fluctuations in the price of oil or gas; ● speculation in the press or investment community; ● sales of our common shares by us or our shareholders, or the perception that such sales may occur; ● involvement in litigation; ● changes in personnel; ● announcements by the company; ● domestic and international economic, legal and regulatory factors unrelated to our performance; ● variations in our quarterly operating results; ● volatility in our industry, the industries of our customers and the global securities markets; ● changes in our dividend policy; ● risks relating to our business and industry, including those discussed above; ● strategic actions by us or our competitors; ● actual or expected changes in our growth rates or our competitors’ growth rates; ● investor perception of us, the industry in which we operate, the investment opportunity associated with our common shares and our future performance; ● adverse media reports about us or our directors and officers; ● addition or departure of our executive officers; 30 Table of Contents ● change in coverage of our company by securities analysts; ● trading volume of our common shares; ● future issuances of our common shares or other securities; ● terrorist acts; or ● the release or expiration of transfer restrictions on our outstanding common shares. Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. We are committed to return value to our shareholders. From 2018 to 2023, we distributed US$156.4 million to shareholders through share buybacks and US$68.5 million in cash dividends. However, our availability to continue making distributions to shareholders in the future will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. For example, from April to November 2020, we temporarily suspended our quarterly cash dividends and share buybacks due to the sharp decline in oil prices as a result of the COVID-19 pandemic. Furthermore, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Companies Act, 1981 (as amended) of Bermuda (the “Companies Act”), we may not declare or pay a dividend or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become due; or (ii) that the realizable value of our assets would thereby be less than our liabilities. We are also subject to contractual restrictions under certain of our indebtedness. “Contributed surplus” is defined for purposes of section 54 of the Companies Act to include the proceeds arising from donated shares, credits resulting from the redemption or conversion of shares at less than the amount set up as nominal capital and donations of cash and other assets to the company. We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us. As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenue and cash flow is distributions from our subsidiaries. Thus, our ability to service our debt, finance acquisitions and pay dividends to our stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash distributions to us. Our subsidiaries are and will be separate legal entities, and although they may be wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends, distributions or otherwise. The ability of our subsidiaries to distribute cash to us will also be subject to, among other things, restrictions that are contained in our subsidiaries’ financing and joint operations agreements, availability of sufficient funds in such subsidiaries and applicable state laws and regulatory restrictions. Claims of creditors of our subsidiaries generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our ability to grow, pursue business opportunities or make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially limited. We may not be able to fully control the operations and the assets of our joint operations and we may not be able to make major decisions or take timely actions with respect to our joint operations unless our joint operation partners agree. We may, in the future, enter into joint operations agreements imposing additional restrictions on our ability to pay dividends. 31 Table of Contents Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. We may issue additional common shares or convertible securities in the future, for example, to finance potential acquisitions of assets, which we intend to continue to pursue. Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our memorandum of association, we are authorized to issue up to 5,171,949,000 common shares, of which 55,327,520 common shares were outstanding as of December 31, 2023. We cannot predict the size of future issuances of our common shares or the effect, if any, that future sales and issuances of shares would have on the market price of our common shares. Provisions of the Notes due 2027 could discourage an acquisition of us by a third party. Certain provisions of the Notes due 2027 could make it more difficult or more expensive for a third party to acquire us or may even prevent a third party from acquiring us. For example, upon the occurrence of a change of control, holders of the Notes due 2027 will have the right, at their option, to require us to repurchase all of their notes at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts, if any) to the date of purchase. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their common shares at a premium over prevailing market prices. Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control. Certain members of our board of directors and our executive officers held 17.9% of our outstanding common shares as of March 19, 2024, holding the shares either directly or through privately held funds. As a result, these shareholders, if acting together, would be able to influence matters requiring approval by our shareholders, including the election of directors and the approval of amalgamations, mergers, or other extraordinary transactions. They may also have interests that differ from yours and may vote in a way with which you disagree, and which may be adverse to your interests. The concentration of ownership may have the effect of delaying, preventing, or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market price of our common shares. See “Item 7. Major Shareholders and Related Party Transactions—A. Major shareholders” for a more detailed description of our share ownership. Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price. Shareholder activism has been increasing generally and in the energy industry specifically. Investors may attempt to effect changes to our business or governance, such as with respect to climate change or otherwise, by means such as shareholder proposals, public campaigns, proxy solicitations or other means. Such actions could adversely impact us by distracting the Board and employees from core business operations, increasing advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of the business. As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it. As a foreign private issuer, the rules governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although we intend to report quarterly financial results and report certain material events, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly or current reports may contain less information than required under U.S. filings. In addition, we are exempt 32 Table of Contents from the Section 14 proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Our exemption from Section 16 rules regarding sales of common shares by insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. For example, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales of our common shares. The periodic disclosure required of foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Information—H. Documents on display.” As a foreign private issuer, we are exempt from complying with certain corporate governance requirements of the NYSE applicable to a U.S. issuer, including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve any equity issuance by us which represents 20% or more of our outstanding common shares. As the corporate governance standards applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under U.S. law and the NYSE rules as shareholders of companies that do not have such exemptions. There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make. The permission of the Bermuda Monetary Authority is required, under the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of shares (which includes our common shares) of Bermuda companies to or from a non-resident of Bermuda for exchange control purposes, other than in cases where the Bermuda Monetary Authority has granted a general permission. The Bermuda Monetary Authority, in its notice to the public dated June 1, 2005, has granted a general permission for the issue and subsequent transfer of any securities of a Bermuda company from and/or to a non-resident of Bermuda for exchange control purposes for so long as any “Equity Securities” of the company (which would include our common shares) are listed on an “Appointed Stock Exchange” (which would include the New York Stock Exchange). In granting the general permission the Bermuda Monetary Authority accepts no responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this annual report. Any changes in the permission granted by the Bermuda Monetary Authority and related regulations could result in a delay or denial of any transfer of shares an investor might seek. We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. We are incorporated as an exempted company under the laws of Bermuda and our assets are substantially located in Colombia, Ecuador and Brazil. In addition, several of our directors and executive officers reside outside the United States and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult or impossible to effect service of process within the United States upon us, or to recover against us on judgments of U.S. courts, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violation of U.S. federal securities laws because these laws have no extraterritorial application under Bermuda law and do not have force of law in Bermuda. However, a Bermuda court may impose civil liability, including the possibility of monetary damages, on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. However, the courts of Bermuda would recognize any final and conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence 33 Table of Contents relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct procedures under the laws of Bermuda. In addition, and irrespective of jurisdictional issues, the Bermuda courts will not enforce a U.S. federal securities law that is either penal or contrary to Bermuda public policy. An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, will not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, would not be available under Bermuda law or enforceable in a Bermuda court, as they would be contrary to Bermuda public policy. The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia. In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax established in article 90-3 of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad are taxed in Colombia when such transaction represents a transfer of assets located in Colombia (“Colombian Assets”). Although certain conditions and exemptions apply, corporate reorganizations shall monitor this new regulation. As we indirectly own Colombian Assets, the indirect transfer rules would apply to transfers of our common shares provided certain conditions outside of our control are met. If such conditions were present and as a result the indirect transfer rules were to apply to sales of our common shares, such sales would be subject to indirect transfer tax on the capital gain realized in connection with such sales. For a description of the indirect transfer rules and the conditions of their application see “Item 10. Additional Information—E. Taxation—Colombian tax on transfers of shares.” Legislation enacted in Bermuda as to Economic Substance may affect our operations. Pursuant to the Economic Substance Act 2018 (as amended) of Bermuda (the “ES Act”) that came into force on January 1, 2019, a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda (“non-resident entity”) that carries on as a business any one or more of the “relevant activities” referred to in the ES Act must comply with economic substance requirements. The ES Act may require in-scope Bermuda entities which are engaged in such “relevant activities” to be directed and managed in Bermuda, have an adequate of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income- generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing, leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities. The ES Act could affect how we operate our business, which could adversely affect our business, financial condition and results of operations. Although it is presently anticipated that the ES Act will have little material impact on us or our operations, as the legislation is new and remains subject to further clarification and interpretation, it is not currently possible to ascertain the precise impact of the ES Act on us. ITEM 4. INFORMATION ON THE COMPANY A. History and development of the company General We were incorporated as an exempted company pursuant to the laws of Bermuda in February 2006. We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our principal executive office is located at Street 94 N° 11-30, 8th floor, Bogotá, Colombia, telephone number +57 1 743 2337. The SEC maintains an internet website that contains reports, proxy, information statements and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. The Company’s website address is www.geo-park.com. The information contained on, or that can be accessed through, the Company’s website is not part of, and is not incorporated into, this annual report. 34 Table of Contents Our Company We are a leading independent oil and natural gas exploration and production (“E&P”) company with operations in Latin America. We currently operate in Colombia, Ecuador and Brazil. We are focused on Latin America because we believe it is one of the richest and most underexplored hydrocarbon regions globally, with less presence of independent E&P companies compared to the United States and Canada. In this region, much of the acreage has historically been controlled or owned by state-owned companies. We believe that these factors create an opportunity for smaller, more agile companies like us to build a long-term business. We produced a net average of 36.6 mboepd during the year ended December 31, 2023, of which 90.0%, 2.5%, 2.8% and 4.7% were, respectively, in Colombia, Ecuador, Brazil and Chile, and of which 92.9% was oil. As of December 31, 2023, according to the ANH, we were ranked as the second largest oil operator in Colombia, where we made the largest new oil field discovery in the last 20 years. A clear set of priorities and key values have driven our Company through a two-decade track record of growth, sustainability performance and strong value delivery. Furthermore, our internal value system called Safety, Prosperity, Employees, Environment and Community Development (“SPEED”), which has been part of the Company’s culture since its inception, differentiates us from our peers, guides our decision-making process and is the basis for our value-generation approach to all our stakeholders. Meeting the energy needs of a growing population while contributing to the energy transition requires us to conduct best- in-class oil and gas exploration and operation, to manage our assets in the most ethical and sustainable way, and to continue creating long-term value for our shareholders and all our stakeholders. Our business model Our updated business model can be summarized in four simple words and one unifying idea: “We Make Assets Better”. This principle is underscored by our track record of adapting to change, expanding our capabilities, and continuously enhancing our asset portfolio. The model contains three comprises three interlocking elements: ● We deliver more energy by focusing on finding and producing energy as well as in effectively taking it to the market. This means we have a strong focus on results and to that end, our business model requires the right people, the right assets, and the right execution. ● We invest with the goal of returning value to all our stakeholders. That means we follow a disciplined capital allocation targeting the highest value projects, while responsibly taking on and managing risk. ● We create and share prosperity with everyone from our employees to governments and local communities. “Creating Value and Giving Back” is a central tenet of our Company and bringing prosperity to people while looking after the environment will always be one of our top priorities, all while maintaining the highest standards of ethics and governance. At the center of our company and our updated business model is our culture of agility, adaptability, and trust, and we have a horizontal structure where all our employees have autonomy, ownership, and a key role to play. Our culture is our binding force, and we need to protect and nurture it if we are to excel at the three interlocking elements described above. History We were founded in 2002. We are a leading independent oil and natural gas exploration and production (“E&P”), company with operations in Latin America. During 2023, we had operations in Colombia, Ecuador, Brazil and Chile, and as of January 2024, we have divested the entirety of our business in Chile as further described below. Our History can be summarized by our growth in each country and our performance in the capital markets: 35 Table of Contents Colombia In the first quarter of 2012, we entered into Colombia by acquiring three privately held E&P companies, that were later merged into GeoPark Colombia S.A.S. These acquisitions provided us with an attractive platform of reserves and resources in Colombia, including a 45% operated working interest in the Llanos 34 Block. During 2019, jointly with Ecopetrol/Hocol, we acquired five low-cost, low-risk and high-potential exploration blocks in the Llanos Basin, surrounding the Llanos 34 Block, and we also executed an agreement to assume a 50% non-operated working interest in the Llanos 94 Block. In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development, and exploration blocks in Colombia, distributed as follows: twelve operated blocks in the Putumayo basin (including the producing Platanillo Block) and one non-operated block in the Llanos basin (the producing CPO-5 Block), and a cross-border oil pipeline from Colombia to Ecuador. In 2023, we drilled and put into production five oil exploration wells in the Llanos 87 and Llanos 123 Blocks. Ecuador On May 22, 2019, we signed participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico (GeoPark non-operated, 50% working interest) Blocks in Ecuador. In 2022, we recorded our first oil sales in Ecuador due to the successful exploration campaign in the Perico Block, which continued during 2023, and we also acquired 60 sq km of 3D seismic and drilled our first exploration well in the Espejo Block. Brazil Since 2013, we have participated in several Bid Rounds promoted by the Brazilian ANP. In 2014, we acquired a 10% non-operated working interest in the BCAM-40 Concession, which included an interest in the Manati Gas Field operated by Petrobras. Chile In 2006, after demonstrating our technical expertise and committing to an exploration and development plan, we obtained a 100% operating working interest in the Fell Block from the Republic of Chile. Then, in 2011, ENAP awarded us operating working interests in each of the Isla Norte, Flamenco and Campanario Blocks. In December 2023, we entered into an agreement to sell our Chilean subsidiaries which comprised the entirety of our business in the country. The divestment transaction closed in January 2024 and, as part of the transaction, we have retained certain rights over unconventional activities that would be carried out in the Fell Block over the current operating contract in the future. Other Latin American countries During our history as operators, we have also had operations in Argentina and Peru, and we have participated in bid rounds in Mexico. As of the date of this annual report, we do not have operations in these countries. Funding In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares. Between 2005 and 2023, we raised approximately US$200 million in equity offerings at the holding company level and nearly US$1.5 billion through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity. 36 Table of Contents In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. The Notes due 2027 are fully and unconditionally guaranteed by GeoPark Colombia, S.L.U. Final maturity will be January 17, 2027. On June 17, 2022, we received requisite consents from holders of the Notes due 2027 for certain amendments to the indenture governing the Notes due 2027. The amendments addressed the impact of adverse market conditions and related drop in the price of crude oil during 2020 on our results, which in turn negatively impacted the restricted payments builder basket, and increased and reset the general restricted payments basket in the indenture to provide us additional restricted payments capacity, giving us additional financial flexibility. Consequently, on June 27, 2022, we paid a consent fee equal to $10.00 per $1,000 to holders of the Notes due 2027 that delivered their consents for the abovementioned amendments to the indenture governing the Notes due 2027. From April 2021 to September 2022, we repurchased and cancelled our US$425.0 million aggregate principal amount of 6.5% senior secured notes due 2024 (the “Notes due 2024”). In April 2021, we executed a tender to purchase US$255.0 million of the Notes due 2024, funded with a combination of cash in hand and the abovementioned reopening of the Notes due 2027. From March to September 2022, we repurchased and cancelled the remaining amount of the Notes due 2024 for a nominal amount of US$ 170.0 million. Following the abovementioned transactions, we reduced our total indebtedness nominal amount by US$275.0 million by using the cash generated from our operations and improved our financial profile by extending our debt maturities. On August 3, 2023, we signed a senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. which provides us with access to up to US$80 million, with an availability period until November 3, 2024, and final maturity on August 3, 2025. As of the date of this annual report, we have not withdrawn any amount under this credit facility. B. Business Overview We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. We continually evaluate the potential acquisition of strategic assets that will allow us to continue growing our business in line with our recent operating and financial successes. Since our inception, we have supported our growth through our prospect development efforts, drilling program, long-term strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and engineers, including professionals with specialized expertise in the geology of Colombia, Ecuador, Brazil, Chile and Argentina. 37 Table of Contents The following map shows the countries in which we have blocks with working and/or economic interests as of December 31, 2023. For information on our working interests in each of these blocks, see “—Our assets” below. (1) (2) In process of relinquishment. See “—Our operations—Operations in Colombia” and “—Our operations—Operations in Argentina.” In process of transferring our working interest in the block to the partner. See “—Our operations—Operations in Colombia” and “—Our operations—Operations in Argentina.” (3) Divested in January 2024. See “—Our operations—Operations in Chile.” 38 Table of Contents The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2023. For the year ended December 31, 2023 Country Colombia Ecuador Brazil Chile(1) Other Total Oil (mmbbl) 59.3 2.3 0.0 1.1 — 62.8 Gas (bcf) 1.1 — 8.9 10.8 — 20.8 Oil equivalent (mmboe) 59.5 2.3 1.5 2.9 — 66.2 100.0 % 1.9 % 37.9 % % Oil 99.7 % 702,401 19,097 14,019 15,644 5,464 94.8 % 756,625 Revenues (in thousands % of total revenues of US$) (1) Divested in January 2024. See “—Our operations—Operations in Chile.” The following table sets forth our average net production during the last five years, as measured by boepd. Average net production (mboepd) % oil 2023 36.6 93% For the year ended December 31, 2021 2020 2022 38.6 91% 37.6 86% 40.2 87% 92.8 % 2.5 % 1.9 % 2.1 % 0.7 % 100.0 % 2019 40.0 86% The following table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of December 31, 2023. Oil production Total crude oil production (bopd) Natural gas production Total natural gas production (mcf/day) Oil and natural gas production Colombia Ecuador Average daily production For the year ended December 31, 2023 Chile(1) Brazil Total 32,795 926 16 221 33,958 573 — 6,065 8,993 15,631 Total oil and natural gas production (mboepd) 32,890 926 1,027 1,720 36,563 (1) Divested in January 2024. See “—Our operations—Operations in Chile.” Our assets We have a portfolio of assets that includes working and/or economic interests in 34 hydrocarbon blocks, 33 of which are onshore blocks, including 10 in production as of December 31, 2023, and provides the ability to quickly optimize capital allocation as market conditions change. Our assets give us access to more than 4.7 million gross exploratory and productive acres. According to the D&M Reserves Report, as of December 31, 2023, the blocks in Colombia, Ecuador, Brazil and Chile in which we have a working interest had 66.2 mmboe of net proved reserves, with 89.9%, 3.5%, 2.3% and 4.4% of such net proved reserves located in Colombia, Ecuador, Brazil and Chile, respectively. We produced a net average of 36.6 mboepd during the year ended December 31, 2023, of which 90.0%, 2.5%, 2.8% and 4.7%, were in Colombia, Ecuador, Brazil and Chile, respectively, and of which 92.9% was oil. Our strengths We believe that we benefit from the following competitive strengths: 39 Table of Contents High quality and diversified asset base built through a successful track record of organic growth and acquisitions Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys in Latin America. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited assets and turn them into valuable, productive assets, and to allocate resources effectively based on prevailing conditions. For further information on our organic growth and acquisitions in each country, see “—A. History and Development of the Company—History” and “—Our operations.” Significant drilling inventory and resource potential from existing asset base Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological formations, which provide several attractive opportunities with varying levels of risk. Our drilling inventory and our development plans target locations that provide attractive economics and support a predictable production profile, as demonstrated by our expansions in Colombia. Our geoscience team continues to identify new potential accumulations and expand our inventory of prospects and drilling opportunities. Risk-balanced asset portfolio We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In general, when we enter a new country we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term possibility of production, to generate cash flows; (ii) an inventory of adjacent low-risk prospects that can offer medium-term upside for steady growth; and (iii) a periphery of higher- risk projects which have a potential to generate significant upside in the long run. For example, in Colombia, we acquired Amerisur in 2020 to pursue a risk-balanced approach: one block had mainly proven production and reserves to provide us with a steady cash flow base, and the remaining blocks had highly prospective exploration licenses. We believe this approach will allow us to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside potential. See “—Our operations.” Platform and Funding We are focused on continued growth utilizing a disciplined capital structure and a conservative financial philosophy. Due to the volatile nature of commodity prices, expenditure discipline and a focus on disciplined capital structure are critical to our business. Our multi-country platform and asset portfolio is managed through our capital allocation methodology, which also allows us to quickly adapt and grow. Under this methodology, we rank all of the projects based on economic, technical, environmental, social and corporate governance and strategic criteria, for the purpose of comparing projects. This also creates opportunities for improvements in the projects that can, in turn, improve their ranking. Finally, once the production and reserve growth targets are defined, we agree on the amount of capital to be invested and allocates that capital to the highest value-adding projects. As an example, for the 2024 capital allocation process, over 307 projects were selected which comprise our 2024 work program, under the base capital program. Additionally, given the inherent oil price volatility, we design our work programs to be flexible, which means that they can be increased or decreased depending on the oil price scenario. We have historically benefited from access to debt and equity capital markets and cash flows from operations, as well as other funding sources, which have provided us with funds to finance our organic growth and the pursuit of potential new opportunities. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.” 40 Table of Contents We generated US$300.9 million and US$467.5 million in cash from operations in the years ended December 31, 2023 and 2022, respectively, and had US$133.0 million and US$128.8 million of cash and cash equivalents as of December 31, 2023 and 2022, respectively. As of December 31, 2023, we had US$501.0 million of total outstanding indebtedness which is scheduled to mature in January 2027. Strong cash flow We benefit from a strong cash flow from operating activities. For the year ended December 31, 2023, cash flows from operating activities were US$300.9 million. Our cash flows from operating activities plays a significant role in funding our capital expenditures and shareholders return. Maintain financial strength We seek to maintain a prudent and sustainable capital structure and a strong financial position to allow us to maximize the development of our assets and capitalize on business opportunities as they arise. We intend to remain financially disciplined by limiting substantially all our debt incurrence to identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition to the international capital markets. Our cash flow generation is complemented by our financial hedging program. Since October 2016, we have entered into derivative financial instruments to partially manage our exposure to oil price risk. The purpose of our hedging strategy is to establish minimum oil prices to secure a stable cash flow and the execution of our work program. For more information regarding our financial hedging program please see Note 8 to our Consolidated Financial Statements. We believe that by maintaining a disciplined capital structure and a conservative financial philosophy, including limiting our debt incurrence to specified projects with repayment sources and our use of financial hedges, we are positioned to maintain sufficient liquidity and remain flexible in volatile commodity price environments. Our financial flexibility also gives us the ability to pursue new opportunities through future potential acquisitions. Pursue strategic acquisitions in Latin America We have historically benefited from, and intend to continue to grow through, strategic acquisitions in Latin America. These acquisitions have provided us with additional attractive platforms in the region. Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become the second largest operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30 million and have achieved 1P reserve PV-10 of US$823 million as of December 31, 2023. Our enhanced regional portfolio, including investment-grade countries and strong partnerships, position us as a regional consolidator. We intend to continue to grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix of oil and gas-producing assets (though we expect to remain weighted towards oil) and focusing on both assets and corporate targets. In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and one non-operated block in the Llanos Basin) and a cross-border oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“OBA”). Maintain a high degree of operatorship to control production costs As of the date of this annual report, we are and intend to continue to be the operator of a majority of the blocks and concessions in which we have working interests. Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically and efficiently within a diversified asset portfolio. We 41 Table of Contents believe that this strategy has allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and our talented technical, operating and management teams. Long-term strategic partnerships and strong strategic relationships provide us with additional funding flexibility to pursue further acquisitions We benefit from a number of strong partnerships and relationships. In Colombia, we believe we have developed a strong relationship with Ecopetrol, the Colombian state-owned oil and gas company. In Brazil, we believe we will continue to derive benefits from the long-term relationship with Petrobras. Maintain our commitment to environmental, safety, human rights and social responsibility An important component of our business strategy is our corporate approach and commitment to our safety, environmental and social responsibilities, which is embodied in decisions that are framed by our safety, environmental and social responsibility internal policies and aligned with international standards. We see this as a fundamental element in securing business initiatives for long-term growth. Our commitment to sustainable development has allowed us to generate positive impacts in the territories in which we operate, with important contributions to the protection of biodiversity and the environment, as well as to the wellbeing and reduction of multidimensional poverty in neighboring communities. We maintain a social license to operate, based on the construction and maintenance of mutually beneficial relationships with local communities, the return of value as allies for their social and economic development, the respect for their human rights and the care and preservation of the environment. Detailed information can be found in our last SPEED Report which is available at the Company’s website. Our internal value system is called Safety, Prosperity, Employees, Environment and Community Development (“SPEED”). Our SPEED program was developed in accordance with several international quality standards, including ISO 14001 (for environmental management issues), ISO 45001 (for occupational health and safety management issues), ISO 26000 (for social responsibility and workers’ rights issues), IFC guidelines for social and environmental performance, and guidelines from associations including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.” Our Environmental Management System (“EMS”) has been certified under the ISO 14001:2015 standard since 2017. The scope of this certification includes all our activities, processes and products related to the exploration and exploitation of hydrocarbons in Colombia, covering 97% of our operations. In 2023, we obtained the latest re-certification of the ISO 14001:2015, which is valid until August 2026. Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-1 standard of the Colombian Institute of Technical Standards and Certification (ICONTEC). GeoPark was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions of greenhouse gases and help the countries where we operate meet their commitments under the Paris Agreement. During 2023, we continued to incorporate clean energy sources in our operations, and implemented energy efficiency measures, while also managing our methane emissions in accordance with our decarbonization targets. In January 2023, GeoPark was included for a second year in a row in the Bloomberg Gender-Equality Index, including companies with best-in-class gender-related practices and policies. Additionally, we were recognized by the Portfolio Awards in the Corporate Social Responsibility category for our commitment and positive impact on neighboring communities. During 2023, we carried out our first ever double materiality assessment with the help of an expert consultant and following GRI guidelines. Our new materiality matrix includes the following topics: climate action; ethics and transparency; responsible management of water and biodiversity; health and safety in the workplace; community engagement; human talent management, equality, inclusion and diversity; energetic transformation; air quality management; and supply chain management. 42 Table of Contents In 2023, we delivered our SPEED/sustainability report and Environment, Social and Governance metrics according to the Global Reporting Initiative (GRI) standards as well as the sustainability reporting guide of the Global Oil and Gas Association for Advancing Environmental and Social Performance (IPIECA, 2020), selected metrics of the Sustainability Accounting Standards Board (SASB, 2018) and in alignment with Spain’s Law 11 of 2018 on non-financial information disclosures. Furthermore, our 2023 SPEED/ESG+ Report will include the guidelines of the Task Force on Climate Related Financial Disclosures (TCFD) for the first time. In 2023, we submitted the Carbon Disclosure Project’s (CDP) Climate Change questionnaire for the second time and obtained a B rating, an improvement from the C obtained in the year prior. We also submitted the CDP water questionnaire for the first time and obtained a C giving us a baseline against to benchmark future performance. We were recognized with the 2023 Portfolio Award in the Corporate Social Responsibility category. The Portfolio Awards are given annually by the “El Tiempo” editorial house to companies with outstanding sustainability performance. In 2022, the Colombian national government, through its department for social prosperity, once again recognized our “Sustainable Housing” program among the 24 most important public, private and international cooperation programs in terms of overcoming poverty in Colombia. The homes of more than 2,000 families that are neighbors to our areas of operation in the country have been benefitted by this program, which we have been carrying out since 2013 in alliance with the ‘Minuto de Dios’ corporation. In 2022, we participated along with the 150 largest companies in Colombia, obtaining special recognition for best performance in the “Focusing” component associated with the implementation of social and environmental investment initiatives in the most vulnerable areas and populations of the country. Since 2021, we have participated in the private social investment index, an independent syndicated study conducted by Jaime Arteaga y Asociados (JA&A), which aims to measure the effort of the private sector to improve the living conditions of communities and/or population groups based on their voluntary decision to invest in social and environmental projects. In 2019, we joined the Equipares gender equality certification program, an initiative of the Colombian government and the United Nations Development Program (UNDP) focused on achieving parity in the workplace. In 2020, we created a standing company-wide committee to implement action plans that encourage and sustain the values of equity, inclusion and diversity. In 2020, we also reported for the first time our gender equality metrics using the Bloomberg Gender Reporting Framework. In 2021, we achieved the Equipares Silver Seal, after the Colombian Institute of Technical Standards and Certification (ICONTEC) gave a 91/100 rating to our SGIG (Gender Equality Management System). In 2018, the Colombian government granted GeoPark the “Best Social Practices in the Energy Industry” award for our good neighbor social conflict prevention program. GeoPark’s model for community engagement was chosen out of 107 different initiatives by a panel composed of representatives from the Ministry of Mines and Energy, the National Hydrocarbons Agency and the United Nations Development Program. In 2019, we won the “Best Social Practices in the Energy Industry” award for the second year in a row, along with the “Best Socio-Laboral Practices” award for our “Juntos Sumamos” program. In 2021, we again won the “Best Social Practices in the Energy Industry” award for our “Sustainable Housing” program, which improves the living conditions and well-being of our neighbors in Casanare and Putumayo. The jury was composed of public sector members and representatives from academic and multilateral organizations. The award was determined based on the impact of each initiative, its sustainability efforts, innovation, and relation to the 2030 agenda. Additionally, we recently improved our performance in the MSCI ESG Ratings Assessment from A to AA, providing our stakeholders with further evidence of our commitment to sustainability and value generation across the board. Our approach on human rights seeks to conduct business in a way that is consistent with the UN Guiding Principles on Business and Human Rights (the “UN Guiding Principles”), the ten UN Global Compact Principles and the Voluntary Principles on Security and Human Rights. Our commitment to these standards is reflected in our SPEED program, as well as in all our policies and procedures. Human Rights aspects are integrated into internal management processes, tools, communications, contracts, and trainings. 43 Table of Contents As part of our commitment to sustainable development and the sustainability development goals, we joined the United Nations Global Compact in 2023. We have a grievance mechanism in place for all our blocks and operations in Colombia, which is aligned with the UN Guiding Principles (UNGP) on Business and Human Rights, meaning it is accessible, legitimate, aligned with judicial and non-judicial grievance mechanisms, based on dialogue and participation, and predictable, to name a few of the eleven principles established in the UNGP. Having open, accessible, transparent, and respectful communication with all our stakeholders is crucial to respecting their human rights to information and participation. Our grievance mechanism, “Cuéntame” (“Tell me” in English), is one of our most important tools to engage with communities, contractors and service providers, and our employees on the ground, and this is especially true because it is easily accessible to all through all our social engagement employees, email, several mobile and Whatsapp numbers, and an office in the biggest city close to our operations. Furthermore, if any stakeholder approaches our doors, they will be informed about the mechanism and will be able to present a grievance, complaint or question immediately. To further align and strengthen our grievance mechanism with the highest standards on human rights, in 2022, we worked with a reputable NGO in Colombia called “Fundación Ideas para la Paz” to assess “Cuéntame” against the UNGP, the OECD Guidance, the International Financial Corporation and the World Bank standards. We were ranked as having best practices (meaning a complete level of implementation) in one of the UNGP, as having high level of progress and implementation in eight of the UNGP, and as having progress with an opportunity to improve in two of the UNGP. As part of the results, we have implemented a plan to close some of the gaps identified, for example by increasing the number of forums and meetings to communicate and raise awareness of the existence of the grievance mechanism, as well as providing stakeholders the opportunity to give feedback on the mechanism’s operation, effectiveness, responses, among others. To be even closer to our neighbors in Colombia, we opened a “Cuentame” office in Puerto Asis (Putumayo) in 2021 and one in Tauramena (Casanare) in 2023. The offices are open to the community, and through it GeoPark seeks to continue strengthening dialogue with all its stakeholders and encourage active community participation so that all neighbors can share proposals and ideas to promote harmonious coexistence and good neighborliness. For further information related to health, safety and environmental matters, please see “—Health, safety and environmental matters.” Transparency, ethics and anti-corruption Transparency is a cornerstone of good governance and it is embodied in our corporate values. Transparency allows business to prosper in a predictable and competitive environment. We believe that doing business in an ethical and transparent manner is a prerequisite for sustainable business. We have zero-tolerance policy towards all forms of corruption. This policy is embedded across our Company through our corporate values, our Code of Conduct (Our Code), and our Compliance Program. They prohibit all forms of corruption and bribery and reflects our values and our commitment to high ethical standards in business activities; they apply to all our employees, board members and third parties. Our Compliance Program aims to support and promote an ethics culture, as well as create and establish commitments and procedures that ensure internal and external regulatory compliance and anti-corruption matters. Program execution and implementation is the responsibility of our Compliance Department, which is directed by the Corporate Governance and Compliance Manager, who reports directly to the Audit Committee. Additionally, the Board's Audit Committee monitors the effectiveness of the compliance program, controls, and risk mitigation measures, and oversees plans to strengthen ethical culture. The program is based on three pillars: ● Prevention: ethics-based culture, including tone from the top matters, training and awareness and ethic line management. ● Detection: risk assessment and advisory, including policies and procedures assurance, laws and regulations compliance and risk assessment management. ● Monitoring: monitor and oversight, including on-going monitoring, due diligence third parties and regulations oversight. 44 Table of Contents Since 2018, we have actively participated in the Colombian Extractive Industries Transparency Initiative (EITI) and contributed data to the country’s annual EITI report. During 2023, GeoPark continued its adherence to the Business Ethics Leadership Alliance (BELA) as part of its efforts to continue strengthening its ethical culture. BELA is a platform of more than 375 companies in 60 industries recognized worldwide for their ethics and compliance leadership. Highly committed founding shareholder and technical and management teams with proven industry expertise and technically-driven culture Management and operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture, which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience on finding and developing oil and gas fields. In addition, we strive to provide a safe and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals. One of our founding shareholders and current Vice Chair of the Board, Mr. James F. Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, drilling and production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and capital raising for the industry. As of March 19, 2024, Mr. Park held 15.9% of our outstanding common shares. Our management and operating team have an average experience in the energy industry of more than 25 years in companies such as Chevron, Ecopetrol, ENAP, Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our history, our management and operating team has had success in unlocking unexploited value from previously underdeveloped assets. In addition, as of March 19, 2024, our executive directors and executive officers (excluding Mr. James F. Park) owned 1.2% of our outstanding common shares, aligning their interests with those of our shareholders and helping retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management and Employees— B. Compensation.” One of our founding shareholders is also involved in our daily operations and strategy. Technically-driven culture and capitalization of local knowledge We intend to continue to pursue strategies that maximize value. For this purpose, we intend to continue expanding our technical teams and to foster a culture that rewards talent according to results. For example, we have been able to maintain the technical teams we inherited through our Colombian and Brazilian acquisitions. We believe local technical and professional knowledge is key to operational and long-term success and intend to continue to secure local talent as we grow our business in different locations. Innovation We embrace innovation as a foundation for cultivating a dynamic work culture that consistently seeks improvements in our operational processes. The objective is to streamline costs, increase production, minimize risks, and optimize information management. At GeoPark, we firmly believe that creating an innovative culture is necessary for ensuring our enduring success. Through a proactive approach to innovation, our goal is to create positive impacts on productivity, enable effective decision-making based on reliable and timely information, fortify teamwork, foster leadership skills, and establish a culture that champions creativity and innovation. 45 Table of Contents The innovation program continues to generate not only tangible benefits across the company and environmental sustainability, but strengthens the development of new skills within the organization. Innovation not only contributes to improving internal conditions but also plays a vital role in positively influencing the communities where we operate. In 2023, we diligently monitored a range of innovation projects identified during workshops, effectively fostering a culture of innovation across various areas. The integration of digital capabilities, including Artificial Intelligence, Machine Learning, Internet of Things, Big Data, Automation, and Cloud Computing, marked a significant achievement. Throughout the year, collaborative innovation initiatives with leading partners such as Microsoft, Google, Halliburton, Cisco, SAP, Indra and many others were executed, showcasing our commitment to cutting-edge advancements. The ongoing innovation journey is exemplified by several projects, some still in progress: ● Horizontal drilling: implementing a pilot and executing horizontal drilling campaign, improving the recovery factor in our reserves of hydrocarbons in the Llanos 34 Block. ● Carbon Quantum Dot (CQD): simultaneous development and injection of Nanotracers based on CQD for waterflooding in Llanos 34 Block, allowing us to not only prove the technology but also obtain tax benefits. ● Process Integration: implementing systems aimed at achieving high reliability level of production tests data utilizing Multiphase Meter equipment while expediting their management. Additionally, optimizing production data to minimize the time required for information gathering, analysis, and identification of opportunities to increase production in the wells. ● Nanotechnology PoC: applying nanotechnology in fluids to induce specific chemical and physical reactions on a nanometric scale to improve oil production. The concept is expected to be proven in 2024. ● Centrifuge for tank bottoms: implement a centrifuge decanter to reduce waste-water in +50%, reducing OPEX and CO2 emissions in our operation in the Llanos 34 Block. It is expected to be implemented in 2024. ● Electrocoagulation: improving waste-water treatment for injection or road dampening in minor field. ● Facilities optimization: addressing energy consumers and enhancing the energy efficiency of water injection pumps. ● Video analytics and pipeline failure detection: deploying a real-time monitoring system for facilities powered by solar energy and artificial intelligence to detect failures and non-ethical intrusions. ● Cloud journey: approximately 100% of the infrastructure is in the cloud with intercloud redundancies and strong cybersecurity capabilities. Other innovation projects were executed across all organizational areas, encompassing people, processes, and technology. We remain vigilant in our commitment to identify innovation opportunities that enhance enterprise productivity, employee collaboration, communication, and decision-making through technology. Ongoing efforts aim to further embed this innovation culture throughout the company with plans for new workshops geared towards capturing and developing ideas and strengthening skills in our team while focusing on: production, geosciences, circular economy and energy transition, and innovation management. 2024 Strategy and Outlook Oil prices have been volatile over the past years. In preparation for continued volatility, we have developed multiple scenarios for our 2024 capital expenditures program. 46 Table of Contents Our preliminary base capital program for 2024 considered a reference oil price assumption of US$80-90 per barrel and calls for approximately US$150-200 million to fund our exploration and development which we intend to fund through cash flows from operations and cash-in-hand. In addition, we have developed downside and upside work program scenarios based on different oil prices and project performance. The downside scenario work program considers a reference oil price assumption below US$70 per barrel and consists of an alternative capital expenditure program of approximately US$100-150 million consisting mainly of certain low risk projects with shorter payback periods. The upside scenario work program considers a reference oil price assumption above US$90 per barrel or higher and consists of an alternative capital expenditure program of approximately US$200-250 million to be selected from identified projects designed to increase reserves and production. To secure minimum oil prices for our 2024 production, we have commodity risk management contracts in place covering a portion of our production for the year and monitor market conditions on a continuous basis to evaluate additional new commodity risk management contracts for the future. See Note 8 to our Consolidated Financial Statements. As part of our strategy, we continue to monitor the impact of oil price volatility on our financial condition, cash flows and results of operations. Our operations We have a portfolio of assets that includes working and/or economic interests in 34 hydrocarbon blocks, 33 of which are onshore blocks, including 10 in production as of December 31, 2023, and provides the ability to quickly optimize capital allocation as market conditions change. Our assets give us access to more than 4.7 million gross exploratory and productive acres. Operations in Colombia Our Colombian assets currently give us access to 3,401,000 gross exploratory and productive acres across 20 blocks in what we believe to be one of South America’s most attractive oil and gas geographies. Since we entered Colombia in 2012, we have achieved successful exploration and development activities at our operated Llanos 34 Block, which as of December 31, 2023, accounts for 66.8% of our production and 71.1% of our proved reserves in Colombia. Highlights of the year ended December 31, 2023, related to our operations in Colombia included: ● Successful drilling and putting into production the Saltador 1, Toritos 1, Bisbita Centro 1 exploration wells in the Llanos 123 Block; ● Successful drilling and putting into production the Zorzal 1 and Zorzal Este-1 exploration wells in the Llanos 87 Block; ● Successful drilling and putting into production the Halcon 1 exploration well in the CPO-5 Block; ● Drilling campaign with 16 gross development wells drilled and putting into production in the Tigana, Tigui and Tua oil fields in the Llanos 34 Block, including successful drilling and putting into production 5 horizontal wells in the Tigana oil field; ● Photovoltaic solar system installed in the OBA export pipeline (running from the Platanillo block) that allows us to reduce GHG emissions and reduce energy and maintenance costs; ● Average net oil production of 32,795 boepd in 2023 (33,640 boepd in 2022), influenced by a temporary shut-in of the Indico 6 and Indico 7 wells in the CPO-5 Block from January to September 2023, reaching an exit production in the fourth quarter of 2023 of 34,154 boepd; ● Proved oil and gas reserves 59.5 mmboe at year-end 2023 (64.6 mmboe at year-end 2022), after producing 11.2 mmboe; 47 Table of Contents ● Capital expenditures of US$178.1 million in 2023 (US$139.2 million in 2022), representing an 89% of our total capital expenditures; and ● Operating costs levels per barrel of US$11.5 in 2023 (US$6.6 in 2022), mainly due to higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues from a given block based on bilateral agreements with the concessionaires. The table below summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2023. Gross acres (thousand acres) 61.8 148.3 490.8 Working interest(1) 100% 50% 30% Partners(2) — Parex ONGC Videsh Operator GeoPark Parex ONGC Videsh Production (boepd) Basin — Putumayo — Llanos 5,563 Llanos 8.5 12.5% Verano Energy Verano Energy 360 Llanos 59.1 255.5 107.6 89.2 274.8 88.3 27.6 74.1 27.5 102.8 121.5 114.6 148.0 589.0 586.6 45% 50% 50% 50% 50% 50% 50% 50% 100% 50% 50% 100% 50% 50% 50% Verano Energy Hocol Hocol Parex Hocol Hocol Hocol Sierracol Energy — Sierracol Energy Sierracol Energy — Sierracol Energy Sierracol Energy Sierracol Energy GeoPark GeoPark GeoPark Parex GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark GeoPark 24,425 Llanos — Llanos 68 Llanos — Llanos — Llanos 352 Llanos — Llanos — Putumayo Putumayo — Putumayo — Putumayo — Putumayo — Putumayo — Putumayo — Putumayo 2,103 Block Coatí CPO-4-1 CPO-5 Llanos 32 Llanos 34 Llanos 86 Llanos 87 Llanos 94(4) Llanos 104 Llanos 123 Llanos 124 Mecaya Platanillo PUT-8 PUT-9 PUT-14 PUT-36 Tacacho Terecay Concession expiration year Exploration: Currently suspended Exploration: 2025 Exploration: 2025 Exploitation: 2042-2045(3) Exploration: 2022 Exploitation: 2040-2045(3) Exploitation: 2039-2045(3) Exploration: 2026 Exploration: 2023 Exploration: 2025 Exploration: 2026 Exploration: 2024 Exploration: 2024 Exploration: Currently suspended Exploitation: 2033(3) Exploration: 2024 Exploration: Currently suspended In process of termination Exploration: Currently suspended In process of termination In process of termination (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. (2) Partners with working interests. (3) The concession expiration year is set on a field-by-field basis. (4) In process of transferring our working interest in the block to the partner. As of December 31, 2023, we had net proved reserves of 56.3 mmboe in various blocks in the Llanos Basin, with the Llanos 34 Block representing 83.6% of the reserves, and 3.2 mmboe in the Platanillo Block in the Putumayo Basin. The table below summarizes information about the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 2023. Block Abanico Gross acres (thousand acres) 25.7 Economic interest(1) Operator 10% Frontera Production (boepd) Basin 20 Magdalena (1) Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. 48 Table of Contents Eastern Llanos Basin: The Eastern Llanos Basin is a Cenozoic Foreland basin in the eastern region of Colombia. Two giant fields (Caño Limón and Castilla), three major fields (Rubiales, Apiay and Tame Complex) and approximately fifty minor fields had been discovered. The source rock for the basin is located beneath the east flank of the Eastern Cordillera, as a mixed marine- continental shale basinal facies of the Gachetá formation. The main reservoirs of the basin are represented by the Paleogene Carbonera, Guadalupe and Mirador sandstones. Within the Cretaceous sequence, several sandstones are also considered to have good reservoirs. Llanos 34 Block. We are the operator of, and have a 45% working interest in, the Llanos 34 Block, which covers approximately 59,085 gross acres (239 sq. km.). We acquired an interest in and took operatorship of the block in the first quarter of 2012, which at that time had no production, reserves or wells drilled on it, and with 210 sq. km. of existing 3D seismic data on which our team had mapped multiple exploration prospects. From 2012 to 2023 we engaged in exploration and development activities that resulted in 10 new oil fields discoveries and increased proved reserves and oil production up to a peak oil production of 34,995 bopd. Average net production in 2023 was 24,425 bopd and net reserves of 47.1 mmboe. By the end of 2023, we have drilled more than 230 wells, with 166 producer wells that have accumulated more than 179 million barrels of oil. The Llanos 34 Block has three reservoirs: the Guadalupe Formation, which produces 72% of our oil production in the Block, Mirador, which produces 26% of our oil production in the Block and Gacheta, which produces 2% of our oil production in the Block, with an API gravity between 12.7° and 30.6°. During these 12 years of operation in Llanos 34 Block, we have built all the required infrastructure to produce and manage the fluids of the assets, including 10 production facilities, 81 kilometers of power grid, more than 97 kilometers of flowlines for fluid transfer, 169 kilometers of roads and a 42 kilometers oil pipeline. By the end of 2023, we have transported more than 72 million barrels of oil from Tigana and Jacana fields through the ODCA pipeline further reducing truck traffic, contributing to the reduction of operational risk, shutdowns (due to road blockades), costs and carbon emissions. In August 2022, we connected the Llanos-34 Block to the national power grid, reducing the risk of shutdown, cost and carbon emissions. In October 2023, we entered into an interconnection agreement through which we expect to have an additional 20 megawatts of power energy transmission capacity available for our operations in Llanos 34 Block by early 2025. Our partner in the Llanos 34 Block is Verano Energy (a subsidiary of Parex), which has a 55% interest. See “—Our operations.” We operate in the block pursuant to an E&P contract with the ANH. See “—Significant Agreements—Colombia —E&P contracts—Llanos 34 Block E&P contract.” Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block. The Llanos 32 Block covers approximately 8,556 gross acres (35 sq. km.). Verano Energy is the operator of this block and has an 87.5% working interest. Since 2015, the operator focused on the commissioning of a gas facility on this block to produce natural gas and light crude oil from the Une formation and to facilitate shipment of processed gas south to the adjacent Llanos 34 Block. For the year ended December 31, 2023, our average net production in the Llanos 32 Block was 360 bopd. As of the date of this annual report, we do not aim to continue exploring on certain exploration acreage available in the Llanos 32 Block, and therefore, we will retain interest on the existing producing fields only. Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico Block, which covers an area of approximately 25,658 gross acres (103 sq. km.). We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Frontera, who subsequently assigned its participation interest to Cepsa Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. Llanos 86 and Llanos 104 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest executed an E&P contract over these blocks on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are the operator of these contracts that are in their exploratory phase 1 and cover approximately 530,309 gross acres (2,146 sq. km.). Due to the presence of indigenous communities in the area, we conducted the due prior consultation process with these communities and reached agreements, thereby concluding the process on August 29, 2023. We requested, and the ANH approved, an extension of the first phase of the exploratory 49 Table of Contents period in the Llanos 86 and Llanos 104 Blocks due to delays attributable to the environmental authority in approving environmental management measures. Accordingly, as of the date of this annual report, outstanding investment commitments consist of acquisition of 3D seismic and drilling of one exploratory well in each block for an estimated amount of US$9.8 million for Llanos 86 Block and US$8.8 million for Llanos 104 Block, before June 19, 2026. Llanos 87 Block. We and Hocol, each with fifty percent (50%) working interest executed an E&P contract over this block on July 11, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019, and we are the operator of this contract. As of the date of this annual report, the total investments needed to fulfill the exploratory activities committed in the block have already been incurred and the ANH final acquittal-approval is pending. As a result of the activity performed during the exploratory period, we made two discoveries in the block: Tororoi and Zorzal. Therefore, we submitted to the ANH an appraisal program for each of Tororoi and Zorzal, which includes the drilling of one exploratory well during the two-year term ending July 27, 2025. As of the date of this annual report, the ANH approval for the appraisal program is pending. Llanos 123 and Llanos 124 Blocks: We and Hocol, each with fifty percent (50%) working interest executed E&P contracts over these blocks on December 20, 2019, as a result of the Permanent Competitive Process launched by ANH in 2019. We are the operator of these contracts that cover approximately 115,956 gross acres (469 sq. km.). Phase 1 commitments related to these blocks corresponded to (i) reprocessing 3D seismic and drilling of two exploratory wells for Llanos 123 Block for an estimated amount of US$7.1 million before January 14, 2024, and; (ii) the acquisition and reprocessing of 3D seismic and drilling of three exploratory wells for Llanos 124 Block for an estimated amount of US$10.4 million before January 14, 2024. As of the date of this annual report, the total investments needed to fulfill the commitments in the blocks have already been incurred or transferred to another block, and the ANH approval is pending. Llanos 94 Block. On July 24, 2019, the E&P contract was awarded to Parex Energy as a result of the Permanent Competitive Process launched by ANH in 2019. We acquired a 50% working interest from Parex and obtained ANH’s approval to such transfer in May 2020. As a result of an extension in the exploratory period approved by the ANH in 2023, the current Phase 1 commitments consist of drilling one exploratory well before October 1, 2025. However, we are not interested in drilling such prospect and agreed to transfer our 50% working interest back to our partner and thus we are not liable for the exploratory commitment in the block. CPO-5 Block. On December 26, 2008, the E&P contract was executed between ONGC Videsh, as operator and the ANH as a result of the Competitive Process “Ronda Colombia 2008”. This contract covers approximately 490,825 gross acres (1,986 sq. km.). We hold a 30% working interest since the acquisition of Amerisur in 2020. As of the date of this annual report, this contract is in exploratory phase 2 in which the pending commitment corresponds to the acquisition, processing and interpretation of 73 sq. km. of 3D seismic for an amount of US$2.9 million, and drilling of one exploratory well for an amount of US$6.4 million, to be fulfilled before May 18, 2027. As of the date of this annual report, the committed exploratory well has already been drilled. There are two commercial fields called Mariposa and Indico, and we also had successful drilling and putting into production exploration wells in the fields called Flamenco, Halcon and Perico. Average net production in 2023 was 5,563 bopd and net reserves were 6.3 mmboe. CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this annual report, this contract is in exploratory phase 1 and covers approximately 148,263 gross acres (600 sq. km.). The outstanding investment commitment related to the block corresponds to the drilling of an exploratory well for an estimated amount of US$2.9 million before September 19, 2025. Magdalena Basin: VIM-3 Block. As of the date of this annual report, the ANH has approved the termination and final liquidation of the contract is in process. 50 Table of Contents Putumayo Basin: Coati Block. We are the operator of and have a 100% working interest in the Coati Block, which covers approximately 61,843 gross acres (250 sq. km.). The outstanding exploration commitment consisted of the acquisition of 57 sq. km. of 3D seismic and 30 km. of 2D seismic, for an estimated amount of US$4.5 million. The evaluation area is currently suspended. On November 3, 2022, we submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and transfer the pending commitments to other E&P contracts. As of the date of this annual report, we completed the transfer of the pending commitments in the block and the ANH approval is pending. Mecaya Block. We are the operator of and have a 50% working interest in the Mecaya Block, which covers approximately 74,128 gross acres (300 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, which remaining exploration commitment consists of the acquisition of 52.2 sq. km. of 3D seismic for an amount of US$0.6 million. On December 2010, the former operator declared an evaluation area and presented an evaluation program for the Mecaya-1 well (Mecaya Evaluation Program). Both the unified phases 1 and 2 and the evaluation program are currently suspended due to force majeure events (relating to prior consultations). Platanillo Block. We are the operator of and have a 100% working interest in the Platanillo Block, which covers approximately 27,500 gross acres (111 sq. km.). On September 11, 2009, we began the commercial exploitation of the Platanillo Block. Average net production in 2023 was 2,103 bopd and net reserves of 3.2 mmboe. Putumayo 8 Block. We are the operator of and have a 50% working interest in the Putumayo 8 Block, which covers approximately 102,800 gross acres (416 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period. Outstanding investment commitments of US$13.1 million related to this block correspond to the drilling of 3 exploratory wells and the acquisition of 112 sq. km. of 3D seismic before June 14, 2024. Part of the 3D seismic committed in the block was acquired during 2020 and 2021. On October 25, 2022, we submitted to the ANH a request to transfer the investment commitment related to the pending 3D seismic to the Platanillo Block, and the partner reported the transfer of the outstanding committed value to one of its blocks. This transfer of commitments is subject to authorization from the ANH. During 2023, the actions required to obtain environmental licenses were carried out, including holding of a public environmental hearing. As a result, in August 2023, the environmental authority granted the license for the Bienparado project, which was confirmed in January 2024. Additionally, the Nyctibius project public environmental hearing is pending by the environmental licensing authority (Autoridad Nacional de Licencias Ambientales or ANLA). Putumayo 9 Block. We are the operator of and have a 50% working interest in the Putumayo 9 Block, which covers approximately 121,453 gross acres (491 sq. km.). Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period and outstanding investment commitments of US$4.4 million related to this block correspond to drilling of two exploratory wells before October 14, 2020, and the acquisition of 126.25 sq. km. of 3D seismic. Phase 1 was suspended on June 25, 2019, due to the occurrence of a force majeure event consisting of the issuance of the Municipal Agreement No. 007 of Puerto Guzmán, which prohibits the hydrocarbon exploration and production activities in such municipality. Putumayo 14 Block. We are the operator of and have a 100% working interest in the Putumayo 14 Block, which covers approximately 114,560 gross acres (464 sq. km.). Exploration commitments in the block corresponded to the acquisition of 2D seismic and drilling of an exploratory well for an estimated amount of US$16.1 million. On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers, ANH will continue with the contract’s termination. As of the date of this annual report, the total investment needed to fulfill the commitments has already been incurred and the ANH approval is pending. Putumayo 36 Block. We are the operator of and have a 50% working interest in the Putumayo 36 Block, which covers approximately 148,021 gross acres (599 sq. km.). Sierracol is the owner of the remaining 50% working interest. As part of the prior consultation process, the Ministry of Interior certified the presence of one indigenous community in the area. As of the date of this annual report, the contract is in phase 0 as the applicable prior consultation process must be completed. 51 Table of Contents Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the block over the three-year term of phase 1 would be the acquisition of 105.6 sq. km. of 3D seismic and the drilling of two exploratory wells for an estimated amount of US$11.7 million. Prior consultation has not been initiated with the ethnic community due to the restrictions from the issuance of Municipal Agreement No. 007 of Puerto Guzmán, which caused the current phase 0 of the process to be suspended. Tacacho and Terecay Blocks. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks, which covers approximately 589,009 gross acres (2,384 sq. km.) and 586,625 gross acres (2,374 sq. km.), respectively. Sierracol Energy is the owner of the remaining 50% working interest. Both contracts are in phase 1, which is currently suspended due to the occurrence of force majeure events related to social and public order conditions of the area. The outstanding investment commitments corresponded to (i) the acquisition, processing and interpretation of 480 km. of 2D seismic for the Tacacho Block with an estimated amount of US$1.2 million, and; (ii) the acquisition, processing and interpretation of 476 km. of 2D seismic for the Terecay Block with an estimated amount of US$2.9 million. On September 21, 2022, we submitted to the ANH a request for termination of the E&P contract and, in January 2024, we submitted additional third-party reports as supporting documentation to such request. As of the date of this annual report, the termination request is under review by the ANH. As per farm-out agreement executed on November 21, 2018, Sierracol Energy shall carry us in certain exploration activities for the Mecaya, PUT-9, Tacacho and Terecay Contracts. Andaquies, Putumayo 12 and Putumayo 30 Blocks. As of the date of this annual report, the ANH has approved the termination and final liquidation of the contracts is in process. Operations in Ecuador Our Ecuadorian assets currently give us access to 33,300 of gross exploratory and productive acres across 2 blocks in an attractive oil and gas geography. Highlights of the year ended December 31, 2023, related to our operations in Ecuador include: ● Successful drilling and putting into production of the Perico Centro 1 exploration well, and the Yin 2 and Perico Norte 4 appraisal wells in the new combined structural/stratigraphic U-sand play in the Perico Block; ● Average net oil production of 926 boepd in 2023 (848 boepd in 2022), reaching an exit production in the fourth quarter of 2023 of 1,419 boepd; ● Proved oil reserves of 2.3 mmboe (100% in the Perico Block) at year-end 2023 (0.3 mmboe at year-end 2022), after producing 0.3 mmboe; ● Capital expenditures of US$20.9 million in 2023 (US$18.5 million in 2022), representing an 11% of our total capital expenditures. The table below summarizes information about the blocks in Ecuador in which we have working interests as of December 31, 2023. Block Espejo Perico Gross acres (thousand acres) 15.6 17.7 Working interest (1) 50% 50% Operator GeoPark Frontera Production (boepd) Basin 67 Oriente 859 Oriente Expiration concession year Exploration: 2025 Exploitation: 2045 Exploration: 2025 Exploitation: 2045 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. 52 Table of Contents Espejo and Perico blocks In May 2019, we signed participation contracts for the Espejo and Perico Blocks. We are the operator of the Espejo Block with a 50% working interest, and Frontera is the operator of the Perico Block with 50% working interest. We assumed a commitment of carrying out 3D seismic and drilling four exploration wells in the Espejo Block for an estimated amount of US$20.9 million during the first exploratory period ending June 17, 2025 and drilling four exploratory wells in the Perico Block for an estimated amount of US$18.1 million during the first exploratory period ending June 16, 2025. As of the date of this annual report, we have drilled the four exploratory wells in the Perico Block (hence Perico Block does not have any pending exploratory commitments) and we have completed the acquisition of 60 sq km of 3D seismic and drilled two exploratory wells in the Espejo Block. Operations in Brazil Our Brazilian assets currently give us access to 61,400 of gross exploratory and productive acres across 6 blocks (5 exploratory blocks and the BCAM-40 Concession, which is in production phase) in an attractive oil and gas geography. Highlights of the year ended December 31, 2023, related to our operations in Brazil included: ● Average net oil and gas production of 1,027 boepd (98.5% gas) in 2023 (1,516 boepd in 2022); and ● Proved oil and gas reserves in the Manati Block of 1.5 mmboe at year-end 2023 (from 1.6 mmboe at year-end 2022), after producing 0.4 mmboe. The following table sets forth information as of December 31, 2023, on our concessions in Brazil in which we have a current or future working interest: Concession POT-T-785 REC-T 58 REC-T 67 REC-T 77 POT-T 834 Gross acres (thousand acres) 7.9 7.8 7.7 7.7 7.5 Working interest(1) 70% 100% 100% 100% 100% Partners Petroil — — — — Operator GeoPark GeoPark GeoPark GeoPark GeoPark Production (boepd) Basin — Potiguar — Recôncavo — Recôncavo — Recôncavo — Potiguar Manati 22.8 10% Petrobras; Enauta; Gas Bridge Storage S.A. Petrobras 1,027 Camamu- Almada Concession expiration year Exploration: 2025 Exploitation: 2050 Exploration: 2025 Exploitation: 2052 Exploration: 2025 Exploitation: 2052 Exploration: 2025 Exploitation: 2052 Exploration: 2025 Exploitation: 2052 Exploitation: 2029 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. Manati Field We have a 10% working interest in the BCAM-40 Concession, which originally included an interest in the Manati Field, which is located in the Camamu-Almada Basin. Petrobras is the operator of, and has a 35% working interest in, the BCAM-40 Concession, which covers approximately 22,784 gross acres (92.2 sq. km.). In addition to us, Petrobras’ partners in the block are Gas Bridge Storage S.A. and Enauta Energia S.A. (Enauta), with 10% and 45% working interests, respectively. Petrobras operates the BCAM-40 Concession pursuant to a concession agreement with the ANP, executed on August 6, 1998. See “— Significant Agreements—Brazil—Overview of concession agreements—BCAM-40 Concession Agreement.” In September 2009, Petrobras announced the relinquishment of BCAM-40’s exploration area within the concession to the ANP, except for the Manati Field. 53 Table of Contents The Manati Field is located 65 km. south of Salvador, offshore at a water depth of 35 meters. The field was discovered in October 2000, and, in 2002, Petrobras declared the field commercially viable. Production began in January 2007. As of December 31, 2023, 11 wells had been drilled in the Manati Field, 6 of which are productive and connected to a fixed production platform installed at a depth of 35 meters, located 9 km. from the coast of the State of Bahia. From the platform, the gas flows by sea and land through a 125 km. pipeline to the Estação Vandemir Ferreira or EVF gas treatment plant. The gas is sold to Petrobras up to a maximum volume as determined in the existing Petrobras gas sales agreement. POT-T-785 Concession The POT-T-785 block covers an area of 7,875 acres in the Potiguar Basin, surrounded by producing fields operated by Petrobras. Total commitment to the ANP was R$1.2 million (US$0.2 million, at the December 31, 2023, exchange rate of R$5.22 to US$1.00) during the first exploratory period and is equivalent to acquiring 4 sq. km. of 3D seismic and performing geochemical analysis before April 29, 2025. In 2023, preliminary activities for the environmental licensing have started. As of December 31, 2023, the estimated remaining commitment in the POT-T-785 block amounts to US$0.1 million. POT-T-834, REC-T-58, REC-T-67 and REC-T-77 Concessions During ANP’s First Open Acreage Bid Round held in September 2019, we were awarded four exploratory blocks, one in the Potiguar Basin (Block POT-T-834) and three on the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). The Concession Agreements were executed in February 2020. In 2023, we started preliminary activities for the environmental licensing in Block POT-T-834. As of December 31, 2023, the estimated commitment in the blocks to be executed before February 14, 2025, amounted to US$0.6 million. Operations in Chile In December 2023, we entered into an agreement to sell our Chilean subsidiaries which comprised the entirety of our business in the country. The divestment transaction closed in January 2024 and, as part of the transaction, we have retained certain rights over unconventional activities that would be carried out in the Fell Block over the current operating contract in the future. The table below summarizes information about the blocks in Chile in which we had working interests as of and for the year ended December 31, 2023. Block Fell Isla Norte Campanario Flamenco Gross acres (thousand acres) 367.8 97.7 144.2 47.1 Working interest (1) 100% 60% 50% 50% Partners (2) — ENAP Operator GeoPark GeoPark Production (boepd) Basin 1,720 Magallanes — Magallanes ENAP GeoPark — Magallanes ENAP GeoPark — Magallanes Concession expiration year Exploitation: 2032 Exploration: 2024 Exploitation: 2044 Exploration: 2024 Exploitation: 2045 Exploitation: 2044 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. (2) Partners with working interests. Fell Block In 2006, we became the operator and 100% interest owner of the Fell Block. When we first acquired an interest in the Fell Block in 2002, it had no material oil and gas production. Since then, we completed more than 1,100 sq. km. of 3D 54 Table of Contents seismic surveys and drilled 141 exploration and development wells. In the year ended December 31, 2023, we produced an average of 1,720 boepd in the Fell Block, consisting of 87.2% gas. Tierra del Fuego Blocks (Isla Norte, Campanario and Flamenco Blocks) In 2012, we entered into three CEOPs with ENAP and Chile granting us working interests in the Isla Norte, Campanario and Flamenco Blocks, located in the center-north of the Tierra del Fuego Province of Chile. We were the operator of the three blocks, with working interests of 60%, 50% and 50%, respectively. As of the date of closing of the divestment transaction, there were outstanding investment commitments of US$0.9 million and US$5.0 million related to the Isla Norte and Campanario Blocks, respectively, and pursuant to the terms of the divestment transaction, we remain liable for such outstanding investment commitments. Operations in Argentina The table below summarizes information about the blocks in Argentina in which we had working interests as of and for the year ended December 31, 2023. Block Puelen Los Parlamentos Gross acres (thousand acres) 260.2 330.9 Working interest (1) 18% 50% Operator Pluspetrol YPF Production (boepd) Basin — Neuquén — Neuquén Expiration concession year In process of relinquishment Exploration: 2023 (1) Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. Puelen Block On August 20, 2014, the consortium of Pluspetrol and us was awarded the exploration license in the Puelen Block, as part of the 2014 Mendoza Bidding Round in Argentina, carried out by Empresa Mendocina de Energía S.A. (“EMESA”). The consortium consists of Pluspetrol (operator with a 72% working interest), EMESA (non-operator with a 10% working interest) and us (non-operator with an 18% working interest). As of December 31, 2023, we fulfilled the total commitments and are in process of relinquishing the block. Los Parlamentos Block In June 2018, we announced the acquisition of a 50% working interest in the Los Parlamentos exploratory block in partnership with YPF, the largest oil and gas producer in Argentina. In accordance with the partnership agreement, YPF assumed the operatorship of the block and we assumed a commitment which amounted to US$6 million at our working interest. On October 27, 2023, we agreed to transfer our 50% working interest in the Los Parlamentos Block to YPF and thus, once formally approved by local authorities, we will no longer be liable to remaining capital commitments or other legal obligations resulting from our participation in the block. 55 Table of Contents Oil and natural gas reserves and production Our reserves The following table sets forth our oil and natural gas net proved reserves as of December 31, 2023, which is based on the D&M Reserves Report. Net proved reserves As of December 31, 2023 Total net proved reserves (mmboe)(1) Natural gas (bcf) Oil (mmbbl) Net proved developed Colombia Ecuador Brazil Chile Total net proved developed Net proved undeveloped Colombia Ecuador Chile Total net proved undeveloped (2) Total net proved (Colombia, Ecuador, Brazil and Chile) 43.1 1.0 0.0 0.6 44.8 16.2 1.3 0.5 18.0 62.8 1.1 — 8.9 10.0 19.9 — — 0.9 0.9 43.3 1.0 1.5 2.3 48.1 16.2 1.3 0.6 18.1 % Oil 99.6 % 100.0 % 1.9 % 27.2 % 93.1 % 100.0 % 100.0 % 77.1 % 99.2 % 20.8 66.2 94.8 % (1) We calculate one barrel of oil equivalent as six mcf of natural gas. (2) We plan to put 100% of our reported 2023 year-end proved undeveloped reserves into production through activities to be implemented within five years of initial disclosure. We had net proved reserves of 66.2 mmboe at December 31, 2023, compared to net proved reserves of 70.4 mmboe as of December 31, 2022. The 6% decrease in net proved reserves in 2023 is mainly attributable to: ● Production of 12.5 mmboe; and ● Lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl. This was partially offset by: ● Extensions and discoveries that resulted in an increase of 4.5 mmboe in various fields in the Llanos Basin in Colombia and the Jandaya field extension in the Perico Block in Ecuador; ● Changes in a previously adopted development plan in Colombia, resulting in 1.7 mmbbl increase; ● Higher-than-expected performance from the existing wells in Colombia and Brazil, resulting in an increase of 1.5 mmbbl and 0.3 mmboe, respectively; ● Changes in the royalties payment in certain fields in Colombia from kind to cash, resulting in a 0.4 mmboe increase; and ● Higher average prices in Ecuador, resulting in a 0.3 mmboe increase. During the year ended December 31, 2023, we had 4.3 mmboe of our proved undeveloped reserves from December 31, 2022, converted to proved developed reserves due to development drilling in various blocks in the Llanos Basin in Colombia. For further information relating to the reconciliation of our net proved reserves for the years ended 56 Table of Contents December 31, 2023, 2022 and 2021, please see Table 5 included in Note 38 (unaudited) to our Consolidated Financial Statements. Internal controls over reserves estimation process We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimating process and who have knowledge of the specific properties under evaluation. Our Chief Technical Officer, Augusto Zubillaga, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our reserves estimation. He has over 26 years of experience in production, engineering, well completion, corrosion control, reservoir management and field development. See “Item 6. Directors, Senior Management and Employees—A. Directors and executive officers.” In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives: ● estimates are prepared using generally accepted practices and methodologies; ● estimates are prepared objectively and free of bias; ● estimates and changes therein are prepared on a timely basis; ● estimates and changes therein are properly supported and approved; and ● estimates and related disclosures are prepared in accordance with regulatory requirements. Throughout each fiscal year, our technical team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally-generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer and management bias. Recognizing that reserves estimates are based on interpretations and judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified Reserves Engineer sends a preliminary copy of the reserves report to be reviewed by the Corporate Reserves team, the Executive Committee (integrated by the Chief Executive Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy, Sustainability and Legal Officer and Chief People Officer) and the Technical Committee (composed by four technical experts of our board of directors). A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be reviewed and analyzed by the Technical Committee which recommends to the Board of Directors to approve its disclosure and publication. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees of our board of directors.” Independent reserves engineers Reserves estimates as of December 31, 2023, for Colombia, Ecuador, Brazil and Chile included elsewhere in this annual report are based on the D&M Reserves Report, dated March 1, 2024, and effective as of December 31, 2023. The D&M Reserves Report, a copy of which has been filed as an exhibit to this annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines at our request in order to estimate reserves and for the areas and period indicated therein. DeGolyer and MacNaughton Corp. (“DeGolyer and MacNaughton” or “D&M), a Delaware corporation with offices in Dallas, Houston, Moscow, Algiers, Astana and Buenos Aires has been providing consulting services to the oil and gas industry since 1936. The firm has more than 200 professionals, including engineers, geologists, geophysicists, petrophysicists and economists that are engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation and does not 57 Table of Contents accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm. The D&M Reserves Report covered 100% of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of DeGolyer and MacNaughton that brought into question the validity or sufficiency of any such information or data, DeGolyer and MacNaughton did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. DeGolyer and MacNaughton independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4 10(a)(1)-(32) of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation. D&M’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us. The assumptions, data, methods and procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the D&M Reserves Report were appropriate for the purpose served by such report, and DeGolyer and MacNaughton used all methods and procedures as it considered necessary under the circumstances to prepare such reports. However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning the oil and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates. Technology used in reserves estimation According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation. There are various generally accepted methodologies for estimating reserves including volumetrics, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. The particular method chosen should be based on the evaluator’s professional judgment as being the most appropriate, given the geological nature of the 58 Table of Contents property, the extent of its operating history and the quality of available information. It may be appropriate to employ several methods in reaching an estimate for the property. Estimates must be prepared using all available information (open and cased hole logs, core analyses, geologic maps, seismic interpretation, production/injection data and pressure test analysis). Supporting data, such as working interest, royalties and operating costs, must be maintained and updated when such information materially changes. Proved undeveloped reserves As of December 31, 2023, we had 18.1 mmboe in proved undeveloped reserves, a decrease of 0.1 mmboe, or 1%, compared to our December 31, 2022, proved undeveloped reserves of 18.2 mmboe. Changes for the year ended December 31, 2023, include: (i) (ii) a decrease of 4.3 mmboe in Colombia due to the conversion of proved undeveloped reserves to proved developed reserves in various fields in the Llanos Basin; a decrease of 0.8 mmboe due to a lower-than-expected performance in Colombia (0.6 mmboe) and Ecuador (0.2 mmboe); and (iii) a decrease of 0.1 mmboe due to lower average gas prices in Chile. This was partially offset by: (iv) (v) (vi) an increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan; an increase of 1.4 mmboe in Colombia due to the discoveries of various fields in the Llanos Basin; an increase of 1.2 mmboe in Ecuador due to the extension in the Jandaya field in the Hollin reservoir and the discovery of the Ui reservoir in the Perico Block; (vii) an increase of 0.3 mmboe due to higher-than-expected performance in Chile; (viii) an increase of 0.3 mmboe due to change in the royalties’ payment in certain fields in Colombia from kind to cash; and (ix) an increase of 0.2 mmboe due to higher average oil prices in Ecuador. Of our 18.1 mmboe of net proved undeveloped reserves, 16.2 mmboe (89.5%)1.3 mmboe (7.1%) and 0.6 mmboe (3.4%) were located in Colombia, Ecuador and Chile, respectively. No net proved undeveloped reserves were located in Brazil as of December 31, 2023. During 2023, we incurred approximately US$52.2 million in capital expenditures in Colombia to convert such proved undeveloped reserves to proved developed reserves. 59 Table of Contents The following table shows the evolution of total net proved undeveloped (“PUD”) reserves in the year ended December 31, 2023. Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2022 (All amounts shown in mmboe) Plus: Extensions, discoveries and acquisitions: -Colombia -Ecuador Less: PUD Reserves converted to proved developed reserves: -Colombia Plus/less: PUD Reserves revisions and movement to/from other categories: -Colombia -Chile Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2023 Production, revenues and price history 18.2 1.4 1.2 (4.3) 1.4 0.2 18.1 The following table sets forth certain information on our production of oil and natural gas in Colombia, Ecuador, Brazil, Chile and Argentina for each of the years ended December 31, 2023, 2022 and 2021. Average daily production(1) As of December 31, 2022 Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Arg (2) Colombia Brazil Chile Arg (2) 2021 2023 Oil production Average crude oil production (bopd) Average sales price of crude oil (US$/bbl) Natural Gas production Average natural gas production (mcfpd) Average sales price of natural gas (US$/mcf) Oil and gas production cost Average operating cost (US$/boe) Average royalties and economic rights in cash (US$/boe) Average production cost (US$/boe)(3) 32,795 926 16 221 33,640 848 21 441 80 30,920 26 313 1,215 66.8 69.9 82.1 68.0 82.7 89.9 103.1 94.7 56.7 58.3 70.2 62.8 56.4 573 — 6,065 8,993 776 — 8,967 11,387 416 1,374 11,357 12,507 5,529 3.9 — 6.5 3.4 4.5 — 6.4 3.8 2.0 4.4 5.2 3.4 2.7 11.5 37.5 10.9 13.0 6.6 27.1 7.4 16.1 24.0 6.5 4.6 12.3 20.8 7.9 19.4 — 3.1 0.9 37.5 14.0 13.9 21.0 27.6 — 3.1 1.5 5.0 27.1 10.5 17.6 29.0 9.6 16.2 2.6 7.2 0.9 6.1 13.2 26.9 (1) We present production figures net of interests due to others, but before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. (2) “Arg” is Argentina. (3) Calculated pursuant to FASB ASC 932. 60 Table of Contents The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Ecuador, Brazil, Chile and Argentina for each of the years ended December 31, 2023, 2022 and 2021. Tigana oil field(1) Jacana oil field(1) Rest of Colombia Ecuador Brazil Chile Argentina Total 2023 2022 2021 Oil Mbbl 3,904 4,411 3,655 338 6 81 — 12,395 Gas MMcf Oil Mbbl — 4,057 — 4,678 3,543 209 310 — 8 2,214 161 3,283 — 29 12,786 5,705 Gas MMcf Oil Mbbl — 3,670 — 4,023 2,747 283 — — 9 3,273 100 4,156 434 152 10,983 7,864 Gas MMcf — — 502 — 3,796 4,403 1,584 10,285 (1) The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years indicated above. Drilling activities The following table sets forth the exploratory wells we drilled during the years ended December 31, 2023, 2022 and 2021. 2023 Exploratory wells(1) 2022 Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Colombia Brazil 2021 Chile Argentina 7.0 3.3 6.0 2.8 3.0 1.5 — — — — — — 13.0 6.0 3.0 1.5 — — — — — — — — 4.0 2.6 4.0 2.3 8.0 4.9 4.0 2.0 — — 4.0 2.0 — — — — — — — — — — — — 3.0 1.9 3.0 0.8 6.0 2.7 — — — — — — — — — — — — — — — — — — Productive(2) Gross Net Dry(3) Gross Net Total Gross Net (1) Includes appraisal wells. (2) A productive well is an exploratory, development, or extension well that is not a dry well. (3) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. 61 Table of Contents The following table sets forth the development wells we drilled during the years ended December 31, 2023, 2022 and 2021. Productive(1) Gross Net Dry(2) Gross Net Total Gross Net Development wells 2022 Colombia Ecuador Brazil Chile Colombia Ecuador Brazil Chile Colombia Brazil Chile Argentina 2023 2021 25.0 11.8 7.0 3.7 32.0 15.5 — — — — — — — — — — — — — — — — — — 28.0 12.0 2.0 0.9 30.0 12.9 — — — — — — — — — — — — 1.0 1.0 1.0 1.0 2.0 2.0 24.0 10.8 — — 24.0 10.8 — — — — — — — — — — — — — — — — — — (1) A productive well is an exploratory, development, or extension well that is not a dry well. (2) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. Developed and undeveloped acreage The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in Colombia, Ecuador, Brazil, Chile and Argentina as of December 31, 2023. Total developed acreage Gross Net Total undeveloped acreage Gross Net Total developed and undeveloped acreage Gross Net Colombia Ecuador Acreage(1) Brazil (in thousands of acres) Chile Argentina 25.2 13.0 3,350.4 1,672.4 3,375.6 1,685.4 1.1 0.6 32.2 16.1 33.3 16.7 4.1 0.4 57.3 38.1 61.4 38.5 5.6 5.6 651.2 516.5 656.8 522.1 — — 591.1 212.3 591.1 212.3 (1) Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves. Net acreage is based on our working interest. 62 Table of Contents Productive wells The following table sets forth our total gross and net productive wells as of February 29, 2024. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells. Oil wells Gross Net Gas wells Gross Net Productive wells(1) Colombia Ecuador Brazil 206.0 104.1 2.0 0.3 8.0 4.0 - - - - 6.0 0.6 (1) Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are not the operator. A productive well is an exploratory, development, or extension well that is not a dry well. Present activities From January 1, 2024, to February 29, 2024, we produced a net average of approximately 36.1 mboepd, including production from our operations in Chile up to, and including, January 18, 2024 (the date on which the transaction for the divestment of our operations in Chile closed). The main highlights of the 2024 drilling campaign year-to-date are detailed as follows: ● we drilled the Perico 1 well in the CPO-5 Block in Colombia, which tested oil in the northern part of the block, next to the Llanos 34 Block; ● we drilled the Tigana Horizontal Well 7 and two injector wells in the Llanos 34 Block in Colombia, continuing the horizontal drilling campaign as well as expanding our water flooding project; and ● we drilled the Perico Norte 5 well in the Perico Block in Ecuador, which tested oil, representing the fourth successful well drilled in the new U-sand play. Marketing and delivery commitments Colombia Our production in Colombia consists primarily of crude oil which is sold according to price formulas based on market reference indices (Brent price, Vasconia and Oriente differential) and discounts that consider transportation costs and quality adjustments. During 2023, our sales were allocated on a competitive basis to leading industry participants, including traders and other producers. We continued to deliver at both at well-head and at various points in the Colombian pipeline system and via Ecuador for the Putumayo production. Our sales strategy is aimed at securing the highest available pricing for our production while securing a reliable and safe path to market. To that end, we focus on developing synergies and strategic partnerships with both clients and the national transport systems, in order to obtain a reduction in costs and increased revenues by making use of the best alternatives available. Such is the case of the implementation of an unloading facility at Jaguey Station in partnership with Oleoducto de Los Llanos Orientales S.A. (ODL) in 2015. This unloading facility is located 42 km. away from the Llanos 34 Block and allowed for reduced trucking distance and associated costs. Additionally, during 2019 we completed a project to connect the Llanos 34 Block to the ODL pipeline via a flowline. In the third quarter of 2019, we started sending our 63 Table of Contents Jacana production volumes via this flowline to the ODL pipeline, eliminating trucking for that portion of our production and allowing further cost efficiencies and increased operational reliability. In November 2020, the flowline was converted into the Oleoducto del Casanare (“ODCA”) receiving full authorization from the Ministry of Energy and Mines to operate as such, determining the regulated tariff and allowing the transportation of third-party crudes. In 2020, we also inaugurated an unloading facility in Jacana, allowing for volumes of other fields to be transported via the ODCA. At the end of 2020, we connected the Tigana field to ODCA, further reducing transport of our volumes via truck. Since 2021, ODCA has been a central piece of our crude transportation in Colombia, including volumes of Jacana, Tigana and other fields. In 2021, we also entered into an agreement to connect the third party owned Cabrestero Block to ODCA, which allows us to transport third party crude. The connection was completed during the first half of 2022, and we began to transport third-party crude oil through the ODCA. In 2023, we reached an agreement with Ecopetrol to transport the royalties and economic rights paid in kind of the Jacana, Tigana and Tua fields through ODCA, increasing third-party crudes transported through ODCA and therefore, optimizing the use of the available capacity. In addition, we are developing a dilution project at Tigana Station with our partner in the Llanos 34 Block, which will allow to increase the volume transported through ODCA, reducing transportation costs. In the case of the Platanillo Block in the Putumayo Basin, we gather the crude via truck and flowlines to pump it towards Ecuador via the Oloeducto Binacional Amerisur (“OBA”). This pipeline is operated by us and our affiliates and connects us to the Ecuadorian pipeline system via RODA allowing us to sell our production FOB in Esmeraldas port in Ecuador. We hold transport contracts with RODA and SOTE for the transport, storage and loading of our crude in Ecuador. If we were to lose any of our customers, the loss could temporarily delay production and sale of our oil in the corresponding block. However, given the wide availability of customers for Colombian crude, we believe we could identify a substitute customer to purchase the impacted production volumes in a very short period. Ecuador Ecuador has a well-developed crude oil market with broad access to international markets and an extensive pipeline transportation system. Our oil production, which began in 2022, is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of our sales are exported on a competitive basis to industry leading participants including traders, refineries, and other producers. The oil price is linked to Brent and adjusted by a differential that varies month to month and resembles Oriente crude reference price. Brazil Our production in Brazil consists of natural gas, condensate and crude oil. Natural gas production is sold through a long- term, extendable agreement with Petrobras, which provides for the delivery and transportation of the gas produced in the Manati Field to the EVF gas treatment plant in the State of Bahia. The contract is in effect until delivery of the maximum committed volume or June 2030, whichever occurs first. The contract allows for sales above the maximum committed volume if mutually agreed by both seller and buyer. The price for the gas is fixed in reais and is adjusted annually in accordance with the Brazilian inflation index. In July 2015, we signed an amendment to the existing gas sales agreement with Petrobras that covers 100% of the remaining gas reserves in the Manati Field. The low gas prices seen in the Brazilian market during 2023 have represented a risk in the commercialization of gas from Manatí. The contractually agreed price considers inflation but is not affected by market conditions, which reduces the appetite of the client, who has access to more favorable conditions. The condensate produced in the Manati Field is subject to a condensate purchase agreement with Petrobras, pursuant to which Petrobras has committed to purchase all of our condensate production in the Manati Field, but only in the amounts that we produce, without any minimum or maximum deliverable commitment from us. Considering this prerogative, in February 2023, we signed an agreement with DAX Oil Refino S.A., a local private refinery, for the selling of condensate for a one-year term, with the possibility of an extension for the same period. Through this agreement, we increased our portfolio of clients and improved our revenues. Both agreements were valid through December 31, 2023, and can be renewed upon an amendment signed by the purchasers and the seller. 64 Table of Contents Chile Our customer base in Chile was limited in numbers and primarily consists of ENAP and Methanex. For the year ended December 31, 2023, we sold 100% of our oil production in Chile to ENAP and 100% of our gas production to Methanex, with sales to ENAP and Methanex accounting for 2% of our total revenues. We had a long-lasting commercial relationship with ENAP and sold our crude to them for the past years. We had a sales agreement with ENAP whereby ENAP had committed to purchase our oil production in the Fell Block in the amounts that we produced, subject to the limitation of available storage capacity at the Gregorio Terminal. We delivered the oil we produced in the Fell Block to ENAP at the Gregorio Terminal, where ENAP assumed responsibility for the oil transferred. During 2023, we were able to renegotiate and renew the sales agreement with ENAP. The negotiation process was developed from January to May, due to prolonged discussions on the fees related to mercury content. During the negotiation timeframe, the contract for crude oil purchasing was suspended, affecting production of oil and gas in the Fell Block. In March 2017, we executed a gas supply agreement with Methanex effective from May 1, 2017, to December 31, 2026. Under the agreement, Methanex committed to purchase up to 400,000 SCM/d of gas produced by us. During 2022, we executed an amendment to increase the purchase commitment up to the total gas produced by GeoPark in Chile. We gathered the gas we produced in several wells through our own flow lines and injected it into several gas pipelines owned by ENAP. The transportation of the gas we sold to Methanex through these pipelines was pursuant to a private contract between Methanex and ENAP. We did not own any natural gas pipelines for the transportation of natural gas. Corporate GeoPark Limited, our holding company incorporated under the laws of Bermuda, has entered into a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside our Putumayo Basin production. Sales of this crude oil purchased from third parties accounted for 1% of our consolidated revenue in 2023. Significant Agreements Colombia E&P contracts We have entered into E&P contracts granting us the right to explore and operate, as well as working interests in twenty three blocks in Colombia. These E&P contracts are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and (2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable. Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties to the relevant E&P contract. The exploitation period for an area may be extended until such time as such area is no longer commercially viable and certain other conditions are met. Pursuant to our E&P contracts, we are required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a field-by-field basis. See Note 33.1 to our Consolidated Financial Statements. Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P contract governing such area, the ANH is entitled to receive a “windfall profit”, to be paid periodically, calculated pursuant to such E&P contract. 65 Table of Contents In each of the exploration and exploitation periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P contract. Our E&P contracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses, ANH regulation or termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian law, if certain conditions are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government during a certain period. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our contracts in obtaining rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our CEOPs, E&P contracts, production sharing agreements and concession agreements are subject to early termination in certain circumstances.” Eastern Llanos Basin: Llanos 34 Block E&P contract. On March 13, 2009, the E&P contract was awarded to Unión Temporal Llanos 34, currently integrated by GeoPark Colombia S.A.S. with 45%, and Verano Limited with 55% working interest. The Llanos 34 Block E&P contract provides a 24-year exploitation period for each production area, beginning on the date of a commercial declaration. The exploitation period may be extended for periods of up to 10 years at a time if certain conditions are met and subject to ANH approval. As of the date of this annual report there are production areas for the Max, Túa, Tarotaro, Tigana, Jacana, Chachalaca, Tilo, Chiricoca, Jacamar and Guaco fields. Pursuant to the Llanos 34 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P contract. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the Llanos 34 Block E&P contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. See Note 33.1 to our Consolidated Financial Statements. Llanos 32 Block. We have a 12.5% working interest in the Llanos 32 Block. Verano Energy is the operator of this block and has an 87.5% working interest. Economic rights to the ANH are similar to those under the Llanos 34 Block. Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico Block. We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement initially entered into with Kappa Resources Colombia Limited (now Frontera, who subsequently assigned its participation interest to Cepsa Colombia S.A., who then assigned the interest to Explotaciones CMS Oil & Gas), Maral Finance Corporation and Getionar S.A. Llanos 86, Llanos 87, Llanos 104, Llanos 123 and Llanos 124 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest, executed E&P contracts over these blocks in 2019, as a result of the Permanent Competitive Process launched by ANH. We are the operator of these contracts that are in exploratory phase 1. In these E&P contracts, we are required to pay subsurface rights to the ANH, calculated based on the total acreage of the blocks, or the remaining area if in case of relinquishment had taken place. There is also an additional annual 25% markup of said subsurface rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to legal royalties, the ANH is entitled to receive a percentage of total production net of royalties, at the delivery point (multiplied by a factor set in the contract and based on international oil prices). That percentage is 3% in the Llanos 87 E&P contract, 2% in the Llanos 86 and Llanos 104 E&P contracts and 1% in the Llanos 123 and Llanos 124 E&P contracts. There is an additional 5-10% share payable to the ANH applicable upon extensions to the production period and 66 Table of Contents when the accumulated gross aggregate production of the area of the contract exceeds 5 million barrels and the WTI exceeds a defined price. ANH becomes entitled to an additional share on production in accordance with a formula set in the contract. Llanos 94 Block. On July 24, 2019, the E&P contract was awarded to Parex Energy as a result of the Permanent Competitive Process launched by ANH in 2019. We acquired a 50% working interest from Parex and obtained ANH’s approval to such transfer in May 2020. This contract is in an extended exploratory phase 1 and due to the extension of the exploratory period approved in 2023, the current phase 1 commitments consist of drilling one exploratory well before October 1, 2025. We are not interested in drilling such prospect and have agreed to transfer our 50% working interest to our partner. Accordingly, on December 28, 2023, Parex requested ANH approval for such transfer and, once approval is obtained, we will no longer be liable for the capital commitment in the block. In the Llanos 94 E&P contract, we are required to pay subsurface rights to the ANH, calculated based on the total acreage of the blocks, or the remaining area if relinquishment had taken place. There is also an additional annual 25% markup of said subsurface rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to legal royalties, the ANH is entitled to receive 2% of total production net of royalties, at the delivery point (multiplied by a factor set in the contract and based on international oil prices). There is an additional 5-10% share payable to the ANH applicable upon extensions to the production period and when the accumulated gross aggregate production of the area of the contract exceeds 5 million barrels and the WTI exceeds a defined price. ANH becomes entitled to an additional share on production in accordance with a formula set in the contract. CPO-5 Block E&P contract. On December 26, 2008, the E&P contract was executed between ONGC Videsh, as operator and the ANH as a result of the Competitive Process “Ronda Colombia 2008”. We hold a 30% working interest since the acquisition of Amerisur. As of the date of this annual report, the contract is in phase 2 of the exploration period. There are two commercial fields called Mariposa and Indico, and we also had successful drilling and putting into production exploration wells in the fields called Flamenco, Halcon and Perico. Pursuant to the CPO-5 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the CPO-5 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the CPO- 5 Block E&P contract. The ANH also has an additional economic right equivalent to 23% of production, net of royalties. In accordance with the CPO-5 Block E&P contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this annual report, this contract is in exploratory phase 1. Pursuant to CPO-4-1 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the CPO-4-1 Block. Additionally, we are required to pay a surface and subsoil usage fee to the ANH. We are required to comply with the VEE (economic value for exclusivity) equivalent to the commitments for the exploratory period; however, if we do not perform such commitments, the VEE amount calculated as provided in the CPO-4-1 E&P contract, must be paid to the ANH. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the CPO-4-1 Block E&P contract, when the accumulated production of the area of the contract, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. Putumayo Basin: Coati Block E&P contract. We are the operator of and have a 100% working interest in the Coati Block. The Coati Block has an evaluation area, declared in September 2006, by the former operator in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coati-1 well. Pursuant to the Coati Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons 67 Table of Contents produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Coati Block E&P contract. In accordance with the Coati Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. Mecaya Block E&P contract. We are the operator of and have a 50% working interest in the Mecaya Block. Sierracol Energy is the owner of the remaining 50% working interest in the contract. As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, and it is suspended due to Force Majeure Events (Prior Consultations). Pursuant to the Mecaya Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Mecaya Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Mecaya Block E&P contract. In accordance with the Mecaya Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. Platanillo Block E&P contract. We are the operator of and have a 100% working interest in the Platanillo Block. On September 11, 2009, we began commercial exploitation. Pursuant to the Platanillo Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Platanillo Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Platanillo Block E&P contract. In accordance with the Platanillo Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. Putumayo 8 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 8 Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period. Pursuant to the Putumayo 8 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 8 Block E&P contract. The ANH also has an additional economic right equivalent to 2% of production, net of royalties. In accordance with the Putumayo 8 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. Putumayo 9 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 9 Block. Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, which is suspended since June 25, 2019, due to the occurrence of a Force Majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). Pursuant to the Putumayo 9 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 9 Block E&P contract. The ANH also has an additional economic right equivalent to 18% of production, net of royalties. In accordance with the Putumayo 9 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. Putumayo 14 Block E&P contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block. On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer 68 Table of Contents the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers, ANH will proceed with the contract’s termination. As of the date of this annual report, the total investment needed to fulfill the commitments has already been incurred and the ANH approval is pending. Putumayo 36 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 36 Block. Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, which is suspended since April 1, 2020 due to the occurrence of a Force Majeure Event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). Pursuant to the Putumayo 36 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 36 Block E&P contract, and the payment of 25% of the Economic Right for the use of the subsoil for institutional strengthening and Technology Transfer. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the Putumayo 36 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. Tacacho and Terecay Blocks E&P contracts. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks. Sierracol Energy is the owner of the remaining 50% working interest in each E&P contract. The contracts are in phase 1 of the exploration period, which are currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area. Pursuant to the Tacacho and Terecay Blocks E&P contracts and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the blocks. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Tacacho and Terecay Blocks E&P contracts. In accordance with the Tacacho and Terecay Blocks operation contracts, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. On September 21, 2022, we submitted to the ANH requests for termination of the E&P contracts and, in January 2024, we submitted additional third-party reports as supporting documentation to such request. As of the date of this annual report, the requests are under review by the ANH. Overriding Royalty Agreements We are obligated to pay an overriding royalty of 4% and 2.5%, respectively, to the previous owners of the Llanos 34 and CPO-5 Blocks, based on the production and sale of hydrocarbons discovered in the blocks. During 2023, the Group has accrued US$27.5 million in relation to these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they were exploratory blocks with no production during 2023, these agreements had no impact on our results. Ecuador Production sharing contracts We entered into two production sharing contracts with the Ministry of Energy and Mines. While we are the operators in the Espejo Block, Frontera operates the Perico Block. The production sharing contracts in Ecuador are generally divided into two stages: (i) an exploration period of 4 years, which may be extended to 6 years; and (ii) a production period of 20 years. The exploitation or production period commences upon Governmental approval of the exploitation and development plan of a commercial field (although early production during the exploration period is allowed). The extension of the production period requires entering into an amendment to the contract with the Government of Ecuador, which may imply revision of contractual conditions. In the Espejo and Perico production sharing contracts, production is measured and distributed among the contractor and the Government at the delivery point where a production sharing formula is applied based on international oil prices of the Oriente marker in the previous month and the offer made as base point in each tender. No further royalties apply. In 69 Table of Contents addition, we are obliged to make a yearly payment of US$24,000 as compensation for the use of water and natural construction materials, which increases to US$60,000 during the production stage. Furthermore, there is an institutional development fee of US$100,000 payable every year. Brazil Overview of concession agreements The Brazilian oil and gas industry is governed mainly by the Brazilian Petroleum Law, which provides for the granting of concessions to operate petroleum and gas fields in Brazil, subject to oversight by the ANP. A concession agreement is divided into two phases: (1) exploration and (2) development and production. The exploration phase consists of one exploratory period that begins on the date of execution of the concession agreement, which can last from three to eight years (subject to earlier termination upon the total return of the concession area or the declaration of commercial viability with respect to a given area), while the development and production phase, which begins for each field on the date a declaration of commercial viability is submitted to the ANP, can last up to 27 years. Upon each declaration of commercial viability, a concessionaire must submit to the ANP a development plan for the field within 180 days. The concessions may be renewed for an additional period equal to their original term if renewal is requested with at least 12 months’ notice and provided that a default under the concession agreement has not occurred and is then continuing. Even if obligations have been fulfilled under the concession agreement and the renewal request was appropriately filed, renewal of the concession is subject to the discretion of the ANP. The main terms and conditions of a concession agreement are set forth in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the concession area; (2) validity and terms for exploration and production activities; (3) conditions for the return of concession areas; (4) guarantees to be provided by the concessionaire to ensure compliance with the concession agreement, including required investments during each phase; (5) penalties in the event of noncompliance with the terms of the concession agreement; (6) procedures related to the assignment of the agreement; and (7) rules for the return and vacancy of areas, including removal of equipment and facilities and the return of assets. Assignments of participation interests in a concession are subject to the approval of the ANP, and the replacement of a performance guarantee is treated as an assignment. The main rights of the concessionaires (including us in our concession agreements) are: (1) the exclusive right of drilling and production in the concession area; (2) the ownership of the hydrocarbons produced; (3) the right to sell the hydrocarbons produced; and (4) the right to export the hydrocarbons produced. However, a concession agreement set forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire must fulfill the needs of the domestic market. In order to ensure the domestic supply, the Brazilian Petroleum Law granted the ANP the power to control the export of oil, natural gas and oil products. Among the main obligations of the concessionaire are: (1) the assumption of costs and risks related to the exploration and production of hydrocarbons, including responsibility for environmental damages; (2) compliance with the requirements relating to acquisition of assets and services from domestic suppliers; (3) compliance with the requirements relating to execution of the minimum exploration program proposed in the winning bid; (4) activities for the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments for government participation; and (7) responsibility for the costs associated with the deactivation and abandonment of the facilities in accordance with Brazilian law and best practices in the oil industry. A concessionaire is required to pay to the Brazilian government the following: a license fee, rent for the occupation or retention of areas, a special participation fee, royalties, and taxes. Rental fees for the occupation and maintenance of the concession areas are payable annually. For purposes of calculating these fees, the ANP takes into consideration factors such as the location and size of the relevant concession, the sedimentary basin and the geological characteristics of the relevant concession. A special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulations, and is 70 Table of Contents payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation fee, whenever due, varies between 0% and 40% of net revenues depending on (1) the volume of production and (2) whether the concession is onshore or in shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based on the quarterly net revenues of each field, which consist of gross revenues calculated using reference prices established by the ANP (reflecting international prices and the exchange rate for the period) less royalties paid, investment in exploration, operational costs, and depreciation adjustments and applicable taxes. The Brazilian Petroleum Law also requires that the concessionaire of onshore fields pay to the landowners a special participation fee that varies between 0.5% to 1.0% of the net operational income originated by the field production. BCAM-40 Concession Agreement. On August 6, 1998, the ANP and Petrobras executed the concession agreement governing the BCAM-40 Concession, or the BCAM-40 Concession Agreement, following the first round of bidding, referred to as Bid Round Zero, under the regime established by the Brazilian Petroleum Law. The exploitation phase will end in November 2029. On September 11, 2009, Petrobras announced the termination of BCAM-40 Concession’s exploration phase and the return of the exploratory area of the concession to the ANP, except for the Manati Field. Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly royalty payment equal to 7.5% of the production of oil and natural gas in the concession area. In addition, in case the special participation fee of 10% shall be applicable for a field in any quarter of the calendar year, the concessionaire is obliged to make qualified research and development investments equivalent to one percent of the field’s gross revenue. Area retention payments are also applicable under the concession agreement. We acquired Rio das Contas’ 10% participation interest in the BCAM-40 Concession on March 31, 2014. Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements. Under the Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements, the ANP is entitled to a monthly royalty corresponding to up to 10% of the production of oil and natural gas in the concession area, in addition to the special participation fee described above, the payment for the occupation of the concession area of approximately R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and natural gas produced in the concession area. During bidding, a work program offer is made in the form of work units and the ANP asks for a guarantee of a monetary amount proportional to the offered units. However, depending on the work performed by the operator, the actual work program investment might have a different value to the guaranteed value. Overview of consortium agreements A consortium agreement is a standard document describing consortium members’ respective percentages of participation and appointment of the operator. It generally provides for joint execution of oil and natural gas exploration, development and production activities in each of the concession areas. These agreements set forth the allocation of expenses for each of the parties with respect to their respective participation interests in the concession. The agreements are supplemented by joint operating agreements, which are private instruments that typically regulate the aggregation of funds, the sharing of costs, mitigation of operational risks, preemptive rights and the operator’s activities. An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, of the Brazilian Corporate Law) is the joint liability among consortium members as established in the Brazilian Petroleum Law (Article 38, item II). BCAM-40 Consortium Agreement On January 14, 2000, Petrobras, Queiroz Galvão Perfurações (now Enauta) and Petroserv entered into a consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. Enauta, Gas Bridge Storage S.A. 71 Table of Contents and GeoPark Brazil have a 45%, 10% and 10% participation interest, respectively. The BCAM-40 Consortium Agreement has a specified term of 40 years, terminating on January 14, 2040 and, at the time the obligations undertaken in the agreement are fully completed, the parties will have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets out the rights and obligations of the parties in respect of the operations in the concession. Petrobras Natural Gas Purchase Agreement Enauta, GeoPark Brazil, Gas Bridge Storage S.A. and Petrobras are party to a natural gas purchase agreement providing for the sale of natural gas by Enauta, GeoPark Brazil and Gas Bridge Storage S.A. to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the term of agreement. The Petrobras Natural Gas Purchase Agreement is valid until the earlier of Petrobras’ receipt of this total contractual quantity or June 30, 2030. The agreement may not be fully or partially assigned except upon execution of an assignment agreement with the written consent of the other parties, which consent may not be unreasonably withheld provided that certain prerequisites have been met. The agreement provides for the provision of “daily contractual quantities” to Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until 2030. The parties may agree to lower volumes as dictated by Manati Field’s depletion. Pursuant to the agreement, the base price is denominated in reais and is adjusted annually for inflation pursuant to the general index of market prices (IGPM). Additionally, the gas price applicable on a given day is subject to reduction as a result of the gas quantity acquired by Petrobras above the volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase Agreement provides that all of the Manati Field’s daily production be sold to Petrobras. Chile CEOPs As of December 31, 2023, we had four CEOPs in effect with Chile, one for each of the blocks in which we operated, which granted us the right to explore and exploit hydrocarbons in these blocks, determined our working interests in the blocks and appointed the operator of the blocks. These CEOPs were divided into two phases: (1) an exploration phase, which was divided into two or more exploration periods, and which began on the effectiveness date of the relevant CEOP, and (2) an exploitation phase, which was determined on a per-field basis, commencing on the date we declared a field to be commercially viable and ending with the term of the relevant CEOP. In order to transition from the exploration phase to an exploitation phase, we had to declare a discovery of hydrocarbons to the Ministry of Energy. This was a unilateral declaration, which granted us the right to test a field for a limited period of time for commercial viability. If the field proved commercially viable, we would have to make a further unilateral declaration to the Ministry of Energy. In the exploration phase, we were obligated to fulfill a minimum work commitment, which generally included the drilling of wells, the performance of 2D or 3D seismic surveys, minimum capital commitments and guaranties or letters of credit, as set forth in the relevant CEOP. We also had relinquishment obligations at the end of each period in the exploration phase in respect of those areas in which we had not made a declaration of discovery. We were also able to voluntarily relinquish areas in which we had not declared discoveries of hydrocarbons at any time, at no cost to us. In the exploitation phase, we generally did not face formal work commitments, other than the development plans we filed with the Chilean Ministry of Energy for each field declared to be commercially viable. Our CEOPs provided us with the right to receive a monthly remuneration from Chile, payable in petroleum and gas, based either on the amount of petroleum and gas production per field or according to Recovery Factor, which considered the ratio of hydrocarbon sales to total cost of production (capital expenditures plus operating expenses). Pursuant to Chilean law, the rights contained in a CEOP could not be modified without consent of the parties. Fell Block CEOP. On November 5, 2002, we acquired a percentage of rights and interests of the CEOP for the Fell Block with Chile, or the Fell Block CEOP, and on May 10, 2006, we became the sole owners, with 100% of the rights and interest in the Fell Block CEOP. The Fell Block CEOP provided us with a right to receive a monthly retribution from Chile payable in petroleum and gas, based on the following per-field formula: 95% of the oil production sold in the field, for production sold of up to 5,000 bopd, ring fenced by field, and 97% of gas production sold in the field, for production sold 72 Table of Contents of up to 882.9 mmcfpd. If we exceeded these levels of production sold, our monthly retribution from Chile would decrease based on a sliding scale set forth under the Fell Block CEOP to a maximum of 50% of the oil and 60% of the gas that we sold per field. TDF Blocks CEOPs. In 2012, we signed 3 CEOPs, together with ENAP, for the Isla Norte, Campanario and Flamenco Blocks, all of them located in Tierra del Fuego (“TDF”), Magallanes region. Our working interest was 60% in Isla Norte and 50% in Campanario and Flamenco Blocks. The CEOPs had a term of 32 years, with an initial exploration phase which last for up to 10 years, including a first exploration period of 3 years. The hydrocarbon discoveries opened up an exploitation phase that lasts up to 25 years. We discovered hydrocarbon fields in the 3 blocks, starting in 2013 in the Flamenco Block, and in 2014 in both Campanario and Isla Norte Blocks. The CEOPs provided us with a right to receive a remuneration payable by means of a fraction of the production sold, which in the TDF Blocks was based on a formula depending on the recovery of the total accumulated expenses incurred (capital expenditure plus operational expenditure plus administrative and general expenses). While the recovery factor was less than 1.0, the remuneration was 95% of the hydrocarbons sold, either oil or gas. If the recovery factor surpassed 1.0, a formula would apply reducing gradually the remuneration fraction to a minimum of 75% when the recovery factor was 2.5 times the total accumulated expenses. Argentina Overview of exploration permits Our exploration permits granted us and our partners the exclusive right to explore for hydrocarbons and declare a commercial discovery within the acreage of our permits. Our exploration permits were made up of three subperiods, each lasting 3, 2 and 1 year(s), respectively, plus an extension period of up to 5 years. We were bound to pursue specific minimum work or investment commitments during each of the subperiods of each exploration permit. Such exploration works were valued in work units assigned to each particular type of work under the applicable bidding conditions. Work and investment programs for the permits were required to be assured by issuing a performance bond for the value of the committed work plan. Under the terms of our exploration permits and concession agreements, we were entitled to our proportionate share of the hydrocarbons production lifted from each block. We paid annual surface rental fees established under Hydrocarbons Law 17,319 (“Hydrocarbons Law”) and Resolution 588/98 of the Argentine Secretariat of Energy and Decree 1454/2007, and certain landowner fees. Our Argentine exploration permits had no change of control provisions, though any assignment of these concessions was subject to the prior authorization by the executive branch of the Province of Mendoza and rights of first refusal in favor of our partners and EMESA. Each of these permits or future concessions could be terminated for default in payment obligations and/or breach of material statutory or regulatory obligations. We were subject to the obligation to relinquish at least 50% of the acreage of each exploration permit at the end of each exploration subperiod. We might also voluntarily relinquish acreage to the provincial authorities. Our Argentine exploration permits were governed by the laws of Argentina and the resolution of any disputes must be sought in the Mendoza Provincial Courts. If and when we made a commercial discovery in one or more of our exploration permits, we would have the right to request and obtain an exploitation concession to produce hydrocarbons in the block for 25 years, with an optional extension of up to 10 years. We would also receive the right to be granted a 35-year oil transport concession to build and make use of pipelines or other transport facilities beyond the boundaries of the concession. Additionally, oil and gas producers in Argentina must grant a privilege to the domestic market over the export market, including hydrocarbon export restrictions, domestic price controls, export duties and domestic market supplier obligations. 73 Table of Contents Title to properties In each of the countries in which we operate, the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. In Colombia, Ecuador, Brazil, Chile and Argentina, local governments grant such rights through E&P contracts or contracts of association, production sharing contracts, concession agreements, CEOPs and exploitation concessions, respectively. See “Item 3. Key Information—D. Risk factors—Risks relating to the countries in which we operate— Oil and natural gas companies in Colombia, Ecuador and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries.” Other than as specified in this annual report, we believe that we have satisfactory rights to exploit or benefit economically from the oil and gas reserves in the blocks in which we have an interest in accordance with standards generally accepted in the international oil and gas industry. Our E&P contracts, contracts of association, production sharing contracts, concession agreements, CEOPs and exploitation concessions are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.” Our customers In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. During 2023, the oil and gas production was sold to three clients that concentrated 96% of the Colombian subsidiaries’ revenue. In Ecuador, 100% of our sales were exported on a competitive basis to industry leading participants including traders and other producers. In Brazil, all our gas produced in Manati was sold to Petrobras. In Chile, our customers were ENAP and Methanex. As of December 31, 2023, ENAP purchased all our Chilean oil and condensate production and Methanex purchased all our natural gas production in Chile. We managed the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure. For further information, please see Note 3 to our Consolidated Financial Statements. Seasonality Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not played a significant role in our ability to conduct our operations, including drilling and completion activities. Our competition The oil and gas industry is competitive, and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring and developing licenses in the countries where we operate or plan to operate. Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel.” 74 Table of Contents We may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations. Health, safety and environmental matters General Our corporate HSE commitment governs our actions, in accordance with the legal framework, industry best practices and international standards in terms of socio-environmental, health and safety performance. We work closely with our suppliers and contractors to transfer the best HSE practices throughout our value chain and extend our responsibility towards safety and the environment, with binding contractual agreements, monthly safety and environmental performance evaluations, annual compliance evaluations and the construction of capacities and competencies necessary to be in line with our health, safety, and environmental commitment. We have a health and safety management plan focused on hazard identification and evaluation, including systematic tools implemented in all the operations involving both employees’ and contractors’ activities. We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and actions that ensure respect and protection of the environment in the territories where we operate. In each of the countries where we operate, we ensure compliance with applicable health, safety and environmental requirements. All our operations have the environmental licenses and permits required under the applicable legislation, which are derived from the development of environmental studies with citizen participation for the definition of management measures and impact mitigation. In 2023, our Health and Safety Management System (HSMS) was certified under the ISO standard: 45001:2018, including all Colombian operations. We also implemented our HSMS in our operations in other countries, such as Ecuador and Chile, based on corporate commitment. Our Environmental Management System (EMS), certified under the ISO standard: 14001:2015 for our operations in Colombia, defines programs for the integral management of water resources; solid and liquid waste management; atmospheric emissions and energy; biodiversity and ecosystem services and training and awareness regarding the protection of the environment for employees and suppliers. In addition, it defines the roles and responsibilities of management regarding to the performance of our environmental issues. Although we do not have a certified EMS in countries such as Ecuador and Chile, we have implemented the main programs contemplated by our corporate environmental commitment. Our corporate environmental commitment is mainly based on the management of the following issues: Integral water management We recognize water as a strategic resource and axis of sustainable development in the territories. For this reason, we implement initiatives and strategies for saving and efficiently using the resource, and we focus our efforts on seeking efficiencies in the operation, on reusing water and on reducing environmental impacts and conflicts associated with water management. We have an integral water management program that allows us to monitor the information needed to control its use and consumption, ensure compliance with our environmental permits and take the necessary measures to control the different activities where we use water. 75 Table of Contents All the waste waters generated in our operations is treated and disposed of in accordance with the environmental licenses. In 2023, we did not use natural surface water sources in our permanent operations in the Llanos 34, Platanillo and Fell Blocks and we did not carry out any type of wastewater discharge into surface waterbodies, to avoid any potential conflict with the other users of this resource due to its quality or quantity. We are committed to eliminate any natural surface waterbody withdrawal in all our permanent operations (fields under development) by 2025, as well as continuing to maintain zero (0) direct discharges into surface water sources. We are making advancements to define the corporate water footprint under a recognized standard. Biodiversity Through our management, we articulate our efforts to avoid, mitigate and eliminate any impact that may represent a material risk to the biodiversity of the environment where we operate, applying the mitigation hierarchy to protect nature and use it sustainably. We recognize the importance of biodiversity in the areas of our interest since the planning stage of our projects. We are committed to avoiding operations in legally protected areas and taking into account biodiversity value and ecosystem services as a driver to design, planning and execute our projects. Ecosystem services are the services that nature provides to the people, such as fresh water, food, medicines, regulation of floods and soil erosion and carbon dioxide capture. In addition, we compensate for our residual impact on biodiversity and, we participate and promote programs related to the rehabilitation, restoration, and conservation of high value ecosystems through strategic alliances for the conservation of biodiversity, strengthening social and cultural connections with nature, and promoting knowledge of the natural wealth of the countries we operate in. Some of the projects related to biodiversity that contribute to the reduction of biodiversity loss, the promotion of conservation of the environment and the stability of ecosystems during 2023, included: ● The donation of 1,600 hectares of land to the Manacacias National Park to be declared by the Colombian government as part of the biodiversity offset measurements of our activities in Llanos 34 block. ● We continue being part of the Putumayo Regional Agreement for Biodiversity and Development, which integrates efforts by the private sector and national and regional entities to preserve the biodiversity and connectivity of this region of the Amazon. As part of this agreement, in 2023, we made an alliance with the Sinch Amazon Institute of Scientific Research, Wildlife Conservation Society - WCS and other Colombian O&G Company, to implement the project call “Ríos diversos” in order to characterize the water’s biological quality in the Putumayo watershed and study its relationship with the local communities. ● In Ecuador, in the canton of Shushufindi, province of Sucumbios, we developed, in coordination with the local and provincial government, a project for the recovery of plant cover in areas of watercourses and estuaries with an ecosystem, landscape and watershed protection approach, in order to improve the natural balance and the biodiversity of the territory. ● We actively participated in initiatives led by national and local governments in the countries where we operate focused on reducing deforestation and promote the restauration of disturbed areas. In 2023, we contributed by planting or donating more than 40,000 trees, as part of our environmental obligations and voluntary initiatives. Climate change Our response to climate change and our contribution to achieve the sustainable development goal number 13 of the United Nations is part of our plan to minimize Greenhouse Gas (GHG) emissions announced by us in November 2021, following approval of our board of directors: 76 Table of Contents ● 35-40% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2025; ● 40-60% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2030; and ● net zero Scope 1 and 2 emissions by or before 2050. All our abovementioned goals are defined against a 2020 baseline. These goals take into account the execution of some operational and environmental projects. The following projects are the most relevant achieved during 2023 in Colombia: ● Both the interconnection of the core Llanos 34 Block to Colombia’s national grid and the dedicated 10MW solar photovoltaic plant, although completed during 2022, showed their full impact during 2023; and ● the construction of permanent flare systems in our main fields in Colombia in compliance with current regulations. Medium-term actions include energy efficiency, small-scale renewable projects, management of methane emissions, and potential participation in carbon markets, among others. Longer-term actions may include carbon capture, use and storage projects, reforestation and afforestation initiatives. As of the date of this annual report, we have other ongoing environmental initiatives related to climate adaptation, such as, in Colombia, we continue the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía, in the hydrographic zone of the Meta River, which will contribute to improve water management, comprehensive risk management and climate change adaptation. Integral waste management and circular economy Regarding the proper management of solid waste generated by our activities, we focus our management on the principles of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with applicable regulations. In 2023, we continue strengthening our circular economy strategic plan and the roadmap for its implementation. As part of this plan, we are carrying out more than 8 circular initiatives as part of the three (3) circularity models that we have prioritized: 1. Water management. 2. Waste management. 3. Use of GHG. Spill Management In 2023, we had zero recordable hydrocarbon spills (>=1Bbl uncontained) in our operations. Our HSE Plan Our health, safety and environmental management plan is focused on undertaking realistic and practical programs based on recognized world practices. Our emphasis is on building key principles and company-wide ownership and then expanding programs as we continue growing. Our SPEED philosophy and our HSE Plan have been developed with reference to ISO 14001 for environmental management issues, ISO 45000 for occupational health and safety management issues, SA 8000 for social accountability and workers’ rights issues and general guidelines from international entities such as IOGP, IPIECA, IADC and ARPEL. Our HSE Policy Our policy seeks to meet or exceed safety and environmental regulations in the countries in which we operate. We believe that oil and gas can be produced in an environmentally responsible manner with proper care, understanding and 77 Table of Contents management, while safeguarding the well-being of all people. Within our SPEED philosophy we have a team that is exclusively focused on securing the environmental authorizations and permits for the projects we undertake and promoting the best health and safety practices. This professional and trained team, specialized in environmental issues, is also responsible for the achievement of the health, safety and environmental standards set by our board of directors and for training and supporting our personnel. Our senior executives, personnel in the field, visitors and contractors have also received training in proper health, safety and environmental management. Our health and safety practices and outcomes We continue to improve and update management tools to strengthen our health and safety policy. We have implemented world-class programs focused on analyzing, assessing, and controlling hazards that may cause injury or illness to our employees, contractors, and visitors. Our main occupational health and safety programs are: the proactive observation program (POP), the authority to stop an activity (ADA), the safety operational standard (SOS), the incident reporting and investigation (IRIS), the road transportation safety (RTS), and the business continuity master plan (PMCN). In 2023, we reached several significant milestones, among which the following stand out: ● Our assets in Putumayo (Colombia) and Ecuador, which maintained a constant operation throughout 2023, had no recordable people incidents. ● Record of hours worked, and kilometers travelled, 20% and 35% higher than 2022, respectively. ● Total recordable injury rate (TRIR) and recordable vehicular incidents rate (MVC) goals achieved. ● ISO 45001 certification. As of December 31, 2023, and for the last twelve months, our HS indicators were the following: ● People injury. Indicators calculated per 1,000,000 hours worked (for both employees and contractors): ● Lost time injury rate (LTIR) of 0.48. ● Total recordable incident rate (TRIR) of 0.67. ● One fatal incident resulting from a vehicular accident involving one of our contractors. ● Vehicle incidents, calculated per 1,000,000 kilometers travelled: ● Recordable vehicular incidents rate (MVC) of 0.12. The fatal incident reported above was the result of a vehicular accident in the Llanos 34 Block. Both the contractor and the Company conducted internal investigations and determined the incident was accidental in nature. Furthermore, with the intent of reinforcing safety in our operations, we carried out a third-party peer review of our risk management system to enhance our action plans in response to potential occurrence of similar events. In 2023, we performed a third-party health and safety management system peer review, including more than 1,300 survey participants, 25 interviews / focus groups and documents review. As a result, we plan to implement a workplan focused on leadership, operative discipline, and contractor management. Certain Bermuda law considerations We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are 78 Table of Contents no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares. Insurance We maintain insurance coverage of types and amounts that we believe to be customary and reasonable for companies of our size and with similar operations in the oil and gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive. Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, cyber security, director’s and officer’s liability and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business.” Industry and regulatory framework Colombia Regulation of the oil and gas industry The ANH is responsible for managing all exploration acreage not subject to previously existing association contracts with Ecopetrol. Two decades ago, the ANH began offering all undeveloped and unlicensed exploration areas in the country under concession-fashion Exploration and Production Contracts (“E&P contracts”) and Technical Evaluation Agreements, (or “TEAs”), which resulted in a significant increase in Colombian exploration activity and competition, according to the ANH. The regime for ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. The Agreement 004 of 2012 regulates E&P contracts entered into from May 4, 2012, and onwards. E&P contracts signed before that date are still regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the ANH implemented transitory measures through Agreements 002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which replaced Agreement 004 of 2012 and transitory measures adopted in 2014 and 2015. Agreement 002 of 2017 established rules for granting hydrocarbon areas and adopted criteria for the exploration and exploitation of hydrocarbons owned by Colombia, including the selection of contractors, and management, execution, termination, liquidation, monitoring, control, and supervision of corresponding contracts. Agreement 002 of 2017 (compiled by Acuerdo 009 of 2021) regulates contracts entered into from May 18, 2017, and onwards. E&P contracts entered into before that date are still regulated by the agreements under which they were executed. Since 2004, the ANH has promoted several bidding processes resulting in various E&P contracts. In 2020, and due to COVID-19 pandemic and the then-current oil low price scenario, the ANH issued Agreement 002 of 2020 with transitory relief measures such as term extensions for the exploratory phases, reduction of the amounts of the guarantees, among other measures. All these measures are subject to the accomplishment of certain conditions, some of which are related to the average oil price for the previous months. In 2021, ANH issued Agreement 010 of 2021 to enable the execution of pending investments in any free area on the map of available areas published by ANH. This agreement has enabled companies with E&P contracts with pending obligations (investments) to execute them in other areas promoting exploration activities in Colombia whilst helping companies comply with contractual commitments. In 2022, ANH issued Agreement 01, 2022 to regulate termination requests of E&P contracts under specific conditions such as being suspended for at least 24 consecutive months. This agreement enables companies to request termination of E&P contracts which appear to be inexecutable due to external factors out of a company’s control. In September 2023, the ANH issued Agreement 06, 2023, with the purpose of promoting exploration by granting extensions of exploratory and evaluation periods and the possibility for contractors to maintain areas for a longer period of time in exchange for additional exploratory commitments in the areas. 79 Table of Contents Regulatory framework Regulation of exploration and production activities Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is the authority responsible for creating national energy policy and regulating all activities related to the exploration and production of hydrocarbons in Colombia. Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, establishes the general procedures and requirements that must be completed by a private investor and disclosure procedures that should be met during the performance of these activities. Exploration and production activities were governed by Decree 1895 of 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by Decree 743 of 1975) governed the contracts and contracting processes carried out by Ecopetrol and the rules applicable to such contracts and provided that Ecopetrol was responsible for administering the hydrocarbons resources in the Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, which restructured the hydrocarbons sector, but all agreements entered into by Ecopetrol prior to 2003 with other oil companies are still regulated by Decree 2310 of 1974. By Decree Law 1760 of 2003, Ecopetrol was spun off and the ANH was created. One of the main purposes of this decree was to treat Ecopetrol as another oil and gas company in the market and to transfer regulatory functions to the ANH as administrator of the nation’s hydrocarbons. This enabled Ecopetrol to differentiate its role and avoid it being a party and judge to contractual matters. Resolution 18-1495 of 2009, modified by Resolution 40048 of 2015, establishes a series of regulations regarding hydrocarbon exploration and exploitation. In the E&P contracts, operators are afforded access to blocks by committing to perform an exploratory work program. These E&P contracts provide companies with 100% of new production, less the participation of the ANH, which participation may differ for each E&P contract and depends on the percentage that each company has offered to the ANH to be granted with a block, applicable royalties and revenue taxes. In addition, the Colombian government also introduced TEAs, in which companies that enter into TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas by executing seismic and /or drilling stratigraphic wells and to propose work commitments on those areas, and have a preemptive right to enter into an E&P contract (Right to convert the TEA contract into an E&P contract), thereby providing companies with low-cost access to larger areas for preliminary evaluation prior to committing to broader exploration programs. Under a TEA, the contractor commits to exclusively perform the committed exploration activities. Pursuant to Colombian law, oil companies are obliged to pay royalties (a percentage of their production) to the ANH in kind or in money as per ANH’s instruction and pursuant to the E&P contracts. Companies must also pay the ANH an economic right called participating interest in the production, commonly known as “X factor” among other economic rights established in the E&P contracts (i.e. high price provision, technology transfer, use of the subsurface). Producing fields pay royalties in accordance with the applicable law at the time of the discovery. Under the E&P contracts, ANH contractors also undertake obligations in favor of the communities located in the area of influence of the oil & gas projects, called “Proyectos en Beneficio de las Comunidades” or (PBC). In 2022, ANH launched Ronda Colombia 2021 with an addition to the terms of reference to include the Exclusivity Economic Value (EEV). The EEV includes both the minimum amount required by the ANH and the additional amount eventually included in the proposal, and which should be offered by the initial offers and counteroffers to surpass the initial proposal and equalize or exceed the most favorable counteroffer presented in each round. EEV is represented in the number of exploratory wells offered by a company to be drilled during the E&P contract’s exploratory phase of six years. The companies should offer at least 1 EEV (minimum accepted by ANH) and grant a stand-by letter of credit for 100% of the estimated value of the well as per ANH’s reference values. In the event the company does not comply with the offered EEV, the letter of credit will be enforced by ANH. ANH granted 30 areas in Ronda Colombia 2021 in which we did not participate. However, Parex transferred to us a 50% non-operated working interest in the CPO4-1 Exploration and Production Contract, which was granted to it under Ronda Colombia 2021. 80 Table of Contents Taxation The Tax Statute and Law 9 of 1991 provide the primary features of the oil and gas industry’s tax and foreign exchange system in Colombia. Generally, national taxes under the general tax statute apply to all taxpayers, regardless of industry. The latest tax reform was enacted in December 2022, including modifications to the corporate income tax rate and the tax treatment of royalties, in-kind and in cash. However, in November 2023, the Constitutional Court ruled that the modification that prohibited the deduction of royalties is unconstitutional, and such deductions are allowed as was the case until 2022. See Note 16 to our Consolidated Financial Statements. The main taxes currently in effect are the income tax (35%, plus a surtax for companies developing crude oil extractive activities from 2023 onwards, ranging between 0% and 15%, depending on the Brent oil price level), capital gains tax (15%), sales or value added tax (19%), and the tax on financial transactions (0.4%). Additional regional taxes also apply with some special rules for the companies belonging to the oil and gas industry. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax. Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment in Colombia. Resolution 1/2018 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing exchange operations. Articles 94 to 97 of Resolution 1 provide for a special exchange regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies. Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Central Bank and Ministry of Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 1 and may not be able to access the special exchange regime for a period of 10 years. Ecuador Regulatory framework Petroleum Ownership and Regulation Oil, gas, minerals and natural resources underground belong to the Republic of Ecuador, in accordance with the Ecuadorian Constitution. This is a primary concept in both the Constitu tion and the law. However, the State can allow private invest ment to explore and produce hydrocarbons under different types of contracts as provided under the law. The Ministry of Energy and Non-Renewable Natural Resources (“Ministry of Energy”) regulates and oversees all hydrocarbon-re lated activities in the country, including exploration, produc tion, transportation, refining and marketing. The Ministry of Energy has absorbed the functions and duties of the Secretariat of Hydrocarbons and, through the Vice-Ministry of Hydrocarbons, oversees awarding, executing and monitoring contracts with private companies for the explo ration and production of hydrocarbons. On the other hand, the Agency for Regulation and Control of Energy and Non-Renewable Natural Resources (“ARCERNNR” for its Spanish acronym) has the legal duty to oversee, audit, collect levies and duties on operations, and conduct accounting control of all upstream and downstream hydrocarbon operations. The Ministry of the Environment, Water and Ecological Transition of Ecuador (“MAATE” for its Spanish acronym) has the legal competence for granting environmental licenses for all oil and gas ac tivities and to ensure such operations are conducted in compliance with environmental laws and regulations. The MAATE is independent from the Ministry of Energy. 81 Table of Contents Petroleum Laws and Regulations The Ecuadorian Constitution contains the main provisions, which stipulate that all hydrocarbons belong to the State of Ecuador, that the national oil company is EP PETROECUADOR has preferential rights for oil ex ploration, production, transportation and sale, and that, in case a contract is executed with a private oil company, the State’s benefit must be more than that of the private company. The State’s benefit is understood as all taxes, production shar ing and other economic benefits the State receives from oil production, while the company’s benefit is understood as all proceeds received from payment for the service of producing oil, or from the sales of its share of oil, less all amortization of investments, costs and taxes paid by the company. The Hydrocarbons Law is the main body of law below the Ecuadorian Constitution and regulates the different types of contracts the government can enter into with international oil com panies, as well as the rights, obligations and penalties for private companies. The main contracts that have been imple mented in Ecuador from time to time are service contracts and fairly recently the production-sharing contracts (“PSC”). Under a service contract, the State of Ecuador pays a contractually agreed tariff per barrel. Under a PSC, the investing company receives a share of the oil produced which it can freely trade. There are several regulations ranking below the Hydrocar bons Law that set further rules for all activities, including the regulation of hydrocarbon operations and special local rules on the accounting principles for each type of contract. In addition to all the other generally applicable laws of the country, the Environmental Law, Labor Law (including local content in hiring of personnel) and Tax Law should be carefully considered. Background for Contract types for Private Investment in Petroleum During almost 50 years, Ecuador has been producing oil, through two types of contracts: production-sharing contracts and service con tracts. Traditionally, the government has imposed service contracts when the price of oil was high and production- sharing contracts when the price of oil was low. In 2010, a legal reform required all oil companies that were operating under the umbrella of production-sharing contracts to transform their con tracts into service contracts. Service contracts can be executed by the Ministry of Hydrocarbons for exploration blocks or for fields already in production (followed a 2021 reform to the Law of Hydrocarbons). In both cases, the con tracting company receives a pre- agreed tariff that is usually negotiated considering the amount of the investment, exist ing reserves, production cost and an estimated reasonable profit for the company. In July 2018, Executive Decree No. 449 reinstated the production-sharing type of contracts locally referred to as Participation Contracts. In 2019, the Ministry of Energy executed several Participation Contracts for exploration and exploitation of hydrocarbons. The contract term for a production-sharing contract is usually four years for exploration, ex tendable for two additional years, and 20 years for produc tion, subject to an extension if reserves have been added and new investments are committed. As of the date of this annual report, we hold two production-sharing contracts with a 50% working interest in consortium with Frontera Energy (Espejo Block, operated, and non-operated Perico Block), which were awarded by the Ministry of Energy during the First Intracampos Bidding Round in April 2019. Taxation The guiding principle is that the government’s share will always be higher than the contracting company’s share. If the contracting company’s share is higher than 51%, it triggers a sovereignty margin adjustment in favor of the government. Under a production-sharing contract, the government’s share is composed of the sales price or the reference price of the share of oil assigned to the government as per the contract, plus all taxes and contributions paid by the company. In this type of contract, the contracting company’s share is the higher of the sales price and the reference price of the 82 Table of Contents company’s oil, less all amortization of investments, operating costs, trans portation costs up to the port of Balao on the Pacific Coast and all taxes and contributions paid pursuant to the law and the contract. Basically, the taxes are: ● employee profit-sharing (15 per cent of net profits before income tax); ● 25 per cent income tax rate; ● 12 per cent value-added tax; ● money outflow tax, applied to remittances abroad, except when it comes to distribution of profits, with the following rates: 4% until January 31, 2023, 3.75% from February 1, 2023, to June 30, 2023, 3.5% from July 1, 2023, to December 30, 2023 and 2% from December 31, 2023 onwards; ● municipal taxes; and ● other fees and contributions charged by petroleum oversight authorities. Production Risk For any type of contract to be entered into in Ecuador, the investing company has to take on all exploration and pro ‐ duction risks and investments, as well as environmental responsibilities in accordance with its corresponding envi ronmental obligations. Furthermore, the investing company must strictly abide by all employment laws, in terms of legal requirements concerning the maximum number of foreign employees. Some contracts have allowed for arbitration as a dispute resolution mechanism; however, certain matters, such as taxes, cannot be submitted to arbitration. This is also true for certain termination provisions in the event of the investing company breaching the law (such as transfer of rights without consent). The reform to the Law of Hydrocarbons enacted in 2021 allows the entry into investment treaties with the Government of Ecuador, allowing to freeze tax incentives in consideration for investment commitments and expanding local employment. Brazil Regulation of the oil and gas industry Article 177 of the Brazilian Federal Constitution of 1988 provides for the Federal Government’s monopoly over the prospecting and exploration of oil, natural gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline transportation of crude oil and natural gas. Initially, paragraph one of article 177 barred the assignment or concession of any kind of involvement in the exploration of oil or natural gas deposits to private industry. On November 9, 1995, however, Constitutional Amendment Number 9 altered paragraph one of article 177 so as to allow private or state-owned companies to engage in the exploration and production of oil and natural gas, subject to the conditions to be set forth by legislation. Regulatory framework Pricing policy Until the enactment of the Brazilian Petroleum Law, the Brazilian government regulated all aspects of the pricing of oil and oil products in Brazil, from the cost of oil imported for use in refineries to the price of refined oil products charged to the consumer. Under the rules adopted following the Brazilian Petroleum Law, the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government: (1) introduced a new methodology for determining the price of oil products designed to track prevailing international prices denominated in U.S. dollars, and (2) gradually eliminated controls on wholesale prices. 83 Table of Contents Concessions In addition to opening the Brazilian oil and natural gas industry to private investment, the Brazilian Petroleum Law created new institutions, including the ANP, to regulate and control activities in the sector. As part of this mandate, the ANP is responsible for licensing concession rights for the exploration, development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding process. The ANP has conducted 17 bidding rounds for exploration concessions from 1999 through 2021, four open acreage bid rounds, 6th Production Sharing Bidding Round and two Transfer of Right Surplus Bidding Round. Taxation The Brazilian Petroleum Law introduced significant modifications and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation is the government take, comprised of license fees, fees payable in connection with the occupation or title of areas, royalties and a special participation fee. The introduction of the Brazilian Petroleum Law presents certain tax benefits primarily with respect to indirect taxes. Such indirect taxes are very complex and can add significantly to project costs. Direct taxes are mainly corporate income tax and social contribution on net profit. With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required to pay the Brazilian federal government the following: license fees, rent for the occupation or retention of areas, special participation fee, and royalties on production. The minimum value of the license fees is established in the bidding rules for the concessions, and the amount is based on the assessment of the potential, as conducted by the ANP. The license fees must be paid upon the execution of the concession contract. Additionally, concessionaires are required to pay a rental fee to landowners varying from 0.5% to 1.0% of the respective hydrocarbon production. The special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation rate, whenever due, may reach up to 40% of net revenues depending on (i) volume of production and (ii) whether the block is onshore, shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate for the period) less: royalties paid; investment in exploration; operational costs; and depreciation adjustments and applicable taxes. The ANP is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other factors, the geological risks involved, and the production levels expected. State VAT (ICMS) ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based on the sale price, including the ICMS itself. For intrastate transactions (carried out by a seller and a buyer located in the same Brazilian state) or imports, the ICMS rate is determined by the legislation of the state where the sale is made and generally varies from 17% to 20%. Interstate transactions (carried out between a seller and buyer located in different Brazilian states), in turn, are subject to reduced rates of 4% (if the products are imported and not submitted to a manufacturing process or, in case of further manufacturing, if the resulting product has a minimum imported content of 40%), 7% or 12%, depending on the states involved. One exception is that, due to the immunity established by the Brazilian Federal Constitution, ICMS is not due on interstate crude oil transactions when destined to industrialization and commercialization. On the other hand, in case of consumables 84 Table of Contents or fixed assets, the buyer must pay to the state where the buyer is located, the ICMS DIFAL, which is calculated based on the difference between the interstate rate and the buyer’s own internal ICMS rate. ICMS is calculated under the noncumulative regime, and therefore some input transactions could result in tax credits (for example the acquisition of inputs and fixed assets directly used in the company’s activity). Social contribution taxes on gross revenue (PIS and COFINS) PIS and COFINS are social contribution taxes charged on gross revenues earned by a Brazilian Federal Revenue noncumulative regime of calculation. Under the noncumulative regime, PIS and COFINS are generally charged at a combined nominal rate of 9.25% (1.65% PIS and 7.6% COFINS) on national revenues earned by a legal entity. In that case, certain business costs result in tax credits to offset PIS and COFINS liabilities (e.g., input and services acquisitions, expenses of depreciation and amortization of machinery, equipment and other fixed assets acquired to be directly used in the company’s activities). PIS and COFINS paid upon the importation of certain inputs, assets and services contracted that are destined to the company’s activity are also creditable. Although upstream industries are generally subject to this regime, it is not clear yet when this benefit is applied according to the stage of the field, (exploration or production). Since July 1, 2015, taxpayers subject to the noncumulative regime must calculate PIS and COFINS over certain financial revenues, applying rates of 0.65% and 4%, respectively. Federal Industrialization VAT (IPI) and Municipality VAT (ISS) IPI is a non-cumulative tax and may be due on goods acquisitions by importation or national transactions. The IPI rate will be applied depending on the NCM classification of the product according to TIPI (Table of IPI). On the acquisition of local goods subject to IPI, such tax is included in the price of the good. Considering that O&G activity (upstream) is not subject to IPI taxation, the amount of the tax cannot be considered as a credit (even though IPI is under the non-cumulative regime applicable for IPI’s taxpayers), which means that this will be a cost for the legal entity acquirer. In relation to the importation, the importer of record will be considered as the taxpayer and will be obliged to pay the IPI due on the transaction. For the same aforementioned reasons for the O&G companies (upstream), this will be considered as cost when the importation is subject to IPI. ISS is a cumulative tax which is due on provided services and imported services. Usually, regarding local transactions, such tax is included in the price of the service charged by the service provider. In relation to the import of service, the Brazilian entity contractor is responsible for the payment of the ISS, which means that, depending on contractual arrangement, the tax burden may be supported by the Brazilian contractor or the foreign service provider. ISS tax rate may vary from 2% to 5% and will depend on the nature of service, as well as where the service provider is located (in general, some exceptions may apply). Additionally, in 2018, GeoPark Brazil was granted a tax benefit issued by SUDENE (Northeastern Development Superintendence), by means of the Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by 75% the Income Tax and Additions, calculated over the company exploration profits, based on Article 1 of the Provisory Measure 2,199-14 of August 24, 2001, in accordance with the requirements established by the Decree 6,539 of August 18, 2008. The benefit will be valid for 10 years, starting from January 1, 2018, under the condition of modernizing the entire project on the SUDENE operating area, observing all provided legal conditions and requirements that includes compliance with labor and social law and with all environmental protection and control regulations, annual submission of a declaration of income and a restriction to the distribution to partners or shareholders of the tax amount which is not paid due to the tax exemption. 85 Table of Contents The noncompliance with the requirements provided constitutes a default of the beneficiary company in respect to SUDENE and shall be subject to the applicable penalties. Chile Regulation of the oil and gas industry Under article 24 of the Chilean Constitution, the state is the exclusive owner of all mineral and fossil substances, including hydrocarbons, regardless of who owns the land on which the reserves are located. The exploration and exploitation of hydrocarbons may be carried out by the state, companies owned by the state or private entities through administrative concessions granted by the President of Chile by Supreme Decree or CEOPs (administrative contract for the provision of oilfield services) executed by the Minister of Energy. Exploitation rights granted to private companies are subject to special taxes and/or royalty payments. The hydrocarbon exploration and exploitation industry are supervised by the Chilean Ministry of Energy. In Chile, a participant is granted rights to explore and exploit certain assets under a CEOP. If a participant breaches certain obligations under a CEOP, the participant may lose the right to exploit certain areas or may be required to return all or a portion of the awarded areas to Chile with no right of compensation. Although the government of Chile cannot unilaterally modify the rights granted in the CEOP once it is signed, exploration and exploitation are nonetheless subject to significant government regulations, such as regulations concerning the environment, tort liability, health and safety, and labor. Regulatory framework Regulation of exploration and production activities Oil and gas exploration and development is governed by the Political Constitution of the Republic of Chile and Decree with Law Force No 2 of 1986 of the Ministry of Mines, which set forth the revised text of the Decree Law 1089 of 1975, on CEOPs. However, the right to explore and develop fields is granted for each area under a CEOP between Chile and the relevant contractors. The CEOP establishes the legal framework for hydrocarbon activities, including, among other things, minimum investment commitments, exploration and exploitation phase durations, compensation for the private company (either in cash or in kind) and the applicable tax regime. Accordingly, all the provisions governing the exploitation and development of our Chilean operations are contained in our CEOPs and the CEOPs constitute all the licenses that we need in order to own, operate, import and export any of the equipment used in our business and to conduct our gas and petroleum operations in Chile. Under Chilean law, the surface landowners have no property rights over the minerals found under the surface of their land. Subsurface rights do not generate any surface rights, except the right to impose legal easements or rights of way. Easements or rights of way can be individually negotiated with individual surface landowners or can be granted without the consent of the landowner through judicial process. Pursuant to the Chilean Code of Mines, a judge can permit a party to use an easement pending final adjudication and settlement of compensation for the affected landowner. Taxation Under the Chilean tax regime, hydrocarbon exploitation benefits from the general income tax legislation are established at the time of the execution of each CEOP for the exploitation of each block. Thus, new tax reforms do not affect the current taxation for our subsidiaries in Chile. Further, transactions between foreign related parties and our local subsidiaries are compliant with several tax reporting provisions set forth by the Chilean legislation for transfer pricing and indirect transfer tax purposes, at the same time that benefits derived from double taxation agreements entered into by Chile and the relevant countries are applied as well. 86 Table of Contents Argentina Regulatory framework The Hydrocarbon Law No. 17,319 enacted in 1967 continues in force until today, subject to amendments introduced by the Laws No. 24,145, 26,197 and 27,007. A bill to amend the Hydrocarbons Law 17,319 was presented by the National Executive Branch to the National Congress in December 2023 and continues under study as of March 2024. The Hydrocarbon Law No. 17,319 provided for the existence of a state-owned oil & gas company (originally, YPF) for whom private companies initially served as service contractors or joint venture partners. But it also provided for a concession & royalty system which became the prevailing contractual granting instrument after the deregulation of petroleum activities introduced by Decrees No. 1055/89, 1212/89 and 1589/89 (the “Petroleum Deregulation Decrees”) and the YPF Privatization Law 24,145 enacted in 1992. On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty Law 26,741 which (i) impaired the Deregulation Decrees; (ii) declared that achieving self-sufficiency in the supply of hydrocarbons, shall be a national public interest and a priority for Argentina; and (iii) expropriated 51% of the share capital of YPF then owned by the Spanish company Repsol. Domain and Jurisdiction of hydrocarbons resources After a constitutional reform enacted in 1994, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested in such provincial state, while eminent domain over hydrocarbon resources lying offshore on the continental platform beyond the jurisdiction of the coastal provincial states is vested in the federal state. Thus, oil and gas exploration permits, and exploitation concessions are now granted by each provincial government. Hydrocarbon Exports and Self-Sufficiency Achieving self-sufficiency has been an energy policy goal from the early days of the industry. Supply privileges favoring the domestic market over the export market, including hydrocarbon export restrictions, domestic price controls, price subsidies, export duties and domestic market supply obligations have been implemented several times throughout Argentina´s history. Hydrocarbon Exploitation Concessions Terms With regards to concessions, three types of exploitation concessions are provided: (i) 25-years conventional concessions; (ii) 35-years unconventional hydrocarbon concessions and (iii) 30-years offshore concessions. With regards to royalties, the standard royalty rate is 12%, but incremental 3% rates are provided to apply when a concession holder elects to renew an ongoing concession at the end of its term, subject to a cap of 18%. The payment of an extension bonus to the government is also provided for a maximum amount equal to 2% of the remaining proven reserves at the end of effective term of the concession valued at the average basin price applicable to the respective hydrocarbons during the immediate past 2 years. Regulation of transportation activities Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial states or the federal government, depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other fixed facilities necessary for the transportation of oil, gas and by-products. Transportation facilities with surplus capacity must transport third parties’ hydrocarbons on an open-access basis, for a fee which is the same for all users on similar terms. As a result of the privatizations of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered and continue to operate to date. Effective February 8, 2019, to promote transportation capacity expansions, Decree 115/2019 allowed interested shippers to reserve transportation capacity in new or expanded pipelines through freely negotiated capacity reservation agreements. 87 Table of Contents Taxation Exploitation concessionaires are subject to the general federal and provincial tax regime. The most relevant federal taxes are the income tax (35%) and the value-added tax (21%). The most relevant provincial taxes are the turnover tax (3% on average) and stamp tax. Corporate income tax rate may range from 25% to 35% on bands of income that can be adjusted annually. Foreign Exchange Restrictions Since September 1, 2019, wide foreign exchange restrictions were re-established in Argentina. Different promotional investment regimes (such as National Decree 929/2013 and National Decree 277/2022) were with a view to lessening such restrictions on new hydrocarbon investments projects. But foreign exchange restrictions continue to limit remittances of dividends, financial and commercial obligations with foreign creditors. Environmental Hydrocarbon operations are subject to concurrent national and provincial environmental statutes and regulations, and to the concurrent jurisdiction of national and provincial environmental and hydrocarbon enforcement authorities. The different hydrocarbon producing provincial states have enacted and enforce comprehensive environmental decommissioning, restoration and remediation frameworks. C. Organizational structure We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements. D. Property, plant and equipment See “—B. Business Overview—Title to properties.” ITEM 4A. UNRESOLVED STAFF COMMENTS Not applicable. ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS A. Operating results The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto. The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking statements.” Factors affecting our results of operations We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following: 88 Table of Contents Discovery and exploitation of reserves Our results of operations depend on our level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce. For the year ended December 31, 2023, we made total capital expenditures of US$199.0 million (US$178.1 million and US$20.9 million in Colombia and Ecuador, respectively), consisting of US$73.2 million related to exploration. Oil prices have been volatile, particularly since the start of the COVID-19 pandemic and the armed conflict in Ukraine. In preparation for continued volatility, we have developed multiple scenarios for our 2024 capital expenditure program. See “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook.” Funding for our capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program which would cause us to further decrease our work program, which could harm our business outlook, investor confidence and our share price. If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase our work and investment program and thereby further increase oil and gas production. Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business, results of operations and financial condition. Oil and gas revenue and international prices Our revenues are derived from the sale of our oil and natural gas production, as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent. The price realized for the natural gas we produced in Chile was linked to the international price of methanol, which is settled in the international markets in US$. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions, and a variety of additional factors. For example, during the four-year period from March 1, 2020, to February 29, 2024, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel. We seek to partially mitigate our exposure to crude oil price volatility using derivatives by hedging a portion of our production for a limited period going forward. We use a combination of options to manage our production’s exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. For further information related to Commodity Risk Management Contracts, please see Note 8 to our Consolidated Financial Statements. Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price is linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin 89 Table of Contents that is transported through Ecuador. In both basins, the reference price is then adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur content, delivery point and transport costs. In Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles the Oriente crude reference price. In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in reais and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the “IGPM”). In Chile, the price of oil we sold to ENAP was based on Dated Brent minus certain marketing and quality discounts such as, API, sulphur content and others. We had a long-term gas supply contract with Methanex. The price of the gas sold under this contract was determined by a formula that considered a basket of international methanol prices, including US and European price indices. If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$42.4 million (US$47.3 million in 2022). Production and operating costs Our production and operating costs consist primarily of expenses associated with the production of oil and gas, the most significant of which are facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties, economic rights, and consumables, among others. Our production costs may vary as a consequence of the increase or decrease of commodity prices and other factors, such as the increase in energy costs occurred in 2023 due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. We have historically not hedged our costs to protect against fluctuations. Availability and reliability of infrastructure Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.” Production levels Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and oil and natural gas prices. We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.” Contractual obligations In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P contracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our 90 Table of Contents commitments under these agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various E&P contracts, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries and file periodic reports in order to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.” Acquisitions As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally incorporate our acquired business into our results of operations at or around the date of closing. On January 16, 2020, we acquired the 100% share capital of Amerisur. Considering that Amerisur issued financial information monthly, we considered the identified assets and liabilities as of December 31, 2019. If the purchase price allocation exercise had been carried out as of January 16, 2020, it would not have deferred significantly. Functional and presentational currency Our Consolidated Financial Statements are presented in US$, which is our presentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is the real. Geographical segment reporting In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non- Ecuadorian, non-Brazilian, non-Chilean and non-Argentine operations, primarily consisting of our corporate head office operations. As of December 31, 2023, we divided our business into five geographical segments—Colombia, Ecuador, Brazil, Chile and Argentina—that corresponded to our principal jurisdictions of operation. Activities not falling into these five geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment. Description of principal line items The following is a brief description of the principal line items of our consolidated statement of income. Revenue Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place. 91 Table of Contents Commodity risk management contracts Includes realized and unrealized gains and losses arising from commodity risk management contracts. The derivatives that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were accounted for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were recognized immediately as gains or losses in the results of the periods in which they occur as part of the Commodity risk management contracts line item in the Consolidated Statement of Income. The derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, and onwards are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the Revenue line item in the Consolidated Statement of Income. Production and operating costs Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, royalties and economic rights in cash are also included within this account. For a description of our production and operating costs, see “— Factors affecting our results of operations.” Depreciation Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. Geological and geophysical expenses Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies. Administrative expenses Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share- based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions. Our administrative expenses for the year ended December 31, 2023, decreased by US$6.1 million, or 12%, compared to the year ended December 31, 2022, mainly due to higher overhead related to joint operations, and a one-time share-based payment made to the Group´s former CEO in 2022, as part of his transition agreement described in “Item 6. Directors, Senior Management and Employees – B. Compensation – CEO Transition Agreement.” 92 Table of Contents Selling expenses Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs and selling taxes. Our selling expenses for the year ended December 31, 2023, increased by US$5.1 million, or 64%, compared to the year ended December 31, 2022, mainly due to deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses. Write-off of unsuccessful exploration efforts Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending on whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. During 2023, we recognized write-off of unsuccessful exploration efforts of US$29.6 million (US$25.8 million in 2022). See Note 20 to our Consolidated Financial Statements. Impairment of non-financial assets Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value minus costs to sell and value in use. During 2023, we recognized a net impairment loss of US$13.3 million in the Fell Block due to the known selling price of the related net assets in the context of the divestment transaction of the Chilean business. See Note 36.1 in our Consolidated Financial Statements. During 2022, no impairment losses were recognized or reversed. Financial results Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. Recent accounting pronouncements See Note 2.1.1 to our Consolidated Financial Statements. Results of operations The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes. In preparation for continued volatility, we have developed multiple scenarios for our 2024 capital expenditure program. See “Item 4. Information on the Company –B. Business Overview—2024 Strategy and Outlook.” 93 Table of Contents Year ended December 31, 2023, compared to year ended December 31, 2022 The following table summarizes certain of our financial and operating data for the years ended December 31, 2023 and 2022. For the year ended December 31, % Change from prior year (in thousands of US$, except for percentages) 2023 2022 Revenue Sale of crude oil Sale of purchased crude oil Sale of gas Commodity risk management contracts designated as cash flow hedges Revenue Commodity risk management contracts Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful exploration efforts Impairment loss recognized for non-financial assets Other (expenses) income Operating profit Financial expenses Financial income Foreign exchange (loss) gain Profit before income tax Income tax expense Profit for the year Net production volumes Oil (mbbl)(2) Gas (mcf)(3) Total net production (mboe) Average net production (boepd) Average realized sales price Oil (US$ per bbl) Gas (US$ per mmcf) Average unit costs per boe (US$) Operating cost Royalties and economic rights in cash Production costs(1) Geological and geophysical expenses Administrative expenses Selling expenses 726,947 5,464 25,024 (810) 756,625 — (232,325) (11,192) (43,969) (13,084) (120,934) (29,563) (13,332) (21,319) 270,907 (45,815) 6,237 (16,820) 214,509 (103,441) 111,068 12,395 5,705 13,345 36,563 67.0 4.6 12.5 7.2 19.6 0.9 3.7 1.1 1,004,775 9,454 35,350 — 1,049,579 (70,221) (359,779) (10,529) (50,024) (7,995) (96,692) (25,789) — 527 429,077 (57,073) 3,180 19,725 394,909 (170,474) 224,435 12,786 7,864 14,096 38,620 82.2 4.8 8.0 18.8 26.8 0.8 3.7 0.6 (28)% (42)% (29)% 100 % (28)% (100)% (35)% 6 % (12)% 64 % 25 % 15 % 100 % (4,145)% (37)% (20)% 96 % (185)% (46)% (39)% (51)% (3)% (27)% (5)% (5)% (18)% (4)% 57 % (62)% (27)% 21 % (0)% 86 % (1) Calculated pursuant to FASB ASC 932. (2) We present production figures before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. Oil production figures presented on page F-70 are net of royalties, economic rights and government’s production share. (3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page F-71 is gas measured at the point of delivery. 94 Table of Contents The following table summarizes certain financial data. Colombia Ecuador Brazil Chile Argentina Other Total Colombia Ecuador Brazil Chile Argentina Other Total (in thousands of US$) 2023 2022 For the year ended December 31, 702,401 (101,666) 19,097 (7,096) 14,019 (2,332) 15,644 (9,815) — 5,464 (3) (22) 756,625 (120,934) 978,423 (78,775) 10,671 (788) 19,873 (2,796) 29,196 (14,076) 1,962 (254) 9,454 (3) 1,049,579 (96,692) (29,563) — — (13,332) — — (42,895) (21,318) (4,471) — — — — (25,789) Revenue Depreciation Impairment and write-off Revenue For the year ended December 31, 2023, crude oil sales were our principal source of revenue, with 96%, 1% and 3% of our total revenue from crude oil, purchased crude oil and gas sales, respectively. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2022, to the year ended December 31, 2023. Consolidated Sale of crude oil Sale of purchased crude oil Sale of gas Commodity risk management contracts designated as cash flow hedges Total By country Colombia Ecuador Brazil Chile Argentina Other Total For the year ended December 31, 2023 2022 (in thousands of US$) 726,947 5,464 25,024 (810) 756,625 1,004,775 9,454 35,350 — 1,049,579 Year ended December 31, 2023 2022 Change from prior year % (in thousands of US$, except for percentages) 702,401 19,097 14,019 15,644 — 5,464 756,625 978,423 10,671 19,873 29,196 1,962 9,454 1,049,579 (276,022) 8,426 (5,854) (13,552) (1,962) (3,990) (292,954) (28)% 79 % (29)% (46)% (100)% (42)% (28)% Revenue decreased 28%, from US$1,049.6 million for the year ended December 31, 2022, to US$756.6 million for the year ended December 31, 2023, as a result of lower realized prices and lower deliveries. Sales of crude oil decreased due to lower realized prices and lower sold volumes of 10.9 mmbbl in the year ended December 31, 2023, compared to 12.2 mmbbl in the year ended December 31, 2022, and resulted in net revenue of US$726.9 million for the year ended December 31, 2023, compared to US$1,004.8 million for the year ended December 31, 2022. In addition, sales of gas decreased from US$35.4 million for the year ended December 31, 2022, to US$25.0 million for the year ended December 31, 2023, due to lower natural gas deliveries and lower realized prices. The decrease in 2023 net revenue of US$293.0 million is mainly explained by: ● a decrease of US$276.0 million in Colombia, due to lower realized prices and lower deliveries; ● an increase of US$8.4 million in Ecuador, mainly due to higher deliveries partially offset by lower realized oil prices; 95 Table of Contents ● a decrease of US$5.9 million in Brazil, mainly due to lower gas deliveries, partially offset by higher realized gas prices; ● a decrease of US$13.6 million in Chile, due to lower realized prices and lower deliveries; ● a decrease of US$2.0 million in Argentina due to the divestment of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks on January 31, 2022; and ● a decrease of US$4.0 million due to lower trading operation performed by the holding company, GeoPark Limited. Revenue attributable to our operations in Colombia for the year ended December 31, 2023, was US$702.4 million, compared to US$978.4 million for the year ended December 31, 2022, representing 92.8% and 93.2% of our total consolidated sales, respectively. The decrease is related to a decrease in the average realized price per barrel of crude oil from US$82.7 per barrel to US$66.9 per barrel, primarily due to lower reference international prices, in addition to a decrease in oil deliveries from 11.8 mmbbl to 10.5 mmbbl. Revenue attributable to our operations in Ecuador for the year ended December 31, 2023, was US$19.1 million, a 79% increase from US$10.7 for the year ended December 31, 2022. This increase was mainly due to higher oil deliveries from 0.12 mmboe for the year ended December 31, 2022, to 0.27 mmboe for the year ended December 31, 2023, principally as a result of the successful drilling campaign in the Perico Block during the year, partially offset by lower realized oil prices from US$89.9 per boe for the year ended December 31, 2022, to US$69.9 per boe for the year ended December 31, 2023. The contribution to our revenue from our operations in Ecuador during the year ended December 31, 2023, and 2022, was 2.5% and 1.0%, respectively. Revenue attributable to our operations in Brazil for the year ended December 31, 2023, was US$14.0 million, a 29% decrease from US$19.9 million for the year ended December 31, 2022, principally due to lower gas deliveries from 0.5 mmboe for the year ended December 31, 2022, to 0.3 mmboe for the year ended December 31, 2023, to respond to the lower gas demand in Brazil, partially offset by higher realized gas prices from US$38.3 per boe for the year ended December 31, 2022, to US$39.0 per boe for the year ended December 31, 2023. The contribution to our revenue from our operations in Brazil during the years ended December 31, 2023, and 2022, was 1.9%, in both years. Revenue attributable to our operations in Chile for the year ended December 31, 2023, was US$15.6 million, compared to US$29.2 million for the year ended December 31, 2022, principally due to (1) a decrease in oil sales by US$9.4 million reflecting lower average realized prices per barrel of crude oil from US$94.7 per barrel for the year ended December 31, 2022, to US$68.0 per barrel for the year ended December 31, 2023, and a decrease in oil deliveries from 0.15 mmbbl to 0.07 mmbbl, and, (2) a decrease in gas sales by US$4.1 million reflecting lower deliveries and lower average realized prices from US$22.7 per boe for the year ended December 31, 2022, to US$20.5 per boe for the year ended December 31, 2023. The contribution to our revenue during the years ended December 31, 2023, and 2022, from our operations in Chile was 2.1% and 2.8%, respectively. For the year ended December 31, 2023, no revenue was generated from our operations in Argentina due to the divestment of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks on January 31, 2022. For the year ended December 31, 2022, revenue was US$2.0 million which contributed in a 0.2% to our revenue. Revenue attributable to our trading operation performed by the holding company, GeoPark Limited, for the year ended December 31, 2023, was US$5.5 million, compared to US$9.5 million for the year ended December 31, 2022. The contribution to our revenue from our trading operation during the year ended December 31, 2023, and 2022, was 0.7% and 0.9%, respectively. 96 Table of Contents Production and operating costs The following table summarizes our production and operating costs for the years ended December 31, 2023 and 2022. For the year ended December 31, % Change 2023 2022 from prior year (in thousands of US$, except for percentages) Consolidated (including Colombia, Ecuador, Brazil, Chile and Other) Royalties in cash Economic rights in cash Staff costs and share-based payments Well and facilities maintenance Operation and maintenance Consumables Equipment rental Transportation costs Field camp Safety and insurance costs Personnel transportation Consultant fees Gas plant costs Non-operated blocks costs Crude oil stock variation Purchased crude oil Other costs Total (12,845) (72,032) (14,639) (26,089) (8,143) (37,556) (4,314) (5,850) (6,546) (5,487) (3,363) (2,291) (1,865) (20,421) (2,004) (4,666) (4,214) (232,325) 2023 Year ended December 31, (80)% (62)% 4 % 26 % 24 % 72 % (43)% 45 % 61 % 47 % 36 % 7 % 11 % 61 % (131)% (41)% (6)% (35)% (63,298) (188,989) (14,069) (20,779) (6,545) (21,789) (7,580) (4,021) (4,070) (3,745) (2,480) (2,133) (1,680) (12,650) 6,449 (7,929) (4,471) (359,779) 2022 Colombia Ecuador Brazil Chile Other Colombia Ecuador Brazil Chile Argentina Other (in thousands of US$) By country Royalties in cash Economic rights in cash Staff costs and share-based payments Well and facilities maintenance Operation and maintenance Consumables Equipment rental Transportation costs Field camp Safety and insurance costs Personnel transportation Consultant fees Gas plant costs Non-operated blocks costs Crude oil stock variation Purchased crude oil Other costs Total (11,201) (72,032) (12,006) (23,280) (8,143) (36,078) (3,461) (5,145) (5,761) (5,075) (3,211) (2,241) (131) (12,168) (1,012) — (3,301) (204,246) — (1,096) — — (548) — — (60,314) — (188,989) — (1,546) — — (1,165) — (273) — — — (2,601) (2) (30) (1,368) (1,439) (2) — — — — (1,357) (121) (15) — (838) (632) — (73) (776) — (9) (184) (183) (45) (107) — (45) — (42) (8) — — (1,734) — (108) (101) — — (376) (4,946) — (10,647) — (13,670) — (6,240) — (19,727) (7,372) — (3,163) — (3,239) — (3,321) — (2,334) — (2,067) — — — (6,618) — 3,652 — — (4,666) — (3,577) — (327,626) (4,666) (537) (8,226) (8,145) (891) — — (10,241) (3,180) (5) (38) (5,029) (1,732) (191) — — — — (1,917) (16) — — (148) (848) — (3) (795) — — (195) (217) — (83) — (9) (51) — (3) (241) — (1,375) (215) — (235) — — — (438) (206) (14,126) (5,299) (5,817) 3,053 — — (3,220) (199) — (157) — (305) — (129) — (60) — (7) — (36) — (12) — (54) — (12) — (64) — — — — (21) — (7,929) — (7,929) (250) (1,579) Consolidated production and operating costs decreased 35%, from US$359.8 million for the year ended December 31, 2022, to US$232.3 million for the year ended December 31, 2023, primarily due to a decrease in royalties and economic rights paid in-cash, partially offset by an increase in consumables due to higher energy costs in Colombia and an increase in non-operated block costs due to higher activities in the CPO-5 and Perico Blocks in Colombia and Ecuador. 97 Table of Contents Production and operating costs in Colombia decreased by 38%, to US$204.2 million for the year ended December 31, 2023, as compared to US$327.6 million for the year ended December 31, 2022, primarily due to lower royalties and economic rights which decreased by US$249.3 million, mainly due to a decrease in the mix of royalties and economic rights paid “in-cash” as compared to royalties and economic rights paid “in-kind”, and lower international prices, partially offset by an increase in consumables due to higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power and an increase in non-operated block costs due to higher activities in the CPO-5 Block. Production and operating costs in Ecuador were US$10.2 million for the year ended December 31, 2023, compared to US$3.2 million the year ended December 31, 2022. The increase was mainly the result of higher deliveries that increased 130% during 2023, compared to 2022, and higher activity in the Perico block. Production and operating costs in Brazil decreased by 7%, to US$4.9 million for the year ended December 31, 2023, as compared to the year ended December 31, 2022, mainly resulting from lower royalties due to a decrease in gas deliveries and maintenance activities in the Manati Block. Operating costs per boe increased to US$10.9 per boe for the year ended December 31, 2023, from US$7.4 per boe for the year ended December 31, 2022, due to lower gas deliveries during 2023. Production and operating costs in Chile decreased by 42% to US$8.2 million due to lower well intervention and maintenance activities in the Fell Block. Operating costs per boe decreased to US$13.0 per boe in 2023 from US$16.1 per boe in 2022. Purchases of crude oil for the trading operation performed by the holding company, GeoPark Limited, amounted to US$4.7 million and US$7.9 million for the years ended December 31, 2023, and 2022, respectively. No production and operating costs were recorded in Argentina for the year ended December 31, 2023, due to the divestment of the Aguada Baguales, Puesto Touquet and El Porvenir Blocks on January 31, 2022. Geological and geophysical expenses Geological and geophysical expenses increased by 6%, from US$10.5 million for the year ended December 31, 2022, to US$11.2 million for the year ended December 31, 2023, as the result of higher exploratory activities. Administrative costs Administrative costs decreased by 12%, from US$50.0 million for the year ended December 31, 2022, to US$44.0 million for the year ended December 31, 2023, primarily as the result of higher overhead related to joint operations, and a one-time share-based payment made to the Group´s former CEO in 2022 as part of his transition agreement described in “Item 6. Directors, Senior Management and Employees – B. Compensation – CEO Transition Agreement.” Selling expenses Colombia Ecuador Chile Argentina Total Year ended December 31, Change from prior year 2023 % (in thousands of US$, except for percentages) 2022 (10,976) (1,850) (258) — (13,084) (5,887) (1,676) (328) (104) (7,995) (5,089) (174) 70 104 (5,089) 86 % 10 % (21)% (100)% 64 % Selling expenses increased by 64%, from US$8.0 million for year ended December 31, 2022, to US$13.1 million for the year ended December 31, 2023, primarily due to deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses. 98 Table of Contents Commodity risk management contracts As from January 1, 2023, commodity risk management contracts are designated and qualify as cash flow hedges, so that realized gains or losses are recorded within Revenue while unrealized gain and losses are recorded in the Reserves line item within Equity. We recorded a net loss of US$70.2 million for the year ended December 31, 2022, composed by a realized and an unrealized portion. The realized loss of US$83.2 million reflected Brent oil prices above ceiling prices of the commodity risk management contracts settled during the period and the unrealized gain of US$13.0 million reflected the reclassification to realized loss of the previously mentioned settled contracts. Depreciation Colombia Ecuador Brazil Chile Argentina Other Total Year ended December 31, 2023 2022 Change from prior year % (in thousands of US$, except for percentages) (101,666) (7,096) (2,332) (9,815) (22) (3) (120,934) (78,775) (788) (2,796) (14,076) (254) (3) (96,692) (22,891) (6,308) 464 4,261 232 — (24,242) 29 % 801 % (17)% (30)% (91)% — % 25 % Depreciation charges increased by 25% from US$96.7 million for the year ended December 31, 2022, to US$120.9 million for the year ended December 31, 2023, primarily due to an increase in the depreciation cost per boe in Colombia as a consequence of lower proved and probable reserves at the end of 2022 in the CPO-5 and Llanos 34 Blocks, and higher production sold in Ecuador, partially offset by lower production sold in Chile. Operating profit Colombia Ecuador Brazil Chile Argentina Other Total Year ended December 31, 2023 2022 Change from prior year % (in thousands of US$, except for percentages) 321,512 (1,912) 4,514 (21,878) (11,189) (20,140) 270,907 443,584 (1,033) 10,521 (728) 923 (24,190) 429,077 (122,072) (879) (6,007) (21,150) (12,112) 4,050 (158,170) (28)% 85 % (57)% 2,905 % (1,312)% (17)% (37)% We recorded an operating profit of US$270.9 million for the year ended December 31, 2023, compared to US$429.1 million for the year ended December 31, 2022, as a result of the reasons described above. In 2023, we recorded a write-off of unsuccessful exploration efforts of US$29.6 million that corresponded to three unsuccessful exploratory wells drilled in the Llanos 87 Block (Colombia), an unsuccessful exploratory well drilled in the Llanos 124 Block (Colombia) and other exploration costs incurred in the Llanos 94, Coati and Llanos 124 Blocks (Colombia). During 2023, we also recognized an impairment loss of US$13.3 million in the Fell Block due to the known selling price of the related net assets in the context of the divestment transaction of the Chilean business. In addition, we recorded termination and other costs incurred from the divestment process in Chile, including a provision for investment commitments maintained by GeoPark after the transaction, for a total amount of US$9.7 million, together with the amount 99 Table of Contents paid for transferring the working interest in the Los Parlamentos Block in Argentina to the joint operation partner of US$7.0 million. In 2022, we recorded a write-off of unsuccessful exploration efforts of US$25.8 million that corresponded to exploration costs incurred in previous years in the Tacacho and Terecay Blocks (Colombia), four exploratory wells drilled in the CPO-5, Platanillo, Llanos 34 and Llanos 94 Blocks (Colombia), and certain exploration costs incurred in the Espejo Block (Ecuador). No impairment losses were recognized during 2022. Financial results Net financial results decreased 27% to US$39.6 million for the year ended December 31, 2023, as compared to US$53.9 million for the year ended December 31, 2022, mainly resulting from the deleveraging process executed during 2021 and 2022 that resulted in significant debt reduction with extended maturities and lower costs of debt. Foreign exchange (loss) gain Foreign exchange difference was a loss of US$16.8 million for the year ended December 31, 2023, compared to a gain of US$19.7 million for the year ended December 31, 2022. The results in both years mainly correspond to the effect of the fluctuation of the local currency in Colombia on the liabilities held in that currency, such as the income tax payable, the provision for asset retirement obligation and other environmental liabilities, and the lease liabilities. The Colombian Peso revalued by 21% in 2023 and devalued by 21% in 2022. Profit before income tax Colombia Ecuador Brazil Chile Argentina Other Total Year ended December 31, Change from prior year 2023 2022 % (in thousands of US$, except for percentages) 287,243 (3,188) 5,504 (23,462) (6,933) (44,655) 214,509 460,561 (1,469) 11,119 (2,491) (4,337) (68,474) 394,909 (173,318) (1,719) (5,615) (20,971) (2,596) 23,819 (180,400) (38)% 117 % (50)% 842 % 60 % (35)% (46)% For the year ended December 31, 2023, we recorded a profit before income tax of US$214.5 million, compared to a profit of US$394.9 million for the year ended December 31, 2022, primarily due to the reasons mentioned above. Income tax expense Colombia Ecuador Brazil Chile Other Total Year ended December 31, Change from prior year 2023 2022 % (in thousands of US$, except for percentages) (96,770) 198 (396) (3,878) (2,595) (103,441) (162,565) (780) (3,566) (525) (3,038) (170,474) 65,795 978 3,170 (3,353) 443 67,033 (40)% (125)% (89)% 639 % (15)% (39)% Our effective tax rate was 48% for the year ended December 31, 2023, compared to 43% in 2022. The increase in the effective tax rate was primarily due to higher statutory income tax rate applicable to companies engaged in the extraction of crude oil in Colombia, partially offset by the effect of the revaluation of the local currency in Colombia on the tax bases of property, plant and equipment. 100 Table of Contents In 2023 and 2022, the statutory income tax rate in Colombia was 35%, though a tax surcharge is also applicable in 2023, as a result of a tax reform approved in November 2022, impacting companies engaged in the extraction of crude oil like GeoPark. The tax surcharge varies from zero to 15%, depending on different Brent oil prices. The applicable surcharge for 2023 was 10%. Profit for the year Colombia Ecuador Brazil Chile Argentina Other Total Year ended December 31, 2023 2022 Change from prior year % (in thousands of US$, except for percentages) 190,473 (2,990) 5,108 (27,341) (6,933) (47,249) 111,068 297,996 (2,249) 7,553 (3,016) (4,337) (71,512) 224,435 (107,523) (741) (2,445) (24,325) (2,596) 24,263 (113,367) (36)% 33 % (32)% 807 % 60 % (34)% (51)% For the year ended December 31, 2023, we recorded a net profit of US$111.1 million as a result of the reasons described above, compared to a net profit of US$224.4 million for the year ended December 31, 2022. Year ended December 31, 2022, compared to year ended December 31, 2021 For a discussion of the results of our operations for the year ended December 31, 2022, compared to the year ended December 31, 2021, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2022, compared to the year ended December 31, 2021” in our Annual Report on Form 20-F for the year ended December 31, 2022. B. Liquidity and capital resources Overview Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including: ● changes in oil and natural gas prices and our ability to generate cash flows from our operations; ● our capital expenditure requirements; ● the level of our outstanding indebtedness and the interest we have to pay on this indebtedness; and ● changes in exchange rates which will impact our generation of cash flows from operations when measured in US$. We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all. Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash generated by our operations. We have also in the past entered into offtake and prepayment agreements. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.” 101 Table of Contents We believe that our current operations and 2024 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, oil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook.” Capital expenditures In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview—2024 Strategy and Outlook”. In the year ended December 31, 2023, we had total capital expenditures related to the purchase of property, plant and equipment of US$199.0 million (US$178.1 million and US$20.9 million in Colombia and Ecuador, respectively). In the year ended December 31, 2022, we had total capital expenditures related to the purchase of property, plant and equipment of US$168.8 million (US$139.2 million, US$18.5 million, US$11.1 million and US$0.1 million in Colombia, Ecuador, Chile and Argentina, respectively). Cash flows The following table sets forth our cash flows for the periods indicated: Cash flows from (used in) Operating activities Investing activities Financing activities Net increase (decrease) in cash and cash equivalents Cash flows from operating activities 2023 Year ended December 31, 2022 (in thousands of US$) 2021 300,938 (198,590) (98,721) 3,627 467,471 (153,673) (286,552) 27,246 216,777 (126,558) (190,442) (100,223) For the year ended December 31, 2023, cash flows from operating activities were US$300.9 million, a 36% decrease from US$467.5 million for the year ended December 31, 2022, mainly resulting from the decrease in revenues reflecting lower oil and gas prices in 2023. For the year ended December 31, 2022, cash flows from operating activities were US$467.5 million, a 116% increase from US$216.8 million for the year ended December 31, 2021, mainly resulting from the increase in oil revenues reflecting higher prices in 2022, partially offset by the loss on commodity risk management contracts. Cash flows used in investing activities For the year ended December 31, 2023, cash flows used in investing activities were US$198.6 million, a 29% increase from US$153.7 million for the year ended December 31, 2022. This variation is primarily explained by an increase of US$30.2 million in capital expenditures related to the purchase of property, plant and equipment. 102 Table of Contents For the year ended December 31, 2022, cash flows used in investing activities were US$153.7 million, a 21% increase from US$126.6 million for the year ended December 31, 2021. This variation is primarily explained by an increase of US$39.6 million in capital expenditures related to the purchase of property, plant and equipment. Cash flows used in financing activities Cash flows used in financing activities were US$98.7 million for the year ended December 31, 2023, compared to US$286.6 million used in financing activities for the year ended December 31, 2022. This variation was principally related to the full redemption during 2022 of the Notes due 2024. Cash flows used in financing activities were US$286.6 million for the year ended December 31, 2022, compared to US$190.4 million used in financing activities for the year ended December 31, 2021. This variation was principally related to the full redemption of the Notes due 2024 plus an increase in the programs of repurchase of shares and quarterly cash distributions. Indebtedness As of December 31, 2023, and 2022, we had total outstanding indebtedness of US$501.0 million and US$497.6 million, respectively, as set forth in the table below. Notes due 2027 Total Our material outstanding indebtedness is described below. Notes due 2027 General As of December 31, 2023 2022 (in thousands of US$) 500,981 500,981 497,642 497,642 In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. Final maturity will be January 17, 2027. On June 17, 2022, we received requisite consents from holders of the Notes due 2027 for certain amendments to the indenture governing the Notes due 2027. The amendments addressed the impact of adverse market conditions and related drop in the price of crude oil during 2020 on our results, which in turn negatively impacted the restricted payments builder basket, and increased and reset the general restricted payments basket in the indenture to provide us additional restricted payments capacity, giving us additional financial flexibility. Consequently, on June 27, 2022, we paid a consent fee equal to $10.00 per $1,000 to holders of the Notes due 2027 that delivered their consents for the abovementioned amendments to the indenture governing the Notes due 2027. Ranking The Notes due 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U. (the “Guarantor”). The Notes due 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantor (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantor; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantor and their respective subsidiaries to the extent of the value of the collateral securing such obligations. 103 Table of Contents Optional redemption We may, at our option, redeem all or part of the Notes due 2027, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 17 of the years indicated below: Year 2024 2025 2026 and after Change of control Percentage 102.750 % 101.375 % 100.000 % Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2027, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2027 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2027 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption. Covenants The Notes due 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company. In the event the Notes due 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable. The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to EBITDA ratio should not exceed 3.25 and the EBITDA to interest ratio should exceed 2.5. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions). Events of default Events of default under the indentures governing the Notes due 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2027 to become or to be declared due and payable. 104 Table of Contents Off-balance sheet arrangements We did not have any off-balance sheet arrangements as of December 31, 2023, or as of December 31, 2022. C. Research and development, patents and licenses, etc. See “Item 4. Information on the Company——B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to properties.” D. Trend information For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company—B. Business Overview—2024 Strategy and Outlook.” E. Critical accounting policies and estimates We prepare our Consolidated Financial Statements in accordance with IFRS and the interpretations of the IFRS Interpretations Committee (“IFRIC”), as issued by the IASB. The preparation of the financial statements requires us to make judgments, estimates and assumptions that affect the reported amounts of assets, liabilities, revenue and expenses, and related disclosure of contingent assets and liabilities. We continually evaluate these estimates and assumptions based on the most recently available information, our own historical experience and various other assumptions that we believe to be reasonable under the circumstances. Since the use of estimates is an integral component of the financial reporting process, actual results could differ from those estimates. An accounting policy is considered critical if it requires an accounting estimate to be made based on assumptions about matters that are highly uncertain at the time such estimate is made, and if different accounting estimates that reasonably could have been used, or changes in the accounting estimates that are reasonably likely to occur periodically, could materially impact the financial statements. We believe that the following accounting policies represent critical accounting policies as they involve a higher degree of judgment and complexity in their application and require us to make significant accounting estimates. The following descriptions of critical accounting policies and estimates should be read in conjunction with our Consolidated Financial Statements and the accompanying notes and other disclosures. Reserves estimates The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2023, prepared by DeGolyer and MacNaughton Corp., an independent international oil and gas consulting firm based in Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management Reporting System (PRMS) framework. It incorporates many factors and assumptions including: ● expected reservoir characteristics based on geological, geophysical and engineering assessments; ● future production rates based on historical performance and expected future operating and investment activities; ● future oil and gas prices and quality differentials; ● assumed effects of regulation by governmental agencies; ● tax rates by jurisdiction, and ● future development and operating costs. Our management believes these factors and assumptions are reasonable based on the information available to them at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. 105 Table of Contents Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; which may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income, which may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment that may require revision where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities and, (d) the recognition and carrying value of deferred income tax assets that may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets. Cash flow estimates for impairment assessments Cash flow estimates for impairment assessments of non-financial assets require assumptions about three primary elements: future prices, reserves and discount rate. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs. Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate. For further information related to impairment of property, plant and equipment, please see Note 37 to our Consolidated Financial Statements. Exploration and evaluation expenditures The Group adopts the successful efforts method of accounting. Our management makes assessments and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the advice from qualified experts. The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available. Depreciation of oil and gas assets Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block. The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved and probable reserves, or future capital expenditure estimates change. Changes to proved and probable reserves could arise due to changes in the factors or assumptions used 106 Table of Contents in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues. Asset retirement obligations Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant liabilities. We record the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recognized, the cost is also capitalized by increasing the carrying amount of the related asset. Over time, the liability is accreted to its present value at each reporting date, and the capitalized cost is depreciated over the estimated useful life of the related asset. Estimating the future abandonment costs is difficult and requires management to make estimates and judgments because most of the obligations will be settled after many years. Technologies and costs are constantly changing, as well as political, environmental, health, safety and public relations considerations. Consequently, the timing and future cost of abandonment are subject to significant modification. Any change in the variables underlying our assumptions and estimates can have a significant effect on the liability and the related capitalized asset. The present value of future costs necessary for well abandonment is calculated for each area at the present value of the estimated future expenditure. The liability recognized is based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required. Contingencies (1) From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental and health & safety matters. For example, from time to time, the Company receives notices of environmental, health and safety violations. Based on what our Management currently knows, such claims are not expected to have a material impact on the Consolidated Financial Statements. 107 Table of Contents ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES A. Directors and executive officers Board of directors Our board of directors is currently composed of nine members. Our directors are elected by shareholders annually at the Company’s annual general meeting and can hold office for such term as the shareholders may determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. The term for the current directors expires on the date of our next annual general meeting of shareholders to be held in 2024. The current members of the board of directors were appointed at our annual general meeting held on July 19, 2023. The table below sets forth certain information concerning our current board of directors. All ages are current as of March 27, 2024. Name Sylvia Escovar Gómez (1)(2) James F. Park Robert Bedingfield (1)(2) Constantin Papadimitriou (1)(2) Somit Varma (1) Brian F. Maxted (1) Carlos E. Macellari (1) Marcela Vaca Andrés Ocampo Position Chair and Director Deputy Chair, Director and Co-founder Director Director Director Director Director Director Chief Executive Officer and Director (1) Independent director under SEC Audit Committee rules. (2) Member of the Audit Committee. At the Company Age 62 68 75 63 63 66 70 55 45 since 2020 2002 2015 2018 2020 2022 2022 2012 2010 Biographical information of the current members of our board of directors is set forth below. Unless otherwise indicated, the current business address for our directors is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia. Sylvia Escovar Gómez has been a member of our board of directors since August 2020 and was appointed as Chair on June 6, 2021. An economist by training, she received her undergraduate degree from the Universidad de Los Andes in Colombia. She has had a long and prestigious career in both the public and private sectors, having worked for the World Bank, the Central Bank of Colombia and the Colombian National Department of Planning. Previously, she served as Deputy Secretary of Education and Deputy Secretary of Finance for Bogota’s government as well as Vice President of Finance of Fiduciaria Bancolombia. Ms. Escovar was the CEO of Terpel S.A., a fuel distribution company that operates in Colombia, Ecuador, Panama, Peru and the Dominican Republic from 2012 until December 2020. In 2014, Ms. Escovar was named the top businessperson of the year by Portafolio, Colombia’s leading financial daily. In 2018, she received the National Order of Merit for spearheading private sector support for peacebuilding and reconciliation in Colombia. In 2020, she was the only woman on the Corporate Reputation Business Monitor’s list of Colombian leaders with the best reputation to rank in the top 10. In 2023, Forbes named Sylvia Escovar as one of the 100 most powerful women in Colombia. Ms. Escovar’s other Board memberships include Grupo Bancolombia, Empresa de Telecomunicaciones de Bogotá, Organización Corona S.A., Organización Terpel, Compañía de Medicina EPS Sanitas and Grupo Energía Bogotá. James F. Park since co-founding the Company in 2002, has served for 20 years as our Chief Executive Officer until his retirement effective June 30, 2022. He initially funded, built the team, and led the strategy and growth of GeoPark from its small footprint at the southern tip of South America into becoming one of the leading oil and gas companies operating across Latin America today. He continues to serve as Vice Chair of our board of directors and advisor to the team. Beginning as a drilling rig roughneck in his teenage years, Mr. Park has more than 50 years of experience in all phases of the upstream oil and gas business, with a record of achievement in the acquisition, technical operation, and management 108 Table of Contents of international projects and teams across the globe - including projects in North America, Central America, South America, Asia, Europe, Africa, and the Middle East - and with a successful emphasis on people, communities, and the environment. He earned a Bachelor of Science in Geophysics from the University of California at Berkeley and previously worked as a research scientist focused on earthquakes and tectonics at the University of Texas. Mr. Park is a member of the board of directors of GoodRock LLC, Spark Resources LLC and Rocabuena S.A.S., and is a former Board member of the humanitarian non-profit SEE (Surgical Eye Expeditions) International, and the service and advocacy non-profit Girls, Inc. He is a member of the AAPG and SPE, has a degree in environmental management, and has lived in Latin America since 2002. Robert Bedingfield has been a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a Certified Public Accountant. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies; including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. From 2013 to 2023, Mr. Bedingfield served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). Mr. Bedingfield became age ineligible to serve on SAIC’s board on June 7, 2023. Constantin Papadimitriou has been a member of our board of directors since May 2018. He is a respected and successful international investor and businessman, with more than 30 years of investment experience in global capital markets and in resource and industrial projects and was an early investor in GeoPark. Mr. Papadimitriou was for 18 years the Head of General Oriental Investments S.A., the Investment Manager of the Cavenham Funds, as part of the Cavamont Group founded by the Late Sir James Goldsmith. During his tenure at the Cavamont group, Mr. Papadimitriou was initially responsible for Treasury Management, then the Private Equity Portfolio as well as representing the group on the Boards of associated companies including investments in the oil and gas, mining, real estate, and gaming sectors (including Basic Petroleum, a Nasdaq-listed Guatemalan oil and gas company). He is a founding partner of Diorasis International, a company mainly focusing on investments in Greece and the broader Balkans in Aquaculture, and he also chairs the Greek Language School of Geneva and Lausanne. Mr. Papadimitriou holds an Economics and Finance degree and a post-graduate Diploma in European Studies from Geneva University. Mr. Papadimitriou is currently a member of the board of directors of Cavamont Holdings Limited, General Oriental Advisory (formerly known as General Oriental Investments S.A.), Diorasis International S.A. and Tellco AG. Somit Varma has been a member of our board of directors since August 2020. He has been a proven and respected investor in oil, gas, mining, and infrastructure projects across the globe for more than three decades. During his time at the International Finance Corporation (IFC), he was the Global Head of Oil, Gas, Mining and Chemicals, Chairman of the IFC Oil, Gas, Mining and Chemicals Investment Committee and Chairman of the Global Gas Flaring Reduction Partnership. From 2011 until July 2020, Mr. Varma was a Managing Director of the Energy Group at Warburg Pincus LLC, one of the world’s premier private equity firms. Throughout his tenure at Warburg Pincus, Mr. Varma served on the boards of several international energy companies where he worked with management teams on a diverse set of issues including new acquisitions, strategic partnerships, capital allocation, risk management, succession planning, and growing and mentoring teams. Mr. Varma was Chairman of the Energy and Infrastructure Council of EMPEA, the global industry association for private capital in emerging markets. He is also currently an advisor to a global private equity firm and a family office. Mr. Varma earned his MBA at Boston University before attending the Executive Development Program at Harvard Business School. During the last 5 years, Mr. Varma has served as board member of several companies including Delonex Energy, Zenith International, Apex Energy and Zenith US. Brian F. Maxted has been a member of our board of directors since July 2022. He holds a bachelor’s degree in geology from the University of Sheffield and a master’s degree in organic geochemistry and petrology from the University of Newcastle-upon-Tyne. Mr. Maxted is a proven oil and gas explorer, private equity entrepreneur and public company leader in the upstream E&P business, with a global track record of significant basin and play discoveries over 30 years. He spent the first part of his professional life from the late 1970s working for BP in locations including Europe, Africa, 109 Table of Contents North America and South America, where he was involved in the discovery of Colombia’s giant Cusiana and Cupiagua oil fields in the early 1990s. During the second half of his career from the mid-1990s through the 2010s Mr. Maxted held various exploration leadership roles for US-based independents, including Triton Energy and Hess Corporation. In 2003, Mr. Maxted became a founding partner and later the CEO/CXO and Board Director of Kosmos Energy. Mr. Maxted retired from Kosmos in 2019 and established Limatus Energy Advisory Limited to provide strategic counsel to upstream E&P companies. In addition, he led the formation of Lapis Energy, a company focused on carbon solutions in the US Lower 48, where he currently serves as Chair of the Board. Mr. Maxted is also a member of the board of directors of JHI Energy – now Triple 7 Energy Inc. Carlos E. Macellari has been a member of our board of directors since July 2022. He holds a bachelor’s degree in geology from the Universidad Nacional de La Plata in Argentina, and a master´s degree and a PhD in geology from Ohio State University. He has over 30 years of successful exploration, development and management experience in the oil and gas industry across several continents, at Tecpetrol, Repsol YPF, Hocol, Benton Oil & Gas, Enron Oil & Gas International and Pecten International (Shell Oil). As Director of Exploration and Development for Tecpetrol, he led the subsurface team responsible for making Fortín de Piedra the largest gas producing block in Argentina, and the discovery and development of the Pendare Field in Colombia. As Worldwide Director of Geology, he also led the technical group behind Repsol’s exploration success in locations such as Libya, Algeria, Pre-Salt Brazil, the Gulf of Mexico, Venezuela and Peru. He has published over 50 technical papers and has been guest lecturer in numerous international forums. He is the founder of the Journal of South American Earth Sciences, has lectured several courses in the USA, Colombia, Spain and Argentina and is currently a professor for postgraduate students at Universidad Nacional de La Plata. At present he is an independent consultant on oil and gas exploration and production after founding and managing Andes Energy Consulting, since 2020 he has been a Board member at Inverban Investments, Tecpetrol Investments, Tecpetrol International and Suizum, and since 2024 independent board member at Olympic Peru. Marcela Vaca joined GeoPark in August 2012 and served as General Director until August 2022. She has been a member of our board of directors since July 2022. She has more than 20 years of experience in planning, legal, environmental and social articulation and management of hydrocarbon exploration and production projects in Colombia and elsewhere in Latin America. Under her leadership as Director for Colombia and General Director, GeoPark became one of the leading oil and gas companies in the country. She plays a crucial role in advancing GeoPark’s diversity, equality and inclusion efforts, and promotes female empowerment as a key to the economic development of Latin America. Prior to joining our company, for nine years Ms. Vaca was the CEO of the Hupecol Group, where her achievements included leading the development of the Caracara field and the construction of the Jaguar–Santiago Pipeline. From November 2000 to June 2003, she worked as Legal, Administrative and External Affairs Manager at GHK Company Colombia. Bloomberg Linea includes Ms. Vaca in its 500 most influential people in Latin America, and in 2020, 2021 and 2022 Forbes named her as one of the 50 most powerful women in Colombia. Ms. Vaca was a member of the board of directors of the Colombian Oil Association (ACP, Asociación Colombiana de Petróleo) from 2010 to 2021 and served as Chair of the Board until March 2022. Marcela graduated in Law with a specialization in Commercial Law from the Pontificia Universidad Javeriana in Colombia and is a Fulbright Scholar with a Summa Cum Laude Master (LLM) from Georgetown University in the USA. Currently, Ms. Vaca serves as board member at Corficolombiana and Fundación Juanfe. Andrés Ocampo has served as our Chief Executive Officer and as a member of our board of directors since July 2022. He previously served as our Chief Financial Officer (from November 2013 through June 2022) and Director of Growth and Capital Markets (from January 2011 through October 2013), and has been with our company since July 2010. Mr. Ocampo holds a Bachelor’s degree in Economics from Universidad Católica Argentina, has more than 17 years of experience in business and finance. Andrés has been instrumental in helping GeoPark reach some of its greatest milestones, including its entry into Colombia and Brazil, the IPO on the New York Stock Exchange, the acquisition of Amerisur Resources and significant acreage expansion in Colombia. Our board of directors appointed Mr. Ocampo to serve as Chief Executive Officer of the Company effective July 1, 2022, by virtue of his wide experience in business management and finance together with his character, vision, knowledge of the Company and his proven ability to lead successful teams. Before joining our Company, Mr. Ocampo worked at Crédit Agricole Corporate & Investment Bank and Citigroup, focusing on the oil and gas and commodities industries. 110 Table of Contents Executive officers Our executive officers are responsible for the management and representation of our company. The table below sets forth certain information concerning our executive officers. All ages are current as of March 27, 2024. Name Andrés Ocampo Jaime Caballero Uribe Augusto Zubillaga James Deckelman Rodolfo Martín Terrado Mónica Jiménez Agustina Wisky Position Chief Executive Officer and Director Chief Financial Officer Chief Technical Officer Chief Exploration Officer Chief Operating Officer Chief Strategy, Sustainability and Legal Officer Chief People Officer At the Company Age 45 49 54 67 49 48 47 since 2010 2024 2006 2023 2018 2022 2002 Biographical information of our executive officers is set forth below. Unless otherwise indicated, the current business address of our executive officers is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia. Jaime Caballero Uribe has served as our Chief Financial Officer since January 2024. He has more than 25 years of industry and finance experience, including senior positions in large corporations as well as in start-ups and entrepreneurial businesses. Until August 2023, Mr. Caballero was Group CFO at Ecopetrol, the largest corporation in Colombia and one of the 400 largest companies in the world where he helped the management team achieve various performance records, including the delivery of more than US$20 billion in growth financing and debt refinance. During his tenure, he was recognized by the Institutional Investor publication as one of the top three sector CFOs in Latin America. Previously, he held multiple positions at BP plc over 17 years, where his most recent appointment was CFO for the Brazil Region, which includes Colombia, Uruguay and Venezuela. Mr. Caballero holds a degree in Law from Universidad de Los Andes, an MBA in Energy Business from Fundação Getulio Vargas, and certificates in CFO Excellence from Wharton and Energy Innovation and Emerging Technologies from Stanford. Mr. Caballero currently serves as a board member of Agricola Cerro Prieto S.A. Augusto Zubillaga has served as our Chief Technical Officer since July 2022. He previously served in other management positions throughout the Company including as Chief Operating Officer, Operations Director, Argentina Director and Production Director. He is a petroleum engineer with more than 26 years of experience in production, engineering, well completions, corrosion control, reservoir management and field development. He has a degree in petroleum engineering from the Instituto Tecnológico de Buenos Aires. Prior to joining our company, Mr. Zubillaga worked for Petrolera Argentina San Jorge S.A. and Chevron San Jorge S.A. At Chevron San Jorge S.A., he led multi-disciplinary teams focused on improving production, costs and safety, and was the leader of the Asset Development Team, which was responsible for creating the field development plan and estimating and auditing the oil and gas reserves of the Trapial field in Argentina. Mr. Zubillaga was also part of a Chevron San Jorge S.A. team that was responsible for identifying business opportunities and working with the head office on the establishment of best business practices. He has authored several industry papers, including papers on electrical submersible pump optimization, corrosion control, water handling and intelligent production systems. James Deckelman has served as our Chief Exploration Officer since October 2023. He is a highly successful explorer with over 25 years of experience in Latin America, the Middle East, Africa, Southeast Asia and North America, leading projects ranging from ultra-deepwater to unconventional. Mr. Deckelman added over a billion barrels of recoverable resources for companies including ConocoPhillips, BP and Talisman Energy. In Latin America, he has led projects and transactions in Colombia, Venezuela, Peru, Ecuador, Mexico, Brazil and Argentina. Mr. Deckelman is highly experienced in investment evaluation, new asset capture, and delivering production and reserve growth. He has a Master´s degree in geology from Utah State University and has authored over 15 industry publications focused on Latin America. Among other awards, in 2021, he was recognized as one of “Industry’s 100 Who Made a Difference” by the American Association of Petroleum Geologists. 111 Table of Contents Rodolfo Martín Terrado has served as our Chief Operating Officer since July 2022. He previously served as our Director of Operations since he joined GeoPark in August 2018. Mr. Terrado has more than 25 years of experience in the oil industry, working in field development and operations. Martín has a degree in Petroleum Engineering from the Instituto Tecnológico de Buenos Aires (ITBA) and an MBA from the IAE Business School at the Universidad Austral in Buenos Aires. He is a member of the Society of Petroleum Engineers (SPE). Prior to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San Jorge and Chevron San Jorge S.A. in different international operations, including in Argentina, the United States and Venezuela. Mr. Terrado previously led heavy oil operations in Venezuela assets and his prior responsibilities include waterflooding, CO2 flooding and unconventionals. Mónica Jiménez has served as our Chief Strategy, Sustainability and Legal Officer and Company Secretary since August 2022. She leads the strategy and sustainability (ESG) within the Company and leads the governance and legal team. Mrs. Jiménez is an experienced attorney in corporate and international law in Canada and Colombia with extensive experience in international commercial and investment arbitration. After living in Canada for more than 16 years, Mrs. Jiménez was Vice President of Corporate Affairs and Secretary General of Ecopetrol (NYSE), Colombia´s largest company, before joining GeoPark. Mrs. Jiménez studied Law at Universidad the Los Andes, has a postgraduate degree in Civil Liability and Damages from the Universidad Externado de Colombia, and a Master of Science in Development Studies from the London School of Economics (LSE). Recognized as one of the leading in-house lawyers in Colombia by The Legal 500 GC Powerlist: Colombia 2022 and 2023, Mrs. Jiménez is a current member of the International Court of Arbitration of the International Chamber of Commerce (ICC). She has served as board member of several companies and is currently a member of the Board of Grupo Bolivar S.A. Agustina Wisky is GeoPark’s Chief People Officer, responsible for enriching and promoting an organizational culture based on trust, teamwork, continuous improvement, mutual respect, and diversity. Agustina has been with the Company since it was founded in 2002, and she created and has led the People department for over 15 years, guided by the principles of attracting, motivating and developing the best professionals, and ensuring the comprehensive wellbeing of staff and their families. She previously held the position of Performance Director at GeoPark. Before joining GeoPark, Agustina worked at PricewaterhouseCoopers and AES Gener in Argentina. Agustina is a Public Accountant and has a Master’s degree in Human Resources from the IAE Business School of the Universidad Austral in Buenos Aires, Argentina. Thanks to Agustina’s leadership in the implementation of inclusion and diversity best practices, GeoPark won the Equipares Silver Award in 2020, which is given by the Government of Colombia with technical support from the United Nations Development Program. GeoPark was furthermore included in the Bloomberg Gender-Equality Index (GEI) in 2022, which evaluates the performance of listed companies that are committed to transparency in gender reporting. B. Compensation Executive officers and director compensation For the year ended December 31, 2023, we paid an aggregate of US$2.0 million to the members of our board of directors for their services in all capacities. This amount includes payments made to Mr. Carlos Macellari for his services as a consultant for the period from May to August 2023. It does not include payments made to executive director Andrés Ocampo as he only received compensation in his capacity as an executive officer (as described below). Disclosure of compensation on an individual basis is included in Note 11 to our Consolidated Financial Statement. During this same period, we paid an aggregate of US$8.9 million for salaries and other benefits (including with respect to grants of awards under the LTIP Executives and contingent amounts or deferred compensation accrued for the year, even if payable at a later date) to the executive officers of the Company for their services in all capacities. Annual Bonus Program Our Corporate Governance Guidelines set forth that the Compensation Committee will evaluate annually the performance of the Chief Executive Officer and other executive officers of the Company based on objective and relevant corporate goals and that the board of directors, in consultation with and at the recommendation of the Compensation Committee will review executive officers’ annual performance evaluations. In addition, the Charter of the Compensation Committee establishes that the Committee shall review and approve written annual and longer-term corporate goals and 112 Table of Contents objectives relevant to the compensation of the Chief Executive Officer and other executive officers, making sure that they are appropriately linked to the Company´s strategy. In this regard, the Compensation Committee reviews and recommends that the board of directors approve the annual performance scorecard that contains the performance metrics and objective criteria against which the Chief Executive Officer and other executive officers are evaluated. Depending on the performance evaluation, the amounts to be paid to the Chief Executive Officer and other executive officers as annual bonuses are recommended by the Committee and submitted to be approved by our board of directors. The 2023 performance bonus approved by our board of directors on March 6, 2024, corresponds to 65% score payout applied to target annual bonus of each executive officer, including the Chief Executive Officer. CEO Transition Agreement Mr. James F. Park (former CEO of the Company and current non-executive member of the board of directors and consultant of the Company, advising on M&A and strategic matters) has a consulting agreement with the Company, approved by the board of directors on March 2022, as part of the transition of the CEO position. Such agreement governs his consulting services and does not provide for payments upon a termination of service (other than previously earned or accrued amounts). Pursuant to the terms of his transition agreement, James F. Park was provided certain severance benefits, including (i) cash severance payments, payable in a combination of cash and stock, (ii) accelerated vesting of unvested equity awards, and (iii) administrative support for 1-2 years, reimbursement for reasonable relocation costs and 12 months of health and life insurance premiums. Senior Management Severance Our board of directors determined that it is in the best interests of the Company and its shareholders to provide certain members of the Company’s senior management with payments and benefits in connection with certain qualified terminations and/or in connection with certain change in control scenarios. Therefore, the board of directors approved the adoption of an Executive Termination and Change in Control Benefits Plan (the “Severance Plan”). In addition, the board of directors approved an employment agreement with our current CEO, Andrés Ocampo, which provides for severance benefits consistent with those provided under the Severance Plan. In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control, the executive will be entitled to receive the following, subject to the execution of a release of claims: (i) cash severance in an amount equal to 2 times the sum of (x) the executive’s annual base salary, (y) the average of any cash bonuses paid in the two years preceding the termination date and (z) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000; and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of employment. In addition, the Severance Plan provides that, in the event an executive has relocated at the Company’s request and is terminated during the 12 months following the change in control, the executive will be provided the costs for relocation back to their home country. In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability, other than in the 24 months following a change in control, then, subject to the execution of a release of claims, the executive sill be entitled to the following benefits: (i) cash severance in an amount equal to 1.5 times (or, in the case of the CEO, 2 times) the sum of (x) the executive’s annual base salary, (y) the average of any cash bonuses paid in the two years preceding the termination and (z) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000, and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of employment. In addition, the executive’s unvested equity awards will accelerate pro-rata (in the case of performance equity awards, subject to achievement of the applicable performance metrics). Pursuant to the Severance Plan, in the event of a change in control, outstanding performance equity awards will convert into a number of time-based equity awards based on actual performance through the date of the change in control and, except as set forth below, will vest in accordance with the awards’ original schedule, subject to the executive’s 113 Table of Contents continued service through such date. In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control: (i) all outstanding time-vesting equity awards will fully accelerate and vest; and (ii) performance equity awards, as converted in accordance with clause (i) above, will fully accelerate and vest. In the event that the acquiror cashes out outstanding equity awards at closing of the change in control, then, at closing, (i) performance awards will accelerate, and vest based on actual performance through the date of the change in control and (ii) all outstanding time-vesting equity awards will fully accelerate and vest. GeoPark Limited 2018 Equity Incentive Plan Given the expiration of our Stock Awards Plan on November 3, 2018, on November 5, 2018, we adopted the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those participating employees and executives to perform at the highest level and to further the best interests of the Company and our shareholders. The Plan is designed as an omnibus plan, pursuant to which we may grant awards in the form of options, share appreciation rights, restricted shares, restricted stock units, performance awards, other share-based awards or other cash-based awards throughout the ten (10)-year term of the Plan. Subject to adjustments as set forth in the Plan, the maximum number of shares available for issuance under the Plan is 5,000,000 shares. The applicable award documentation will set forth the terms and conditions of the awards granted under the Plan, including, but not limited to, the vesting conditions and the effect on a termination of service or a Change in Control on awards. The following table sets forth the common share awards granted to our employees and executive officers under the Plan which are outstanding as of the date of this annual report: Number of underlying common shares outstanding 800,000 (1) 215,000 (2) 25,000 (4) 571,984 (5) 197,197 (6) 1,000,000 (7) 5,968 (8) 20,000 (9) 25,000 (10) 351,971 (11) Grant date 01/01/2020 03/31/2022 03/31/2022 10/01/2022 02/14/2023 01/02/2023 10/01/2023 10/01/2023 01/15/2024 02/14/2024 Vesting date 01/02/2023 03/31/2025 (3) 03/31/2025 01/02/2025 01/02/2026 01/02/2026 01/02/2026 10/01/2026 01/15/2027 01/02/2027 (1) On November 6, 2019, our board of directors approved a share-based compensation program for approximately 800,000 shares to be granted in 2020. Considering the performance conditions, the Compensation Committee determined that only a total of 152,030 shares have vested. As of December 31, 2023, 61,980 shares have been exercised, with a remaining amount of 90,050 shares to be exercised. (2) Awards corresponding to the Retention and Hiring Bonus scheme. (3) The vesting date is March 31, 2025, or 3 years from grant date. (4) Service agreement. The awards granted under this agreement vest in three annual installments (March 31, 2023, March 31, 2024, and March 31, 2025). As of December 31, 2023, 8,333 shares have been exercised, with a remaining amount of 16,666 shares to be exercised. (5) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2025. (6) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2026. (7) Awards corresponding to LTIP Employees approved in December 2022. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2026. (8) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2026. (9) Awards corresponding to the Hiring Bonus scheme. (10) Awards corresponding to the Hiring Bonus scheme. 114 Table of Contents (11) Awards corresponding to the LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2027. Currently, we have the following incentive equity programs in place under the Plan: the Stock Awards Program (“Stock Awards Program”), the Retention and Hiring Bonus Scheme, the Long-Term Incentive Program for Executives (“LTIP Executives”) and the Long-Term Incentive Program for Employees (“LTIP Employees”). Employees Long-Term Incentive Program to Employees (“LTIP Employees”) In December 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new Long-Term Incentive program for employees and new hirings. Main characteristics of the program are: ● All employees (non-top management) and new hirings are eligible. ● 3-year program, with a grant date of January 2, 2023, or the date on which the employees are hired. ● The components of the program are the following: - - - 30% Time-based RSUs: vesting annually ratably in three equal installments; 30% Company Performance: measured over three-year performance period (December 2022-December 2025); and 40% Absolute Performance Shares: share price at the date of vesting must be higher than the share price at the date of grant or date of hiring. ● The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026. Executive officers Long-Term Incentive Program to Executive Officers (“LTIP Executives”) In March 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new Long-Term Incentive program for the executive officers. Main characteristics of the program are: ● All executive officers are eligible. ● Grants are awarded annually to executive officers. ● The components of the program are the following: - - - 20% Time-based Restricted Share Units (RSUs) vesting ratably in three equal installments on each of the first three anniversaries of the grant date; 35% Relative Performance Share Units based on relative total shareholder return (TSR) and measured over three-year performance period relative to peer group; and 45% Absolute Performance Share Units (PSUs) based on absolute total shareholder return (TSR) and measured over three-year performance period. In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated 571,984 total shares, to vest during a three-year period. On February 17, 2023, the Compensation Committee approved a new grant, effective as of February 14, 2023, of 197,197 shares to vest during a three-year period. On February 26, 2024, the Compensation Committee approved a new grant, effective as of February 14, 2024, of 351,971 shares to vest during a three- year period. On January 25, 2023, and February 26, 2024, the Compensation Committee determined that 246,110 and 86,602 shares, respectively, should be delivered to the participants according to the first and second vesting periods of the abovementioned grants. 115 Table of Contents Non-Executive Director Plan In August 2014, our board of directors adopted the Non-Executive Director Plan in order to grant shares to non-executive directors as part of their compensation program for serving as directors (the “Non-Executive Director Plan”). The Non- Executive Director Plan was amended and restated in October 2016, when additional 1,000,000 shares were registered as the maximum number of shares available to be issued under this plan. In accordance with the resolutions adopted by our board of directors on May 20, 2014, our non-executive directors are paid their quarterly fees in the form of equity awards granted under the Non-Executive Director Plan. Under the Non-Executive Director Plan, the compensation committee may award common shares, restricted share units and other share-based awards that may be denominated or payable in common shares or factors that influence the value of common shares. Potential dilution resulting from Equity Incentive Compensation Plans In accordance with the equity awards granted by the Company under its Stock Awards Program and the Plan, as of March 19, 2024, there were 1,850,149 outstanding shares that had been awarded but which had not yet vested, representing approximately 3.3% of the total issued share capital as of that date. Stock Ownership Guidelines In December 2022, to further align the interests of our executive officers with those of the Company’s shareholders, our board of directors approved minimum stock ownership guidelines applicable to the Company’s executive officers, as determined by the board of directors. Each such executive officer is required to hold, within five years after the adoption of the guidelines or, if later, within five years after becoming subject to the policy, a number of shares with an aggregate value of at least three times his or her annual base salary. Shares beneficially owned by the applicable officer or held in a family trust established by the applicable executive officer and shares underlying vested equity awards (which, in the case of stock options, are at- or in-the-money) are taken into account for purposes of determining compliance with these guidelines. Until an officer has met his or her ownership requirement, he or she is required to retain at least 50% of shares received from the vesting, settlement or exercise of equity awards (and which remain outstanding after tax withholding and payment of any applicable exercise price). C. Board practices Overview Directors are expected to provide stewardship to promote the long-term success of the Company. They are expected to fulfill their fiduciary duties and duty of care in the best interests of the Company, considering the various needs of its stakeholders (shareholders, employees, communities, suppliers and clients), providing advice to and oversight of management’s activities. Within its responsibilities, the board of directors oversees the company’s strategic goals; financial statements, control and risk management; core values, integrity and ethical standards; management and board remuneration and succession planning, among others. On December 23, 2020, and as amended from time to time, the board of directors adopted our Corporate Governance Guidelines (available at the Company’s website) to further regulate and enhance the board’s corporate governance structures and processes. Board composition Our bye-laws and board resolutions provide that the board of directors consist of a minimum of three and a maximum of nine members. All of our directors were elected at our annual shareholders’ meeting held on July 19, 2023. Their term expires on the date of our next annual shareholders’ meeting, to be held in 2024. The board of directors meets regularly throughout the year, at least on a quarterly basis. Committees of our board of directors Our board of directors has established an Audit Committee, a Compensation Committee, a Nomination and Corporate Governance Committee, a Strategy & Risk Committee, a Technical Committee and a SPEED/Sustainability Committee. 116 Table of Contents The composition and responsibilities of each board committee are described below. The Nomination and Corporate Governance Committee annually considers and recommends to the board of directors the membership and the chair of each board committee. Our board of directors may establish other committees to assist with its responsibilities. Audit Committee The Audit Committee is currently composed of three independent directors. The current members of the Audit Committee are Mr. Robert Bedingfield (who serves as Chairman of the committee), Mr. Constantin Papadimitriou and Ms. Sylvia Escovar. Mr. Robert Bedingfield is regarded as audit committee financial expert. The Nomination and Corporate Governance Committee determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou and Ms. Sylvia Escovar are independent, as such term is defined under SEC rules applicable to foreign private issuers. The main purposes of the Audit Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board of directors in its oversight of: (i) the integrity of the Company’s financial statements and the company’s accounting and financial reporting processes and financial statement audits; (ii) the independent auditor’s performance, qualifications and independence; (iii) the Company’s compliance with legal and regulatory requirements and the company´s ethical standards; and (iv) the performance of the company´s internal audit function. Compensation Committee The Compensation Committee is currently composed of four independent directors. The current members of the compensation committee are Mr. Constantin Papadimitriou (who serves as Chairman of the committee), Mr. Robert Bedingfield, Mr. Brian F. Maxted and Mr. Somit Varma. The main purposes of the Compensation Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) evaluate and recommend for approval by the independent members of the Board the remuneration, benefits and incentive compensation arrangements for the executive officers of the Company; (ii) establish performance indicators against which the executive officers of the Company will be evaluated; (iii) evaluate and review the identification, recruitment and succession planning for the executive officers of the Company; and (iv) review and recommend to the board of directors any changes to the remuneration of the non-executive directors of the Company. Nomination and Corporate Governance Committee The Nomination and Corporate Governance Committee is currently composed of three independent directors. The current members of the Nomination and Corporate Governance Committee are Mr. Somit Varma (who serves as Chairman of the committee since November 11, 2021), Ms. Sylvia Escovar and Mr. Robert Bedingfield. The main purposes of the Nomination and Corporate Governance Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) review board succession planning, including identifying and selecting suitable board candidates in accordance with the criteria set forth in its charter and approved by the board of directors; (ii) review and recommend to the board of directors the membership and Chair of each board Committee; (iii) develop, review and monitor the Company’s corporate governance guidelines, processes and structures; and (iv) conduct and oversee the board of directors’ annual evaluation process. Strategy & Risk Committee The Strategy & Risk Committee was created in December 2020, and is currently composed of six directors. The current members of the Strategy & Risk Committee are Mr. James F. Park (who serves as Chairman of the committee), Mr. Constantin Papadimitriou. Mr. Somit Varma, Mr. Brian F. Maxted, Mr. Andrés Ocampo and Mr. Carlos E. Macellari. The main purposes of the Strategy and Risk Committee, without prejudice of any additional objectives or functions foreseen in its Charter, are to assist the Board in (i) its oversight function of understanding the various key risks to which the Company is exposed, and the interlink between the Company’s strategy and such risks; and (ii) its review of new strategic opportunities and transactions (including mergers, acquisitions, divestments and similar transactions). 117 Table of Contents Technical Committee The Technical Committee is currently composed of four directors. The current members of the technical committee are Mr. Brian F. Maxted (who serves as Chairman of the committee), Mr. Carlos E. Macellari, Mr. James F. Park and Mr. Somit Varma. The main purposes of the Technical Committee, without prejudice of any additional objectives or functions foreseen in its Charter, are to assist the Board in fulfilling its responsibilities by providing strategic oversight on specific technical matters which are beyond the scope or expertise of non-technical Board members to: (i) optimize and assure technical decision making in existing assets to ensure business performance targets, as defined by the annual corporate scorecard, and long-range plan goals are achieved, including with respect to the design, execution and delivery of the exploration and appraisal strategy and plan, as well as the field development programs and drilling/production operations; (ii) review and advise the Board on the technical analysis of prospective new ventures and/or in conjunction with the Strategy and Risk Committee, potential corporate merger and acquisition opportunities, as and when required; (iii) provide regular, timely feedback, guidance and support to the management team and technical staff on all sub-surface matters to facilitate the Board processes related to work programs and budget planning, execution and reporting, as well as people and business performance review; and (iv) review and analyze the annual report presented by the management team in relation to the Company’s oil reserves and recommend to the board of directors to approve its disclosure and publication. SPEED/Sustainability Committee The SPEED/Sustainability Committee is currently composed of four directors. The current members of the SPEED/Sustainability committee are Ms. Marcela Vaca (who serves as Chairman of the committee), Ms. Sylvia Escovar, Mr. James F. Park and Mr. Andrés Ocampo. The main purposes of the SPEED/Sustainability Committee, without prejudice of any additional objectives or functions foreseen in its Charter, are to assist the Board in (i) its guidance and oversight function of the Company’s strategy concerning the SPEED/Sustainability matters, including the safety of its operations, the initiatives to give back value to stakeholders, the wellbeing of employees, preservation of the environment, community development, and any other matters related to sustainability; and (ii) its review of the performance on the topics above. Liability insurance We maintain liability insurance coverage for all of our directors and officers, the level of which is reviewed annually. D. Employees As of December 31, 2023, we had 470 employees, representing a decrease of 2.5% from December 31, 2022. The following table sets forth a breakdown of our employees by geographic segment for the periods indicated. Colombia Ecuador Brazil Chile Argentina Corporate Total Year ended December 31, 2022 2021 2023 412 5 4 27 15 7 470 388 8 4 49 24 9 482 321 3 4 52 74 9 463 From time to time, we also utilize the services of independent contractors to perform various field and other services as needed. As of December 31, 2023, 13 of our employees were represented by labor unions or covered by collective bargaining agreements. We believe that relations with our employees are satisfactory. 118 Table of Contents E. Share ownership As of March 19, 2024, members of our board of directors and our executive officers held as a group 9,906,640 of our common shares and 17.9% of our outstanding share capital. The following table shows the share ownership of each member of our board of directors and executive officers as of March 19, 2024. Shareholder James F. Park (1) Sylvia Escovar Robert Bedingfield Constantin Papadimitriou Somit Varma Brian Maxted Carlos Macellari Marcela Vaca Andrés Ocampo Jaime Caballero Uribe Augusto Zubillaga James Deckelman Rodolfo Martín Terrado Mónica Jiménez Agustina Wisky Sub-total executive officers' ownership Total Common shares 8,817,251 61,610 172,296 73,664 72,876 13,816 13,816 12,656 * * * * * * * 668,655 9,906,640 Percentage of outstanding common shares 15.9 % * * * * * * * * * * * * * * 1.2 % 17.9 % Indicates ownership of less than 1% of outstanding common shares. * (1) Held by Mr. Park directly and indirectly through GoodRock, LLC. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2024. 352,400 of Mr. Park’s shares have been pledged pursuant to lending arrangements. Certain members of our board of directors have, since the time of our initial public offering in the U.S., entered into certain pledges of Company securities in order to access some liquidity with respect to those shares and/or to diversify their holdings. On June 29, 2021, the board of directors, based on the recommendation of the Nomination and Corporate Governance Committee, revised its Insider Trading Policy with respect to securities pledging and prohibited employees and directors from pledging Company securities in any circumstance, including by purchasing Company securities on margin or holding Company securities in a margin account. In the event that an employee or director pledged any Company securities prior to June 29, 2021, and provided that any such pledges were made in compliance with the Insider Trading Policy of the Company effective at the time such securities were pledged, the employee or director must terminate any such arrangements by June 29, 2024. F. Disclosure of a registrant’s action to recover erroneously awarded compensation Not applicable. 119 Table of Contents ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS A. Major shareholders The following table presents the beneficial ownership of our common shares as of March 19, 2024, except for certain shareholders whose last available data is as of December 31, 2023, or as noted below. The percentages reported herein are based on the shares outstanding as of March 19, 2024. Shareholder James F. Park (1) Compass Group LLC (2) Renaissance Technologies LLC (3) Socoservin Overseas SPF S.à.r.l. (4) Cobas Asset Management, SGIIC, SA (5) Gerald E. O’Shaughnessy (6) Other shareholders Total Common shares 8,817,251 3,312,589 3,091,863 2,889,315 2,801,544 2,793,392 31,764,896 55,470,850 Percentage of outstanding common shares 15.9 % 6.0 % 5.6 % 5.2 % 5.1 % 5.0 % 57.2 % 100.0 % (1) 7,305,133 shares are held by GoodRock, LLC, which is controlled by James F. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2024. 352,400 of Mr. Park´s shares have been pledged pursuant to lending arrangements. (2) The information listed in the table is based solely on the disclosure set forth in Compass Group LLC´s most recent Schedule 13G filed with the SEC on February 14, 2024. (3) The information listed in the table is based solely on the disclosure set forth in Renaissance´s most recent Schedule 13G filed with the SEC on February 13, 2024. (4) The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’ most recent Schedule 13G filed with the SEC on July 25, 2023. (5) The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset Management’s most recent Schedule 13G filed with the SEC on March 20, 2024. (6) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP; GPK Holdings, LLC; The Globe Resources Group, Inc.; and other investment vehicles. The information listed in the table is based solely on the disclosure set forth in Mr. O´Shaughnessy’s most recent Schedule 13D filed with the SEC on March 15, 2024. 2,700,000 of Mr. O ´Shaughnessy´s shares have been pledged pursuant to lending arrangements. Principal shareholders do not have any different or special voting rights in comparison to any other common shareholder. According to our transfer agent, as of March 19, 2024, we had 12 registered shareholders, out of which 6 are registered as U.S. shareholders. Since some of the shares are held by nominees, the number of shareholders may not be representative of the number of beneficial owners. B. Related party transactions We have entered into the following transactions with related parties: Executive Directors’ Service Agreements We have entered into service contracts with certain of our executive directors. See “Item 6. Directors, Senior Management and Employees—B. Compensation—Executive officers and director compensation—.” For further information relating to our related party transactions and balances outstanding as of December 31, 2023, 2022 and 2021, please see Note 34 to our Consolidated Financial Statements. 120 Table of Contents C. Interests of Experts and Counsel Not applicable. ITEM 8. FINANCIAL INFORMATION A. Consolidated statements and other financial information Financial statements See “Item 18. Financial Statements,” which contains our audited financial statements prepared in accordance with IFRS. Legal proceedings From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, environmental, safety and health matters. For example, from time to time, we receive notice of environmental, health and safety violations. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position and results of operations. On January 8, 2020, Amerisur received a copy of a claim form issued in the High Court of England and Wales (the “Court”) by Leigh Day solicitors on behalf of a group of claimants (the “Claimants”) described as members of a farming community in the department of Putumayo in Colombia, seeking compensation for economic and non-economic damages said to be caused by alleged environmental contamination and pollution caused by Amerisur’s operations in the region. Following initial court hearings, an interim freezing order was imposed on Amerisur for a certain amount of its assets located in the United Kingdom. On November 10, 2020, the freezing order was discharged by agreement between the parties as Amerisur provided alternative security in the form of a letter of credit. On August 11, 2023, a settlement (the “Settlement”) was signed between Leigh Day and Amerisur, made on a no-admission of liability basis and included a payment made by Amerisur. All Claimants represented by Leigh Day agreed to the Settlement. On October 2, 2023, the Court approved the Settlement, the litigation was discontinued, and the letter of credit was cancelled. For further information on the contingent liability related to the above, please see Note 29 to our Consolidated Financial Statements. Dividends and dividend policy Holders of common shares will be entitled to receive dividends, if any, paid on the common shares. On March 31, 2023, and May 31, 2023, we paid dividends of US$0.13 per share, on September 7, 2023, we paid dividends of US$0.132 per share and, on December 11, 2023, we paid dividends of US$0.134 per share. Because we are a holding company with no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries. The terms of our indebtedness may restrict us from paying dividends. Under the Companies Act 1981, as amended of Bermuda (the “Bermuda Companies Act”), we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than our liabilities. Under our bye-laws, each common share is entitled to dividends if, as and when dividends are declared by our board of directors, subject to any preferred dividend right of the holders of any preference shares, if any. Additionally, any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors and our shareholders, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. See “Item 3. Key Information—D. Risk factors—Risks related to our common shares—Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash 121 Table of Contents requirements, prospects and other factors” and “—We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us,” as well as “Item 10. Additional Information—B. Memorandum of association and bye-laws.” B. Significant changes A discussion of the significant changes in our business can be found under “Item 4. Information on the Company—B. Business Overview.” ITEM 9. THE OFFER AND LISTING A. Offering and listing details Not applicable. B. Plan of distribution Not applicable. C. Markets Our common shares have been listed on the NYSE under the symbol “GPRK” since February 7, 2014. D. Selling shareholders Not applicable. E. Dilution Not applicable. F. Expenses of the issue Not applicable. ITEM 10. ADDITIONAL INFORMATION A. Share capital Not applicable. B. Memorandum of association and bye-laws The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws. General We are an exempted company limited by shares incorporated under the laws of Bermuda. We are registered with the Registrar of Companies in Bermuda under registration number 33273. The rights of our shareholders will be governed by Bermuda law and by our memorandum of association and bye-laws. Bermuda company law differs in some material 122 Table of Contents respects from the laws generally applicable to Delaware corporations. Below is a summary of some of those material differences. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and to our shareholders. Share capital and bye-laws Our share capital consists of common shares only. Our authorized share capital consists of 5,171,949,000 common shares of par value US$0.001 per share. As of March 19, 2024, there are 55,470,850 common shares outstanding. All of our issued and outstanding common shares are fully paid and non-assessable. We also have an employee incentive program (LTIP Employees and LTIP Executives), pursuant to which we have granted share awards to our executive officers and employees. See “Item 6. Directors, Senior Management and Employees.” According to our bye-laws, if our share capital is divided into different classes of shares, the rights attached to any class (unless otherwise provided by the terms of issue of the shares of that class) may, whether or not the Company is being wound- up, be varied with the consent in writing of the holders of at least two-thirds of the issued shares of that class or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least, in person or by proxy, holding or representing one- third of the issued shares of the class. The rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further shares ranking pari passu therewith. Our bye-laws give our board of directors the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary. Common shares Holders of our common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Under our bye-laws, each common share is entitled to dividends, if, as and when dividends are declared by our board of directors, subject to any preferred dividend right of the holders of any preference shares, if any. Holders of common shares have no pre-emptive, redemption, conversion or sinking fund rights. In the event of our liquidation, dissolution or winding up the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares. Board composition Our bye-laws provide that the minimum number of directors shall be three or such other number as shall be determined from time to time by our board of directors. In addition, our bye-laws provide that our board of directors shall determine the maximum size of the board. As per the meeting of the board of directors of GeoPark Limited, which took place on May 10, 2022, the modification of the members of the board of directors was approved and it was determined that the maximum number of members will be nine. Therefore, the current number of members of the Board is nine. Election and removal of directors Our bye-laws provide that our directors shall hold office for such term as the shareholders shall determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. Directors whose term has expired may offer themselves for re-election at each election of the directors. A director may be removed by the shareholders at any special general meeting by a resolution adopted by 65% or more of the votes cast at the meeting, provided that notice of the shareholders meeting convened to remove the director is given to the director. The notice must contain a statement of the intention to remove the director and must be served on 123 Table of Contents the director not less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the motion for his removal. In addition, our bye-laws provide that our board of directors may remove a director only for cause by the affirmative vote of at least three-quarters of the board of directors, provided that notice of any such meeting convened for the purpose of removing a director shall contain a statement of the intention to remove the director and must be served on the director not less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the motion for his removal. Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or her place or, in the absence of any such election, by the board of directors. Any other vacancy, including a newly created directorship due to an increase in the maximum number of directors on our board, may be filled by our board of directors. Proceedings of board of directors Our bye-laws provide that our business is to be managed and conducted by our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. The quorum necessary for the transaction of business at meetings of the board of directors shall be the presence of a majority of the board of directors from time to time. Our bye-laws also provide that resolutions unanimously signed by all directors are valid as if they had been passed at a meeting of the board duly called and constituted. Duties of directors The Companies Act authorizes the directors of a company, subject to its bye-laws, to exercise all powers of the company except those that are required by the Companies Act or the company’s bye-laws to be exercised by the shareholders of the company. Our bye-laws provide that our business is to be managed and conducted by our board of directors. Under Bermuda common law, members of a board of directors owe a fiduciary duty to the Company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly. This duty has the following essential elements: (1) a duty to act in good faith in the best interests of the company; (2) a duty not to make a personal profit from opportunities that arise from the office of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the purpose for which such powers were intended. The Bermuda Companies Act also imposes a duty on directors (and officers) of a Bermuda company, to act honestly and in good faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Companies Act imposes various duties on directors (and officers) of a company with respect to certain matters of management and administration of the company. Under Bermuda law, directors (and officers) generally owe fiduciary duties to the company itself, not to the company’s individual shareholders, creditors or any class thereof. The Companies Act provides that in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit. By comparison, under Delaware law, the business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees. The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears the burden of rebutting the presumptions afforded to directors by the “business judgment rule.” If the presumption is not rebutted, the business 124 Table of Contents judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing, Delaware courts subject directors’ conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation. Interested directors Pursuant to our bye-laws, a director shall declare the nature of his interest in any contract or arrangement with the company as required by the Companies Act. A director so interested shall not, except in particular circumstances set out in our bye-laws, be entitled to vote or be counted in the quorum at a meeting in relation to any resolution in which he has an interest, which is to his knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of the company). A director will be liable to us for any secret profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director’s relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit. Indemnification of directors and officers Section 98 of the Companies Act provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favour or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Companies Act. We have adopted provisions in our bye-laws that provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such director is not legally entitled. Our bye-laws provide that the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company’s directors for any act or failure to act in the performance of such director’s duties, except in respect of any fraud or dishonesty of such director. Section 98A of the Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director. We have purchased and maintain a directors’ and officers’ liability policy for such a purpose. Meetings of shareholders Under Bermuda law, the company is required to convene at least one general meeting of shareholders each calendar year (the “annual general meeting”). However, the members may by resolution waive this requirement, either for a specific year or period of time, or indefinitely. When the requirement has been so waived, any member may, on notice to the company, terminate the waiver, in which case an annual general meeting must be called. Bermuda law provides that a special general meeting of shareholders may be called by the board of directors of a company and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company carrying the right to vote at general meetings. Bermuda law also requires that shareholders be given at least five days' advance notice of a general meeting, but the accidental omission to give notice to any person does not invalidate the proceedings at a meeting. Our bye-laws provide that our board of directors may convene an annual general meeting or a special general meeting. Under our bye-laws, not less than fifteen nor more than sixty days' notice of an annual general meeting or a special general meeting must be given to each shareholder entitled to vote at such meeting. This notice requirement is subject to the ability 125 Table of Contents to hold such meetings on shorter notice if such notice is agreed: (i) in the case of an annual general meeting by all of the shareholders entitled to attend and vote at such meeting; or (ii) in the case of a special general meeting by a majority in number of the shareholders entitled to attend and vote at the meeting holding not less than 95% in nominal value of the shares entitled to vote at such meeting. The quorum required for a general meeting of shareholders is two or more persons present in person and representing in person or by proxy in excess of 50% of the total issued voting shares in the Company throughout the meeting, provided that if the Company shall at any time have only one shareholder, one shareholder present in person or by proxy shall form the quorum. Unless otherwise required by law or by our bye-laws, shareholder action requires a resolution adopted by the affirmative votes of a majority of votes cast by shareholders at a general meeting at which a quorum is present. Shareholder proposals Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group composed of at least 100 shareholders may require a proposal to be submitted to an annual general meeting of shareholders by giving a requisition in writing to the company. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide (among other things) advance notice, as set out in our bye-laws. Shareholders may only propose a person for election as a director at an annual general meeting. Shareholder action by written consent Our bye-laws provide that, except for the removal of auditors and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by the shareholders through the unanimous written consent of all the shareholders who would be entitled to vote on the matter at the general meeting. Amendment of memorandum of association and bye-laws Our memorandum of association and bye-laws may be amended with the approval of a majority of our board of directors and by a resolution by a majority of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under Bermuda law, the holders of an aggregate of not less than 20% in par value of the company's issued share capital or any class thereof have the right to apply to the Supreme Court of Bermuda for an annulment of any amendment of the memorandum of association adopted by shareholders at any general meeting, other than an amendment which alters or reduces a company's share capital as provided in the Companies Act. Where such an application is made, the amendment becomes effective only to the extent that it is confirmed by the Bermuda court. An application for an annulment of an amendment of the memorandum of association must be made within twenty-one days after the date on which the resolution altering the company's memorandum of association is passed and may be made on behalf of persons entitled to make the application by one or more of their number as they may appoint in writing for the purpose. No application may be made by shareholders voting in favour of the amendment. Business combinations The amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Under the Companies Act, unless the company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass a resolution to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation or merger will require the approval of our board of directors and of our shareholders by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value 126 Table of Contents has been offered for such shareholder’s shares may, within one month of the notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the value of those shares. Our bye-laws provide that the directors shall manage the business of the Company and may exercise all such powers as are not, by the Companies Act or by the bye-laws, required to be exercised by the Company in general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise all the powers of the Company including, but not by way of limitation, the power to borrow money and to mortgage or charge all or any part of the undertaking property and assets (present and future) and uncalled capital of the Company and to issue debentures and other securities, whether outright or as security for any debt, liability or obligation of the Company or any third party. Compulsory Acquisition of Shares Held by Minority Holders An acquiring party is generally able to acquire compulsorily the common shares of minority holders in the following ways: (1) By a procedure under the Companies Act 1981 known as a “scheme of arrangement”. A scheme of arrangement could be effected by obtaining the agreement of the company and of holders of common shares, representing in the aggregate a majority in number and at least 75% in value of the common shareholders present and voting at a court ordered meeting held to consider the scheme of arrangement. The scheme of arrangement must then be sanctioned by the Bermuda Supreme Court. If a scheme of arrangement receives all necessary agreements and sanctions, upon the filing of the court order with the Registrar of Companies in Bermuda, all holders of common shares could be compelled to sell their shares under the terms of the scheme of arrangement. (2) If the acquiring party is a company it may compulsorily acquire all the shares of the target company, by acquiring pursuant to a tender offer 90% of the shares or class of shares not already owned by, or by a nominee for, the acquiring party (the offeror), or any of its subsidiaries. If an offeror has, within four months after the making of an offer for all the shares or class of shares not owned by, or by a nominee for, the offeror, or any of its subsidiaries, obtained the approval of the holders of 90% or more of all the shares to which the offer relates, the offeror may, at any time within two months beginning with the date on which the approval was obtained, require by notice any nontendering shareholder to transfer its shares on the same terms as the original offer. In those circumstances, nontendering shareholders will be compelled to sell their shares unless the Supreme Court of Bermuda (on application made within a one-month period from the date of the offeror's notice of its intention to acquire such shares) orders otherwise. (3) Where one or more parties holds not less than 95% of the shares or a class of shares of a company, such holder(s) may, pursuant to a notice given to the remaining shareholders or class of shareholders, acquire the shares of such remaining shareholders or class of shareholders. When this notice is given, the acquiring party is entitled and bound to acquire the shares of the remaining shareholders on the terms set out in the notice, unless a remaining shareholder, within one month of receiving such notice, applies to the Supreme Court of Bermuda for an appraisal of the value of their shares. This provision only applies where the acquiring party offers the same terms to all holders of shares whose shares are being acquired. Dividends and repurchase of shares Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than its liabilities. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due. Shareholder suits Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company 127 Table of Contents to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they may have, both individually and on our behalf, against any director in relation to any action or failure to take action by such director, including the breach of any fiduciary duty by a director, except in respect of any fraud or dishonesty of such director or to recover any gain, personal profit or advantage to which such director is not legally entitled. Comparison of Bermuda law to Delaware corporate law Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders. Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by our memorandum of association and bye-laws and Bermuda company law. The provisions of the Companies Act, which applies to us, differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Our shareholders approved the adoption of our bye-laws with effect on February 19, 2014, and amended with effect on July 15, 2021. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders. Interested Directors. Under our bye-laws and the Companies Act, a director shall declare the nature of his interest in any contract or arrangement with the company. Our bye-laws further provide that a director so interested shall not, except in particular circumstances, be entitled to vote or be counted in the quorum at a meeting in relation to any resolution in which he has an interest, which is to his knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of the company). A director will be liable to us for any secret profit realized from the transaction. See “Item 10—B. Memorandum of association and bye-laws—Interested directors.” Amalgamations, Mergers and Similar Arrangements. Pursuant to the Companies Act, the amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliates) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Under our bye-laws, an amalgamation or merger will require the approval of our board of directors and our shareholders by Special Resolution, which is a resolution adopted by 65% of more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. The quorum for any such general meeting must be two or more persons, in person or by proxy, representing more than one-third of the issued shares of the company. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholders shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the 128 Table of Contents amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction. Shareholders’ Suit. Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. See “Item 10—B. Memorandum of association and bye-laws— Shareholder suits.” Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they might have, individually or in the right of the company, against any director for any act or failure to act in performance of such director’s duties, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or to recover any gain, personal profit or advantage to which such director is not legally entitled. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action. Indemnification of Directors. We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. See “Item 10—B. Memorandum of association and bye-laws—Enforcement of Judgments.” Our bye-laws provide that we shall indemnify our officers and directors in respect of their acts and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such Director is not legally entitled, and (by incorporation of the provisions of the Companies Act) that we may advance money to our officers and directors for the costs, charges and expenses incurred by our officers and directors in defending any civil or criminal proceedings against them on condition that the directors and officers repay the money if any allegations of fraud or dishonesty is proved against them provided, however, that, if the Companies Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking, by or on behalf of such indemnitee, to repay all amounts if it shall ultimately be determined by final judicial decision that such indemnitee is not entitled to be indemnified for such expenses under our bye-laws or otherwise. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors. As a result of these differences, investors could have more difficulty protecting their interests than would shareholders of a corporation incorporated in the United States. Tax matters. Under current Bermuda law, we are not subject to tax on income or capital gains in Bermuda. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035, except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda. On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of the last four fiscal years beginning on or after January 1, 2025. We are incorporated in Bermuda as an exempted company and pay annual Bermuda government fees. In addition, all entities employing individuals in Bermuda 129 Table of Contents are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. Neither we nor our Bermuda subsidiaries employ individuals in Bermuda as at the date of this annual report. Access to books and records and dissemination of information Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company’s memorandum of association, including its objects and powers, and certain alterations to the memorandum of association. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings and the company’s audited financial statements, which must be presented to the annual general meeting. The register of members of a company is also open to inspection by shareholders and by members of the general public without charge. The register of members is required to be open for inspection for not less than two hours in any business day (subject to the ability of a company to close the register of members for not more than thirty days in a year). A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Companies Act, establish a branch register outside of Bermuda. A company is required to keep at its registered office a register of directors and officers that is open for inspection for not less than two hours in any business day by members of the public without charge. A company is also required to file with the Registrar of Companies in Bermuda a list of its directors to be maintained on a register, which register will be available for public inspection subject to such conditions as the Registrar may impose and on payment of such fee as may be prescribed. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records. Registrar or transfer agent A register of holders of the common shares is maintained by Conyers Corporate Services (Bermuda) Limited in Bermuda, and a branch register is maintained in the United States by Computershare Trust Company, N.A., who serves as branch registrar and transfer agent. Enforcement of Judgments We are incorporated as an exempted company limited by shares under the laws of Bermuda, and substantially all of our assets are located in Colombia, Ecuador, Brazil and Argentina. In addition, most of our directors and executive officers reside outside the United States, and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws. There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. However, the courts of Bermuda would recognize any final and conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct procedures under the laws of Bermuda. An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, may not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, may not be available under Bermuda law or enforceable in a Bermuda court, as they may be contrary to Bermuda public policy. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violations of U.S. federal securities laws because these laws have no extraterritorial jurisdiction under Bermuda law and do not have force of law in Bermuda. A Bermuda court may, however, impose civil liability on us or our directors and officers if the 130 Table of Contents facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. However, section 281 of the Companies Act allows a Bermuda court, in certain circumstances, to relieve officers and directors of Bermuda companies of liability for acts of negligence, breach of duty or trust or other defaults. C. Material contracts See “Item 4. Information on the Company—B. Business Overview—Significant Agreements.” D. Exchange controls Not applicable. E. Taxation The following summary contains a description of certain Bermudian, U.S. federal income, Colombian and Chilean tax consequences of the acquisition, ownership and disposition of our common shares. The summary is based upon the tax laws of Bermuda, the United States, Colombia and Chile, and regulations thereunder as of the date hereof, which are subject to change. Bermuda tax consideration At the date of this annual report, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our common shares. On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of the last four fiscal years beginning on or after January 1, 2025. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our common shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda. Material U.S. federal income tax considerations The following is a description of the material U.S. federal income tax consequences to U.S. Holders (as defined below) of owning and disposing of our common shares. This discussion is not a comprehensive description of all tax considerations that may be relevant to a particular person’s decision to hold our common shares. This discussion applies only to a U.S. Holder that holds our common shares as capital assets for tax purposes. In addition, it does not describe all of the tax consequences that may be relevant in light of the U.S. Holder’s particular circumstances, including alternative minimum tax and Medicare contribution tax consequences and differing tax consequences applicable to a U.S. Holder subject to special rules, such as: ● certain financial institutions; ● a dealer or trader in securities who uses a mark-to-market method of tax accounting; ● a person holding common shares as part of a straddle, wash sale or conversion transaction or entering into a constructive sale with respect to the common shares; ● a person whose functional currency for U.S. federal income tax purposes is not the U.S. dollar; ● a partnership or other entities classified as partnerships for U.S. federal income tax purposes; 131 Table of Contents ● a tax-exempt entity, including an “individual retirement account” or “Roth IRA;” ● a person that owns or is deemed to own 10% or more of our shares by vote or value; ● a person who acquired our shares pursuant to the exercise of an employee stock option or otherwise as compensation; or ● a person holding common shares in connection with a trade or business conducted outside of the United States. If an entity that is classified as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships holding common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares. This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date hereof, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances. A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal income tax purposes that is: · · · a citizen or individual resident of the United States; a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source. This discussion assumes that we are not, and will not become, a passive foreign investment company, as described below. Taxation of distributions Distributions paid on our common shares, other than certain pro rata distributions of common shares, will generally be treated as dividends to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions will generally be reported to U.S. Holders as dividends. Subject to the passive foreign investment company rules described below, dividends paid by qualified foreign corporations to certain non-corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the NYSE where our common shares are traded. Non-corporate U.S. Holders should consult their tax advisers to determine whether the favorable rate will apply to dividends they receive and whether they are subject to any special rules that limit their ability to be taxed at this favorable rate. A dividend generally will be included in a U.S. Holder’s income when received, will be treated as foreign-source income to U.S. Holders and will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code with respect to dividends paid by domestic corporations. Sale or other taxable disposition of common shares Gain or loss realized on the sale or other taxable disposition of our common shares will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder held our common shares for more than one year. Long-term capital 132 Table of Contents gain of a non-corporate U.S. Holder is generally taxed at preferential rates. The deductibility of capital losses is subject to limitations. The amount of the gain or loss will equal the difference between the U.S. Holder’s tax basis in the common shares disposed of and the amount realized on the disposition. If a non-U.S. tax is withheld on the sale or disposition of common shares, a U.S. Holder’s amount realized will include the gross amount of the proceeds of the sale or disposition before deduction of the non-U.S. tax. Gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. U.S. Holders should consult their tax advisers as to whether the non-U.S. tax on gains may be creditable against the U.S. Holder’s U.S. federal income tax on foreign-source income from other sources. The rules governing foreign tax credits are complex. For example, under applicable Treasury regulations, in the absence of an election to apply the benefits of an applicable income tax treaty, in order for a non-U.S. income tax to be creditable, the foreign jurisdiction’s income tax rules must be consistent with certain U.S. federal income tax principles, and we have not determined whether the Chilean or Colombian income tax system meets all these requirements. The IRS has released notices that provide relief from certain of the provisions of the Treasury regulations described above for taxable years ending before the date that a notice or other guidance withdrawing or modifying the temporary relief is issued (or any later date specified in such notice or other guidance). With regards to the possible application of the Chilean or Colombian tax on transfers of shares, described under "—Chilean tax on transfers of shares" and "—Colombian tax on transfers of shares" below, respectively, you generally will not be entitled to claim a foreign tax credit for any Chilean or Colombian taxes imposed on gains from taxable dispositions of our common shares (although it is possible that such taxes may reduce the amount realized on the disposition). The US-Chile income tax treaty and accompanying protocol (together, the “Treaty”) entered into force on December 19, 2023. If you qualify for the benefits of the Treaty, with respect to taxes withheld at source, the Treaty will have effect for amounts paid or credited on or after February 1, 2024. For all other taxes, the Treaty will have effect for taxable periods beginning on or after January 1, 2024. The rules governing foreign tax credits and the application of the Treaty are complex and, therefore, you should consult your own tax adviser regarding the creditability or deductibility of any Chilean or Colombian tax on disposition gains (including any applicable limitations) and the determination of the amount realized in your particular circumstances. Passive foreign investment company rules We believe that we were not a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes for 2023, and we do not expect to be a PFIC in the foreseeable future. However, because the composition of our income and assets will vary over time, there can be no assurance that we will not be a PFIC for any taxable year. The determination of whether we are a PFIC is made annually and is based upon the composition of our income and assets (including the income and assets of, among others, entities in which we hold at least a 25% interest), and the nature of our activities. If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would generally be allocated ratably over the U.S. Holder’s holding period for the common shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations for that year, as appropriate, and an interest charge would be imposed on the tax on such amount. Further, to the extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, that distribution would be subject to taxation in the same manner as gain, as described immediately above. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of our common shares. U.S. Holders should consult their tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances. Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were treated as a PFIC for the taxable year in which we paid a dividend or the prior taxable year, the preferential dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply. 133 Table of Contents Information reporting and backup withholding Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries generally are subject to information reporting, and may be subject to backup withholding, unless (1) the U.S. Holder is a corporation or other exempt recipient or (2) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the Internal Revenue Service. Chilean tax on transfers of shares As provided in Decree Law No. 824 of 1974, income tax is triggered on the indirect transfer of shares, equity rights, interests or other rights in the equity, control or profits of a Chilean entity as well as transfers of other assets and property of permanent establishments or other businesses in Chile. Reforms introduced in 2014 imposed a measure which obliges the company from which shares are transferred to pay taxes if the entity which undertakes the transfer of shares fails to do so. The indirect transfer rules apply to sales of shares of an entity: ● If such entity is an offshore holding company located in a black-listed tax haven jurisdiction as determined by Chilean tax law, or a black-listed jurisdiction, (such as Bermuda) that holds Chilean Assets; and either a Chilean resident holds 5% or more of such entity, or such entity’s rights to equity, control or profits, or 50% or more of such entity’s rights to equity or profits are held by residents in black-listed jurisdictions; or ● the shares or rights transferred represent 10% or more of the offshore holding company (considering dispositions by related persons and over the preceding 12-month period) and the underlying Chilean Assets indirectly transferred, in the proportion indirectly owned by the seller, (a) are valued in an amount equal to or higher than UTA 210,000 (approximately US$200 million) (adjusted by the Chilean inflation unit of reference) or (b) represent 20% or more of the market value of the interest held by such seller in such offshore holding company. Based on information available to us, (i) no Chilean resident holds 5% or more of our rights to equity, control or profits; (ii) residents in black-listed jurisdictions do not hold 50% or more of our rights to equity, control or profits; (iii) the Chilean Assets are not valued at more than UTA 210,000; and (iv) the Chilean Assets do not represent 20% or more of the market value of the offshore holding companies. Therefore, we do not believe the indirect transfer rules will apply to transfers of our common shares, unless the shares or rights transferred represent 10% or more of the company and the other conditions described above are met (considering dispositions by related persons and over the preceding 12-month period). However, there can be no assurance that, at any time in the future, a Chilean resident will not hold 5% or more of our rights to equity, control or profits or that residents in black-listed jurisdictions will not hold 50% or more of our rights to equity, control or profits. If this were to occur, all sales of our common shares would be subject to the indirect transfer tax referred to above. Our expectations regarding the indirect transfer rules are based on our understandings, analysis and interpretation of these enacted indirect transfer rules, which are subject to additional interpretation and rule-making by the Chilean authorities. As such, there is uncertainty relating to the application by Chilean authorities of the indirect transfer rules on us. Colombian tax on transfers of shares In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax set in article 90-3 of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad are 134 Table of Contents taxed in Colombia when such transaction represents a transfer of underlying assets located in Colombia. The latter applies unless (i) shares transferred are listed on a stock exchange recognized by the Colombian Government and no more than 20% of such shares are owned by a single beneficiary; or (ii) the value of assets indirectly transferred represents less than 20% of book and/or fair market value of all assets owned by the non-resident entity transferor. For income tax purposes, indirect transfer shall be assessed at fair market value of the Colombian underlying assets and the relevant tax basis is the one held in the underlying Colombian asset, which should be calculated based on the Colombian Tax Code rules. When the underlying assets are held by a Colombian branch, any taxable base determined shall be allocated first to amortization/depreciation recapture taxed as ordinary income. When a subsequent indirect transfer is made, the tax basis of the underlying Colombian assets corresponds to the purchase price paid and allocated to the underlying Colombian assets. However, Decree 1103 clarifies that the tax basis of the entity owning the underlying asset in Colombia is not stepped up. See “Item 3. Key Information—D. Risk Factors—Risks related to our common shares—The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia.” F. Dividends and paying agents Not applicable. G. Statement by experts Not applicable. H. Documents on display We are subject to the informational requirements of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC maintains an Internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. I. Subsidiary information Not applicable. ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK We are exposed to a variety of market risks, including commodity price risk, interest rate risk, currency risk and credit (counterparty and customer) risk. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates. For further information on our market risks, please see Note 3 to our Consolidated Financial Statements. ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES A. Debt securities Not applicable. B. Warrants and rights Not applicable. 135 Table of Contents C. Other securities Not applicable. D. American Depositary Shares Not applicable. ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES PART II A. Defaults No matters to report. B. Arrears and delinquencies No matters to report. ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS Not applicable. ITEM 15. CONTROLS AND PROCEDURES A. Disclosure Controls and Procedures As of December 31, 2023, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), which are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives. Based on such evaluation, our Chief Executive Officer and Chief Financial Officer, with assistance from other members of management, have concluded that the disclosure controls and procedures were not effective as of such date due to a material weakness in internal control over financial reporting, described below. B. Management’s Annual Report on Internal Control over Financial Reporting Our management is responsible for establishing and maintaining an adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act. Our internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers, management and other personnel, to provide reasonable assurance regarding the 136 Table of Contents reliability of financial reporting and the preparation of our financial statements for external reporting purposes, in accordance with generally accepted accounting principles. These include those policies and procedures that: ● pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; ● 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 are being made only in accordance with authorization of our management and directors; and ● provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. its inherent limitations, Because of internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projections of, and any evaluation of effectiveness of the internal controls in 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. Under the supervision and with the participation of our management, including our Chief Executive Officer, our Chief Financial Officer, and our Chief Strategy, Sustainability and Legal Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2023, based on the criteria established in Internal Control - Integrated Framework of the Committee of Sponsoring Organizations of the Treadway Commission (2013). We identified a material weakness in internal control related to ineffective information technology general controls (ITGCs) over the timely removal of user access upon personnel termination. Our business process controls (both automated and manual) that are dependent on the affected ITGCs were also deemed ineffective because they could have been adversely impacted, as we do not have any compensatory control upon the outgoing employees in our ITGC matrix. We believe that these control deficiencies were a result of (i) IT control processes lacking sufficient documentation such that the successful operation of ITGCs was overly dependent upon knowledge and actions of certain individuals with IT expertise, (ii) insufficient training of IT personnel on the importance of ITGCs, and (iii) inadequate risk-assessment processes for the identification and assessment of changes in IT environments that could impact internal control over financial reporting. Based on this material weakness, we have concluded that as of December 31, 2023, our internal control over financial reporting was not effective. Notwithstanding, we have also concluded that the material weakness did not result in any identified misstatements to the consolidated financial statements, and there were no changes to previously released financial results. Following identification of the material weakness and prior to filing this annual report on Form 20-F, we completed substantive procedures for the year ended December 31, 2023. Based on these procedures, management believes that our consolidated financial statements included in this annual report have been prepared in accordance with International Financial Reporting Standards as issued by the International Accounting Standards Boards. Our Chief Executive Officer and Chief Financial Officer have certified that, based on their knowledge, the consolidated financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Company as of, and for, the periods presented in this annual report. Ernst & Young Audit S.A.S. has issued an unqualified opinion on our consolidated financial statements. See pages F-2 to F-3 of this annual report. Remediation Management has been implementing and continues to implement measures designed to ensure that control deficiencies contributing to the material weakness are remediated, such that these controls are designed, implemented, and operating effectively. The remediation actions include: (i) developing a training program addressing ITGCs and related policies, including educating control owners on the principles and requirements of each control, with a focus on those related to user access over IT systems impacting financial reporting; (ii) developing and maintaining documentation underlying ITGCs to promote knowledge transfer upon personnel and function changes; (iii) implementing an IT management review and testing plan to monitor ITGCs with a specific focus on timely removal of user access to applications systems supporting 137 Table of Contents our financial reporting processes upon personnel termination; and (iv) enhanced quarterly reporting on the remediation measures to the Audit Committee of the board of directors. As of the date of this annual report, we are implementing remediation actions and we believe that these remediation actions will remediate the material weakness. However, the weakness 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. We expect that the remediation of this material weakness will be completed prior to the end of 2024. C. Attestation Report of the Registered Public Accounting Firm The effectiveness of the Company’s internal control over financial reporting as of December 31, 2023, has been audited by independent registered public accounting firm, Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited). Ernst & Young Audit S.A.S., has issued an audit report on the effectiveness of the Company’s internal control over financial reporting as of December 31, 2023. See pages F-4 to F-5 of this annual report. D. Changes in Internal Control over Financial Reporting Except for the material weakness identified and the ongoing implementation of remediation actions as described above, there have been no changes in the Company’s internal control over financial reporting that occurred during the year ended December 31, 2023, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting. ITEM 16. RESERVED ITEM 16A. Audit committee financial expert We have determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou and Ms. Sylvia Escovar are independent, as such term is defined under SEC rules applicable to foreign private issuers. In addition, Mr. Robert Bedingfield and Ms. Sylvia Escovar are regarded as audit committee financial experts. ITEM 16B. Code of Conduct We have adopted a code of conduct applicable to the board of directors and all employees. Since its effective date on September 24, 2012, we have not waived compliance with or amended the code of conduct. The code of conduct is available at the Company’s website. ITEM 16C. Principal Accountant Fees and Services Our independent registered public accounting firm is Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited), beginning with the audit of the year ended December 31, 2023. In 2022, and from 2020, our independent registered public accounting firm was Pistrelli, Henry Martin y Asociados S.R.L. (member of Ernst & Young Global Limited). See “ITEM 16F. Change in registrant’s certifying accountant”. The following table provides detail in respect of audit, audit related, tax and other fees billed by the independent registered public accounting firm and other member firms of Ernst & Young Global Limited for professional services: Audit fees Audit related fees Tax services fees Total 138 2023 2022 (in millions of US$) 0.98 0.03 — 1.01 0.94 0.02 0.03 1.00 Table of Contents Fees are shown net of VAT and other associated tax charges. Audit Fees Audit fees are fees billed for professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for those fiscal years. It includes the audit of our Consolidated Financial Statements and other services that generally only the independent accountant reasonably can provide, such as statutory audits. Audit-Related Fees Audit-related fees are fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our Consolidated Financial Statements and not reported under the previous category. These services would include, among others: comfort letters, consents and assistance with and review of documents, accounting consultations and audits in connection with acquisitions, attestation of services that are not required by statue or regulation and consultation concerning financial accounting and reporting standards. Tax Fees Tax fees are fees billed for professional services for tax compliance, tax advice and tax planning. Pre-Approval Policies and Procedures Following the listing of our common shares on the NYSE, the Audit Committee proposes the appointment of the independent auditor to the board of directors to be put to shareholders for approval at the Annual General meeting. The Audit Committee oversees the auditor selection process for new auditors and ensures key partners in the appointed firm are rotated in accordance with best practices. Also, following our NYSE listing, the Audit Committee is required to pre-approve the audit and non-audit fees and services performed by the Company’s auditors in order to be sure that the provision of such services does not impair the audit firm’s independence. All of the audit fees, audit-related fees and tax fees described in this item 16C have been approved by the Audit Committee. ITEM 16D. Exemptions from the listing standards for audit committees None. ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers. We have recurring programs to repurchase our own shares. The latest renewal took place on November 8, 2023, and established a program to repurchase up to 10% of our shares outstanding, or approximately 5,611,797 shares, until December 31, 2024. In addition to any repurchases under the aforementioned repurchase program, the company has authority from its board to repurchase, on a standalone basis, up to US$50 million of our common shares in 2024. 139 Table of Contents The following table presents purchases of our common shares by the company and “affiliated purchasers” (as that term is defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended) during 2023: 2023 January 3, 2023 February 6 to February 28, 2023 March 1 to March 31, 2023 April 4 to April 28, 2023 May 1 to May 30, 2023 June 2 to June 20, 2023 September 12 to September 22, 2023 November 21, 2023 December 14, 2023 Total Number of Shares Purchased 40,000 80,826 521,222 201,305 371,936 508,534 499,765 340,000 510,000 Average Price Paid per Share 14.17 12.77 11.38 11.21 10.30 9.84 9.91 9.49 8.60 ITEM 16F. Change in registrant’s certifying accountant Total Number of Maximum Number (or Shares Purchased as Approximate Dollar Value) of Part of Publicly Announced Plans or Programs Shares that May Yet be Purchased Under the Plans or Programs 40,000 80,826 521,222 201,305 371,936 508,534 499,765 340,000 510,000 5,010,359 shares 4,929,533 shares 4,408,311 shares 4,207,006 shares 3,835,070 shares 3,326,536 shares 2,826,771 shares 5,271,797 shares 4,761,797 shares On October 17, 2023, Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited) was appointed as our independent registered public accounting firm, effective for the consolidated audit for the year ended December 31, 2023, succeeding Pistrelli, Henry Martin y Asociados S.R.L. (member of Ernst & Young Global Limited), our former independent registered public accounting firm. The change of our independent registered public accounting firm was made at the request of the Audit Committee, after careful consideration and evaluation process and was approved by the Audit Committee. Pistrelli, Henry Martin y Asociados S.R.L. has served as our independent registered public accounting firm since 2020. Pistrelli, Henry Martin y Asociados S.R.L.’s audit reports on our consolidated financial statements as of and for the past two fiscal years did not contain an adverse opinion or disclaimer of opinion and were not qualified or modified as to uncertainty, audit scope, or accounting principles. In connection with the audits of the Company's financial statements for each of the two fiscal years ended December 31, 2022, and in the subsequent interim periods through September 29, 2023, there has been (i) no disagreements (as defined in Item 16F(a)(1)(iv) of Form 20-F and the related instructions thereto) between us and Pistrelli, Henry Martin y Asociados S.R.L. on any matter of accounting principles or practices, financial statement disclosure, or auditing scope or procedure, which disagreements, if not resolved to the satisfaction of Pistrelli, Henry Martin y Asociados S.R.L., would have caused Pistrelli, Henry Martin y Asociados S.R.L. to make reference to the subject matter in their report. During the two most recent fiscal years ended December 31, 2022, and in the subsequent interim period prior to the engagement of Ernst & Young Audit S.A.S. on October 17, 2023, neither we nor anyone acting on our behalf consulted with Ernst & Young Audit S.A.S. regarding either (i) the application of accounting principles to a specified transaction, either completed or proposed, or the type of audit opinion that might be rendered on our consolidated financial statements, and neither a written report nor oral advice was provided to us that Ernst & Young Audit S.A.S. concluded was an important factor considered by us in reaching a decision as to any accounting, audit or financial reporting issue, (ii) any matter that was the subject of a disagreement pursuant to Item 16F(a)(1)(iv) of Form 20-F and the related instructions thereto, or (iii) any reportable event pursuant to Item 16F(a)(1)(v) of Form 20-F. We have provided Pistrelli, Henry Martin y Asociados S.R.L. with a copy of this Item 16F and have requested and received from Pistrelli, Henry Martin y Asociados S.R.L. a letter addressed to the SEC stating whether or not Pistrelli, Henry Martin y Asociados S.R.L. agrees with the above statements. A copy of the letter from Pistrelli, Henry Martin y Asociados S.R.L. is attached as Exhibit 15.4 to this annual report. 140 Table of Contents ITEM 16G. Corporate governance Our common shares are listed on the NYSE. We are therefore required to comply with certain of the NYSE’s corporate governance listing standards (the “NYSE Standards”). As a foreign private issuer, we may follow our home country’s corporate governance practices in lieu of most of the NYSE Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary of those differences is provided as follows. Director independence The NYSE Standards require a majority of the membership of NYSE-listed company boards to be composed of independent directors. Neither Bermuda law, the law of our country of incorporation, nor our memorandum of association or bye-laws require a majority of our board to consist of independent directors. At the date of this annual report, 67% of our board of directors is independent. Non-management directors’ executive sessions The NYSE Standards require non-management directors of NYSE-listed companies to meet at regularly scheduled executive sessions without management. Our memorandum of association and bye-laws do not require our non-management directors to hold such meetings. Committee member composition The NYSE Standards require domestic NYSE-listed companies to have a nominating/corporate governance committee and a compensation committee that are composed entirely of independent directors. Bermuda law, the law of our country of incorporation, does not impose similar requirements. Independence of the compensation committee and its advisers On January 11, 2013, the SEC approved NYSE listing standards that require that the board of directors of a domestic listed company consider two factors (in addition to the existing general independence tests) in the evaluation of the independence of compensation committee members: (i) the source of compensation of the director, including any consulting, advisory or other compensatory fees paid by the listed company, and (ii) whether the director has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. In addition, before selecting or receiving advice from a compensation consultant or other adviser, the compensation committee of a listed company will be required to take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence. Foreign private issuers, such as us, will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we will not be required to implement the NYSE listing standards relating to compensation committees of domestic listed companies. All of the members of our compensation committee are independent, and the charter of our compensation committee does not require the compensation committee to consider the independence of any advisers that assist them in fulfilling their duties. Additional audit committee functions The NYSE Standards require that audit committees of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements, engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these procedures. Finally, audit 141 Table of Contents committees are responsible for designing and implementing an internal audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis. Foreign private issuers such as us are exempt from these additional requirements if home country practice is followed. Bermuda law does not impose similar requirements, and consequently, our audit committee does not perform these additional functions. Our Audit Committee is composed exclusively of independent members. Miscellaneous In addition to the above differences, we are not required to: make our audit and compensation committees prepare a written charter that addresses either purposes and responsibilities or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity compensation plans in certain cases; or adopt and make publicly available corporate governance guidelines. We are incorporated under, and are governed by, the laws of Bermuda. For a summary of some of the differences between provisions of Bermuda law applicable to us and the laws applicable to companies incorporated in Delaware and their shareholders, See “Item 10. Additional Information—B. Memorandum of association and bye-laws.” ITEM 16H. Mine safety disclosure Not applicable. ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections Not applicable. ITEM 16J. Insider trading policies Not applicable. ITEM 16K. Cybersecurity GeoPark prioritizes cybersecurity risk management as an integral part of our overall enterprise risk management model. Our cybersecurity risk management practices provide a framework for handling cybersecurity threats and incidents and facilitating coordination across our different departments. Beginning in 2022, we successfully implemented the NIST framework and established a 24/7 Security Operations Center, reinforcing our commitment to cybersecurity. This framework includes: the following measures: (i) the inventory and prioritization of each of the assets connected to the GeoPark network, (ii) the implementation and assessment of the effectiveness of the necessary controls to protect such assets against cyber threats, (iii) the 24/7 monitoring of cyber threats and the status of the relevant assets, (iv) the implementation and testing of processes for the mitigation and/or containment of cyberattacks, (v) cyber-incident management process, and (vi) a recovery plan, should a cyberattack materialize, that minimizes the impact of such cyberattack on the operations of the company. Under the NIST framework, we address possible cybersecurity threats associated with third-party service providers by identifying the dependence of our operations on third-party service providers. We have established cybersecurity requirements for the provision of services and/or the integration of infrastructures, which are included in the corresponding contractual documentation with third-party service providers. Additionally, we require our third-party service providers to deliver periodic information on compliance with said requirements. In 2023, we reinforced our defenses against cyber threats by enhancing our cybersecurity capabilities with the onboarding of a new Information Security Manager and creation of an operational security management team. Additionally, we optimize our platforms using industry-leading protection systems, such as Crowd Strike, Palo Alto firewalls, Multifactor Authentication, Microsoft Defense, Darktrace, Tanium, DNA Center, Umbrella, GRC, and 142 Table of Contents SDWAN. To strengthen our technology infrastructure and enhance data protection practices, we developed a site recovery solution for critical applications, involving redundant systems in different geographical locations and intercloud backups across multiple service providers. Our board of directors has overall oversight responsibility for our risk management and delegates cybersecurity risk management oversight to the Audit Committee. In this capacity, the Audit Committee reviews and reports to the full board regarding cybersecurity risks and plans to ensure management has processes in place to identify, evaluate and mitigate cybersecurity risks. Management is responsible for ongoing risk assessment, monitoring and maintaining cybersecurity programs, a process led by our corporate IT Director with the support of our Information Security Manager. Our IT Director and Information Security Manager regularly update the Audit Committee on the company’s cybersecurity programs, risks, and mitigation strategies. Following our IT Director’s decision to voluntarily exit the company, effective as of February 29, 2024, we are currently in the process of recruiting a new IT Director with relevant cybersecurity experience and the IT Director’s responsibilities are being covered in an interim fashion by our Information Security Manager, who, while performing any such interim duties and until we onboard our new IT Director, will regularly report to our Chief Financial Officer. Our Information Security Manager holds a master’s degree in computer science and has worked for over 20 years in various information security and cybersecurity positions with increasing levels of responsibility. He also holds a broad range of cybersecurity- related certifications such as and among others: (i) Certified Information Systems Auditor (CISA), (ii) Certified Information Security Manager (CISM), and (iii) Certified in the Governance of Enterprise IT (CGEIT). In the event a cyberattack materializes, our cyber-incident management process is triggered and an interdisciplinary committee (which includes our IT Director, our Information Security Manager and the cybersecurity team) is convened. The interdisciplinary committee is charged with containing the cyberattack in the shortest possible time with the minimum possible impact to our operations. This process has an escalation matrix where, depending on the infrastructure and information compromised, management of the incident is scaled to specific roles in the company. Any material incidents are required to be reported by our IT Director and Information Security Manager to the Audit Committee and the board of directors. As part of our risk management process, we seek to determine if there are any risks that have not been identified or that have not been properly assessed. Accordingly, our IT team and the Information Security Manager conduct annual reviews that inventory, evaluate, and assess cybersecurity risks, including those related to third-party service providers, at both the information and operational infrastructure level. With the goal of having an independent judgment, we complement the internal annual review with the engagement of a third-party cybersecurity expert, with relevant expertise in these kind of methodologies, risk evaluations and mitigation plans design, who conducts ethical hacking exercises to test: (i) from an external viewpoint, the paths that an attacker could use to try to compromise our infrastructure and information by simulating the activity of an attacker using sophisticated tools and expertise, and (ii) from an internal viewpoint, our security operation center’s capability to detect and contain such simulated attack. Following the annual review described above, mitigation plans are generated by the Information Security Manager and approved by the IT director to remove any identified risks or bring them to acceptable levels. Once approved, the IT Director and the Information Security Manager present the mitigation plans to the Audit Committee. Furthermore, we also engage a third-party cybersecurity expert for purposes of conducting an annual audit which seeks to assess and evaluate the effectiveness of cybersecurity controls currently in place. The results of the annual audit are shared with our Audit Committee. As cyber-threats continue to evolve, we may be required to invest significant additional resources to continue modifying and enhancing our protective measures and to investigate and remediate any information security vulnerabilities. We have a cybersecurity insurance policy, and it acknowledges that evolving cyber-threats may require significant additional resources. In 2023, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations, or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats, or provide assurances that we have not experienced an undetected cybersecurity incident. For more information about these risks, please see “Risk Factors – Our business could be negatively impacted by cybersecurity threats and related disruptions.” in this annual report on Form 20-F. 143 Table of Contents ITEM 17. Financial statements We have responded to Item 18 in lieu of this item. ITEM 18. Financial statements PART III Financial Statements are filed as part of this annual report, see pages F-1 to F-73 to this annual report. ITEM 19. Exhibits 1.1 1.2 Exhibit no. Description Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1 2.1 2.3 1.4 2.2 1.3 2.4 4.1 (File No. 333-191068) filed with the SEC on September 9, 2013). Current bye-laws (incorporated herein by reference to Exhibit 1.3 to the Company’s Annual Report on Form 20-F filed with the SEC on March 31, 2021). Certificate of Incorporation on Name Change (incorporated herein by reference to Exhibit 1.4 to the Company’s Annual Report on Form 20-F filed with the SEC on March 31, 2021). Indenture dated January 17, 2020, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on April 1, 2020). First Supplemental Indenture dated August 25, 2021, among GeoPark Limited and GeoPark Colombia S.A.S. and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.6 to the Company’s Annual Report on Form 20-F filed with the SEC on March 31, 2022). Second Supplemental Indenture dated June 27, 2022, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on March 30, 2023). Description of Securities. * Exploration and Production Contract regarding exploration for and exploitation of hydrocarbons in the Llanos 34 Block, dated March 13, 2009, between the Colombian Agencia Nacional de Hidrocarburos and Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit 10.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013). Subsidiaries of GeoPark Limited.* Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.* Consent of Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited). * Consent of Pistrelli, Henry Martin y Asociados (member of Ernst & Young Global Limited). * Consents of DeGolyer and MacNaughton to use its report.* Letter of Pistrelli, Henry Martin y Asociados S.R.L., as required by Item 16F of Form 20-F.* Compensation Recoupment Policy. * Reserves Report of DeGolyer and MacNaughton dated March 1, 2024, for reserves in Brazil, Chile, Colombia and Ecuador as of December 31, 2023.* 101.INS Inline XBRL Instance Document* 101.SCH XBRL Taxonomy Extension Schema Document* 101.CAL XBRL Taxonomy Extension Calculation Linkbase Document* 101.DEF XBRL Taxonomy Extension Definition Linkbase Document* 101.LAB XBRL Taxonomy Extension Label Linkbase Document* 101.PRE XBRL Taxonomy Extension Presentation Linkbase Document* 8.1 12.1 12.2 13.1 13.2 15.1 15.2 15.3 15.4 97.1 99.1 104 104 Cover Page Interactive Data File (formatted in Inline XBRL and included in Exhibit 101) * Filed with this Annual Report on Form 20-F. 144 Table of Contents The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf. SIGNATURES GEOPARK LIMITED By: /s/ Andrés Ocampo Name: Andrés Ocampo Title: Chief Executive Officer and Director Date: March 27, 2024 145 Table of Contents INDEX TO CONSOLIDATED FINANCIAL STATEMENTS Audited Annual Consolidated Financial Statements—GeoPark Limited Reports of Independent Registered Public Accounting Firm: Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited) located in Bogota, Colombia. PCAOB ID No. 1522. Report of Independent Registered Public Accounting Firm: Pistrelli, Henry Martin y Asociados S.R.L. (member of Ernst & Young Global Limited) located in Buenos Aires, Argentina. PCAOB ID No. 1449. Consolidated Statement of Income and Comprehensive Income for the years ended December 31, 2023, 2022 and 2021. Consolidated Statement of Financial Position as of December 31, 2023 and 2022. Consolidated Statements of Changes in Shareholders’ Equity for the years ended December 31, 2023, 2022 and 2021. Consolidated Statements of Cash Flows for the years ended December 31, 2023, 2022 and 2021. Notes to the Audited Annual Consolidated Financial Statements. Page F-2 F-6 F-7 F-9 F-10 F-11 F-12 F-1 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of GeoPark Limited Opinion on the Financial Statements We have audited the accompanying consolidated statement of financial position of GeoPark Limited (the Company) as of December 31, 2023, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for the year then ended 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, 2023, and the results of its operations and its cash flows for the year then ended, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). 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, 2023, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 27, 2024 expressed an adverse opinion on the effectiveness of internal control over financial reporting. Basis for Opinion These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the 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 financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides 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 financial statements that was communicated or required to be communicated to the audit committee and that: (i) relates to accounts or disclosures that are material to the financial statements and (ii) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter 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. Impact of estimated proved and probable oil and gas reserves on the depreciation of oil and gas properties Description of the Matter As discussed in Note 2.11, the proved and probable reserves are used by the Company in the depreciation of the capitalized costs of proved oil and gas properties and production facilities and machinery, using the unit-of-production method based on commercial proved and probable oil and gas reserves, as estimated by independent reserves engineers. As described in Note 10 and 20 to the consolidated financial statements, the carrying value of the Company’s oil and gas properties and production facilities and machinery was $587 million as of December 31, 2023, and depreciation expense was $108 million F-2 Table of Contents for the year then ended. The estimation of proved and probable oil and gas reserves also requires the evaluation of inputs, including oil and gas prices and quality differentials, historical oil and gas production, royalties and future development and operating costs, among others. Auditing the Company’s calculation of depreciation of oil and gas properties was complex because of the use of the work of the independent reserves engineers and the evaluation of management’s determination of the inputs described above used by the engineers in estimating proved and probable oil and gas reserves. How We Addressed the Matter in Our Audit We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s internal controls over its process to calculate depreciation of oil and gas properties, including management’s controls over the completeness and the accuracy of the financial data provided to the specialists for use in estimating proved and probable oil and gas reserves. Our audit procedures included, among others, obtaining the reserves report from the independent reserves engineers and evaluating the competency and objectivity of the independent reserves engineers and management´s qualified persons responsible for overseeing the preparation of the reserves estimates through the consideration of their professional qualifications and experience, as well as the use of generally accepted practices and methodologies in preparing reserves estimates. Additionally, we evaluated the completeness and accuracy of the financial data and inputs used by the independent reserves engineers in estimating proved and probable oil and gas reserves by agreeing the inputs to source documentation and comparing them to historical results. For the future development costs, we also evaluated management’s development plan by assessing consistency of the development projections with the Company’s drill plan and the availability of capital to develop such plan. We also tested the mathematical accuracy of the depreciation computations for oil and gas properties, including testing the underlying data by comparing the proved and probable oil and gas reserves amounts used in the calculations to the reserves report prepared by the independent reserves engineers. /s/ ERNST & YOUNG AUDIT S.A.S Member of Ernst & Young Global Limited We have served as the Company’s auditor since 2023. Bogotá, Colombia March 27, 2024 F-3 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the board of directors of GeoPark Limited Opinion on Internal Control over Financial Reporting We have audited GeoPark Limited’s internal control over financial reporting as of December 31, 2023, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, because of the effect of the material weakness described below on the achievement of the objectives of the control criteria, GeoPark Limited (the Company) has not maintained effective internal control over financial reporting as of December 31, 2023, based on the COSO criteria. A material weakness is a deficiency, or 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. The following material weakness has been identified and included in management’s assessment. Management has identified a material weakness in the design and execution of information technology general controls (ITGCs) over the timely removal of user access upon personnel termination. As a result, application and manual controls that are dependent on the affected ITGCs were also deemed ineffective. We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statement of financial position of the Company as of December 31, 2023, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for the year ended December 31, 2023, and the related notes. This material weakness was considered in determining the nature, timing and extent of audit tests applied in our audit of the 2023 consolidated financial statements, and this report does not affect our report dated March 27, 2024, which 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 Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion. Definition and Limitations of Internal Control Over Financial Reporting A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management F-4 Table of Contents 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/ ERNST & YOUNG AUDIT S.A.S Member of Ernst & Young Global Limited Bogotá, Colombia March 27, 2024 F-5 Table of Contents REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM To the shareholders and the Board of Directors of GeoPark Limited Opinion on the Financial Statements We have audited the accompanying consolidated statement of financial position of GeoPark Limited (the Company) as of December 31, 2022, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the two 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 the results of its operations and its cash flows for each of the two years in the period ended December 31, 2022, in conformity with International Financial Reporting Standards (IFRS) as issued by the International Accounting Standards Board (IASB). Basis for Opinion These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB. We conducted our 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 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 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion. /s/ PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L. Member of Ernst & Young Global Limited We served as the Company’s auditor from 2020 to 2023. Buenos Aires, Argentina March 8, 2023 F-6 Table of Contents CONSOLIDATED STATEMENT OF INCOME Amounts in US$´000 REVENUE Commodity risk management contracts loss Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Depreciation Write-off of unsuccessful exploration efforts Impairment loss for non-financial assets, net Other (expenses) income (a) OPERATING PROFIT Financial expenses Financial income Foreign exchange (loss) gain PROFIT BEFORE INCOME TAX Income tax expense PROFIT FOR THE YEAR Earnings per share (in US$). Basic Earnings per share (in US$). Diluted Note 7 8 9 12 13 14 20 20‑37 15 15 15 17 19 19 2023 756,625 — (232,325) (11,192) (43,969) (13,084) (120,934) (29,563) (13,332) (21,319) 270,907 (45,815) 6,237 (16,820) 214,509 (103,441) 111,068 1.95 2022 1,049,579 (70,221) (359,779) (10,529) (50,024) (7,995) (96,692) (25,789) — 527 429,077 (57,073) 3,180 19,725 394,909 (170,474) 224,435 3.78 2021 688,543 (109,191) (212,790) (7,891) (46,828) (8,730) (88,969) (12,262) (4,334) (11,739) 185,809 (64,112) 1,652 5,049 128,398 (67,271) 61,127 1.00 1.94 3.75 0.99 (a) Includes results related to business transactions in Chile and Argentina. See Note 36. The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements. F-7 Table of Contents CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME Amounts in US$´000 Profit for the year Other comprehensive income: Items that may be subsequently reclassified to profit or loss Currency translation differences Gain on cash flow hedges (a) Income tax expense relating to cash flow hedges Other comprehensive profit (loss) for the year 2023 111,068 2022 224,435 2021 61,127 1,624 2,738 (1,369) 2,993 2,121 966 (483) 2,604 (1,438) — — (1,438) Total comprehensive profit for the year 114,061 227,039 59,689 a) Unrealized result on commodity risk management contracts designated as cash flow hedges. See Note 8. The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements. F-8 Table of Contents CONSOLIDATED STATEMENT OF FINANCIAL POSITION Amounts in US$´000 ASSETS NON-CURRENT ASSETS Property, plant and equipment Right-of-use assets Prepayments and other receivables Other financial assets Deferred income tax asset TOTAL NON-CURRENT ASSETS CURRENT ASSETS Inventories Trade receivables Prepayments and other receivables Derivative financial instrument assets Cash and cash equivalents Assets held for sale TOTAL CURRENT ASSETS TOTAL ASSETS EQUITY Equity attributable to owners of the Company Share capital Share premium Translation reserve Other reserves Retained earnings (Accumulated losses) TOTAL EQUITY LIABILITIES NON-CURRENT LIABILITIES Borrowings Lease liabilities Provisions and other long-term liabilities Deferred income tax liability TOTAL NON-CURRENT LIABILITIES CURRENT LIABILITIES Borrowings Lease liabilities Derivative financial instrument liabilities Current income tax liabilities Trade and other payables Liabilities associated with assets held for sale TOTAL CURRENT LIABILITIES TOTAL LIABILITIES TOTAL EQUITY AND LIABILITIES Note 2023 2022 20 28 22 25 18 23 24 22 25 25 36 26.1 27 28 29 18 27 28 25 17 30 36 686,824 28,451 3,063 12,564 15,920 746,822 13,552 65,049 25,896 3,775 133,036 28,419 269,727 1,016,549 666,879 37,011 121 12,877 18,943 735,831 14,434 71,794 22,106 967 128,843 — 238,144 973,975 55 111,281 (9,962) 45,116 29,530 176,020 58 134,798 (11,586) 73,462 (81,147) 115,585 488,453 23,387 34,083 64,063 609,986 12,528 8,911 70 44,269 137,817 26,948 230,543 840,529 1,016,549 485,114 22,051 51,947 70,123 629,235 12,528 10,000 19 65,002 141,606 — 229,155 858,390 973,975 The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements. F-9 Table of Contents CONSOLIDATED STATEMENT OF CHANGES IN EQUITY Amount in US$‘000 Equity as of January 1, 2021 Comprehensive income: Profit for the year Other comprehensive loss for the year Total Comprehensive (loss) profit for the year 2021 Transactions with owners: Share-based payment (Note 31) Repurchase of shares (Note 26.1.3) Cash distribution (Note 26.2) Total 2021 Balances as of December 31, 2021 Comprehensive income: Profit for the year Other comprehensive profit for the year Total Comprehensive profit for the year 2022 Transactions with owners: Share-based payment (Note 31) Repurchase of shares (Note 26.1.3) Cash distribution (Note 26.2) Total 2022 Balances as of December 31, 2022 Comprehensive income: Profit for the year Other comprehensive profit for the year Total Comprehensive profit for the year 2023 Transactions with owners: Share-based payment (Note 31) Repurchase of shares (Note 26.1.3) Cash distribution (Note 26.2) Total 2023 Balances as of December 31, 2023 Attributable to owners of the Company Share Share Translation Other Retained Earnings (Accumulated Capital 61 Premium 179,399 Reserve (12,269) Reserves 104,485 Losses) (380,866) Total (109,190) — — — — (1) — (1) 60 — — — 1 (3) — (2) 58 — — — 1 (4) — (3) 55 — — — — (1,438) (1,438) — — — 61,127 — 61,127 61,127 (1,438) 59,689 1,661 (11,840) — (10,179) 169,220 — — — — — (7,224) — (7,224) 97,261 (13,707) 4,960 6,621 — (11,841) (7,224) — (12,444) 4,960 (61,945) (314,779) — — — — 2,121 2,121 — 483 483 224,435 — 224,435 224,435 2,604 227,039 1,840 (36,262) — (34,422) 134,798 — — — — — (24,282) — (24,282) 73,462 (11,586) 9,197 11,038 — (36,265) — (24,282) (49,509) 115,585 9,197 (81,147) — — — — 1,624 1,624 — 1,369 1,369 111,068 — 111,068 111,068 2,993 114,061 7,718 (31,235) — (23,517) 111,281 — — — — — (29,715) — (29,715) 45,116 (9,962) (391) 7,328 — (31,239) — (29,715) (53,626) 176,020 (391) 29,530 The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements. F-10 Table of Contents CONSOLIDATED STATEMENT OF CASH FLOWS Amounts in US$‘000 Cash flows from operating activities Profit for the year Adjustments for: Income tax expense Depreciation Loss on disposal of property, plant and equipment Impairment loss for non-financial assets Write-off of unsuccessful exploration efforts Accrual of borrowing’s interests Borrowings cancellation costs Amortization of other long-term liabilities Unwinding of long-term liabilities Accrual of share-based payment Foreign exchange loss (gain) Unrealized gain on commodity risk management contracts Income tax paid (a) Changes in working capital (b) Cash flows from operating activities – net Cash flows from investing activities Purchase of property, plant and equipment Proceeds from disposal of long-term assets Cash flows used in investing activities – net Cash flows from financing activities Proceeds from borrowings Debt issuance costs paid Principal paid Interest paid Borrowings cancellation and other costs paid Lease payments Repurchase of shares Cash distribution Payments for transactions with former non-controlling interest Cash flows used in financing activities – net Net increase (decrease) in cash and cash equivalents Cash and cash equivalents at January 1 Currency translation differences Cash and cash equivalents at the end of the year Ending Cash and cash equivalents are specified as follows: Cash in bank and bank deposits Cash in hand Cash and cash equivalents Note 2023 2022 2021 111,068 224,435 61,127 17 20‑37 20 15 29 15 15 8 5 36 5 5 5 5 5 5 26.1 26.2 103,441 120,934 426 13,332 29,563 30,839 — (127) 6,456 7,328 19,729 170,474 96,692 73 — 25,789 36,360 5,141 (2,407) 6,026 11,038 (19,725) — (13,023) (33,355) (40,047) 467,471 (115,626) (26,425) 300,938 67,271 88,969 787 4,334 12,262 44,378 6,308 (223) 5,079 6,621 (5,049) (463) (65,273) (9,351) 216,777 (199,040) 450 (198,590) (168,808) 15,135 (153,673) (129,258) 2,700 (126,558) — 172,174 — (2,019) — — (274,934) — (172,522) (42,592) (36,514) (12,908) (9,118) (7,518) (7,851) (11,841) (36,265) (7,224) (24,282) — (3,580) (190,442) (286,552) (100,223) 27,246 (27,500) — (10,267) (31,239) (29,715) — (98,721) 3,627 128,843 566 133,036 100,604 993 128,843 201,907 (1,080) 100,604 133,023 13 133,036 128,831 12 128,843 100,587 17 100,604 (a) (b) Includes self-withholding taxes for US$ 35,116,000, US$ 20,767,000 and US$ 12,469,000 in 2023, 2022 and 2021, respectively. Includes withholding taxes from clients for US$ 27,558,000, US$ 27,256,000 and US$ 16,361,000 in 2023, 2022 and 2021, respectively. The notes on pages F-12 to F-73 are an integral part of these Consolidated Financial Statements. F-11 Table of Contents NOTES TO CONSOLIDATED FINANCIAL STATEMENTS Note 1 General Information GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas reserves in Colombia, Ecuador and Brazil. These Consolidated Financial Statements were authorized for issue by the board of directors on March 6, 2024 and have been approved to be included in our 2023 annual report (Form 20-F) on March 27, 2024. Note 2 Summary of significant accounting policies The principal accounting policies applied in the preparation of these Consolidated Financial Statements are set out below. These policies have been consistently applied to the years presented, unless otherwise stated. 2.1 Basis of preparation The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with International Financial Reporting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost basis, except for the following: certain financial assets and liabilities (including derivative instruments) measured at fair value, and assets held for sale – measured at fair value less costs to sell. The Consolidated Financial Statements are presented in thousands of United States Dollars (US$’000) and all values are rounded to the nearest thousand (US$’000), except in the footnotes and where otherwise indicated. The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”. All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise indicated. 2.1.1 Changes in accounting policy and disclosure 2.1.1.1 New and amended standards and interpretations The Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after January 1, 2023, as follows: IFRS 17 Insurance Contracts IFRS 17 Insurance Contracts is a comprehensive new accounting standard for insurance contracts covering recognition and measurement, presentation, and disclosure. This new accounting standard replaces IFRS 4 Insurance Contracts. IFRS 17 applies to all types of insurance contracts (i.e., life, non-life, direct insurance, and re-insurance), regardless of the type of entity that issues them, as well as certain guarantees and financial instruments with discretionary participation features. A few scope exceptions will apply. The overall objective of IFRS 17 is to provide a comprehensive accounting model for insurance contracts that is more useful and consistent for insurers, covering all relevant accounting aspects. IFRS 17 is based on a general model, supplemented by: F-12 Table of Contents ● a specific adaptation for contracts with direct participation features (the variable fee approach), and ● a simplified approach (the premium allocation approach) mainly for short-duration contracts. The new standard had no impact on the Consolidated Financial Statements of the Group. Definition of Accounting Estimates - Amendments to IAS 8 The amendments to IAS 8 clarify the distinction between changes in accounting estimates, changes in accounting policies and the correction of errors. They also clarify how to use measurement techniques and inputs to develop accounting estimates. These amendments had no impact on the Consolidated Financial Statements of the Group. Disclosure of Accounting Policies - Amendments to IAS 1 and IFRS Practice Statement 2 The amendments to IAS 1 and IFRS Practice Statement 2 Making Materiality Judgements provide guidance to apply materiality judgements to accounting policy disclosures. The amendments aim to provide accounting policy disclosures that are more useful by replacing the requirement to disclose their ‘significant’ accounting policies with a requirement to disclose their ‘material’ accounting policies and adding guidance on how to apply the concept of materiality in making decisions about accounting policy disclosures. These amendments had no impact on the Consolidated Financial Statements of the Group. Deferred Tax related to Assets and Liabilities arising from a Single Transaction – Amendments to IAS 12 The amendments to IAS 12 Income Tax narrow the scope of the initial recognition exception, so that it no longer applies to transactions that give rise to equal taxable and deductible temporary differences such as leases and decommissioning liabilities. These amendments had no impact on the Consolidated Financial Statements of the Group. International Tax Reform—Pillar Two Model Rules – Amendments to IAS 12 The amendments to IAS 12 have been introduced in response to the OECD’s BEPS Pillar Two model rules and include: ● a mandatory temporary exception to the recognition and disclosure of deferred taxes arising from the jurisdictional implementation of the Pillar Two model rules, ● disclosure requirements to assist in better understanding the Pillar Two income taxes arising from that legislation, particularly before its effective date. The mandatory temporary exception applies immediately. The disclosure requirements apply for annual reporting periods beginning on or after January 1, 2023, but not for any interim periods ending on or before December 31, 2023. The amendments had no impact on the Consolidated Financial Statements of the Group. 2.1.1.2 Standards issued but not yet effective The new and amended standards and interpretations that have been issued, but are not yet effective, as of the date of issuance of these Consolidated Financial Statements are disclosed below. The Group has not early adopted these new and amended standards and interpretations, and intends to adopt them, if applicable, when they become effective. Amendments to IFRS 16: Lease Liability in a Sale and Leaseback F-13 Table of Contents In September 2022, the IASB issued amendments to IFRS 16 to specify the requirements that a seller-lessee uses in measuring the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognize any amount of the gain or loss that relates to the right of use it retains. The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied retrospectively to sale and leaseback transactions entered into after the date of initial application of IFRS 16. Earlier application is permitted, and any earlier application must be disclosed. The amendments are not expected to have a material impact on the Consolidated Financial Statements of the Group. Amendments to IAS 1: Classification of Liabilities as Current or Non-current In January 2020 and October 2022, the IASB issued amendments to paragraphs 69 to 76 of IAS 1 to specify the requirements for classifying liabilities as current or non-current. The amendments clarify: ● what is meant by a right to defer settlement; ● that a right to defer must exist at the end of the reporting period; ● that classification is unaffected by the likelihood that an entity will exercise its deferral right; and ● that only if an embedded derivative in a convertible liability is itself an equity instrument would the terms of a liability not impact its classification. In addition, a requirement has been introduced to require disclosure when a liability arising from a loan agreement is classified as non-current and the entity’s right to defer settlement is contingent on compliance with future covenants within twelve months. The amendments are effective for annual reporting periods beginning on or after January 1, 2024, and must be applied retrospectively. The Group is currently assessing the impact the amendments will have on current practice and whether existing loan agreements may require renegotiation. Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7 In May 2023, the IASB issued amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures to clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements. The disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects of supplier finance arrangements on an entity’s liabilities, cash flows and exposure to liquidity risk. The amendments will be effective for annual reporting periods beginning on or after January 1, 2024. Early adoption is permitted but would need to be disclosed. The amendments are not expected to have a material impact on the Group’s Consolidated Financial Statements. The Enhancement and Standardization of Climate-Related Disclosures for Investors On March 06, 2024, the Securities and Exchange Commission (SEC) issued the final rule on The Enhancement and Standardization of Climate-Related Disclosures for Investors. This rule mandates the disclosure of information regarding a registrant’s climate-related risks that have materially impacted or are reasonably likely to have a material impact on, its business strategy, results of operations, or financial condition. While compliance with this rule is phased in and not required for these Consolidated Financial Statements, the Group is currently assessing the impact of this rule and planification efforts ahead of initial required compliance. 2.2 Going concern The Directors regularly monitor the Group’s cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecasted operational and investment funding requirements. Sensitivities are run to reflect latest F-14 Table of Contents expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches. Considering the performance of the operations, the Group’s cash position of US$ 133,036,000, the oil hedges to mitigate the price risk exposure within the next twelve to fifteen months, the deleveraging process executed in 2021 and 2022 (see Note 27), and the fact that its total indebtedness as of December 31, 2023, matures in January 2027, the Directors have formed a judgement, at the time of approving the Consolidated Financial Statements, that there is a reasonable expectation that the Group has adequate resources to meet all its obligations for the foreseeable future. For this reason, the Directors have continued to adopt the going concern basis in preparing the Consolidated Financial Statements. 2.3 Consolidation Subsidiaries are all entities (including structured entities) over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases. Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group. 2.4 Segment reporting Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision- maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the Chief Executive Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy, Sustainability and Legal Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. 2.5 Foreign currency translation 2.5.1 Functional and presentation currency The Consolidated Financial Statements are presented in US Dollars, which is the Group’s presentation currency. Items included in the Consolidated Financial Statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Colombia, Ecuador, Chile and Argentina is the US Dollar, meanwhile for the Group´s Brazilian company the functional currency is the local currency, which is the Brazilian Real. 2.5.2 Transactions and balances Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the Consolidated Statement of Income. The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows: assets and liabilities are translated at the closing rate, and income and expenses are translated at average exchange rates. All resulting exchange differences are recognized in Other comprehensive income. F-15 Table of Contents 2.6 Joint arrangements Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined them to be joint operations. The Group combines its share in the joint operations individual assets, liabilities, results and cash flows on a line-by-line basis with similar items in its Consolidated Financial Statements. 2.7 Business combinations Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, which is measured at the acquisition date fair value, and the amount of any non-controlling interests in the acquiree. For each business combination, the Group elects whether to measure the non-controlling interests in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition-related costs are expensed as incurred and included in administrative expenses. The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organized workforce with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs. When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree. Any contingent consideration to be transferred by the acquirer will be recognized at fair value at the acquisition date. Contingent consideration classified as equity is not remeasured and its subsequent settlement is accounted for within equity. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments, is measured at fair value with the changes in fair value recognized in the statement of profit or loss in accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at each reporting date with changes in fair value recognized in profit or loss. Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests and any previous interest held over the net identifiable assets acquired and liabilities assumed). If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re- assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or loss. 2.8 Revenue recognition Revenue from the sale of crude oil and gas is recognized at the point in time when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place. The Group’s sales of crude oil are priced based on market prices. The sales price is linked to US dollar denominated crude oil international benchmarks, such as Brent, adjusted for certain marketing and quality discounts based on, among other things, American Petroleum Institute (“API”) gravity, viscosity, sulphur content, delivery point and transport costs. The Group’s sales of natural gas are priced based on long-term Gas Supply contracts with customers. F-16 Table of Contents Revenue is shown net of VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. See Note 33.1. 2.9 Production and operating costs Production and operating costs are recognized in the Consolidated Statement of Income on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, and royalties and economic rights in cash are also included within this account. 2.10 Financial results Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. The Group has capitalized the borrowing cost directly attributable to wells and facilities identified as qualifying assets, if applicable. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale. The capitalization rate used to determine the amount of borrowing costs to be capitalized, if any, is the weighted average interest rate applicable to the Group’s general borrowings. 2.11 Property, plant and equipment Property, plant and equipment are stated at historical cost less depreciation and impairment charges, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation. Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income. Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e., seismic), direct labor costs and drilling costs of exploratory wells. No depreciation and/or amortization are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which the determination is made, depending on whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. A charge of US$ 29,563,000 has been recognized in the Consolidated Statement of Income within the ‘Write-off of unsuccessful exploration efforts’ line item (US$ 25,789,000 in 2022 and US$ 12,262,000 in 2021). See Note 20. All field development costs are considered construction in progress until they are finished and capitalized within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties. Workovers of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance costs are charged to the Consolidated Statement of Income when incurred. Capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable oil and gas reserves. The calculation of the “unit of production” depreciation considers estimated future finding and development costs and is based on current year-end unescalated price levels. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. F-17 Table of Contents Depreciation of the remaining property, plant and equipment assets (i.e., furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight-line method by applying such annual rates as required to write- off their value at the end of their estimated useful lives. The useful lives range between 3 years and 10 years. Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow the performance of the business. An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.13). 2.12 Provisions and other long-term liabilities Provisions for asset retirement obligations and other environmental liabilities, deferred income, restructuring obligations and legal claims are recognized when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and the amount has been reliably estimated. Restructuring provisions, if any, comprise lease termination penalties and employee services termination payments. Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to the passage of time is recognized as financial expense. 2.12.1 Asset Retirement Obligation The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded, the Group capitalizes the cost by increasing the carrying amount of the related long- lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and the application of current legislation, and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping. The effects of this recalculation are included in the Consolidated Financial Statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset. 2.12.2 Deferred Income Government grants and other contributions relating to the purchase of property, plant and equipment are included in non- current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions. 2.13 Impairment of non-financial assets Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized for the excess of the asset’s carrying amount over its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date. No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable. F-18 Table of Contents Impairment losses were recognized for US$ 13,332,000 in 2023 (no impairment losses were recognized in 2022 and US$ 4,334,000 were recognized in 2021). See Note 37. The write-offs are detailed in Note 20. 2.14 Lease contracts – Group as a lessee The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. 2.14.1 Right-of-use assets The Group recognizes right-of-use assets at the commencement date of the lease. Right of use assets are measured at cost, less any accumulated depreciation and impairment losses, an adjusted for any measurement of lease liabilities. The cost of right-of-use assets comprise the following: ● the amount of the initial measurement of lease liability, ● any lease payments made at or before the commencement date less any lease incentives received, ● any initial direct costs, and ● restoration costs. The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of 1 to 15 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets. If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. The right-of-use assets are also subject to impairment. 2.14.2 Lease liabilities At the commencement date of the lease, the Group recognizes lease liabilities measured at the present value of lease payments to be made over the lease term. Lease liabilities include the net present value of the following lease payments: ● fixed payments, less any lease incentives receivable, ● variable lease payments that are based on an index or a rate, ● amounts expected to be payable by the lessee under residual value guarantees, ● the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and ● payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option. In calculating the present value, the lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the Group’s incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset. 2.14.3 Short-term leases and leases of low-value assets The Group applies the short-term lease recognition exemption to its short-term leases of machinery and equipment (i.e., those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of IT equipment and small items of F-19 Table of Contents office furniture that are considered to be low value. Lease payments on short-term leases and leases of low-value assets are recognized as expense on a straight-line basis over the lease term. 2.15 Inventories Inventories comprise crude oil and materials. Crude oil is measured at the lower of cost and net realizable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method. 2.16 Current and deferred income tax The tax expense for the year comprises current and deferred income tax. Income tax is recognized in the Consolidated Statement of Income. The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the financial statements date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and, in some cases, it is difficult to predict the ultimate outcome. Deferred income tax is recognized, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted as of the financial statements date and are expected to apply when the related deferred income tax asset is realized, or the deferred income tax liability is settled. In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions that are available to be offset against future taxable profit. However, deferred income tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods. Deferred income tax liabilities are provided on taxable temporary differences arising from investments in subsidiaries and joint arrangements, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred income tax is recognized in respect of the retained earnings of overseas subsidiaries only if at the date of the Consolidated Financial Statements, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future. Deferred income tax balances are provided in full, with no discounting. 2.17 Non-current assets or disposal groups held for sale Non-current assets or disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights under insurance contracts, which are specifically exempt from this requirement. An impairment loss is recognized for any initial or subsequent write-down of the asset or disposal group to fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset or disposal group, F-20 Table of Contents but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the date of the sale of the non-current asset or disposal group is recognized at the date of derecognition. Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized. Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented separately from the other assets in the Consolidated Statement of Financial Position. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the Consolidated Statement of Financial Position. As of December 31, 2023, the Group classified non-current assets and liabilities corresponding to the Chilean companies as held for sale due to the divestment process that was agreed to in December 2023 and which closed in January 2024. See Note 36.1. 2.18 Financial assets Financial assets are divided into the following categories: amortized cost; financial assets at fair value through profit or loss and fair value through other comprehensive income. The classification depends on the Group’s business model for managing the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when its business model for managing those assets changes. All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs. Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss. Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date. Interest and other cash flows resulting from holding financial assets are recognized in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured. Amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. These financial assets comprise trade and other receivables and cash and cash equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, less provision for impairment, if applicable. Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of Income. All of the Group’s financial assets are classified as amortized cost. 2.19 Other financial assets Non-current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes. Current other financial assets include short-term investments with original maturities up to twelve months and over three months. 2.20 Impairment of financial assets The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied depends on whether there has been a significant increase in credit risk. For trade F-21 Table of Contents receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial recognition of the receivables. 2.21 Cash and cash equivalents Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts. Bank overdrafts, if any, are shown within borrowings in the current liabilities section of the Consolidated Statement of Financial Position. 2.22 Trade and other payables Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities. Trade payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method. 2.23 Derivatives and hedging activities Derivative financial instruments are recognized in the Consolidated Statement of Financial Position as assets or liabilities and initially and subsequently measured at fair value. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period. The mark-to-market fair value of the Group's outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. 2.23.1 Cash flow hedges that qualify for hedge accounting The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion is recognized immediately in the Consolidated Statement of Income. When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the forward contracts are recognized in Other Reserves within Equity. Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost of the asset. When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately reclassified to the Consolidated Statement of Income. For more information about derivatives designated as cash flow hedges please refer to Note 36.1 and Note 8. 2.23.2 Other Derivatives F-22 Table of Contents Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that does not qualify for hedge accounting are recognized immediately in the Consolidated Statement of Income. For more information about derivatives related to commodity risk management please refer to Note 8 and for more information about derivatives related to currency risk management please refer to Note 3 Currency risk. 2.24 Borrowings Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument. Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the Consolidated Statement of Income over the period of the borrowings using the effective interest method. Direct issue costs are charged to the Consolidated Statement of Income on an accrual basis using the effective interest method. 2.25 Share capital Equity comprises the following: ● "Share capital" representing the nominal value of equity shares. ● "Share premium" representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issuance. ● "Translation reserve" representing the differences arising from translation of investments in overseas subsidiaries. ● "Other reserves" representing: - - the difference between the proceeds from transactions with non-controlling interests received against the book value of the shares acquired in subsidiaries, and the changes in the fair value of the effective portion of derivatives designated as cash flow hedges. ● "Retained earnings (Accumulated losses)" representing: - - accumulated earnings and losses, and the equity element attributable to shares granted according to IFRS 2 but not issued at year end. 2.26 Share-based payment The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to employees and other third-party contractors. Share-based payment transactions are measured in accordance with IFRS 2. The fair value of the share awards payments is determined at the grant date by reference to the market value of the shares, calculated using the Geometric Brownian Motion method or the Monte Carlo simulation, and recognized as an expense over the vesting period. Service and non-market performance conditions are not taken into account when determining the grant date fair value of awards, but the likelihood of the conditions being met is assessed as part of the Group’s best estimate of the number of equity instruments that will ultimately vest. Market performance conditions are reflected within the grant date fair value. Any other conditions attached to an award, but without an associated service requirement, are considered to be non-vesting conditions. Non-vesting conditions are reflected in the fair value of an award and lead to an immediate expensing of an award unless there are also service and/or performance conditions. No expense is recognized for awards that do not ultimately vest because non-market performance and/or service conditions have not been met. Where awards include a market or non-vesting condition, the transactions are treated as vested irrespective of whether the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied. F-23 Table of Contents At each reporting date, the entity revises its estimates of the number of options that are expected to vest. It recognizes the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment to equity. When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium. Note 3 Financial Instruments-risk management The Group is exposed through its operations to the following financial risks: ● Currency risk ● Price risk ● Credit risk– concentration ● Funding and liquidity risk ● Interest rate risk ● Capital risk The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is described in more detail below. Currency risk In Colombia, Ecuador, Chile and Argentina the functional currency is the US Dollar. The fluctuation of the local currencies of these countries against the US Dollar, except for Ecuador where the local currency is the US Dollar, does not impact the loans, costs and revenue held in US Dollars; but it does impact receivables or payables originated in local currency mainly corresponding to VAT and income tax. The Group minimises the local currency positions in Colombia, Chile and Argentina by seeking to balance local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore, the Group maintains a net exposure to them, except for what it is described below. From time to time, the Group enters into derivative financial instruments in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. No currency risk management contracts were in place as of December 31, 2023, and onwards. In January 2023, GeoPark entered into derivative financial instruments (zero- premium collars) with local banks in Colombia, for an amount equivalent to US$ 38,000,000 in order to anticipate any currency fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023. Most of the Group's assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally settled in US Dollar equivalents. During 2023, the Colombian Peso revalued by 21% (devalued by 21% and 16% in 2022 and 2021, respectively), the Chilean Peso devalued by 3% (1% and 19% in 2022 and 2021, respectively), and the Argentine Peso devalued by 356% (72% and 22% in 2022 and 2021, respectively), all against the US Dollar. If the Colombian Peso, the Chilean Peso, and the Argentine Peso had each devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been higher by US$ 13,971,000 (US$ 14,695,000 in 2022 and US$ 9,070,000 in 2021). In Brazil, the functional currency is the local currency, which is the Brazilian Real. The fluctuation of the US Dollars against the Brazilian Real does not impact the loans, costs and revenues held in Brazilian Real; but it does impact the F-24 Table of Contents balances denominated in US Dollars. Such is the case of the provision for asset retirement obligation and the lease liabilities. During 2023, the Brazilian Real revalued by 7% against the US Dollar (revalued by 7% in 2022 and devalued by 7% 2021). If the Brazilian Real had devalued an additional 10% against the US dollar, with all other variables held constant, post-tax profit for the year would have been lower by US$ 728,000 (US$ 726,000 in 2022 and US$ 780,000 in 2021). As currency rate changes between the US Dollar and the local currencies, the Group recognizes gains and losses in the Consolidated Statement of Income. Price risk The realized oil price for the Group is linked to US dollar denominated crude oil international benchmarks. The market price of this commodity is subject to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil, the geopolitical landscape, armed conflicts, the economic conditions and a variety of additional factors. The main factors affecting realized prices for gas sales vary across countries with some closely linked to international references while others are more domestically driven. In Colombia, the realized oil price is linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin that is transported through Ecuador. In both basins, the reference price is then adjusted for certain marketing and quality discounts based on, among other things, API, viscosity, sulphur content, delivery point and transport costs. In Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles Oriente crude reference. In Brazil, prices for gas produced in the Manati Field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral de Preços do Mercado), or IGPM. In Chile, the oil price was linked to Dated Brent minus certain marketing and quality discounts such as, API, sulphur content and others. The gas price, under a long-term Gas Supply Contract with Methanex, was determined by a formula that considers a basket of international methanol prices, including US and European price indices. If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$ 42,393,000 (US$ 47,330,000 in 2022 and US$ 17,899,000 in 2021). GeoPark seeks to partially mitigates its exposure to crude oil price volatility using derivatives by hedging a portion of its production for a limited period going forward. The Group uses a combination of options to manage its exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. GeoPark has also obtained credit lines from different counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8). Credit risk– concentration The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognized values of commodities sold or hedged. GeoPark considers that there is no significant risk associated to the Group’s major customers and hedging counterparties. In Colombia, GeoPark allocates its sales on a competitive basis to industry leading participants including traders and other producers. During 2023, the oil and gas production was sold to three clients which concentrate 96% of the Colombian subsidiaries’ revenue, accounting for 89% of the consolidated revenue (97% and 99% of the Colombian subsidiaries’ F-25 Table of Contents revenue, accounting for 90% and 89% of the consolidated revenue in 2022 and 2021). Delivery points include wellhead and other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the transport through the Ecuadorian pipeline system. The outstanding contracts for Colombian production extend through the first half of 2024. GeoPark manages its counterparty credit risk associated to sales contracts by periodic evaluation of the counterparties’ credit profile and, in certain contracts, including early payment conditions to minimize the exposure. In Ecuador, oil is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of the sales are exported on a competitive basis to industry leading participants including traders and other producers. Sales of crude oil in Ecuador accounted for 3% of the consolidated revenue in 2023 (1% in 2022). In Brazil, all the gas from the Manati Block is sold to Petrobras, the State-owned company, which is also the operator of the Manati Field (2% of the consolidated revenue in 2023 and 2022, and 3% in 2021). In Chile, the oil production was sold to ENAP, the State-owned oil and gas company (1% of the consolidated revenue in 2023, 2022 and 2021), and the gas production was sold to the local subsidiary of Methanex, a Canadian public company (1% of the consolidated revenue in 2023 and 2022, and 2% in 2021). GeoPark Limited has entered into a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside the Group’s Putumayo Basin production. Sales of crude oil purchased from third parties accounted for 1% of the consolidated revenue in 2023 and 2022. The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk. GeoPark executes oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions and trading companies; therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes 8 and 25. Funding and Liquidity risk In the past, the Group has been able to raise capital through different sources of funding including equity, strategic partnerships and financial debt. The Group is positioned at the end of 2023 with a cash balance of US$ 133,036,000, and has access to a US$ 80,000,000 senior unsecured credit facility with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A., and to US$ 179,600,000 in uncommitted credit lines, and its total indebtedness matures in January 2027. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with over 38,000 boepd in production at year end. This scale and positioning permit the Group to protect its financial condition and selectively allocate capital to the optimal projects subject to prevailing macroeconomic conditions. The Indentures governing the Company Notes 2027 include incurrence test covenants related to compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indentures’ provisions and covenants. Interest rate risk The Group’s interest rate risk could arise from long-term borrowings issued at variable rates, which would expose the Group to interest rate risk. F-26 Table of Contents The Group does not currently face interest rate risk on its US$ 500,000,000 Notes which carry a fixed rate coupon of 5.50% per annum and mature in January 2027. Consequently, the accruals and interest payments are not substantially affected by changes in prevailing interest rates. As of December 31, 2023, there were no outstanding borrowings affected by a variable rate. Capital risk The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group manages its capital structure and makes adjustments in light of changes in economic conditions, operating risks and working capital requirements. To maintain or adjust its capital structure, the Group may issue or buy back shares, change its dividend policy, raise or refinance debt and/or adjust its capital expenditures to manage its operating and growth objectives. Additionally, the Group utilizes a planning, budgeting and forecasting process to help determine and monitor the funds needed to maintain appropriate liquidity for operational, capital and financial needs. As of December 31, 2023 and 2022, GeoPark is in compliance with the debt covenant ratios associated with the Company´s Notes due 2027. See Note 27. The following table summarizes the Group’s capital structure balances: Amounts in US$‘000 Total Equity Net Debt (a) Working capital (b) 2023 176,020 367,945 39,184 2022 115,585 368,799 8,989 (a) Calculated as total borrowings (including ‘current and non-current borrowings’ as shown in the Consolidated Statement of Financial Position) less cash and cash equivalents. (b) Calculated as ‘current assets’ less ‘current liabilities’. Note 4 Accounting estimates and assumptions Estimates and assumptions are used in preparing financial statements. Although these estimates are based on management’s best knowledge of current events and actions, actual results may differ. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances. The key estimates and assumptions used in these Consolidated Financial Statements are noted below: ● The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and natural gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2023, prepared by DeGolyer and MacNaughton Corp., an independent international oil and gas consulting firm based in Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management Reporting System (PRMS) framework. It incorporates many factors and assumptions including: o o o o o o expected reservoir characteristics based on geological, geophysical and engineering assessments; future production rates based on historical performance and expected future operating and investment activities; future oil and gas prices and quality differentials; assumed effects of regulation by governmental agencies; tax rates by jurisdiction; and future development and operating costs. F-27 Table of Contents Management believes these factors and assumptions are reasonable based on the information available to them at the time of preparing the estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change. Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment may require revision -where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities- and, (d) the recognition and carrying value of deferred income tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets. ● Cash flows estimates for impairment assessments of non-financial assets require assumptions about three primary elements: future prices, reserves and discount rate. Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs. Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 37). ● The Group adopted the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the advice from qualified experts. The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available. ● Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block. The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved and probable reserves, or future capital expenditure estimates change. Changes to proved and probable reserves could arise due to F-28 Table of Contents changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues. ● Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant obligations. Estimating the future abandonment costs is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future. Technologies and costs are constantly changing as well as political, environmental, safety and public relations considerations. The Group has adopted the following criterion for recognizing well plugging and abandonment related costs: the present value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated future expenditure. The liabilities recognized are based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results. The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required. ● From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental, safety and health matters. For example, from time to time, the Group receives notice of environmental, health and safety violations. Based on what the Group’s Management currently knows, such claims are not expected to have a material impact on the Consolidated Financial Statements. Note 5 Consolidated Statement of Cash Flows The Consolidated Statement of Cash Flows shows the Group’s cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents during the year. Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital and corporate tax. Income tax paid is presented as a separate item under operating activities. Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any. Cash flows from financing activities include changes in equity and proceeds from borrowings and repayment of loans. Cash and cash equivalents include bank overdraft, if any, and liquid funds with a term of less than three months. The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flows: Amounts in US$‘000 Increase (Decrease) in asset retirement obligation Increase (Decrease) in provisions for other long-term liabilities Purchase of property, plant and equipment Additions / changes in estimates of right-of-use assets 2023 7,374 2,370 (7,864) 137 2022 (4,942) (2,616) 7,864 22,462 2021 (651) (443) — 5,288 F-29 Table of Contents Changes in working capital shown in the Consolidated Statement of Cash Flows are disclosed as follows: Amounts in US$‘000 (Increase) Decrease in Inventories Decrease (Increase) in Trade receivables Increase in Prepayments and other receivables and Other assets (a) Increase (Decrease) in Trade and other payables 2023 (1,330) 6,820 (33,328) 1,413 (26,425) 2022 (6,694) (1,425) (30,929) (999) (40,047) 2021 1,241 (23,290) (13,817) 26,515 (9,351) (a) Includes withholding taxes from clients for US$ 27,558,000, US$ 27,256,000 and US$ 16,361,000, in 2023, 2022 and 2021, respectively. The following chart shows the movements in the borrowings and lease liabilities for each of the periods presented: Amounts in US$‘000 As of January 1, 2021 Proceeds from borrowings Debt issuance costs paid Addition to lease liabilities Accrual of borrowing's interests Exchange difference Foreign currency translation Unwinding of discount Principal paid Interest paid Borrowings cancellation costs Borrowings cancellation and other costs paid Lease payments As of December 31, 2021 Addition to lease liabilities Accrual of borrowing's interests Exchange difference Foreign currency translation Unwinding of discount Principal paid Interest paid Borrowings cancellation costs Borrowings cancellation and other costs paid Lease payments As of December 31, 2022 Addition to lease liabilities Accrual of borrowing's interests Exchange difference Liabilities associated with assets held for sale (Note 36.1) Foreign currency translation Unwinding of discount Interest paid Lease payments As of December 31, 2023 F-30 Borrowings 784,586 172,174 (2,019) — 44,323 (581) (265) — (274,934) (42,592) 6,308 (12,908) — 674,092 — 36,360 — 203 — (172,522) (36,514) 5,141 (9,118) — 497,642 — 30,839 — — — — (27,500) — 500,981 Lease Liabilities 22,347 — — 5,288 — (365) (461) 1,453 — — — — (7,518) 20,744 22,462 — Total 806,933 172,174 (2,019) 5,288 44,323 (946) (726) 1,453 (274,934) (42,592) 6,308 (12,908) (7,518) 694,836 22,462 36,360 (6,426) (6,426) 284 2,838 — — — — (7,851) 32,051 137 — 7,061 (26) 174 3,168 — (10,267) 32,298 487 2,838 (172,522) (36,514) 5,141 (9,118) (7,851) 529,693 137 30,839 7,061 (26) 174 3,168 (27,500) (10,267) 533,279 Table of Contents Note 6 Segment information Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision- maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the Chief Executive Officer, Chief Financial Officer, Chief Technical Officer, Chief Exploration Officer, Chief Operating Officer, Chief Strategy, Sustainability and Legal Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective. The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit (loss) for the period (determined as if IFRS 16 Leases has not been adopted), before net finance cost, income tax, depreciation, amortization, certain non-cash items such as impairments and write-offs of unsuccessful exploration efforts, accrual of share-based payment, unrealized result on commodity risk management contracts, geological and geophysical expenses allocated to capitalized projects, and other non-recurring events. Other information provided to the Executive Committee is measured in a manner consistent with that in the Consolidated Financial Statements. Segment areas (geographical segments) Amounts in US$ ‘000 2023 Revenue Sale of crude oil Sale of purchased crude oil Sale of gas Commodity risk management contracts designated as cash flow hedges Production and operating costs Royalties in cash Economic rights in cash Share-based payment Other operating costs Adjusted EBITDA Depreciation Recognition of impairment losses Write-off of unsuccessful exploration efforts Total assets Employees (average) (a) Employees at year end (a) Colombia Ecuador Brazil Chile (b) Argentina Corporate Total 14,019 490 — 13,529 — (4,946) (1,096) — — (3,850) 6,374 (2,332) — — 27,891 4 4 15,644 5,052 — 10,592 — (8,226) (548) — (72) (7,606) 4,952 (9,815) (13,332) — 36,192 33 27 — — — — — — — — — — (2,620) (22) — — 357 18 15 5,464 — 5,464 — — (4,666) — — — (4,666) (8,838) (3) — — 15,873 8 7 756,625 726,947 5,464 25,024 (810) (232,325) (12,845) (72,032) (750) (146,698) 451,862 (120,934) (13,332) (29,563) 1,016,549 469 470 702,401 702,308 — 903 (810) (204,245) (11,201) (72,032) (671) (120,341) 446,835 (101,666) — (29,563) 895,900 400 412 19,097 19,097 — — — (10,242) — — (7) (10,235) 5,159 (7,096) — — 40,336 6 5 F-31 Table of Contents Amounts in US$ ‘000 2022 Revenue Sale of crude oil Sale of purchased crude oil Sale of gas Realized loss on commodity risk management contracts Production and operating costs Royalties in cash Economic rights in cash Share-based payment Other operating costs Adjusted EBITDA Depreciation Write-off of unsuccessful exploration efforts Total assets Employees (average) (a) Employees at year end (a) Amounts in US$ ‘000 2021 Revenue Sale of crude oil Sale of gas Realized loss on commodity risk management contracts Production and operating costs Royalties in cash Economic rights in cash Share-based payment Other operating costs Adjusted EBITDA Depreciation Recognition of impairment losses Write-off of unsuccessful exploration efforts Total assets Employees (average) (a) Employees at year end (a) (a) Unaudited. (b) Divested in January 2024. See Note 36.1. Colombia Ecuador Brazil Chile (b) Argentina Corporate Total 978,423 977,184 — 1,239 (83,244) (327,626) (60,314) (188,989) (843) (77,480) 525,593 (78,775) (21,318) 797,390 362 388 10,671 10,671 — — — (3,220) — — (10) (3,210) 4,197 (788) (4,471) 35,690 7 8 19,873 796 — 29,196 14,460 — 19,077 14,736 — (5,299) (1,546) — — (3,753) 11,654 (2,796) — 34,329 5 4 — (14,126) (1,165) — (103) (12,858) 11,753 (14,076) — 63,379 53 49 1,962 1,664 — 298 — (1,579) (273) — 1 (1,307) (3,643) (254) — 1,296 33 24 9,454 1,049,579 — 1,004,775 9,454 — — (7,929) — — — (7,929) (8,775) (3) — 41,891 9 9 9,454 35,350 (83,244) (359,779) (63,298) (188,989) (955) (106,537) 540,779 (96,692) (25,789) 973,975 469 482 Colombia Ecuador Brazil Chile (b) Argentina Corporate Total 618,268 616,133 2,135 (109,654) (178,384) (33,385) (72,956) (334) (71,709) 294,847 (61,279) — (7,827) 689,401 308 321 — — — — — — — — — (2,071) (200) — — 7,782 8 3 20,109 661 19,448 — (4,596) (1,575) (67) — (2,954) 12,569 (4,082) — — 38,846 4 4 21,471 6,297 15,174 — (11,050) (770) — (31) (10,249) 7,639 (14,275) (17,641) (4,435) 71,515 55 52 28,695 24,468 4,227 — (18,760) (4,270) — 26 (14,516) 2,124 (9,130) 13,307 — 38,111 92 74 — — — 688,543 647,559 40,984 — (109,654) — (212,790) (40,000) — (73,023) — (339) — (99,428) — 300,800 (14,308) (88,969) (3) (4,334) — (12,262) — 895,741 50,086 476 9 463 9 In 2023, approximately 89% of capital expenditure was incurred by Colombia (82% in 2022 and 93% in 2021) and 11% was incurred by Ecuador (11% in 2022 and 4% in 2021). No capital expenditure was incurred by Chile in 2023 (7% in 2022 and 3% in 2021). F-32 Table of Contents A reconciliation of total Adjusted EBITDA to total profit (loss) before income tax is provided as follows: Amounts in US$ ‘000 Adjusted EBITDA Unrealized gain on commodity risk management contracts Depreciation (a) Share-based payment Impairment and write-off of unsuccessful exploration efforts, net Lease accounting - IFRS 16 Others (b) Operating profit Financial expenses Financial income Foreign exchange (loss) gain Profit before tax 2023 451,862 — (120,934) (7,328) (42,895) 10,267 (20,065) 270,907 (45,815) 6,237 (16,820) 214,509 2022 540,779 13,023 (96,692) (11,038) (25,789) 7,851 943 429,077 (57,073) 3,180 19,725 394,909 2021 300,800 463 (88,969) (6,621) (16,596) 7,518 (10,786) 185,809 (64,112) 1,652 5,049 128,398 (a) Net of capitalized costs for oil stock included in Inventories. (b) Includes allocation to capitalized projects. In 2023, also includes termination and other costs incurred because of the divestment process in Chile, including a provision for investment commitments maintained by GeoPark after the transaction, for a total amount of US$ 9,742,000 (see Note 36.1), together with the amount paid for transferring the working interest in the Los Parlamentos Block in Argentina to the joint operation partner for US$ 7,023,000 (see Note 36.2), and others. In 2022, also includes gain from the sale of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina. In 2021, also includes termination costs and write-down of tax credits in Argentina. Note 7 Revenue Amounts in US$ ‘000 Sale of crude oil Sale of purchased crude oil Sale of gas Commodity risk management contracts designated as cash flow hedges (a) 2023 726,947 5,464 25,024 (810) 756,625 2022 1,004,775 9,454 35,350 — 1,049,579 2021 647,559 — 40,984 — 688,543 (a) Realized result on commodity risk management contracts designated as cash flow hedges. See Note 8. Note 8 Commodity risk management contracts The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars and were placed with major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protect the Group from potential non-performance risk by its counterparties. The Group’s derivatives that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were accounted for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were recognized immediately as gains or losses in the results of the periods in which they occurred as part of the ‘Commodity risk management contracts’ line item in the Consolidated Statement of Income. The table below summarizes the results on non-hedge derivative commodity risk management contracts: Realized loss on commodity risk management contracts Unrealized gain on commodity risk management contracts 2023 2022 — (83,244) — 13,023 — (70,221) 2021 (109,654) 463 (109,191) F-33 Table of Contents The Group’s derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, onwards are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in ‘Other Reserves’ within ‘Equity’. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in ‘Other Reserves’ is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the ‘Revenue’ line item in the Consolidated Statement of Income. The following table presents the Group’s production hedged during the year ended December 31, 2023, and for the following periods as a consequence of the derivative contracts in force as of December 31, 2023: Period January 1, 2023 - March 31, 2023 April 1, 2023 - June 30, 2023 July 1, 2023 - September 30, 2023 October 1, 2023 - December 31, 2023 January 1, 2024 - March 31, 2024 April 1, 2024 - June 30, 2024 July 1, 2024 - September 30, 2024 October 1, 2024 - December 31, 2024 Reference ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT ICE BRENT Type Zero Premium Collars Zero Premium Collars Zero Premium Collars Zero Premium Collars Zero Premium Collars Zero Premium Collars Zero Premium Collars Zero Premium Collars Volume bbl/d Weighted average price US$/bbl 9,500 10,000 9,000 9,000 8,500 9,000 7,000 1,000 66.05 Put 112.59 Call 69.25 Put 110.56 Call 70.00 Put 94.69 Call 69.44 Put 91.82 Call 65.59 Put 92.04 Call 67.50 Put 96.99 Call 66.43 Put 99.32 Call 70.00 Put 96.00 Call Note 9 Production and operating costs Amounts in US$ '000 Staff costs (Note 11) Share-based payment (Note 11) Royalties in cash (a) Economic rights in cash (a) Well and facilities maintenance Operation and maintenance Consumables (b) Equipment rental Transportation costs Field camp Safety and insurance costs Personnel transportation Consultant fees Gas plant costs Non-operated blocks costs (c) Crude oil stock variation Purchased crude oil Other costs 2023 13,889 750 12,845 72,032 26,089 8,143 37,556 4,314 5,850 6,546 5,487 3,363 2,291 1,865 20,421 2,004 4,666 4,214 232,325 2022 13,114 955 63,298 188,989 20,779 6,545 21,789 7,580 4,021 4,070 3,745 2,480 2,133 1,680 12,650 (6,449) 7,929 4,471 359,779 2021 16,655 339 40,000 73,023 17,989 7,826 19,270 8,127 3,383 4,386 4,216 2,397 1,732 2,596 4,941 1,271 — 4,639 212,790 (a) Royalties and economic rights in Colombia are payable to the National Hydrocarbons Agency (“ANH”) and are determined on a field-by-field basis depending on different variables such as crude quality and price levels, among others (see Note 33). During 2023, the mix of royalties and economic rights paid “in-kind” increased as compared to royalties and economic rights paid ‘in-cash”. These changes caused variations in the ‘royalties in cash’ and ‘economic rights in cash’ line items from year to year, which are compensated by variations in the quantities of oil sales impacting the ‘Revenue’ line item in the Consolidated Statement of Income. (b) Consumables include energy costs of US$ 26,348,000 in the Llanos 34 Block in 2023 (US$ 6,086,000 in 2022) due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. (c) Non-operated block costs show the increase in activities in the CPO-5 and Perico Blocks in Colombia and Ecuador, respectively. F-34 Table of Contents Note 10 Depreciation Amounts in US$ ‘000 Oil and gas properties Production facilities and machinery Furniture, equipment and vehicles Buildings and improvements Depreciation of property, plant and equipment (a) Related to: Productive assets Administrative assets Depreciation total (a) 2023 95,369 12,896 1,304 503 110,072 108,265 1,807 110,072 2022 76,720 12,244 1,344 672 90,980 88,964 2,016 90,980 2021 66,011 12,468 1,960 700 81,139 78,479 2,660 81,139 (a) Depreciation without considering capitalized costs for oil stock included in Inventories nor depreciation of right-of-use assets. Note 11 Staff costs and Directors’ Remuneration Number of employees at year end (a) Amounts in US$ ‘000 Wages and salaries Share-based payments (Note 31) Social security charges Director’s fees and allowance Recognized as follows: Production and operating costs Geological and geophysical expenses Administrative expenses Selling expenses Board of Directors’ and key managers’ remuneration Salaries and fees Share-based payments Other benefits in kind (a) Unaudited. F-35 2023 470 41,917 7,328 5,992 896 56,133 14,639 8,407 32,604 483 56,133 6,081 4,886 — 10,967 2022 482 38,699 11,038 5,593 1,172 56,502 14,069 7,490 34,533 410 56,502 10,317 8,728 171 19,216 2021 463 42,516 6,621 6,901 2,853 58,891 16,994 6,219 35,360 318 58,891 9,069 5,759 296 15,124 Table of Contents Directors’ Remuneration James F. Park (a) Andrés Ocampo (b) Robert Bedingfield (c) Constantin Papadimitriou (d) Somit Varma (e) Sylvia Escovar Gomez (f) Brian Maxted (g) Carlos Macellari (h) Marcela Vaca (i) Non-Executive Director Fees Cash Equivalent Directors’ Fees Paid in Shares Total Remuneration (in US$) — — — 120,000 — — 120,000 205,000 100,000 (No. of Shares) — — 21,098 8,791 20,219 23,109 8,791 8,791 8,791 (in US$) — — 240,000 220,000 230,000 262,500 220,000 305,000 200,000 (a) Mr. Park has a consulting agreement with the Company to act as CEO advisor and provide support and assistance in addition to his role as Vicechair, non-executive Director and Strategy and Risk Committee Chairman, and he relinquished his fees as a member of the Board. (b) Mr. Ocampo has a service contract to act as Chief Executive Officer, and he relinquished his fees as a member of the Board. (c) Audit Committee Chairman. (d) Compensation Committee Chairman. (e) Nomination and Corporate Governance Committee Chairman. (f) Independent Chair of the Board. (g) Technical Committee Chairman. (h) Mr. Macellari, as member of the Technical Committee, instructed by the Board, was awarded additional fees on strategic and technical exploration advisory. (i) SPEED Committee Chairman. Note 12 Geological and geophysical expenses Amounts in US$ ‘000 Staff costs (Note 11) Share-based payment (Note 11) Communication and IT costs Consultant fees Allocation to capitalized project Other services Note 13 Administrative expenses Amounts in US$ ‘000 Staff costs (Note 11) Share-based payment (Note 11) Consultant fees Safety and insurance costs Travel expenses Non-operated blocks expenses Director’s fees and allowance (Note 11) Communication and IT costs Allocation to joint operations Other administrative expenses F-36 2023 7,879 528 2,139 1,373 (1,254) 527 11,192 2023 25,675 6,033 10,645 3,890 1,730 1,568 896 3,760 (13,986) 3,758 43,969 2022 7,097 393 1,743 917 (416) 795 10,529 2022 23,671 9,690 9,574 3,834 2,336 1,390 1,172 3,419 (9,642) 4,580 50,024 2021 6,042 177 1,071 854 (953) 700 7,891 2021 26,402 6,105 10,806 3,142 719 799 2,853 4,214 (8,574) 362 46,828 Table of Contents Note 14 Selling expenses Amounts in US$ ‘000 Staff costs (Note 11) Shared-based payment (Note 11) Transportation (a) Selling taxes and other 2023 466 17 9,022 3,579 13,084 2022 2021 410 — 4,881 2,704 7,995 318 — 4,233 4,179 8,730 (a) The rise in transportation costs in 2023 is mainly attributed to deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses. Note 15 Financial results Amounts in US$ '000 Financial expenses Interest and amortization of debt issue costs Borrowings cancellation costs Bank charges and other financial results Unwinding of long-term liabilities Financial income Interest received Foreign exchange gains and losses Foreign exchange (loss) gain, net Realized result on currency risk management contracts Total Financial results Note 16 Tax reform in Colombia 2023 2022 2021 (30,839) — (8,520) (6,456) (45,815) (36,360) (5,141) (9,546) (6,026) (57,073) (44,713) (6,308) (8,012) (5,079) (64,112) 6,237 6,237 3,180 3,180 1,652 1,652 (19,729) 2,909 (16,820) (56,398) 19,725 — 19,725 (34,168) 5,049 — 5,049 (57,411) In November 2022, the Colombian Congress approved a Tax Reform (“Law 2277”) which contemplated an increase in the effective tax rate and the government take for certain entities of the oil and gas industry. A relevant provision included in the Law 2277 establishes a permanent surtax for companies developing crude oil extractive activities, ranging between 0% and 15%. The surtax triggers when the Brent price average during the fiscal year meets percentiles 30 and upwards of the Brent price average of the last 10 years (as shown in the table below regarding fiscal year 2024) and is calculated as additional percentage points of the CIT rate that is applicable to the taxable base determined on a regular basis for CIT purposes. The applicable surtax for 2023 was 10%. Income derived from gas production is exempted of surtax. Surcharge Price Triggers applicable for fiscal year 2024 < US$ 67.18 /bbl US$ 67.18 to US$ 76.39 /bbl US$ 76.39 to US$ 79.87 /bbl > US$ 79.87 /bbl Surcharge rate 0% 5% 10% 15% In addition to the aforementioned rules, the Law 2277 included other measures such as the strike off of the straight-line amortization method for new exploratory assets which will pass to be calculated under the ‘unit of production’ method, and repeals the tax credit of 50% of the industry and commerce tax paid during the year, which will no longer be treated F-37 Table of Contents as a tax credit but as a common deduction. The tax rate for dividends increased to 20% as well as the rate for capital gains tax that increased to 15%. These tax provisions became effective in 2023, but the surtax was considered for deferred income tax purposes from the year ended December 31, 2022. Note 17 Income tax Amounts in US$ ‘000 Current income tax liabilities Amounts in US$ ‘000 Current income tax charge Deferred income tax benefit (charge) (Note 18) 2023 44,269 44,269 2023 (107,740) 4,299 (103,441) 2022 (126,269) (44,205) (170,474) 2022 65,002 65,002 2021 (49,291) (17,980) (67,271) The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows: Amounts in US$ ‘000 Profit before tax Tax losses from non-taxable jurisdictions Taxable profit Income tax calculated at domestic tax rates applicable to Profit in the respective countries Tax losses where no deferred income tax benefit is recognized Effect of currency translation on tax base Effect of inflation adjustment for tax purposes Changes in the income tax rate (Note 16) Write-down of deferred income tax benefits previously recognized (a) Previously unrecognized tax losses Income tax on dividends (b) Fiscal recognition of property, plant and equipment Non-taxable results (c) Income tax 2023 214,509 39,526 254,035 2022 394,909 53,005 447,914 2021 128,398 91,351 219,749 (123,202) (6,918) 36,691 — (8,853) (3,895) 632 (2,595) — 4,699 (103,441) (157,315) (2,832) (10,797) — (3,820) (2,938) 9,067 (3,038) — 1,199 (170,474) (71,086) (7,510) (10,354) 2,482 (1,703) (7,261) 9,593 — 8,919 9,649 (67,271) (a) (b) (c) Includes write-down of tax losses and other deferred income tax assets in Chile, Brazil and Argentina where there is insufficient evidence of future taxable profits to offset them, in accordance with the expected future cash-flows as of December 31, 2023, 2022 and 2021. Includes income tax payable in Spain due to dividends received from subsidiaries. Includes non-deductible expenses and non-taxable gains in each jurisdiction. Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Income tax rate in Colombia may range from 35% to 50%, depending on the surcharge applicable for each year (see Note 16). Income tax rates in other countries where the Group operates (Ecuador, Brazil and Chile) ranges from 15% to 34%. There are no income tax consequences attached to the payment of dividends by the Group to its shareholders. F-38 Table of Contents The Group has tax losses available which can be utilized against future taxable profit in the following countries: Amounts in US$ ‘000 Colombia Brazil (a) Chile (a) (c) Argentina (b) Spain (a) Total tax losses as of December 31 2023 — 26,808 313,409 9,981 6,936 357,134 2022 4,837 26,736 323,929 24,065 7,205 386,772 2021 15,557 26,781 285,456 35,773 9,443 373,010 (a) Taxable losses have no expiration date. (b) Tax losses accumulated as of December 31, 2023, are: US$ 2,551,000, US$ 939,000, US$ 2,297,000, US$ 927,000 and US$ 3,267,000 expiring in 2024, 2025, 2026, 2027 and 2028, respectively. (c) The Chilean business was divested on January 18, 2024 (see Note 36.1), and therefore these tax losses no longer belong to GeoPark from such date. As of December 31, 2023, deferred income tax assets in respect of tax losses in Chile and Argentina and a portion of tax losses in Brazil have not been recognized as there is insufficient evidence of future taxable profits to offset them. Note 18 Deferred income tax The gross movement on the deferred income tax account is as follows: Amounts in US$ ‘000 Deferred income tax as of January 1 Currency translation differences Income tax expense relating to cash flow hedges recognized in OCI Income statement benefit (charge) Deferred income tax as of December 31 2023 (51,180) 107 (1,369) 4,299 (48,143) 2022 (6,875) 383 (483) (44,205) (51,180) The breakdown and movement of deferred income tax assets and liabilities as of December 31, 2023, and 2022, are as follows: Amounts in US$ ‘000 Deferred income tax assets Difference in depreciation rates and other Tax losses Total 2023 Total 2022 Amounts in US$ ‘000 Deferred income tax liabilities Difference in depreciation rates and other Total 2023 Total 2022 At the beginning Charged to net profit of year Currency translation differences Reclassification At the end of year 4,759 14,184 18,943 14,072 8,911 (11,485) (2,574) 4,488 (108) 215 107 383 (556) — (556) 13,006 2,914 15,920 — 18,943 At the beginning of year Charged to net profit Income tax expense relating to cash flow hedges Reclassification At the end of year (70,123) (70,123) (20,947) 6,873 6,873 (48,693) (1,369) (1,369) (483) 556 556 — (64,063) (64,063) (70,123) F-39 Table of Contents Note 19 Earnings per share Amounts in US$ ‘000 except for shares Numerator: Profit for the year Denominator: Weighted average number of shares used in basic EPS Earnings after tax per share (US$) – basic 2023 111,068 56,836,682 1.95 2022 224,435 59,330,421 3.78 2021 61,127 60,901,109 1.00 Amounts in US$ ‘000 except for shares Weighted average number of shares used in basic EPS Effect of dilutive potential common shares Stock awards at US$ 0.001 Weighted average number of common shares for the purposes of diluted earnings per shares Earnings after tax per share (US$) – diluted 2023 56,836,682 2022 59,330,421 2021 60,901,109 359,587 552,466 559,012 57,196,269 1.94 59,882,887 3.75 61,460,121 0.99 Note 20 Property, plant and equipment Amounts in US$’000 Cost as of January 1, 2021 Additions / ARO change Currency translation differences Disposals Write-off / Impairment Transfers Assets held for sale (Note 36.3) Cost as of December 31, 2021 Additions / ARO change Currency translation differences Disposals Write-off / Impairment Transfers Cost as of December 31, 2022 Additions / ARO change Currency translation differences Disposals Write-off / Impairment Transfers Assets held for sale (Note 36.1) Cost as of December 31, 2023 Furniture, Production Buildings Oil & gas properties 968,617 (1,094)(b) (3,284) — (1,575)(c) 68,315 (73,047) 957,932 (7,558)(b) 2,921 — — 125,962 1,079,257 9,744 (b) 3,477 — (13,332)(c) 171,538 (330,024) 920,660 facilities and equipment and vehicles machinery 197,829 — (246) (900) (2,759)(c) 13,305 (6,052) 201,177 6 232 (26) — 21,338 222,727 12 277 — — 21,262 (74,491) 169,787 20,707 930 (43) (1,762) — 58 (1,178) 18,712 1,620 37 (1,290) — 14 19,093 1,683 46 (1,223) — 93 (6,559) 13,133 and improvements 12,442 — (16) (978) — 391 (177) 11,662 (14) 6 (774) — 147 11,027 17 8 (2,150) — 93 (4,948) 4,047 Depreciation and write-down as of January 1, 2021 Depreciation Disposals Currency translation differences Assets held for sale (Note 36.3) Depreciation and write-down as of December 31, 2021 Depreciation Disposals Currency translation differences Depreciation and write-down as of December 31, 2022 Depreciation Disposals Currency translation differences Assets held for sale (Note 36.1) Depreciation and write-down as of December 31, 2023 Carrying amount as of December 31, 2021 Carrying amount as of December 31, 2022 Carrying amount as of December 31, 2023 (548,445) (66,011) — 2,219 49,080 (563,157) (76,720) — (2,403) (642,280) (95,369) — (3,179) 310,683 (430,145) 394,775 436,977 490,515 (109,987) (12,468) 900 246 4,692 (116,617) (12,244) 19 (231) (129,073) (12,896) — (277) 68,765 (73,481) 84,560 93,654 96,306 (6,975) (700) 838 16 153 (6,668) (672) 752 (6) (6,594) (503) 1,877 (8) 2,158 (3,070) 4,994 4,433 977 (16,985) (1,960) 1,325 37 915 (16,668) (1,344) 1,246 (33) (16,799) (1,304) 1,189 (41) 6,488 (10,467) 2,044 2,294 2,666 F-40 Construction in progress Exploration and evaluation assets(a) 18,848 82,094 (18) (3,372) — (c) (70,321) (27) 27,204 107,171 18 — — (117,913) 16,480 116,304 21 (119) — (116,905) — 15,781 — — — — — — — — — — — — — — — 78,614 46,234 (30) (338) (12,262)(d) (11,748) — 100,470 67,889 19 — (25,789)(e) (29,548) 113,041 73,160 22 — (29,563)(f) (76,081) — 80,579 — — — — — — — — — — — — — — — 27,204 16,480 15,781 100,470 113,041 80,579 Total 1,297,057 128,164 (3,637) (7,350) (16,596) — (80,481) 1,317,157 169,114 3,233 (2,090) (25,789) — 1,461,625 200,920 3,851 (3,492) (42,895) — (416,022) 1,203,987 (682,392) (81,139) 3,063 2,518 54,840 (703,110) (90,980) 2,017 (2,673) (794,746) (110,072) 3,066 (3,505) 388,094 (517,163) 614,047 666,879 686,824 Table of Contents (a) Exploration wells movement and balances are shown in the table below; mining property associated with unproved reserves and resources, seismic and other exploratory assets amount to US$ 72,581,000 (US$ 96,041,000 in 2022 and US$ 90,166,000 in 2021). Amounts in US$ ‘000 Exploration wells as of December 31, 2021 Additions Write-offs Transfers Exploration wells as of December 31, 2022 Additions Write-offs Transfers Exploration wells as of December 31, 2023 Total 10,304 56,491 (21,460) (28,335) 17,000 61,500 (24,815) (45,687) 7,998 As of December 31, 2023, there were two exploratory wells that have been capitalized for a period less than three years amounting to US$ 7,998,000. (b) Corresponds to the effect of change in estimate of assets retirement obligations. (c) See Note 37. (d) Corresponds to two unsuccessful exploratory wells drilled in the Llanos 32 Block (Colombia), other exploration costs incurred in the Fell Block (Chile), an exploratory well drilled in previous years in the CPO-5 Block (Colombia) and other exploration costs incurred in previous years in the PUT-30 Block (Colombia). (e) Corresponds to exploration costs incurred in previous years in the Tacacho and Terecay Blocks (Colombia), four exploratory wells drilled in the CPO-5, Platanillo, Llanos 34 and Llanos 94 Blocks (Colombia), and certain exploration costs incurred in the Espejo Block (Ecuador). (f) Corresponds to three unsuccessful exploratory wells drilled in the Llanos 87 Block (Colombia), an unsuccessful exploratory well drilled in the Llanos 124 Block (Colombia) and other exploration costs incurred in the Llanos 94, Coati and Llanos 124 Blocks (Colombia). F-41 Table of Contents Note 21 Subsidiary undertakings The following chart illustrates main companies of the Group structure as of December 31, 2023: (1) GeoPark Ecuador S.A. holds 50% working interest in the consortiums that operate the Espejo and Perico Blocks. During the year ended December 31, 2023, the following change to the Group structure has taken place: ● The merger process between GeoPark Colombia S.A.S., GeoPark Colombia E&P S.A. and Petrodorado South America S.A., with GeoPark Colombia S.A.S. being the surviving company, became effective as of its registration in the Public Registry of the Chamber of Commerce of Bogota on January 27, 2023. ● As a result of the abovementioned merger and to comply with local regulatory obligations, GeoPark Colombia S.A.S. incorporated a branch in Panama, which is currently dormant. F-42 Table of Contents Details of all the subsidiaries of the Group as of December 31, 2023, are set out below: Name and registered office Ownership interest Subsidiaries GeoPark Argentina S.A. (Argentina) GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda. (Brazil) GeoPark Chile S.p.A. (Chile) GeoPark Fell S.p.A. (Chile) GeoPark Magallanes Limitada (Chile) GeoPark TdF S.p.A. (Chile) GeoPark Colombia S.A.S. (Colombia) GeoPark Colombia, S.L.U. (Spain) GeoPark Perú S.A.C. (Peru) GeoPark Mexico S.A.P.I. de C.V. (Mexico) GeoPark E&P S.A.P.I. de C.V. (Mexico) GeoPark Ecuador S.A. (Ecuador) GeoPark (UK) Limited (United Kingdom) Amerisur Resources Limited (United Kingdom) Amerisur Exploración Colombia Limited (British Virgin Islands) Amerisur Exploración Colombia Limited Sucursal Colombia (Colombia) Yarumal S.A.S. (Colombia) Fenix Oil & Gas Limited (British Virgin Islands) Fenix Oil & Gas Limited Sucursal Colombia (Colombia) Amerisurexplor Ecuador S.A. (Ecuador) Amerisur S.A. (Paraguay) Market Access LLP (United States) GeoPark Colombia S.A.S. Sucursal Panama (Panama) 100% (a) 100% (a) 100% (a) (c) 100% (a) (c) 100% (a) (c) 100% (a) (c) 100% (a) 100% (a) 100% (a) 100% (a) (b) 100% (a) (b) 100% (a) 100% 100% (a) 100% (a) 100% (a) 100% (a) (b) 100% (a) (b) 100% (a) (b) 100% (a) (b) 100% (a) (b) 9% 100% (a) (b) (a) Indirectly owned. (b) Dormant companies. (c) Divested in January 2024. See Note 36.1. F-43 Table of Contents Details of the joint operations of the Group as of December 31, 2023, are set out below: Name and registered office Ownership interest Joint operations Flamenco Block (Chile) Campanario Block (Chile) Isla Norte Block (Chile) Llanos 34 Block (Colombia) Llanos 32 Block (Colombia) Puelen Block (Argentina) Los Parlamentos (Argentina) Manati Field (Brazil) POT-T-785 Block (Brazil) Espejo Block (Ecuador) Perico Block (Ecuador) Llanos 86 Block (Colombia) Llanos 87 Block (Colombia) Llanos 104 Block (Colombia) Llanos 123 Block (Colombia) Llanos 124 Block (Colombia) CPO-5 Block (Colombia) Mecaya Block (Colombia) PUT-8 Block (Colombia) PUT-9 Block (Colombia) Tacacho Block (Colombia) Terecay Block (Colombia) Llanos 94 Block (Colombia) PUT-36 Block (Colombia) CPO-4-1 Block (Colombia) In process of relinquishment. (a) GeoPark is the operator. (b) (c) Divested in January 2024. See Note 36.1. (d) GeoPark agreed to transfer its 50% working interest to its joint operation partner. Note 22 Prepayments and other receivables Amounts in US$ '000 V.A.T. Income tax payments in advance Other prepaid taxes To be recovered from co-venturers (Note 34) Prepayments and other receivables Classified as follows: Current Non-current F-44 50% (a) (c) 50% (a) (c) 60% (a) (c) 45% (a) 12.5% 18% (b) 50% (d) 10% 70% (a) 50% (a) 50% 50% (a) 50% (a) 50% (a) 50% (a) 50% (a) 30% 50% (a) 50% (a) 50% (a) 50% (a) (b) 50% (a) (b) 50% (d) 50% (a) 50% 2023 4,310 3,685 23 8,630 12,311 28,959 25,896 3,063 28,959 2022 1,826 3,156 37 8,750 8,458 22,227 22,106 121 22,227 Table of Contents Movements on the Group provision for impairment are as follows: Amounts in US$ '000 At January 1 Additions Foreign exchange gain (loss) Note 23 Inventories Amounts in US$ '000 Crude oil Materials and spares The carrying amount of inventories is not pledged as security for liabilities. Note 24 Trade receivables Amounts in US$ '000 Trade receivables 2023 2022 14 — 4 18 7 10 (3) 14 2023 9,441 4,111 13,552 2022 12,630 1,804 14,434 2023 65,049 65,049 2022 71,794 71,794 As of December 31, 2023, and 2022, there are no balances that were aged by more than 3 months. Trade receivables that are aged by less than three months are not considered impaired. The credit period for trade receivables is 30 days. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable. The Group does not hold any collateral as security related to trade receivables. The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature. Note 25 Financial instruments by category Amounts in US$ '000 Financial assets at fair value through profit or loss Derivative financial instrument assets Cash and cash equivalents Other financial assets at amortized cost Trade receivables To be recovered from co-venturers (Note 34) Other financial assets (a) Cash and cash equivalents Total financial assets Assets as per statement of financial position 2022 2023 3,775 — 3,775 65,049 8,630 12,564 133,036 219,279 223,054 967 242 1,209 71,794 8,750 12,877 128,601 222,022 223,231 (a) Non-current other financial assets relate to restricted deposits made for environmental obligations according to Brazilian government regulations. Current other financial assets correspond to short-term investments with original maturities up to twelve months and over three months. F-45 Table of Contents Amounts in US$ ‘000 Liabilities at fair value through profit and loss Derivative financial instrument liabilities Other financial liabilities at amortized cost Trade payables To be paid to co-venturers (Note 34) Lease liabilities Borrowings Total financial liabilities 25.1 Credit quality of financial assets Liabilities as per statement of financial position 2022 2023 70 70 19 19 108,977 522 32,298 500,981 642,778 642,848 102,125 2,815 32,051 497,642 634,633 634,652 The credit quality of financial assets that are neither past due nor impaired can be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates: Amounts in US$ ‘000 Trade receivables Counterparties with an external credit rating (Moody’s, S&P, Fitch) Aa3 A3 Baa1 Baa3 Ba1 Ba2 Ba3 B2 Counterparties without an external credit rating Group 1 (a) Total trade receivables 2023 2022 — 949 1,721 151 15,068 2,953 — 63 44,144 65,049 2,013 1,557 99 198 23,755 — 2,745 4,085 37,342 71,794 (a) Group 1 – no existing balances with customers aged by more than 3 months. All trade receivables are denominated in US Dollars, except in Brazil where they are denominated in Brazilian Real. F-46 Table of Contents Cash at bank and other financial assets (a) Amounts in US$ ‘000 Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services) Aa3 A1 A2 A3 Baa1 Baa2 Baa3 Ba1 Ba2 Ba3 B3 Counterparties without an external credit rating Total 2023 2022 — 91,747 268 16,147 18 17,585 125 — 6,528 5 593 12,571 145,587 10,362 96,077 57 10,389 39 7,030 1,352 64 268 3,066 51 12,953 141,708 (a) The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ 13,000 (US$ 12,000 in 2022). 25.2 Financial liabilities- contractual undiscounted cash flows The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows. Amounts in US$ ‘000 As of December 31, 2023 Borrowings Lease liabilities Trade payables To be paid to co-venturers (Note 34) As of December 31, 2022 Borrowings Lease liabilities Trade payables To be paid to co-venturers (Note 34) Less than 1 Between 1 Between 2 Over 5 years and 5 years and 2 years year 27,500 9,416 108,977 522 146,415 27,500 10,939 102,125 2,815 143,379 27,500 6,515 — — 34,015 27,500 5,653 — — 33,153 541,250 11,719 — — 552,969 568,750 11,209 — — 579,959 — 25,134 — — 25,134 — 25,012 — — 25,012 25.3 Fair value measurement of financial instruments Accounting policies for financial instruments have been applied to classify as either: amortized cost, financial assets at fair value through profit or loss and fair value through other comprehensive income. For financial instruments that are measured in the statement of financial position at fair value, IFRS 13 requires a disclosure of fair value measurements by level according to the following fair value measurement hierarchy: Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities. Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices). Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs). F-47 Table of Contents 25.3.1 Fair value hierarchy The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value as of December 31, 2023, and 2022, on a recurring basis: Amounts in US$ ‘000 Assets Derivative financial instrument assets Commodity risk management contracts Total Assets Liabilities Derivative financial instrument liabilities Commodity risk management contracts Total Liabilities Amounts in US$ ‘000 Assets Cash and cash equivalents Money market funds Derivative financial instrument assets Commodity risk management contracts Total Assets Liabilities Derivative financial instrument liabilities Commodity risk management contracts Total Liabilities Level 1 Level 2 2023 As of December 31, — — — — 3,775 3,775 70 70 3,775 3,775 70 70 Level 1 Level 2 As of December 31, 2022 242 — 242 — — — 967 967 19 19 242 967 1,209 19 19 There were no transfers between Level 2 and 3 during the period. The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as of December 31, 2023. 25.3.2 Valuation techniques used to determine fair values Specific valuation techniques used to value financial instruments include: ● The use of quoted market prices or dealer quotes for similar instruments. ● The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. ● The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the resulting fair value estimates are included in level 2. 25.3.3 Fair values of other financial instruments (unrecognized) The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest receivable/payable is either close to current market rates or the instruments are short-term in nature. Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short-term portion where interest has already been fixed. They are classified under other financial liabilities and measured at their amortized cost. The fair value of these financial instruments as of December 31, 2023, amounts to US$ 443,690,000 (US$ 431,660,000 in 2022). The fair values are based on market price for the Notes and cash flows discounted for other borrowings using a rate based on the borrowing rate and are within level 1 and level 2 of the fair value hierarchy, respectively. F-48 Table of Contents Note 26 Equity 26.1 Share capital and Share premium Issued share capital Common stock (amounts in US$ ‘000) The share capital is distributed as follows: Common shares, of nominal US$ 0.001 Total common shares in issue Authorized share capital US$ per share Number of common shares (US$ 0.001 each) Amount in US$ 2023 2022 55 58 55,327,520 55,327,520 57,621,998 57,621,998 0.001 0.001 5,171,949,000 5,171,949 5,171,949,000 5,171,949 Details regarding the share capital of the Company are set out below. 26.1.1 Common shares As of December 31, 2023, the outstanding common shares confer the following rights on the holder: ● the right to one vote per share ● ranking pari passu, the right to any dividend declared and payable on common shares GeoPark common shares history Shares outstanding at the end of 2021 Buyback program Buyback program Stock awards Buyback program Buyback program Shares outstanding at the end of 2022 Stock awards Buyback program Stock awards Buyback program Buyback program Buyback program Shares outstanding at the end of 2023 Month Mar 2022 Jun 2022 Jul 2022 Sep 2022 Dec 2022 Feb 2023 Mar 2023 May 2023 Jun 2023 Sep 2023 Dec 2023 Shares movement (millions) (0.2) (0.5) 0.1 (1.1) (0.9) 0.6 (0.6) 0.1 (1.1) (0.5) (0.8) Shares closing (millions) 60.2 60.0 59.5 59.6 58.5 57.6 57.6 58.2 57.6 57.7 56.6 56.1 55.3 55.3 US$(`000) Closing 60 60 60 60 59 58 58 58 58 58 57 56 55 55 26.1.2 Stock Award Program and Other Share Based Payments Non-Executive Directors Fees During 2023, the Company issued 99,590 shares (75,636 in 2022 and 64,269 in 2021) to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 1,133,000 (US$ 1,040,000 in 2022 and US$ 861,000 in 2021). The number of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period. F-49 Table of Contents Stock Award Program and Other Share Based Payments On February 3, 2023, 350,938 common shares were issued as part of the compensation agreements related to the CEO transition which occurred in 2022, generating a share premium of US$ 4,799,000. On July 15, 2022, 52,058 common shares were issued as part of the founding executive employment agreement in place with the former Chief Executive Officer (104,439 in 2021), generating a share premium of US$ 800,000 (US$ 800,000 in 2021). On February 3, 2023, 246,110 common shares were issued as a result of the vesting of the first tranche of the Long-Term Incentive program (“LTIP”) oriented to executive officers which was granted in 2022, generating a share premium of US$ 1,505,000. During 2023, 82,472 common shares were issued as part of other equity incentive plans vested during the year, generating a share premium of US$ 281,000. 26.1.3 Buyback Program The Company has recurring buyback programs to repurchase its own shares. The latest renewal took place on November 8, 2023, and established a program to repurchase up to 10% of the shares outstanding, or approximately 5,611,797 shares, until December 31, 2024. In addition to any repurchases under the aforementioned repurchase program, the Company has authority from its Board of Directors to repurchase, on a standalone basis, up to US$ 50,000,000 of its common shares in 2024. During 2023, the Company purchased 3,073,588 common shares (2,743,722 in 2022 and 960,454 in 2021) for a total amount of US$ 31,239,000 (US$ 36,265,000 in 2022 and US$ 11,841,000 in 2021). These transactions had no impact on the Group’s results. 26.2 Cash distributions On November 6, 2019, the Company’s Board of Directors declared the initiation of quarterly cash distributions. The following table summarizes the cash distributions for each of the years presented: Date of distribution April 13, 2021 May 28, 2021 August 31, 2021 December 7, 2021 Date of declaration March 10, 2021 May 5, 2021 August 4, 2021 November 10, 2021 Cash distributions for the year ended December 31, 2021 March 31, 2022 March 9, 2022 June 10, 2022 May 11, 2022 September 8, 2022 August 10, 2022 November 9, 2022 December 7, 2022 Cash distributions for the year ended December 31, 2022 March 31, 2023 March 8, 2023 May 31, 2023 May 3, 2023 September 7, 2023 August 9, 2023 November 8, 2023 December 11, 2023 Cash distributions for the year ended December 31, 2023 These distributions are deducted from Other Reserves. F-50 US$ per share Total amount in US$ ‘000 0.0205 0.0205 0.0410 0.0410 0.0820 0.0820 0.1270 0.1270 0.1300 0.1300 0.1320 0.1340 1,133 1,220 2,442 2,429 7,224 4,847 4,809 7,345 7,281 24,282 7,505 7,378 7,383 7,449 29,715 Table of Contents Note 27 Borrowings Amounts in US$ ‘000 Outstanding amounts as of December 31 Notes due 2027 Classified as follows: Current Non-current 2023 2022 500,981 500,981 12,528 488,453 497,642 497,642 12,528 485,114 On January 17, 2020, the Company placed US$ 350,000,000 aggregate principal amount of 5.500% senior secured notes due 2027 (the “Notes due 2027”), which were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the United States to non U.S. persons in accordance with Regulation S under the Securities Act. The Notes due 2027 were priced at 99.285% and carry a coupon of 5.50% per annum (yield 5.625% per annum). Final maturity will be January 17, 2027. In April 2021, the Company reopened its Notes due 2027, issuing an additional US$ 150,000,000 principal amount. The reopening was priced above par at 101.875%, representing a yield to maturity of 5.117%. The Notes due 2027 were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act, and outside the United States to non-U.S. persons in accordance with Regulation S under the Securities Act. The Notes due 2027 are fully and unconditionally guaranteed by GeoPark Colombia, S.L.U. From April 2021 to September 2022, the Company repurchased and cancelled its US$ 425,000,000 aggregate principal amount of 6.500% senior secured notes due 2024 (the “Notes due 2024”). In April 2021, the Company executed a tender to purchase US$ 255,000,000 of the Notes due 2024, funded with a combination of cash in hand and the abovementioned reopening of the Notes due 2027. From March to September 2022, the Company repurchased and cancelled the remaining amount of the Notes due 2024 for a nominal amount of US$ 170,000,000. The difference between the carrying amount of debt that was repurchased or redeemed and the consideration paid was recognized within ‘Financial expenses’ in the Consolidated Statement of Income. The indenture governing the Notes due 2027 includes incurrence test covenants that provide, among other things, that the Net Debt to Adjusted EBITDA ratio should not exceed 3.25 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. Incurrence covenants, as opposed to maintenance covenants, must be tested by the Company before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others. As of the date of these Consolidated Financial Statements, the Company complies with all the indentures’ provisions and covenants. On August 3, 2023, GeoPark Colombia S.A.S., as borrower, and GeoPark Limited, as guarantor, signed a senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. which provides GeoPark with access to up to US$ 80,000,000, with an availability period until November 3, 2024, and final maturity on August 3, 2025. The agreement establishes a commitment fee of 1.85% per annum with respect to undrawn amounts and an interest rate of SOFR + 3.70% with respect to amounts drawn. “SOFR” (Secured Overnight Financing Rate) is a broad measure of the cost of borrowing cash overnight collateralized by treasury securities. As of the date of these Consolidated Financial Statements, GeoPark has not withdrawn any amount under this credit facility. As of the date of these Consolidated Financial Statements, the Group has access to the abovementioned US$ 80,000,000 senior unsecured committed credit facility and to US$ 179,600,000 in uncommitted credit lines. F-51 Table of Contents Note 28 Leases The Consolidated Statement of Financial Position shows the following amounts relating to leases: Amounts in US$ ‘000 Right of use assets Production, facilities and machinery Buildings and improvements Lease liabilities Current Non-current The Consolidated Statement of Income shows the following amounts relating to leases: Amounts in US$ ‘000 Depreciation charge of Right of use assets Production, facilities and machinery Buildings and improvements Unwinding of long-term liabilities (included in Financial results) Expenses related to short-term leases (included in Production and operating cost and Administrative expenses) Expenses related to low-value leases (included in Administrative expenses) 2023 2022 24,201 4,250 28,451 8,911 23,387 32,298 32,034 4,977 37,011 10,000 22,051 32,051 2023 2022 2021 (7,858) (792) (8,650) (3,168) (838) (775) (6,057) (988) (7,045) (2,838) (2,614) (708) (5,526) (1,136) (6,662) (1,453) (1,101) (906) The table below summarizes the amounts of Right-of-use assets recognized and the movements during the reporting years: Amounts in US$‘000 Right-of-use assets as of January 1 Additions / changes in estimates Foreign currency translation Assets held for sale (Note 36.1) Depreciation Right-of-use assets as of December 31 2023 37,011 137 444 (491) (8,650) 28,451 2022 21,014 22,462 580 — (7,045) 37,011 The table below summarizes the amounts of Lease liabilities recognized and the movements during the reporting years: Amounts in US$‘000 Lease liabilities as of January 1 Additions / changes in estimates Exchange difference Foreign currency translation Liabilities associated with assets held for sale (Note 36.1) Unwinding of discount Lease payments Lease liabilities as of December 31 F-52 2023 32,051 137 7,061 174 (26) 3,168 (10,267) 32,298 2022 20,744 22,462 (6,426) 284 — 2,838 (7,851) 32,051 Table of Contents Note 29 Provisions and other long-term liabilities Amounts in US$ ‘000 As of January 1, 2022 Addition to provision / changes in estimates Exchange difference Foreign currency translation Amortization Unwinding of discount Amounts used during the year As of December 31, 2022 Addition to provision / changes in estimates Exchange difference Foreign currency translation Amortization Unwinding of discount Amounts used during the year Liabilities associated with assets held for sale (Note 36.1) As of December 31, 2023 Asset retirement obligation (a) Deferred Income (b) Other (c) Total 45,842 (4,942) (669) (577) — 2,641 (1,392) 40,903 7,374 1,172 717 — 2,794 (2,502) (26,922) 23,536 3,331 — (167) — (2,407) — — 757 — 180 — (127) — — — 810 13,675 (2,670) (1,147) 14 — 547 (132) 10,287 2,460 560 (13) — 494 (4,051) — 9,737 62,848 (7,612) (1,983) (563) (2,407) 3,188 (1,524) 51,947 9,834 1,912 704 (127) 3,288 (6,553) (26,922) 34,083 (a) The provision for ‘asset retirement obligation’ relates to the estimation of future disbursements related to the abandonment and decommissioning of oil and gas wells (see Note 4). (b) ‘Deferred income’ relates to government grants and other contributions relating to the purchase of property, plant and equipment in Colombia. The amortization is in line with the related assets. (c) ‘Other’ mainly includes environmental obligations in Colombia and Peru. Legal proceeding in the United Kingdom On January 8, 2020, Amerisur Resources Limited (“Amerisur”) received a copy of a claim form issued in the High Court of England and Wales (the “Court”) by Leigh Day solicitors on behalf of a group of claimants (the “Claimants”) described as members of a farming community in the department of Putumayo in Colombia, seeking compensation for economic and non- economic damages said to be caused by alleged environmental contamination and pollution caused by Amerisur’s operations in the region. Following initial court hearings, an interim freezing order was imposed on Amerisur for an amount of GBP 4,465,600 of its assets located in the United Kingdom. On November 10, 2020, the freezing order was discharged by agreement between the parties as Amerisur provided alternative security in the form of a letter of credit. On February 6, 2023, the Court ordered Amerisur to pay the sum of GBP 330,022 (equivalent to US$ 409,000). On August 11, 2023, a settlement (the “Settlement”) was signed between Leigh Day and Amerisur, made on a no-admission of liability basis and included a payment made by Amerisur. All Claimants represented by Leigh Day agreed to the Settlement. On October 2, 2023, the Court approved the Settlement, the litigation was discontinued, and the letter of credit was cancelled. GeoPark had a provision for this contingent liability, which was originally recognized at the moment of the acquisition of Amerisur in 2020. All payments made by Amerisur during 2023 were applied to the previously recognized contingent liability, thus generating a gain of US$ 2,568,000 that was recorded in “Other income (expenses)” in the Consolidated Statement of Income. F-53 Table of Contents Note 30 Trade and other payables Amounts in US$ ‘000 V.A.T Trade payables Customer advance payments Other short-term advance payments (a) Outstanding commitments in Chile (b) Staff costs to be paid Royalties to be paid Taxes and other debts to be paid To be paid to co-venturers (Note 34) Classified as follows: Current Non-current 2023 975 108,977 — 450 5,869 10,852 791 9,381 522 137,817 137,817 — 2022 8,513 102,125 481 — — 9,306 9,403 8,963 2,815 141,606 141,606 — (a) Advance payment collected in relation with the sale of the Group´s business in Chile (see Note 36.1). (b) Investment commitments in the Campanario and Isla Norte Blocks as a result of sale agreement of the Group´s business in Chile (see Note 36.1). The average credit period (expressed as creditor days) during the year ended December 31, 2023, was 90 days (2022: 69 days). The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value. Note 31 Share-based payment The Group has established different stock awards programs and other share-based payment plans to incentivize the directors, executive officers and employees, enabling them to benefit from the increased market capitalization of the Company. During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs that the Company decides to implement throughout such term. The maximum number of shares available for issuance under the Plan is 5,000,000 Shares. In 2020, a share-based compensation program for employees was approved for approximately 800,000 shares, to vest in 2023. On February 17, 2023, the Compensation Committee reviewed the Group’s results and the performance conditions established in the program and approved 152,030 shares to be delivered to participants, due to the fact that, throughout the vesting period, the performance conditions included in the program were only partially achieved and, to a lesser extent, the Group had lower hirings than estimated and not all the beneficiaries continued being employees at the vesting date. On March 8, 2022, the Company’s Board of Directors approved a pool of approximately 215,000 shares oriented for retention of key employees and new hires bonuses, under the Stock Awards Program. Vesting of the plan is in a three-years period from the grant date. During 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program (“LTIP”) for executive officers. Main characteristics of the program are: ● All executive officers are eligible. ● Grants are awarded annually to executive officers. F-54 Table of Contents ● The components of the Program are the following: - - - 20% Time-based Restricted Share Units (RSUs) vesting ratably in three equal installments on each of the first three anniversaries of the grant date; 35% Relative Performance Share Units based on relative total shareholder return (TSR) and measured over three-year performance period relative to peer group; and 45% Absolute Performance Share Units (PSUs) based on absolute total shareholder return (TSR) and measured over three-year performance period. In February 2023, 246,110 common shares were allotted to the trustee of the Employee Beneficiary Trust (“EBT”) as a consequence of the vesting of the first tranche of the abovementioned plan, and the Compensation Committee approved a new grant effective as of February 14, 2023, of 197,197 shares to vest during a three-year period. In December 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program for employees and new hirings. Main characteristics of the program are: ● All employees (non-top management) and new hirings are eligible. ● 3-year program, with a grant date of January 2, 2023, or the date on which the employees are hired. ● The components of the program are the following: - - - 30% Time-based RSUs: vesting annually ratably in three equal installments; 30% Company Performance: measured over three-year performance period (December 2022-December 2025); and 40% Absolute Performance Shares: share price at the date of vesting must be higher than the share price at the date of grant or date of hiring. ● The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026. Details of these costs and the characteristics of the different stock awards programs and other share-based payments are described in the following table: Year of issuance 2023 2022 2020 Subtotal Shares granted to Non-Executive Directors Shares granted to Executive Directors (a) VCP (b) LTIP for executives Awards at the Awards granted Awards Awards Awards at Charged to net profit/loss year end 2023 2022 2021 in the year beginning exercised forfeited No. of Shares Amounts in US$ '000 — 191,400 405,919 597,319 — 375,937 — 571,984 1,545,240 795,412 12,000 807,412 99,590 — — 268,129 1,175,131 (105,695) — (6,112) (9,444) (253,889) (61,980) (365,696) (71,424) (99,590) — — (359,271) — — — (248,825) (779,110) (365,696) 689,717 187,844 90,050 967,611 1,452 990 — 2,442 — 1,133 126 — 3,627 7,328 16,666 — 591,288 1,575,565 — 619 1,691 2,310 1,041 3,560 2,016 2,111 11,038 — — 862 862 861 800 4,098 — 6,621 (a) (b) Includes compensation agreements from CEO transition. The plan named Value Creation Plan (“VCP”), oriented to key management, was approved in 2019. The performance metrics were not achieved to execute this program and is not currently in place. The awards that are forfeited correspond to employees that had left the Group before vesting date. Note 32 Interests in Joint operations The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Ecuador, Brazil, Chile and Argentina. GeoPark is the operator in the Llanos 34, Llanos 86, Llanos 87, Llanos 104, Llanos 123, Llanos 124, Mecaya, PUT-8, PUT-9, PUT-36, Tacacho and Terecay Blocks in Colombia, in the Espejo Block in Ecuador, in the POT-T-785 Block in Brazil, and in the Flamenco, Campanario and Isla Norte Blocks in Chile. F-55 Table of Contents The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been recognized in the Consolidated Statement of Financial Position and Statement of Income: Subsidiary / Joint operation 2023 GeoPark Colombia S.A.S. Llanos 34 Block Llanos 32 Block Llanos 86 Block Llanos 87 Block Llanos 94 Block Llanos 104 Block Llanos 123 Block Llanos 124 Block CPO-5 Block CPO-4-1 Block Amerisur Exploración Colombia Limitada Sucursal Colombia Mecaya Block PUT-8 Block PUT-9 Block PUT-36 Block Tacacho Block Terecay Block GeoPark Ecuador S.A. Espejo Perico GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. Manati Field POT-T‑785 GeoPark TdF S.p.A. Flamenco Block Campanario Block Isla Norte Block GeoPark Argentina S.A. Los Parlamentos Block Puelen Block Interest PP&E Other Total Assets Assets Total Liabilities Net Assets/ Operating (Liabilities) Revenue profit (loss) 45 % 354,361 12.5 % 2,493 50 % 5,532 50 % 16,621 50 % — 50 % 5,536 50 % 16,292 50 % — 30 % 182,484 102 50 % 50 % 3,948 50 % 9,118 50 % 4,454 50 % 2,950 — 50 % — 50 % 50 % 10,072 50 % 22,231 359,440 5,079 2,493 — 5,759 227 17,271 650 — — 5,856 320 17,327 1,035 170 170 — 182,484 109 7 51 306 68 50 103 36 213 — 3,999 9,424 4,522 3,000 103 36 10,285 22,231 (7,641) (655) — (1,211) (336) — (520) (166) (1,540) — (40) — — — — — (467) (889) 351,799 1,838 5,759 16,060 (336) 5,856 16,807 4 180,944 109 464,146 7,811 — 1,527 — — 8,648 — 148,594 — 3,959 9,424 4,522 3,000 103 36 — — — — — — 9,818 21,342 1,450 17,647 10 % 5,233 160 70 % 17,546 — 22,779 160 (12,788) — 9,991 160 14,019 — 50 % 50 % 60 % 50 % 18 % — — — — — — — — — 2 — — — — 2 (1,336) (5,438) (1,018) — (60) (1,336) (5,438) (1,018) — (58) — — — — — 295,556 5,661 (187) (17,722) (1,044) (186) 4,006 (7,496) 50,032 (96) (66) (8) (66) (2) (8) (8) (1,897) 258 4,955 — (178) (5,113) (1,000) (7,086) (51) F-56 Table of Contents Subsidiary / Joint operation 2022 GeoPark Colombia S.A.S. Llanos 34 Block Llanos 32 Block Llanos 86 Block Llanos 87 Block Llanos 94 Block Llanos 104 Block Llanos 123 Block Llanos 124 Block CPO-5 Block CPO-4-1 Block Amerisur Exploración Colombia Limitada Sucursal Colombia Mecaya Block PUT-8 Block PUT-9 Block PUT-36 Block Tacacho Block Terecay Block GeoPark Ecuador S.A. Espejo Perico GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. Manati Field POT-T‑785 GeoPark TdF S.p.A. Flamenco Block Campanario Block Isla Norte Block GeoPark Argentina S.A. CN-V Block Los Parlamentos Block Puelen Block Sierra del Nevado Block Interest PP&E Other Total Assets Assets Total Net Assets/ Liabilities (Liabilities) Revenue Operating profit (loss) 45 % 295,639 12.5 % 2,324 970 50 % 50 % 15,038 50 % 576 50 % 1,001 50 % 1,172 50 % 1,207 30 % 199,748 102 50 % 50 % 3,908 50 % 7,927 50 % 4,420 50 % 2,931 — 50 % — 50 % 297,923 2,284 2,324 — 970 — 15,038 — 576 — 1,001 — 1,172 — — 1,207 — 199,748 102 — — — — — — — 3,908 7,927 4,420 2,931 — — (2,104) (371) — (41) (233) — — — (344) — (17) — — — — — 295,819 1,953 970 14,997 343 1,001 1,172 1,207 199,404 102 3,891 7,927 4,420 2,931 — — 721,326 9,791 — — — — — — 184,160 — — — — — — — 50 % 10,727 50 % 15,195 593 8,506 11,320 23,701 (5,406) (5,315) 5,914 18,386 — 10,671 402,425 7,066 (60) (390) (5,632) (60) (60) (60) 69,422 — (62) (61) (62) (60) (3,699) (300) (5,151) 4,533 10 % 5,665 168 70 % 18,537 — 24,202 168 (12,602) — 11,600 168 19,873 — 11,240 — 50 % 50 % 60 % 50 % 50 % 18 % 18 % — — — — — — — — — — — — 10 1 — — — — — 10 1 (1,314) (422) (160) (14) (93) (105) (4) (1,314) (422) (160) (14) (93) (95) (3) — — — — — — — (261) (115) (131) (131) (176) (69) (8) F-57 Table of Contents Subsidiary / Joint operation 2021 GeoPark Colombia S.A.S. Llanos 34 Block Llanos 32 Block Llanos 86 Block Llanos 87 Block Llanos 94 Block Llanos 104 Block Llanos 123 Block Llanos 124 Block CPO-5 Block Amerisur Exploración Colombia Limitada Sucursal Colombia Mecaya Block PUT-8 Block PUT-9 Block PUT-36 Block Tacacho Block Terecay Block GeoPark Perú S.A.C. - Sucursal Ecuador Espejo Perico GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. Manati Field POT-T‑785 GeoPark TdF S.p.A. Flamenco Block Campanario Block Isla Norte Block GeoPark Argentina S.A.U. CN-V Block Los Parlamentos Block Puelen Block Sierra del Nevado Block Interest PP&E Other Total Assets Assets Total Net Assets/ Liabilities (Liabilities) Revenue Operating profit (loss) 45 % 260,589 12.5 % 2,730 408 50 % 50 % 1,220 50 % 1,489 434 50 % 907 50 % 50 % 841 30 % 210,154 50 % 3,837 50 % 7,070 50 % 4,342 50 % 2,870 50 % 3,629 226 50 % 262,455 1,866 2,730 — 408 — 1,220 — 1,489 — 434 — 907 — — 841 — 210,154 — — — — — — 3,837 7,070 4,342 2,870 3,629 226 1,210 6,107 (5,573) (197) — — (270) — — — (929) (84) — — — — — (610) (4,535) 50 % 1,132 50 % 4,658 78 1,449 256,882 2,533 408 1,220 1,219 434 907 841 209,225 486,779 7,690 — — — — — — 88,479 341,473 5,378 (60) (60) (171) (60) (60) (60) 55,131 3,753 7,070 4,342 2,870 3,629 226 600 1,572 — — — — — — — — 10 % 6,851 157 70 % 18,269 — 25,120 157 (13,657) — 11,463 157 20,109 — 50 % 50 % 60 % 50 % 50 % 18 % 18 % — — — — — — — — — — 149 — 12 1 — — — 149 — 12 1 (2,082) (551) (138) (528) — (18) (5) (2,082) (551) (138) (379) — (6) (4) — — — — — — — — — — — — — (589) (669) 9,899 — (137) (106) (122) (839) (285) (55) (10) Capital commitments are disclosed in Note 33.2. Note 33 Commitments 33.1 Royalty and economic rights commitments 33.1.1 Royalty In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using the level of production sliding scale detailed below: Average daily production in barrels Up to 5,000 5,000 to 125,000 125,000 to 400,000 400,000 to 600,000 Greater than 600,000 Production Royalty rate 8% 8% + (production - 5,000) * 0.1 20% 20% + (production - 400,000) * 0.025 25% The production royalty rate depends on the crude quality. When the API is lower than 15°, the payment is reduced to the 75% of the total calculation. F-58 Table of Contents In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a concession, the ANP takes into consideration, among other factors, the geological risks involved and the production levels expected. In the Manati Block, royalties are calculated at 7.5% of gas production. In Chile, royalties are payable to the Chilean Government. In the Fell Block, royalties were calculated at 5% of crude oil production sold and 3% of gas production sold. In the Flamenco Block, Campanario Block and Isla Norte Block, royalties were calculated at 5% of oil and gas production sold. 33.1.2 Overriding royalty GeoPark is obligated to pay an overriding royalty of 4% and 2.5%, respectively, to the previous owners of the Llanos 34 and CPO-5 Blocks, based on the production and sale of hydrocarbons discovered in the blocks. During 2023, the Group has accrued US$ 27,453,000 (US$ 34,032,000 in 2022 and US$ 22,562,000 in 2021) in relation with these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they are exploratory blocks with no production during 2023, these agreements had no impact on the Group’s results. 33.1.3 Economic rights According to each E&P Contract, the Colombian National Hydrocarbons Agency (“ANH”) has an economic right, offered by the operator at the moment of the ANH bid. This economic right, which is based on the production of the block after royalty discount, is equal to 1% in the Llanos 32, Llanos 34 and Llanos 123 Blocks, 3% in the Llanos 87 Block, 23% in the CPO-5 Block and 0% in the Platanillo Block. When the accumulated production of each field, including the royalties’ volume, exceeds 5,000,000 of barrels and the WTI price exceeds certain price level previously determined, the Group should also deliver to ANH a share of the production net of royalties in accordance with a formula defined in each E&P Contract, which basically depends on the WTI price and the crude quality. 33.2 Capital commitments During 2023, the Group incurred investments of US$ 54,640,000 to fulfil its commitments, at GeoPark’s working interest. 33.2.1 Colombia The future investment commitments assumed by GeoPark, at its working interest, are up to: ● Llanos 32 Block: 5 exploratory wells before February 20, 2022. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments in the block have already been incurred and the ANH approval is pending. ● Llanos 86 Block: 3D seismic and 1 exploratory well (US$ 9,849,000) before June 19, 2026. ● Llanos 87 Block: 3D seismic reprocessing, aerogeophysic and 4 exploratory wells (US$ 13,663,000) before May 14, 2023. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments in the block have already been incurred and the ANH approval is pending. ● Llanos 94 Block: 1 exploratory well (US$ 3,467,000) before October 1, 2025. As of the date of these Consolidated Financial Statements, GeoPark agreed to transfer its 50% working interest to its joint operation partner and thus GeoPark will no longer be liable for this capital commitment in the block. F-59 Table of Contents ● Llanos 104 Block: 3D seismic and 1 exploratory well (US$ 8,752,000) before June 19, 2026. ● Llanos 123 Block: 3D seismic reprocessing, geochemistry and 2 exploratory wells (US$ 7,130,000) before January 14, 2024. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments in the block have already been incurred and the ANH approval is pending. ● Llanos 124 Block: 3D seismic acquisition and reprocessing, geochemistry and 3 exploratory wells (US$ 10,422,000) before January 14, 2024. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments in the block have already been incurred or transferred to another block, and the ANH approval is pending. ● CPO-4-1 Block: 1 exploratory well (US$ 2,922,000) before September 19, 2025. ● CPO-5 Block: 3D seismic acquisition, processing and interpretation and 1 exploratory well (US$ 2,794,000) before May 18, 2027. Pursuant to a private agreement with the joint operation partner, the investment commitment assumed by GeoPark amounts to US$ 9,313,000. As of the date of these Consolidated Financial Statements, the exploratory well has already been drilled and the ANH approval is pending. ● Coati Block: 3D seismic and 2D seismic acquisition (US$ 4,500,000). The evaluation area is currently suspended. On November 3, 2022, GeoPark submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and transfer the pending commitments to other E&P contracts. As of the date of these Consolidated Financial Statements, GeoPark completed the transfer of the pending commitments in the block and the ANH approval is pending. ● Mecaya Block: 3D seismic or 1 exploratory well (US$ 2,000,000). The exploratory period is currently suspended. Pursuant to a private agreement with the joint operation partner, the investment commitment to be incurred by GeoPark amounts to US$ 600,000. ● PUT-8 Block: 3D seismic acquisition and reprocessing and 3 exploratory wells (US$ 13,107,000) before June 14, 2024. Part of the 3D seismic committed in the block has already been acquired during 2020 and 2021. On October 25, 2022, GeoPark submitted to the ANH a request to transfer the investment commitment related to the pending 3D seismic to the Platanillo Block. As of the date of these Consolidated Financial Statements, such investment has been fulfilled and the ANH approval is pending. ● PUT-9 Block: 3D seismic acquisition and 2 exploratory wells (US$ 10,550,000). GeoPark has signed a private agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 4,365,000. The exploratory period is currently suspended. ● PUT-14 Block: 2D seismic acquisition and 1 exploratory well (US$ 16,122,000). On March 10, 2022, GeoPark submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer the pending commitments to the Platanillo and CPO-5 Blocks. As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments have already been incurred and the ANH approval is pending. ● The PUT-36 Block is in a preliminary phase that is suspended as of the date of these Consolidated Financial Statements. During this preliminary phase, GeoPark must request from the Ministry of Interior a certificate that indicates presence or no presence of indigenous communities and develop previous consultation, if applicable. Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the block over three-years term of phase 1 would be 3D seismic acquisition and 2 exploratory wells (US$ 11,742,000). F-60 Table of Contents ● Tacacho Block: 2D seismic acquisition, processing and interpretation (US$ 4,080,000). GeoPark has signed a private agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 1,224,000. The exploratory period is currently suspended. On September 21, 2022, GeoPark submitted to the ANH a request for termination of the E&P contract. As of the date of these Consolidated Financial Statements, the request is under review by the ANH. ● Terecay Block: 2D seismic acquisition, processing and interpretation (US$ 4,046,000). GeoPark has signed a private agreement with the joint operation partner resulting in the total investment commitment to be incurred by GeoPark amounting to US$ 2,856,000. The exploratory period is currently suspended. On September 21, 2022, GeoPark submitted to the ANH a request for termination of the E&P contract. As of the date of these Consolidated Financial Statements, the request is under review by the ANH. 33.2.2 Ecuador The investment commitments assumed by GeoPark, at its 50% working interest, in the Espejo and Perico Blocks during the first exploratory period are up to: ● Espejo Block: 3D seismic and 4 exploratory wells before June 17, 2025 (US$ 20,912,000). As of the date of these Consolidated Financial Statements, GeoPark has already performed the 3D seismic and drilled two of the four committed exploratory wells. ● Perico Block: 4 exploratory wells before June 16, 2025 (US$ 18,084,000). As of the date of these Consolidated Financial Statements, the total investments needed to fulfill the commitments in the block have already been incurred. 33.2.3 Brazil The future investment commitments assumed by GeoPark are up to: ● POT-T-785 Block: 3D seismic and electromagnetic survey before April 29, 2025 (US$ 72,000). ● REC-T-58 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000). ● REC-T-67 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000). ● REC-T-77 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000). ● POT-T-834 Block: 3D seismic and electromagnetic survey before February 14, 2025 (US$ 151,000). 33.2.4 Chile The remaining investment commitments to be assumed 100% by GeoPark for the second exploratory phase in the Campanario and Isla Norte Blocks are up to: ● Campanario Block: 2 exploratory wells before April 25, 2024 (US$ 5,002,000). ● Isla Norte Block: 1 exploratory well before February 19, 2024 (US$ 867,000). As of December 31, 2023, the Group has established guarantees for its total commitments. As part of the divesting process detailed in Note 36.1, GeoPark remains responsible for these outstanding investment commitments and consequently recognized a corresponding liability as of December 31, 2023. F-61 Table of Contents Note 34 Related parties Controlling interest The main shareholders of GeoPark Limited as of December 31, 2023, based solely on Schedules 13D and 13G filed with the SEC, are: Shareholder James F. Park (a) Gerald E. O’Shaughnessy (b) Compass Group LLC (c) Renaissance Technologies LLC (d) Socoservin Overseas SPF S.à.r.l. (e) Cobas Asset Management, SGIIC, SA (f) Other shareholders Common shares 8,817,251 3,673,392 3,312,589 3,091,863 2,889,315 2,808,406 30,734,704 55,327,520 Percentage of outstanding common shares 15.94 % 6.64 % 5.99 % 5.59 % 5.22 % 5.08 % 55.54 % 100.00 % (a) Held by James F. Park directly and indirectly through GoodRock, LLC, which is controlled by Mr. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2024. 352,400 of Mr. Park’s shares have been pledged pursuant to lending arrangements. (b) Held by Mr. O’Shaughnessy directly and indirectly through GP Investments LLP; GPK Holdings, LLC; The Globe Resources Group, Inc.; and other investment vehicles. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. O’Shaughnessy most recent Schedule 13D filed with the SEC on February 2, 2024. 3,435,000 of Mr. O’Shaughnessy’s shares have been pledged pursuant to lending arrangements. (c) The information set forth above and listed in the table is based solely on the disclosure set forth in Compass Group LLC’s most recent Schedule 13G filed with the SEC on February 14, 2024. (d) The information set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13G filed with the SEC on February 13, 2024. (e) The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’ most recent Schedule 13G filed with the SEC on July 25, 2023. (f) The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset Management’s most recent Schedule 13G filed with the SEC on February 12, 2024. F-62 Table of Contents Balances outstanding and transactions with related parties Account (Amounts in US$´000) 2023 To be recovered from co-venturers To be paid to co-venturers 2022 To be recovered from co-venturers To be paid to co-venturers Geological and geophysical expenses Administrative expenses 2021 To be recovered from co-venturers To be paid to co-venturers Geological and geophysical expenses Administrative expenses Transaction in the year Balances at year end Related Party Relationship — 8,630 (522) — Joint Operations Joint Operations Joint Operations Joint Operations — 8,750 — (2,815) 160 492 Joint Operations Joint Operations — Carlos Gulisano — Pedro E. Aylwin Joint Operations Joint Operations Former Non-Executive Director (a) Former Executive Director (b) — 4,680 — (953) 160 656 Joint Operations Joint Operations — Carlos Gulisano — Pedro E. Aylwin Joint Operations Joint Operations Former Non-Executive Director (a) Former Executive Director (b) (a) Corresponding to consultancy services. Carlos Gulisano acted as a Director of the Company until July 2022. (b) Corresponding to wages and salaries acting as Director of Legal and Governance. In 2022, also includes consultancy services. In addition, Aylwin, Mendoza, Luksic & Valencia Law firm, where Pedro Aylwin is a partner and has a participation through Asesorías e Inversiones A&P Ltda, provided general legal services to all the Chilean entities, in Chilean corporate, labor, environmental, regulatory, and commercial laws. There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11. Note 35 Auditors Fees Amounts in US$‘000 Audit fees Audit related fees Tax services fees Total Auditors Fees 2023 2022 977 34 3 1,014 946 24 27 997 2021 1,088 — 47 1,135 Fees are shown net of VAT and other associated tax charges. On October 17, 2023, Ernst & Young Audit S.A.S. (“EY Colombia”), member of Ernst & Young Global Limited, was appointed as the Group’s external auditor, effective for the consolidated audit for the year ended December 31, 2023, succeeding Pistrelli, Henry Martin y Asociados S.R.L. (“EY Argentina”), also member of Ernst & Young Global Limited, that served as the Group’s external auditor from 2020 to 2023. Note 36 Business transactions 36.1 Chile On December 20, 2023, GeoPark signed a Stock Purchase Agreement to sell its wholly owned subsidiary GeoPark Chile S.p.A. and its subsidiaries, GeoPark Fell S.p.A., GeoPark TdF S.p.A. and GeoPark Magallanes Limitada, which comprise the entire business of GeoPark in Chile, for a total consideration of US$ 4,000,000, subject to working capital adjustments. At that date, GeoPark collected an advanced payment of US$ 450,000. F-63 Table of Contents As part of the agreement, GeoPark remains responsible for the outstanding investment commitments in the Campanario and Isla Norte Blocks for US$ 5,002,000 and US$ 867,100, respectively. Consequently, as of December 31, 2023, GeoPark recognized a liability for the full amount of those commitments. Additionally, GeoPark keeps the private right over unconventional activities that would be carried out in the Fell Block and 95% of the revenue derived from such activities over the current operating contract. The divestment transaction closed on January 18, 2024, and consequently GeoPark received an additional payment of US$ 2,792,000, plus a preliminary working capital adjustment of US$ 486,000. The remaining outstanding amount of US$ 758,000 was agreed to be received in 23 monthly equal installments. As of December 31, 2023, the amount of Property, plant and equipment and Right-of-use assets corresponding to the abovementioned subsidiaries and the liabilities associated with them have been classified as held for sale for US$ 28,419,000 and US$ 26,948,000, respectively. Immediately before the classification as held for sale, the recoverable amount of the net assets was estimated and an impairment loss of US$ 13,332,000 was recognized in the Consolidated Statement of Income. In addition, the deferred income tax asset was written down for US$ 2,533,000 as it was assessed as non-recoverable due to the transaction. The restructuring and other costs incurred because of the divestment process for US$ 3,873,000 were recognized within the ‘Other (expenses) income’ line item in the Consolidated Statement of Income. 36.2 Los Parlamentos Block (Argentina) On October 27, 2023, GeoPark agreed to transfer its 50% working interest in the Los Parlamentos Block in Argentina to its joint operation partner and thus, once formally approved by local authorities, GeoPark will no longer be liable to remaining capital commitments or other legal obligations resulting from its participation in the block. As a result of this transaction, GeoPark incurred in a net loss of US$ 2,939,000 in the Consolidated Statement of Income, which is composed by a loss of US$ 7,023,000 within the ‘Other (expenses) income’ line item due to the payment to the joint operation partner, net of a gain of US$ 4,084,000 within the ‘Foreign exchange (loss) gain’ line item due to transactions with U.S. dollar-denominated Argentine securities contributed to the local subsidiary when transferred and disposed in Argentina. 36.3 Aguada Baguales, El Porvenir and Puesto Touquet Blocks (Argentina) In August 2021, the Company’s Board of Directors approved the decision to evaluate farm-out or divestment opportunities to sell its 100% working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina, including the associated gas transportation license through the Puesto Touquet pipeline. On November 3, 2021, GeoPark signed a sale and purchase and assignment agreement for a total consideration of US$ 16,000,000, subject to working capital adjustment. At that moment, GeoPark collected an advance payment of US$ 1,600,000. The divestment transaction closed on January 31, 2022, after the corresponding regulatory approvals were granted and GeoPark received the remaining outstanding payment from the purchaser. In April 2022, GeoPark paid a working capital adjustment amounting to US$ 370,000. As a consequence of this transaction, GeoPark recognized a gain of US$ 3,983,000 within the ‘Other (expenses) income’ line item. As of December 31, 2021, the amount of Property, plant and equipment related to the blocks and the liabilities associated with them had been classified as held for sale. Immediately before the classification as held for sale, the recoverable amount of the blocks was estimated and an impairment reversal of US$ 13,307,000 was recognized in the Consolidated Statement of Income. The reversal was limited so that the carrying amount of the blocks does not exceed the lower of its recoverable amount, or the carrying amount that would have been determined, net of depreciation, had no impairment loss been recognized for the blocks in prior years (see Note 37). F-64 Table of Contents 36.4 REC-T-128 Block (Brazil) In 2021, GeoPark performed a farm-out transaction to sell its 70% interest in the REC-T-128 Block in Brazil. The total consideration was US$ 1,100,000, which was collected at closing in 2021, plus a contingent payment of up to US$ 710,000, subject to international oil price and field production performance. On August 1, 2022, GeoPark collected the contingent payment of US$ 710,000. Note 37 Impairment test on Property, plant and equipment The management of the Group considers as cash-generating unit (“CGU”) each of the blocks or group of blocks in which the Group has working or economic interests. The blocks with no material investment on property, plant and equipment or with operations that are not linked to oil and gas prices were not subject to the impairment test. As of December 31, 2023, the Chilean business divestment transaction described in Note 36.1 was considered to be an impairment indicator for the Fell Block, as the carrying amount of the net assets related to the block exceeded their fair value less cost of disposal. Consequently, the net assets related to the Fell Block were impaired to their known selling price. Additionally, Management assessed impairment indicators for each of the other CGUs, such as future Brent oil prices based on internal estimates and other available sources, the amounts of reserves certified by D&M, changes in market and tax conditions, between others, and concluded that there were no impairment indicators at year-end. As a consequence of the evaluation, the following amounts of impairment loss were (recognized) reversed: Amounts in US$‘000 Chile (a) Argentina (b) 2023 (13,332) — (13,332) 2022 2021 — (17,641) — 13,307 — (4,334) (a) Recognition of impairment loss in the Fell Block due to the known selling price of the related net assets in the context of the transaction described in Note 36.1 in 2023, and due to the decline in the proved reserves estimation in 2021. (b) Reversal of impairment loss in the Aguada Baguales and El Porvenir Blocks due to the known market price of the blocks in the context of the transaction described in Note 36.3. Note 38 Supplemental information on oil and gas activities (unaudited) The following information is presented in accordance with ASC No. 932 “Extractive Activities- Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on December 31, 2008. This information includes the Group’s oil and gas production activities carried out in each country. Table 1 - Costs incurred in exploration, property acquisitions and development The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2023, 2022 and 2021. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves. F-65 Table of Contents Amounts in US$‘000 Year ended December 31, 2023 Acquisition of properties Proved Unproved Total property acquisition Exploration Development (a) Total costs incurred Amounts in US$‘000 Year ended December 31, 2022 Acquisition of properties Proved Unproved Total property acquisition Exploration Development (a) Total costs incurred Amounts in US$‘000 Year ended December 31, 2021 Acquisition of properties Proved Unproved Total property acquisition Exploration Development (a) Total costs incurred Colombia Ecuador Brazil Chile Argentina Total — — — 66,953 125,997 192,950 — — — 13,331 372 13,703 — — — 107 255 362 — — — 56 (564) (508) — — — 1,481 — 1,481 — — — 81,928 126,060 207,988 Colombia Ecuador Brazil Chile Argentina Total — — — 48,771 89,231 138,002 — — — 26,521 648 27,169 — — — — (212) (212) — — — 116 9,952 10,068 — — — 779 — 779 — — — 76,187 99,619 175,806 Colombia Brazil Chile Argentina Total — — — 40,828 81,310 122,138 — — — 3 (2,212) (2,209) — — — 3,940 1,900 5,840 — — — 998 2 1,000 — — — 45,769 81,000 126,769 (a) Includes the effect of change in estimate of assets retirement obligations. Table 2 - Capitalized costs related to oil and gas producing activities The following table presents the capitalized costs as of December 31, 2023, 2022 and 2021, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates. Amounts in US$‘000 As of December 31, 2023 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects Unproved properties Gross capitalized costs Accumulated depreciation Total net capitalized costs Colombia Ecuador Brazil Chile (b) Total 165,666 841,063 15,770 69,823 1,092,322 (447,716) 644,606 — 31,149 — 10,426 41,575 (8,522) 33,053 4,121 48,448 11 330 52,910 (47,388) 5,522 74,491 330,024 — — 404,515 (379,448) 25,067 244,278 1,250,684 15,781 80,579 1,591,322 (883,074) 708,248 (a) Includes capitalized amounts related to asset retirement obligations and impairment loss recognized in Chile for US$ 13,332,000. (b) Classified as ‘Assets held for sale’ as of December 31, 2023, due to the divestment process closed in January 2024. See Note 36.1. F-66 Table of Contents Amounts in US$‘000 As of December 31, 2022 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects Unproved properties Gross capitalized costs Accumulated depreciation Total net capitalized costs Colombia Ecuador Brazil Chile Total 144,672 672,424 16,099 102,760 935,955 (354,981) 580,974 — 18,191 — 9,991 28,182 (2,316) 25,866 3,565 44,716 268 290 48,839 (42,885) 5,954 74,490 343,926 113 — 418,529 (371,171) 47,358 222,727 1,079,257 16,480 113,041 1,431,505 (771,353) 660,152 (a) Includes capitalized amounts related to asset retirement obligations. Amounts in US$‘000 As of December 31, 2021 Proved properties (a) Equipment, camps and other facilities Mineral interest and wells Other uncompleted projects Unproved properties (b) Gross capitalized costs Accumulated depreciation Total net capitalized costs Colombia Brazil Chile Argentina Total 125,078 580,931 26,136 94,419 826,564 (282,616) 543,948 3,333 42,008 250 271 45,862 (38,741) 7,121 72,766 334,993 818 — 408,577 (358,417) 50,160 201,177 — 957,932 — 27,204 — — 94,690 — 1,281,003 — (679,774) 601,229 — (b) Includes capitalized amounts related to asset retirement obligations, impairment loss recognized in Chile for US$ 17,641,000 and impairment loss reversed in Argentina for US$ 13,307,000. (a) Do not include Ecuador capitalized costs. Table 3 - Results of operations for oil and gas producing activities The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2023, 2022 and 2021. Income tax for the years presented was calculated utilizing the statutory tax rates. Amounts in US$‘000 Year ended December 31, 2023 Revenue Production costs, excluding depreciation Operating costs Royalties and economic rights in cash Total production costs Exploration expenses Accretion expense (a) Impairment loss for non-financial assets Depreciation, depletion and amortization Results of operations before income tax Income tax expense Results of oil and gas operations Colombia Ecuador Brazil Chile Argentina Total 702,401 19,097 14,019 15,644 — 751,161 (10,242) (10,242) (309) (87) — (6,205) 2,254 (564) 1,690 (3,850) — (1,096) (4,946) (90) (560) (7,678) (548) (8,226) (56) (1,478) — (13,332) (8,278) (15,726) — (15,726) (1,047) 7,376 (2,508) 4,868 — (142,782) — (84,877) — (227,659) (38,331) (1,481) — (2,794) — (13,332) — (108,265) 360,780 — (168,833) 191,947 (1,481) (1,481) (121,012) (83,233) (204,245) (36,395) (669) — (92,735) 368,357 (165,761) 202,596 F-67 Table of Contents Amounts in US$‘000 Year ended December 31, 2022 Revenue Production costs, excluding depreciation Operating costs Royalties and economic rights in cash Total production costs Exploration expenses Accretion expense (a) Depreciation, depletion and amortization Results of operations before income tax Income tax expense Results of oil and gas operations Amounts in US$‘000 Year ended December 31, 2021 Revenue Production costs, excluding depreciation Operating costs Royalties and economic rights in cash Total production costs Exploration expenses Accretion expense (a) Impairment loss for non-financial assets Depreciation, depletion and amortization Results of operations before income tax Income tax (expense) benefit Results of oil and gas operations Colombia Ecuador Brazil Chile Argentina Total 978,423 10,671 19,873 29,196 1,962 1,040,125 (78,323) (249,303) (327,626) (28,424) (621) (72,386) 549,366 (192,278) 357,088 (3,220) (3,753) — (1,546) (5,299) — (504) (1,509) 12,561 (4,271) 8,290 (3,220) (4,768) — (2,315) 368 (92) 276 (12,961) (1,165) (14,126) (116) (1,516) (12,754) 684 (103) 581 (1,306) (273) (1,579) (779) — — (396) (99,563) (252,287) (351,850) (34,087) (2,641) (88,964) 562,583 — (196,744) 365,839 (396) Colombia Brazil Chile Argentina Total 618,268 20,109 21,471 28,695 688,543 (72,043) (106,341) (178,384) (11,276) (576) — (54,588) 373,444 (115,768) 257,676 (2,954) (1,642) (4,596) (10,280) (770) (11,050) (14,490) (4,270) (18,760) (535) — (4,509) (1,319) — (17,641) (12,806) (25,854) 3,878 (21,976) (2,933) 12,045 (4,095) 7,950 (998) (710) 13,307 (8,152) 13,382 (4,684) 8,698 (99,767) (113,023) (212,790) (16,783) (3,140) (4,334) (78,479) 373,017 (120,669) 252,348 (a) Represents accretion of ARO and other environmental liabilities. Table 4 - Reserve quantity information Estimated oil and gas reserves Proved reserves represent estimated quantities of oil (including crude oil and condensate) and natural gas, which available geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history. The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008. The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, 2023, 2022, 2021 and 2020 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton Corp. prepared its proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S– X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC F-68 Table of Contents 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities). Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be exactly measured, and the reserve estimation depends on the quality of available information and the interpretation and judgement of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based. The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2023, 2022, 2021 and 2020 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf): As of December 31, 2023 As of December 31, 2022 As of December 31, 2021 As of December 31, 2020 Oil and Oil and Oil and condensate Natural gas condensate Natural gas condensate Natural gas (Mbbl) (MMcf) (Mbbl) (MMcf) (Mbbl) (MMcf) Oil and condensate (Mbbl) Natural gas (MMcf) Net proved developed Colombia (a) Ecuador (b) Brazil (c) Chile (d) Argentina (e) Total consolidated Net proved undeveloped Colombia (f) Ecuador (b) Chile (d) Argentina (g) Total consolidated 43,120 1,017 28 619 — 44,784 16,225 1,278 479 — 17,982 1,075 — 8,888 9,956 — 19,919 46,623 322 8 1,115 — 48,068 1,065 — 9,443 14,103 — 24,611 47,766 — 43 755 1,186 49,750 1,207 — 13,601 15,196 3,379 33,383 43,817 — 34 798 1,685 46,334 — 17,765 — — 476 855 — — 18,241 855 — 31,019 — — — 575 603 — — 32,197 — 45,240 — — 1,229 1,563 104 — 46,573 1,563 1,695 — 13,927 19,054 5,599 40,275 — — 5,661 — 5,661 Total proved reserves 62,766 20,774 66,309 24,611 81,947 34,946 92,907 45,936 (a) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 94% and 6% (96% and 4% in 2022, 98% and 2% in 2021, and 97% and 3% in 2020) of the proved developed reserves, respectively. (b) Perico Block accounts for 100% of the reserves (Perico and Espejo Blocks accounted for 85% and 15% of the reserves, respectively, in 2022). (c) BCAM-40 Block accounts for 100% of the reserves. (d) Fell Block accounts for 100% of the reserves. (e) Aguada Baguales, Puesto Touquet and El Porvenir Blocks accounted for 45%, 21% and 33% in 2021 (50%, 26% and 24% in 2020) of the proved developed reserves, respectively. (f) Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for 97% and 3% (95% and 5% in 2022, 97% and 3% in 2021, and 96% and 4% in 2020) of the proved undeveloped reserves, respectively. (g) Aguada Baguales Block accounted for 100% of the proved undeveloped reserves. F-69 Table of Contents Table 5 - Net proved reserves of oil, condensate and natural gas Net proved reserves (developed and undeveloped) of oil and condensate: Thousands of barrels Reserves as of December 31, 2020 Increase (decrease) attributable to: Revisions (a) Extensions and discoveries (b) Production Reserves as of December 31, 2021 Increase (decrease) attributable to: Revisions (c) Extensions and discoveries (d) Disposal of Minerals in place (e) Production Reserves as of December 31, 2022 Increase (decrease) attributable to: Revisions (f) Extensions and discoveries (g) Production Reserves as of December 31, 2023 Colombia 89,057 Ecuador — Brazil 34 Chile 2,027 Argentina 1,789 Total 92,907 (3,207) 3,375 (10,440) 78,785 (2,677) 204 — (11,924) 64,388 3,617 2,549 (11,209) 59,345 — — — — — 632 — (310) 322 324 1,937 (288) 2,295 18 — (9) 43 (27) — — (8) 8 26 — (6) 28 (597) — (100) 1,330 (169) 603 (434) 1,789 (3,955) 3,978 (10,983) 81,947 — (2,282) 422 836 — — (1,760) — (1,760) (29) (12,432) — 66,309 (161) 1,591 (412) — (81) 1,098 3,555 — — 4,486 — (11,584) — 62,766 (a) For the year ended December 31, 2021, the Group’s oil and condensate proved reserves were revised downward by 4.0 mmbbl. The primary factors leading to the above were: - Lower than expected performance from the existing wells that reduced the proved developed reserves in Colombia (8.9 mmbbl), in Argentina (0.3 mmbbl), and in Chile (0.3 mmbbl). - A decrease of 0.6 mmbbl in Chile due to a change in a previously adopted development plan in the Fell Block. - Such decrease was partially offset by a higher average oil prices resulted in a 5.7 mmbbl, 0.1 mmbbl and 0.3 mmbbl increase in reserves from the blocks in Colombia, Argentina and Chile, respectively. (b) In Colombia, the extensions and discoveries are primary due to the Tigui Field appraisal wells and in Argentina are due to the Aguada Baguales Field. (c) For the year ended December 31, 2022, the Group’s oil and condensate proved reserves were revised downward by 2.3 mmbbl. The primary factors leading to the above were: - A decrease of 3.6 mmbbl in Colombia due to a change in the royalties payment in certain fields from cash to kind. - Such decrease was partially offset by a higher average oil prices resulted in a 0.6 mmbbl and 0.1 mmbbl increase in reserves from the blocks in Colombia and Chile, respectively. - Higher than expected performance from the existing wells that increase the proved reserves in Colombia (0.3 mmbbl) and in Chile (0.3 mmbbl). (d) In Colombia, the extensions and discoveries are primary due to the Cante Flamenco new field in CPO-5 Block and in Ecuador are due to the Jandaya, Yin and Tui new fields in the Perico Block and the Pashuri field in the Espejo Block. (e) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3). (f) For the year ended December 31, 2023, the Group’s oil and condensate proved reserves were revised upwards by 3.5 mmbbl. The primary factors leading to the above were: - An increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan. - An increase of 1.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells. - An increase of 0.4 mmbbl in Colombia due to a change in the royalties’ payment in certain fields from kind to cash. - An increase of 0.3 mmbbl in Ecuador due to higher average oil prices. - Such increase was partially offset by lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl. (g) The extensions and discoveries are primarily due to various fields in the Llanos Basin in Colombia and the Jandaya field extension in the Perico Block in Ecuador. F-70 Table of Contents Net proved reserves (developed and undeveloped) of natural gas: Millions of cubic feet Reserves as of December 31, 2020 Increase (decrease) attributable to: Revisions (a) Production Reserves as of December 31, 2021 Increase (decrease) attributable to: Revisions (b) Disposal of Minerals in place (c) Production Reserves as of December 31, 2022 Increase (decrease) attributable to: Revisions (d) Production Reserves as of December 31, 2023 Colombia Brazil Chile 1,695 13,927 24,715 Argentina 5,599 Total 45,936 14 (502) 1,207 141 — (283) 1,065 219 (209) 1,075 3,470 (3,796) 13,601 (886) — (3,272) 9,443 1,659 (2,214) 8,888 (3,553) (4,403) 16,759 1,501 — (4,157) 14,103 (9) (3,283) 10,811 (636) (1,584) 3,379 (705) (10,285) 34,946 — (3,227) (152) — 756 (3,227) (7,864) 24,611 1,869 — — (5,706) — 20,774 (a) For the year ended December 31, 2021, the Group’s proved natural gas reserves were revised downward by 0.7 billion cubic feet. This was the combined effect of: - A decrease of proved developed reserves due to lower performance of existing wells in Argentina (1.6 billion cubic feet) and in Chile (2.7 billion cubic feet) partially offset by better-than-expected performance in the Manati Field in Brazil (2.5 billion cubic feet). - A decrease of 3.4 billion cubic feet in Chile due to the revision of the type well associated with the incremental activity that reduced the proved undeveloped reserves. - A decrease of 1.5 billion cubic feet in Chile due to a change in a previously adopted development plan in the Fell Block. -Such decrease was partially offset by higher average prices which resulted in an increase of 4.0 billion cubic feet, 1 billion cubic feet and 1 billion cubic feet in Chile, Brazil, and Argentina, respectively. (b) For the year ended December 31, 2022, the Group’s proved natural gas reserves were revised upwards by 0.8 billion cubic feet. This was the combined effect of: - An increase of proved reserves due to better performance of existing wells in Chile (0.8 billion cubic feet) and the Llanos 32 block in Colombia (0.1 billion cubic feet). - Higher average prices resulted in an increase of 0.7 billion cubic feet and 0.8 billion cubic feet increase in gas reserves in Chile and Brazil, respectively. - The above was partially offset by lower-than-expected performance of Manati Field in Brazil (1.6 billion cubic feet). (c) The disposal in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 36.3). (d) For the year ended December 31, 2023, the Group’s proved natural gas reserves were revised upwards by 1.9 billion cubic feet. This was the effect of higher-than-expected performance from the existing wells in the Manati Block in Brazil (1.7 billion cubic feet) and the Llanos 32 Block in Colombia (0.2 billion cubic feet). Revisions refer to changes in interpretation of discovered accumulations and some technical and logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases. Table 6 - Standardized measure of discounted future net cash flows related to proved oil and gas reserves The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future net cash flows were estimated using the average first day-of-the-month price during the 12-month period for 2023, 2022 and 2021 and using a 10% annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation F-71 Table of Contents installations and abandonment costs. These future development costs were estimated based on evaluations made by the Group. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have interests, as of the date this supplementary information was filed. This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons. Amounts in US$‘000 As of December 31, 2023 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows As of December 31, 2022 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows As of December 31, 2021 Future cash inflows Future production costs Future development costs Future income taxes Undiscounted future net cash flows 10% annual discount Standardized measure of discounted future net cash flows Colombia Ecuador Brazil Chile Argentina Total 140,607 (45,052) (13,768) (27,648) 54,139 (11,436) 42,703 75,757 (22,815) (1,204) (4,036) 47,702 (6,476) 41,226 26,553 (8,094) (297) 65,002 (29,519) (1,955) — (1,761) 31,767 (8,856) 22,911 18,162 (2,504) 15,658 — 89,208 — (34,930) — (1,955) — (3,449) — 48,874 — (7,171) — 41,703 111,384 (50,343) (41,359) — 19,682 5,205 24,887 190,449 (72,411) (40,659) — 77,379 (13,094) 64,285 136,152 (69,067) (40,339) — 26,746 6,121 32,867 — 4,355,434 — (1,752,099) (203,376) — — (795,993) — 1,603,966 — (442,957) — 1,161,009 — 5,511,603 — (1,743,842) — (225,612) — (1,193,419) — 2,348,730 — (864,075) — 1,484,655 109,678 (61,660) (49,200) (2,947) (4,129) 4,471 342 4,716,229 (1,881,211) (288,955) (760,601) 1,785,462 (492,729) 1,292,733 4,027,686 (1,633,889) (147,045) (764,309) 1,482,443 (430,250) 1,052,193 5,229,599 (1,633,818) (182,701) (1,191,658) 2,221,422 (839,621) 1,381,801 4,381,191 (1,715,554) (197,461) (754,205) 1,713,971 (496,150) 1,217,821 F-72 Table of Contents Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves Colombia Ecuador Brazil — 25,378 759,233 Amounts in US$‘000 Present value as of December 31, 2020 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Net changes in income taxes Accretion of discount Present value as of December 31, 2021 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Disposal of Minerals in place Net changes in income taxes Accretion of discount Present value as of December 31, 2022 Sales of hydrocarbon, net of production costs Net changes in sales price and production costs Changes in estimated future development costs Extensions and discoveries less related costs Development costs incurred Revisions of previous quantity estimates Net changes in income taxes Accretion of discount Present value as of December 31, 2023 Chile Argentina 17,032 (11,520) 64,048 (18,731) — 4,111 (23,776) — 1,703 32,867 (19) (16,855) (3,145) 20,674 (1,020) — 465 244 (2) 342 Total 801,624 (560,896) 1,005,171 99,168 79,913 91,988 (88,204) (257,154) 121,123 1,292,733 — (15,677) — 19,393 861 — — — — — — 11,957 — (2,780) — 2,571 — 41,703 (2,732) (15,317) (14,697) 39,457 — (6,909) (22,675) (933) — — — 11,153 15,513 — — 3,287 64,285 (10,483) 28,873 — — (2,441) — — 1,673 — 4,515 — 22,911 15,658 (6,673) (2,893) (17,908) 63,619 500 10,642 (21,808) 1,566 42,703 (8,143) 21,490 (4,440) — — 9,159 (2,218) 2,467 41,226 (6,362) (33,595) 5,142 — 7 (11,019) — 6,429 24,887 — (924,280) 989,474 — 59,566 — 35,627 — 105,348 — (74,779) — (342) (342) — (203,697) — 205,005 — 1,484,655 — (512,703) — (611,666) (7,745) — 136,376 — 116,503 — 113,038 — 174,743 — — 267,808 — 1,161,009 (516,844) 924,875 96,364 80,933 87,877 (76,850) (254,618) 116,851 1,217,821 (891,534) 956,926 93,657 6,754 94,195 (87,851) — (205,370) 197,203 1,381,801 (491,525) (596,668) 9,461 72,757 115,996 104,256 198,769 257,346 1,052,193 F-73 Exhibit 2.4 DESCRIPTION OF SECURITIES The following description of our capital stock is a summary and does not purport to be complete. It is subject to and qualified in its entirety by reference to our by-laws, which are incorporated by reference as an exhibit to the Annual Report on Form 20-F for the year ended December 31, 2023 of which this Exhibit is a part. We encourage you to read the bylaws for additional information. General We are an exempted company with limited liability incorporated under the laws of Bermuda with registration number 33273 from the Registrar of Companies. The rights of our shareholders will be governed by Bermuda law and by our memorandum of association and by-laws. Bermuda company law differs in some material respects from the laws generally applicable to Delaware corporations. Below is a summary of some of those material differences. Share Capital Our share capital consists of common shares only. Our authorized share capital consists of 5,171,949,000 common shares of par value US$0.001 per share. As of March 19, 2024, there are 55,470,850 common shares outstanding. All of our issued and outstanding common shares are fully paid and non-assessable. We also have employee incentive programs, pursuant to which we have granted share awards to our senior management and certain key employees. According to our bye-laws, if our share capital is divided into different classes of shares, the rights attached to any class (unless otherwise provided by the terms of issue of the shares of that class) may, whether or not the Company is being wound-up, be varied with the consent in writing of the holders of at least two-thirds of the issued shares of that class or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least, in person or by proxy, holding or representing one-third of the issued shares of the class. The rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further shares ranking pari passu therewith. Our bye-laws give our board of directors the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary. Shareholders’ rights Holders of our common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Subject to preferences that may be applicable to any issued and outstanding preference shares, holders of common shares are entitled to receive such dividends, if any, as may be declared from time to time by our board of directors out of funds legally available for dividend payments. Holders of common shares have no redemption, sinking fund, conversion, exchange or other subscription rights. In the event of our liquidation, the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares. Election and Removal of Directors Our bye-laws provide that our board of directors will determine the maximum size of the board, provided that it shall be not be composed of fewer than three directors. The maximum number of directors currently allowed is nine directors and our board of directors currently consists of nine directors. Our bye-laws provide that our directors shall hold office for such term as the shareholders shall determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. Directors whose term has expired may offer themselves for re- election at each election of the directors. Under our bye-laws, a director may be removed by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of our bye-laws. Notice convened for the purpose of removing the director, containing a statement of the intention to do so, must be served on such director not less than 14 days before the meeting. Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or her place or, in the absence of any such election, by the board of directors. Any other vacancy, including a newly created directorship, may be filled by our board of directors. Meetings of Shareholders Under Bermuda law, a company is required to convene the annual general meeting of shareholders each calendar year, unless the shareholders in a general meeting, elect to dispense with the holding of annual general meetings. Under Bermuda law and our bye-laws, a special general meeting of shareholders may be called by the board of directors and may be called upon the requisition of shareholders holding not less than 10% of the paid- up capital of the company carrying the right to vote at general meetings of shareholders. Our bye-laws provide that, at any general meeting of the shareholders, the presence in person or by proxy of two or more shareholders representing in excess of 50% of the total issued voting shares of the company shall constitute a quorum for the transaction of business unless the company only has one shareholder, in which case such shareholder shall constitute a quorum. Unless otherwise required by law or by our bye-laws, shareholder action requires a resolution adopted by a majority of votes cast by shareholders at a general meeting at which a quorum is present. Shareholder Proposals Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group composed of at least 100 or more shareholders may require a proposal to be submitted to an annual general meeting of shareholders. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide (among other things) advance notice, as set out in our bye-laws. Shareholders may only propose a person for election as a director at an annual general meeting. Shareholder action by written consent Our bye-laws provide that, except for the removal of auditors and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by the shareholders through the unanimous written consent of the shareholders who would be entitled to vote on the matter at the general meeting. Amendment of memorandum of association and bye-laws Our memorandum of association and bye-laws may be amended with the approval of a majority of our board of directors and by a resolution by a majority of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye- laws. Business combinations A Bermuda company may engage in a business combination pursuant to a tender offer, amalgamation, merger or sale of assets. The amalgamation or merger of a Bermuda company with another company generally requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Shareholder approval is not required where (a) a holding company and one or more of its wholly- owned subsidiary companies amalgamate or merge or (b) two or more wholly-owned subsidiary companies of the same holding company amalgamate or merge. Under the Bermuda Companies Act (save for such “short-form amalgamations”), unless a company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass a resolution to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation or merger will require the approval of our board of directors and of our shareholders by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of the notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the value of those shares. Under the Bermuda Companies Act, we are not required to seek the approval of our shareholders for the sale of all or substantially all of our assets. However, Bermuda courts will view decisions of the English courts as highly persuasive and English authorities suggest that such sales do require shareholder approval. Our bye-laws provide that the directors shall manage the business of the Company and may exercise all such powers as are not, by the Bermuda Companies Act or by these Bye-laws, required to be exercised by the Company in general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise all the powers of the Company including, but not by way of limitation, the power to borrow money and to mortgage or charge all or any part of the undertaking property and assets (present and future) and uncalled capital of the Company and to issue debentures and other securities, whether outright or as collateral security for any debt, liability or obligation of the Company or any other persons. Under Bermuda law, where an offer is made for shares of a company and, within four months of the offer, the holders of not less than 90% of the shares not owned by the offeror, its subsidiaries or their nominees accept such offer, the offeror may by notice require the non-tendering shareholders to transfer their shares on the terms of the offer. Dissenting shareholders do not have express appraisal rights but are entitled to seek relief (within one month of the compulsory acquisition notice) from the court, which has power to make such orders as it thinks fit. Additionally, where one or more parties hold not less than 95% of the shares of a company, such parties may, pursuant to a notice given to the remaining shareholders, acquire the shares of such remaining shareholders. Dissenting shareholders have a right to apply to the court for appraisal of the value of their shares within one month of the compulsory acquisition notice. If a dissenting shareholder is successful in obtaining a higher valuation, that valuation must be paid to all shareholders being squeezed out or the purchaser may cancel the purchase notice sent. Shareholder Suits Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply under the Bermuda Companies Act for an order of the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. Our bye-laws contain a provision through which we and our shareholders waive any claim or right of action that we or they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or officer. Dividends and Repurchase of Shares Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than its liabilities. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due. Access to Books and Records and Dissemination of Information Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company’s memorandum of association and any amendments thereto. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings of shareholders and the company’s audited financial statements. The company’s audited financial statements must be presented at the annual general meeting of shareholders, unless the board and all the shareholders agree to the waiving of the audited financials. The company’s share register is open to inspection by shareholders and by members of the general public without charge. A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Bermuda Companies Act, establish a branch register outside of Bermuda. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records. Comparison of Bermuda law to Delaware Corporate Law Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by our memorandum of association and bye-laws and Bermuda company law. The provisions of the Bermuda Companies Act, which applies to us, differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to mergers and acquisitions, takeovers and shareholder lawsuits. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders. Amalgamations, Mergers and Similar Arrangements. Pursuant to the Bermuda Companies Act, the amalgamation or merger of a Bermuda company with another company or corporation requires the amalgamation or merger agreement to be approved by the company’s board of directors and, under certain circumstances, by its shareholders. Under our bye-laws, an amalgamation or merger will require the approval of our board of directors and our shareholders by Special Resolution, which is a resolution adopted by 65% of more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws and the quorum for any general meeting must be two or more persons, in person or by proxy, representing in excess of 50% of the total of our issued voting shares. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder of the Bermuda company who did not vote in favor of the amalgamation or merger and who is not satisfied that he has been offered fair value for his shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares. Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction. Shareholders’ Suits. Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply for an order of the Supreme Court of Bermuda regulating the conduct of the company’s affairs in the future or an order to purchase the shares of any shareholders by other shareholders or by the company and, in the case of a purchase by the company, for the reduction accordingly of the company’s capital, or otherwise. Our bye-laws contain a provision by virtue of which we and our shareholders waive any claim or right of action that they have, both individually and on our behalf, against any director or officer in relation to any action or failure to take action by such director or officer, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or officer. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action. Exhibit 8.1 Jurisdiction Details of the subsidiaries of GeoPark Limited as of December 31, 2023, are set out below: Name GeoPark Argentina S.A. GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda. GeoPark Chile S.p.A. GeoPark Fell S.p.A. GeoPark Magallanes Limitada GeoPark TdF S.p.A. GeoPark Colombia S.A.S. GeoPark Colombia S.A.S. Sucursal Panama GeoPark Colombia S.L.U. GeoPark Perú S.A.C. GeoPark Ecuador S.A. GeoPark México S.A.P.I. de C.V. GeoPark E&P S.A.P.I. de C.V. GeoPark (UK) Limited Amerisur Resources Limited Amerisur Exploración Colombia Limited Amerisur Exploración Colombia Limited Sucursal Colombia Yarumal S.A.S. Fenix Oil & Gas Limited Fenix Oil & Gas Limited Sucursal Colombia Amerisurexplor Ecuador S.A. Amerisur S.A. Market Access LLP Argentina Brazil Chile Chile Chile Chile Colombia Panama Spain Peru Ecuador Mexico Mexico United Kingdom United Kingdom British Virgin Islands Colombia Colombia British Virgin Islands Colombia Ecuador Paraguay United States CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 12.1 I, Andrés Ocampo, certify that: 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the company and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c. Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: March 27, 2024 /s/ Andrés Ocampo Chief Executive Officer (Principal Executive Officer) CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 12.2 I, Jaime Caballero Uribe, certify that: 1. I have reviewed this annual report on Form 20-F of GeoPark Limited; 2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report; 3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the company as of, and for, the periods presented in this report; 4. The company’s other certifying officer(s) and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a 15(f) and 15d 15(f)) for the company and have: a. Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the company, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared; b. Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, 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; c. Evaluated the effectiveness of the company’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and d. Disclosed in this report any change in the company’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting; and 5. The company’s other certifying officer(s) and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the company’s auditors and the audit committee of the company’s board of directors (or persons performing the equivalent functions): a. All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the company’s ability to record, process, summarize and report financial information; and b. Any fraud, whether or not material, that involves management or other employees who have a significant role in the company’s internal control over financial reporting. Date: March 27, 2024 /s/ Jaime Caballero Uribe Chief Financial Officer (Principal Financial Officer) CERTIFICATION BY THE PRINCIPAL EXECUTIVE OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 Exhibit 13.1 The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the fiscal year ended December 31, 2023 (the “Report”), I, Andrés Ocampo, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: 1. 2. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Date: March 27, 2024 /s/ Andrés Ocampo Chief Executive Officer (Principal Executive Officer) CERTIFICATION BY THE PRINCIPAL FINANCIAL OFFICER PURSUANT TO 18 U.S.C. SECTION 1350, AS ADOPTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002 The certification set forth below is being submitted in connection with the Annual Report on Form 20-F of GeoPark Limited (the “Company”) for the fiscal year ended December 31, 2023 (the “Report”), I, Jaime Caballero Uribe, certify pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge: 1. 2. the Report fully complies with the requirements of Section 13(a) or 15(d) of the Securities Exchange Act of 1934; and the information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company. Exhibit 13.2 Date: March 27, 2024 /s/ Jaime Caballero Uribe Chief Financial Officer (Principal Financial Officer) CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statements on Form S-8 (No 333-201016, No.333-214291, No.333-228762 and No.333-228763) of GeoPark Limited of our reports dated March 27, 2024, with respect to the consolidated financial statements of GeoPark Limited and the effectiveness of internal control over financial reporting of GeoPark Limited, included in this Annual Report (Form 20-F) of GeoPark Limited for the year ended December 31, 2023. We also consent to the reference to our firm under the headings “Presentation of Financial and Other Information”, “ITEM 15. CONTROLS AND PROCEDURES”, “ITEM 16C. Principal Accountant Fees and Services” and “ITEM 16F. Change in registrant’s certifying accountant” in this Form 20-F. Exhibit 15.1 ERNST & YOUNG AUDIT S.A.S. By /s/ Ernst & Young Audit S.A.S. Ernst & Young Audit S.A.S. Member of Ernst & Young Global Limited Bogota, Colombia March 27, 2024 CONSENT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM We consent to the incorporation by reference in the Registration Statements on Form S-8 (No 333-201016, No.333-214291, No.333-228762 and No.333-228763) of GeoPark Limited of our report dated March 8, 2023, with respect to the consolidated financial statements of GeoPark Limited, included in this Annual Report (Form 20-F) of GeoPark Limited for the year ended December 31, 2023. Exhibit 15.2 PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L. By /s/ Pistrelli, Henry Martin y Asociados S.R.L. Pistrelli, Henry Martin y Asociados S.R.L. Member of Ernst & Young Global Limited Buenos Aires, Argentina March 27, 2024 Exhibit 15.3 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 March 27, 2024 GeoPark Limited Calle 94 N° 11-30, 8o floor Bogotá, Colombia Ladies and Gentlemen: As an independent petroleum consulting firm, we hereby consent to the incorporation by reference to our year-end 2023 report of third party dated March 1, 2024, to be used under certain headings contained in the Annual Report of GeoPark Limited on Form 20-F for the year ended December 31, 2023, and specified in our consent letter dated March 27, 2024, addressed to GeoPark Limited, which is referenced in the previously filed Registration Statement on Form S-8 (File Nos. 333-201016, 333-214291, and 333-228763) under the headings “PART II – Item 3. Incorporation of Documents by Reference” and “Part II – Item 8. Exhibits” and on Form S-8 (File No. 333- 228762) under the heading “Part II – Item 8. Exhibits.” Very truly yours, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 March 27, 2024 GeoPark Limited Calle 94 N° 11 30, 8o floor Bogotá, Colombia Ladies and Gentlemen: We hereby consent to the references to DeGolyer and MacNaughton and to the inclusion of and information derived from our 2023 year-end report of third party dated March 1, 2024, regarding our independent estimates of the net proved oil, condensate, gas, and oil equivalent reserves, as of December 31, 2023, of certain selected properties in which GeoPark Limited has represented it holds an interest in Brazil, Chile, Colombia and Ecuador (our “Report”), as set forth under the headings “Presentation of Financial and Other Information–Oil and gas reserves and production information,” “Item 3. Key Information–D. Risk factors,” “Item 4. Information on the Company–B. Business Overview,” “Item 5. Operating and Financial Review and Prospects–A. Operating results,” “Item 19 Exhibits,” and “GeoPark Limited Consolidated Financial Statements as of and for the year ended December 31, 2023” and as Exhibit No. 99.1 in the Annual Report on Form 20-F of GeoPark Limited (the “Annual Report”). We confirm that we have read the Annual Report and have no reason to believe that there are any misrepresentations in the information contained therein that are derived from our Report or that are within our knowledge as a result of the services performed by us in connection with the preparation of our Report. Very truly yours, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 Exhibit 15.4 March 27, 2024 Securities and Exchange Commission 100 F Street, N.E. Washington, DC 20549 Ladies and Gentlemen: We have read item 16.F – “Change in Registrant’s Certifying Accountant” of the annual report on Form 20-F for the year ended December 31, 2023 of GeoPark Limited. We agree with the statements contained therein in relation to Pistrelli, Henry Martin y Asociados S.R.L. We have no basis to agree or disagree with other statements of the registrant contained therein. Very truly yours, /s/ Pistrelli, Henry Martin y Asociados S.R.L. PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L. Member of Ernst & Young Global Limited GEOPARK LIMITED COMPENSATION RECOUPMENT POLICY Exhibit 97.1 This GeoPark Compensation Recoupment Policy (the “Clawback Policy” or the “Policy”) has been adopted by the Board of Directors (the “Board”) of GeoPark Limited (the “Company”) on 7 November 2023, following the recommendation of the Compensation Committee of the Company. This Policy provides for the recoupment of certain executive compensation in the event of an accounting restatement resulting from material noncompliance with financial reporting requirements under U.S. federal securities laws in accordance with the terms and conditions set forth herein. This Policy is intended to comply with the requirements of Section 10D of the Exchange Act (as defined below) and Section 303A.14 of the NYSE Listed Company Manual (the “Listing Rule”). 1. (a) (b) (c) (d) (e) (f) Definitions. For the purposes of this Policy, the following terms shall have the meanings set forth below. “Committee” means the Compensation Committee of the Board or any successor committee thereof. “Covered Compensation” means any Incentive-based Compensation “received” by a Covered Executive during the applicable Recoupment Period; provided that: (i) (ii) Such Covered Compensation was received by such Covered Executive: (A) after the Effective Date, (B) after he or she commenced service as an Executive Officer, and (C) while the Company had a class of securities publicly listed on a United States national securities exchange; and Such Covered Executive served as an Executive Officer at any time during the performance period applicable to such Incentive-based Compensation. For purposes of this Policy, Incentive-based Compensation is “received” by a Covered Executive during the fiscal period in which the Financial Reporting Measure applicable to such Incentive-based Compensation (or portion thereof) is attained, even if the payment or grant of such Incentive-based Compensation is made thereafter. “Covered Executive” means any current or former Executive Officer. “Effective Date” means the date on which Listing Rule becomes effective. “Exchange Act” means the U.S. Securities Exchange Act of 1934, as amended. “Executive Officer” means, with respect to the Company, (i) its chief executive officer, (ii) its chief financial officer, (iii) its principal accounting officer or if there is no accounting officer, its controller, (iv) its chief people officer, (v) its chief technical officer, (vi) its chief operational officer, (vii) its chief exploration officer and (viii) its chief strategy, sustainability and legal officer, or any other officer or person that succeeds any of the above or that perform policy-making functions for the Company or otherwise meet the definition of “executive officer” under the Listing Rule. Policy-making function is not intended to include policy-making functions that are not significant. The determination as to an individual’s status as an Executive Officer shall be made by the Committee and such determination shall be final, conclusive, and binding on such individual and all other interested persons. Only for the purposes of this Policy, the principal accounting officer or if there is no accounting officer, its controller, shall be considered as Executive Officers. (g) “Financial Reporting Measure” means any: (i) measure that is determined and presented in accordance with the accounting principles used in preparing the Company’s financial statements, (ii) stock price measure, or (iii) total shareholder return measure (and any measures that are derived wholly or in part from any measure referenced in clause (i), (ii) or (iii) above). For the avoidance of doubt, any such measure does not need to be presented within the Company’s financial statements or included in a filing with the U.S. Securities and Exchange Commission to constitute a Financial Reporting Measure. (h) “Financial Restatement” means a restatement of the Company’s financial statements due to the Company’s material noncompliance with any financial reporting requirement under U.S. federal securities laws that is required in order to correct: (i) (ii) an error in previously issued financial statements that is material to the previously issued financial statements; or an error that would result in a material misstatement if (A) the error was corrected in the current period, or (B) left uncorrected in the current period. For purposes of this Policy, a Financial Restatement shall not be deemed to occur in the event of a revision of the Company’s financial statements due to an out-of-period adjustment (i.e., when the error is immaterial to the previously issued financial statements and the correction of the error is also immaterial to the current period), or a retrospective (1) application of a change in accounting principles; (2) revision to reportable segment information due to a change in the structure of the Company’s internal organization; (3) reclassification due to a discontinued operation; (4) application of a change in reporting entity, such as from a reorganization of entities under common control; (5) revision for stock splits (share subdivisions), reverse stock splits (share consolidations), stock dividends (bonus issues) or other changes in capital structure; or (6) adjustment to provisional amounts in connection with a prior business combination. “Incentive-based Compensation” means (i) awards under the Annual Long Term Incentive Program, (ii) awards under the Annual Performance Cash Bonus, (iii) benefits under the Executive Termination and Change in Control Benefits Plan and (iv) any other compensation (including, for the avoidance of doubt, any cash or equity or equity-based compensation, whether deferred or current), in each case that is granted, earned and/or vested based wholly or in part upon the achievement of a Financial Reporting Measure. For purposes of this Policy, “Incentive-based Compensation” shall also be deemed to include any amounts which were determined based on (or were otherwise calculated by reference to) Incentive-based Compensation (including, without limitation, any amounts under any long-term disability, life insurance or supplemental retirement or severance plan or agreement or any notional account that is based on Incentive-based Compensation, as well as any earnings accrued thereon). “NYSE” means the New York Stock Exchange, or any successor thereof. “Recoupment Period” means the three fiscal years completed immediately preceding the date of any applicable Recoupment Trigger Date. Notwithstanding the foregoing, the Recoupment Period additionally includes any transition period (that results from a change in the Company’s fiscal year) within or immediately following those three completed fiscal years, provided that a transition period between the last day of the Company’s previous fiscal year end and the first day of its new fiscal year that comprises a period of nine (9) to twelve (12) months would be deemed a completed fiscal year. “Recoupment Trigger Date” means the earlier of: (i) the date that the Board (or a committee thereof or the officer(s) of the Company authorized to take such action if Board action is not required) concludes, or reasonably should have concluded, that the Company is required to prepare a Financial (j) (k) (l) (m) 2 2. (a) (b) (c) (d) Restatement, and (ii) the date on which a court, regulator or other legally authorized body directs the Company to prepare a Financial Restatement. Recoupment of Erroneously Awarded Compensation. In the event of a Financial Restatement, if the amount of any Covered Compensation received by a Covered Executive (the “Awarded Compensation”) exceeds the amount of such Covered Compensation that would have otherwise been received by such Covered Executive if calculated based on the Financial Restatement (the “Adjusted Compensation”), the Company shall reasonably promptly recover from such Covered Executive an amount equal to the excess of the Awarded Compensation over the Adjusted Compensation, each calculated on a pre-tax basis (such excess amount, the “Erroneously Awarded Compensation”). If: (i) the Financial Reporting Measure applicable to the relevant Covered Compensation is stock price or total shareholder return (or any measure derived wholly or in part from either of such measures), and (ii) the amount of Erroneously Awarded Compensation is not subject to mathematical recalculation directly from the information in the Financial Restatement, then the amount of Erroneously Awarded Compensation shall be determined (on a pre-tax basis) based on the Company’s reasonable estimate of the effect of the Financial Restatement on the Company’s stock price or total shareholder return (or the derivative measure thereof) upon which such Covered Compensation was received. For the avoidance of doubt, the Company’s obligation to recover Erroneously Awarded Compensation is not dependent on: (i) if or when the restated financial statements are filed; or (ii) any fault of any Covered Executive for the accounting errors or other actions leading to a Financial Restatement. Notwithstanding anything to the contrary in Sections 2 (a) through (c) hereof, the Company shall not be required to recover any Erroneously Awarded Compensation if both (x) the conditions set forth in either of the following clauses (i), (ii), or (iii) are satisfied, and (y) the Committee (or a majority of the independent directors serving on the Board) has determined that recovery of the Erroneously Awarded Compensation would be impracticable: (i) (ii) the direct expense paid to a third party to assist in enforcing the recovery of the Erroneously Awarded Compensation under this Policy would exceed the amount of such Erroneously Awarded Compensation to be recovered; provided that, before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation pursuant to this Section 2 (d) (i), the Company shall have first made a reasonable attempt to recover such Erroneously Awarded Compensation, document such reasonable attempt(s) to make such recovery and provide that documentation to the NYSE; recovery of the Erroneously Awarded Compensation would violate Bermuda law to the extent such law was adopted prior to November 28, 2022 (provided that, before concluding that it would be impracticable to recover any amount of Erroneously Awarded Compensation pursuant to this Section 2 (d) (ii)), the Company shall have first obtained an opinion of home country counsel of Bermuda, that is acceptable to the NYSE, that recovery would result in such a violation, and the Company must provide such opinion to the NYSE; or (iii) recovery of the Erroneously Awarded Compensation would likely cause an otherwise tax-qualified retirement plan, under which benefits are broadly available to employees of the Company, to fail to meet the requirements of Sections 401(a)(13) or 411(a) of the U.S. Internal Revenue Code of 1986, as amended (the “Code”). (e) The Company shall not indemnify any Covered Executive, directly or indirectly, for any losses that such Covered Executive may incur in connection with the recovery of Erroneously Awarded 3 (f) 3. 4. 5. 6. Compensation pursuant to this Policy, including through the payment of insurance premiums or gross-up payments. The Committee shall determine, in its sole discretion, the manner and timing in which any Erroneously Awarded Compensation shall be recovered from a Covered Executive in accordance with applicable law, including, without limitation, by (i) requiring reimbursement of Covered Compensation previously paid in cash; (ii) seeking recovery of any gain realized on the vesting, exercise, settlement, sale, transfer or other disposition of any equity or equity-based awards; (iii) offsetting the Erroneously Awarded Compensation amount from any compensation otherwise owed by the Company or any of its affiliates to the Covered Executive; (iv) cancelling outstanding vested or unvested equity or equity-based awards; and/or (v) taking any other remedial and recovery action permitted by applicable law. For the avoidance of doubt, except as set forth in Section 2(d), in no event may the Company accept an amount that is less than the amount of Erroneously Awarded Compensation; provided that, to the extent necessary to avoid any adverse tax consequences to the Covered Executive pursuant to Section 409A of the Code, any offsets against amounts under any nonqualified deferred compensation plans (as defined under Section 409A of the Code) shall be made in compliance with Section 409A of the Code. Administration. This Policy shall be administered by the Committee. All decisions of the Committee shall be final, conclusive and binding upon the Company and the Covered Executives, their beneficiaries, executors, administrators and any other legal representative. The Committee shall have full power and authority to: (i) administer and interpret this Policy; (ii) correct any defect, supply any omission and reconcile any inconsistency in this Policy; and (iii) make any other determination and take any other action that the Committee deems necessary or desirable for the administration of this Policy and to comply with applicable law (including Section 10D of the Exchange Act) and applicable stock market or exchange rules and regulations. Notwithstanding anything to the contrary contained herein, to the extent permitted by Section 10D of the Exchange Act and Section 303A.14 of the NYSE Listed Company Manual, the Board may, in its sole discretion, at any time and from time to time, administer this Policy in the same manner as the Committee. Amendment/Termination. Subject to Section 10D of the Exchange Act and Section 303A.14 of the NYSE Listed Company Manual, this Policy may be amended or terminated by the Committee at any time. To the extent that any applicable law, or stock market or exchange rules or regulations require recovery of Erroneously Awarded Compensation in circumstances in addition to those specified herein, nothing in this Policy shall be deemed to limit or restrict the right or obligation of the Company to recover Erroneously Awarded Compensation to the fullest extent required by such applicable law, stock market or exchange rules and regulations. Unless otherwise required by applicable law, this Policy shall no longer be effective from and after the date that the Company no longer has a class of securities publicly listed on a United States national securities exchange. Interpretation. Notwithstanding anything to the contrary herein, this Policy is intended to comply with the requirements of Section 10D of the Exchange Act and Section 303A.14 of the NYSE Listed Company Manual (and any applicable regulations, administrative interpretations or stock market or exchange rules and regulations adopted in connection therewith). The provisions of this Policy shall be interpreted in a manner that satisfies such requirements and this Policy shall be operated accordingly. If any provision of this Policy would otherwise frustrate or conflict with this intent, the provision shall be interpreted and deemed amended to avoid such conflict. Other Compensation Clawback/Recoupment Rights. Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies, rights or requirements with respect to the clawback or recoupment of any compensation that may be available to the Company pursuant to the terms of any other recoupment or clawback policy of the Company (or any of its affiliates) that may be in effect from time to time, any provisions in any employment agreement, offer letter, equity plan, equity award agreement or similar plan or agreement, and any other legal remedies available to the Company, as 4 7. 8. (a) (b) (c) (d) well as applicable law, stock market or exchange rules, listing standards or regulations; provided, however, that any amounts recouped or clawed back under any other policy that would be recoupable under this Policy shall count toward any required clawback or recoupment under this Policy and vice versa. Exempt Compensation. Notwithstanding anything to the contrary herein, the Company has no obligation to seek recoupment of amounts paid to a Covered Executive which are granted, vested or earned based solely upon the occurrence or non-occurrence of nonfinancial events. Such exempt compensation includes, without limitation, base salary, time-vesting awards, compensation awarded on the basis of the achievement of metrics that are not Financial Reporting Measures or compensation awarded solely at the discretion of the Committee or the Board, provided that such amounts are in no way contingent on, and were not in any way granted on the basis of, the achievement of any Financial Reporting Measure. Miscellaneous. Any applicable award agreement or other document setting forth the terms and conditions of any compensation covered by this Policy shall be deemed to include the restrictions imposed herein and incorporate this Policy by reference and, in the event of any inconsistency, the terms of this Policy will govern. For the avoidance of doubt, this Policy applies to all compensation that is received on or after the Effective Date, regardless of the date on which the award agreement or other document setting forth the terms and conditions of the Covered Executive’s compensation became effective or was first granted or awarded, including, without limitation, compensation received under the GeoPark Limited 2018 Equity Incentive Plan with registration No. 333-228763 and filed with the SEC on December 12, 2018 and its related programs and any successor plan. This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators or other legal representatives. All issues concerning the construction, validity, enforcement and interpretation of this Policy and all related documents, including, without limitation, any employment agreement, offer letter, equity award agreement or similar agreement, shall be governed by, and construed in accordance with, the laws of the State of New York, without giving effect to any choice of law or conflict of law rules or provisions (whether of the State of New York or any other jurisdiction) that would cause the application of the laws of any jurisdiction other than the State of New York. The Covered Executives, their beneficiaries, executors, administrators and any other legal representative and the Company shall initially attempt to resolve all claims, disputes or controversies arising under, out of or in connection with this Policy by conducting good faith negotiations amongst themselves. To ensure the timely and economical resolution of disputes that arise in connection with this Policy, any controversy or claim arising out of or relating to this Policy shall be settled by binding and confidential arbitration before a single arbitrator administered by Judicial Arbitration and Mediation Services under its Employment Arbitration Rules & Procedures taking place in the State of New York, and judgment on the award rendered by the arbitrator may be entered in any court having jurisdiction thereof. To the fullest extent permitted by law, the Covered Executives, their beneficiaries, executors, administrators and any other legal representative and the Company, shall waive (and shall hereby be deemed to have waived): (1) the right to resolve any such dispute through a trial by jury or judge or administrative proceeding; and (2) any objection to arbitration taking place in the State of New York. (e) If any provision of this Policy is determined to be unenforceable or invalid under any applicable law, such provision will be applied to the maximum extent permitted by applicable law and shall automatically be deemed amended in a manner consistent with its objectives to the extent necessary to conform to any limitations required under applicable law. 5 Exhibit 99.1 DeGolyer and MacNaughton 5001 Spring Valley Road Suite 800 East Dallas, Texas 75244 March 1, 2024 GeoPark Limited Calle 94 N° 11-30, 8° floor Bogotá, Colombia Ladies and Gentlemen: Pursuant to your request, this report of third party presents an independent evaluation, as of December 31, 2023, of the extent of the estimated net proved oil, condensate, and gas reserves of certain properties in Brazil, Chile, Colombia, and Ecuador in which GeoPark Limited (GeoPark) has represented it holds an interest. This evaluation was completed on March 1, 2024. GeoPark has represented that these properties account for 100 percent on a net equivalent barrel basis of GeoPark’s net proved reserves as of December 31, 2023. The net proved reserves estimates have been prepared in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the United States Securities and Exchange Commission (SEC). This report was prepared in accordance with guidelines specified in Item 1202 (a)(8) of Regulation S–K and is to be used for inclusion in certain SEC filings by GeoPark. Reserves estimates included herein are expressed as net reserves. Gross reserves are defined as the total estimated petroleum remaining to be produced from these properties after December 31, 2023. Net reserves are defined as that portion of the gross reserves attributable to the interests held by GeoPark after deducting all interests held by others, including royalties paid in kind. Estimates of reserves should be regarded only as estimates that may change as further production history and additional information become available. Not only are such estimates based on that information which is currently available, but such estimates are also subject to the uncertainties inherent in the application of judgmental factors in interpreting such information. Information used in this evaluation was obtained from GeoPark. In the preparation of this report we have relied, without independent verification, upon such information furnished by GeoPark with respect to the property interests being evaluated, production from such properties, current costs of operation and development, current prices for production, agreements relating to current and future operations and sale of production, and various other information and data that were accepted as represented. A field examination was not considered necessary for the purposes of this report. Definition of Reserves Petroleum reserves included in this report are classified as proved. Only proved reserves have been evaluated for this report. Reserves classifications used in this report are in accordance with the reserves definitions of Rules 4–10(a) (1)–(32) of Regulation S–X of the SEC. Reserves are judged to be economically producible in future years from known reservoirs under existing economic and operating conditions and assuming continuation of current regulatory practices using conventional production methods and equipment. In the analyses of production-decline curves, reserves were estimated only to the limit of economic rates of production under existing economic and operating conditions using prices and costs consistent with the effective date of this report, including consideration of changes in existing prices provided only by contractual arrangements but not including escalations based upon future conditions. The petroleum reserves are classified as follows: Proved oil and gas reserves – Proved oil and gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods, and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation. The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. DeGolyer and MacNaughton (i) The area of the reservoir considered as proved includes: (A) The area identified by drilling and limited by fluid contacts, if any, and (B) Adjacent undrilled portions of the reservoir that can, with reasonable certainty, be judged to be continuous with it and to contain economically producible oil or gas on the basis of available geoscience and engineering data. (ii) In the absence of data on fluid contacts, proved quantities in a reservoir are limited by the lowest known hydrocarbons (LKH) as seen in a well penetration unless geoscience, engineering, or performance data and reliable technology establishes a lower contact with reasonable certainty. (iii) Where direct observation from well penetrations has defined a highest known oil (HKO) elevation and the potential exists for an associated gas cap, proved oil reserves may be assigned in the structurally higher portions of the reservoir only if geoscience, engineering, or performance data and reliable technology establish the higher contact with reasonable certainty. (iv) Reserves which can be produced economically through application of improved recovery techniques (including, but not limited to, fluid injection) are included in the proved classification when: (A) Successful testing by a pilot project in an area of the reservoir with properties no more favorable than in the reservoir as a whole, the operation of an installed program in the reservoir or an analogous reservoir, or other evidence using reliable technology establishes the reasonable certainty of the engineering analysis on which the project or program was based; and (B) The project has been approved for development by all necessary parties and entities, including governmental entities. (v) Existing economic conditions include prices and costs at which economic producibility from a reservoir is to be determined. The price shall be the average price during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period, unless prices are defined by contractual arrangements, excluding escalations based upon future conditions. Developed oil and gas reserves – Developed oil and gas reserves are reserves of any category that can be expected to be recovered: (i) Through existing wells with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well; and (ii) Through installed extraction equipment and infrastructure operational at the time of the reserves estimate if the extraction is by means not involving a well. Undeveloped oil and gas reserves – Undeveloped oil and gas reserves are reserves of any category that are expected to be recovered from new wells on undrilled acreage, or from existing wells where a relatively major expenditure is required for recompletion. (i) Reserves on undrilled acreage shall be limited to those directly offsetting development spacing areas that are reasonably certain of production when drilled, unless evidence using reliable technology exists that establishes reasonable certainty of economic producibility at greater distances. (ii) Undrilled locations can be classified as having undeveloped reserves only if a development plan has been adopted indicating that they are scheduled to be drilled within five years, unless the specific circumstances justify a longer time. (iii) Under no circumstances shall estimates for undeveloped reserves be attributable to any acreage for which an application of fluid injection or other improved recovery technique is contemplated, unless such techniques have been proved effective by actual projects in the same reservoir or an analogous reservoir, as defined in [section 210.4–10 (a) Definitions], or by other evidence using reliable technology establishing reasonable certainty. 3 DeGolyer and MacNaughton Methodology and Procedures Estimates of reserves were prepared by the use of appropriate geologic, petroleum engineering, and evaluation principles and techniques that are in accordance with the reserves definitions of Rules 4–10(a)(1)–(32) of Regulation S–X of the SEC and with practices generally recognized by the petroleum industry as presented in the publication of the Society of Petroleum Engineers entitled “Standards Pertaining to the Estimating and Auditing of Oil and Gas Reserves Information (revised June 2019) Approved by the SPE Board on 25 June 2019.” The method or combination of methods used in the analysis of each reservoir was tempered by experience with similar reservoirs, stage of development, quality and completeness of basic data, and production history. Based on the current stage of field development, production performance, the development plans provided by GeoPark, and analyses of areas offsetting existing wells with test or production data, reserves were classified as proved. The undeveloped reserves estimates were based on opportunities identified in the plan of development provided by GeoPark. GeoPark has represented that its senior management is committed to the development plan provided by GeoPark and that GeoPark has the financial capability to execute the development plan, including the drilling and completion of wells and the installation of equipment and facilities. The volumetric method was used to estimate the original oil in place (OOIP) and original gas in place (OGIP). Structure maps were prepared to delineate each reservoir, and isopach maps were constructed to estimate reservoir volume. Electrical logs, radioactivity logs, core analyses, and other available data were used to prepare these maps as well as to estimate representative values for porosity and water saturation. When adequate data were available and when circumstances justified, material-balance methods were used to estimate OOIP or OGIP. Estimates of ultimate recovery were obtained after applying recovery factors to OOIP and OGIP. These recovery factors were based on consideration of the type of energy inherent in the reservoirs, analyses of the petroleum, the structural positions of the properties, and the production histories. When applicable, material balance and other engineering methods were used to estimate recovery factors based on an analysis of reservoir performance, including production rate, reservoir pressure, and reservoir fluid properties. For depletion-type reservoirs or those whose performance disclosed a reliable decline in producing-rate trends or other diagnostic characteristics, reserves were estimated by the application of appropriate decline curves or other performance relationships. In certain cases, reserves were estimated by incorporating elements of analogy with similar wells or reservoirs for which more complete data were available. In the evaluation of undeveloped reserves, type-well analysis was performed using well data from analogous reservoirs for which more complete historical performance data were available. For cases where history-matched dynamic models were available and applicable, model results were used to estimate recovery factors and reserves production forecasts. The reserves estimates contained herein were limited to the economic limit, as defined under the Definition of Reserves heading of this report, or to the end of the concession, whichever occurs first. Data provided by GeoPark from wells drilled through December 31, 2023, and made available for this evaluation were used to prepare the reserves estimates herein. These reserves estimates were based on consideration of monthly production data available for certain properties only through November 2023. Estimated cumulative production, as of December 31, 2023, was deducted from the estimated gross ultimate recovery to estimate gross reserves. This required that production be estimated for up to 1 month. Oil and condensate reserves estimated herein are to be recovered by normal field separation. Oil reserves include fuel oil. Fuel oil is defined as that portion of the oil consumed in field operations. Oil and condensate reserves included in this report are expressed in thousands of barrels (103bbl). In these estimates, 1 barrel equals 42 United States gallons. For reporting purposes, oil and condensate reserves have been estimated separately and are presented herein as a summed quantity. 4 DeGolyer and MacNaughton Gas quantities estimated herein are expressed as sales gas. Sales gas is defined as the total gas to be produced from the reservoirs, measured at the point of delivery, after reduction for fuel usage, flare, and shrinkage resulting from field separation and processing. Gas reserves estimated herein are reported as sales gas. Gas quantities are expressed at a temperature base of zero degrees Celsius (°C) and at a pressure base of 1 kilogram per square centimeter (kg/cm2) for properties located in Chile and at a temperature base of 15.5°C and at a pressure base of 1 kg/cm2 for properties located in other countries. Gas quantities included in this report are expressed in millions of cubic feet (106ft3). Gas quantities are identified by the type of reservoir from which the gas will be produced. Nonassociated gas is gas at initial reservoir conditions with no oil present in the reservoir. Associated gas is both gas-cap gas and solution gas. Gas-cap gas is gas at initial reservoir conditions and is in communication with an underlying oil zone. Solution gas is gas dissolved in crude oil at initial reservoir conditions. Gas quantities reported herein are both nonassociated gas and associated gas. At the request of GeoPark, sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. Primary Economic Assumptions This report has been prepared using initial prices, expenses, and costs provided by GeoPark in United States dollars (U.S.$). Future prices were estimated using guidelines established by the SEC and the Financial Accounting Standards Board (FASB). The following economic assumptions were used for estimating the reserves reported herein: Oil and Condensate Prices GeoPark has represented that the oil and condensate prices were based on a reference price, calculated as the unweighted arithmetic average of the first-day-of-the-month price for each month within the 12-month period prior to the end of the reporting period, unless prices are defined by contractual agreements. GeoPark supplied differentials to a Brent reference price of U.S.$82.09 per barrel and the prices were held constant thereafter. For the Manati field in Brazil, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$70.68 per barrel of condensate. For the fields located in Chile, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$68.04 per barrel of oil and condensate. For the fields located in Colombia, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$68.73 per barrel of oil. For the fields located in Ecuador, the volume-weighted average adjusted product price attributable to the estimated proved reserves was U.S.$61.27 per barrel of oil. Gas Prices GeoPark has represented that the gas prices are defined by contractual agreements and their expected extensions, which are based on specific market conditions. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the Manati field in Brazil was U.S.$6.65 per thousand cubic feet (103ft3) of gas. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the fields located in Chile was U.S.$3.39 per 103ft3 of gas. The volume-weighted average adjusted product price attributable to the estimated proved reserves for the fields located in Colombia was U.S.$6.00 per 103ft3 of gas. 5 DeGolyer and MacNaughton Operating Expenses, Capital Costs, and Abandonment Costs Estimates of operating expenses and capital costs, provided by GeoPark and based on existing economic conditions, were held constant for the lives of the properties. This information included historical costs as well as operating expense and capital cost estimates for future development. In certain cases, future expenditures, either higher or lower than current expenditures, may have been used because of anticipated changes in operating conditions, but no general escalation that might result from inflation was applied. Abandonment costs, which are those costs associated with the removal of equipment, plugging of wells, and reclamation and restoration associated with the abandonment, were provided by GeoPark for each field or block and were included in the year following cessation of production, except in Brazil, where abandonment costs are allocated annually into an abandonment fund. Abandonment costs were not escalated. Operating expenses, capital costs, and abandonment costs were considered in determining the economic viability of the undeveloped reserves estimated herein. In our opinion, the information relating to estimated proved reserves of oil, condensate, and gas contained in this report has been prepared in accordance with Paragraphs 932-235-50-4, 932-235-50-6, 932-235-50-7, and 932-235-50-9 of the Accounting Standards Update 932-235-50, Extractive Industries – Oil and Gas (Topic 932): Oil and Gas Reserve Estimation and Disclosures (January 2010) of the FASB and Rules 4–10(a)(1)–(32) of Regulation S–X and Rules 302(b), 1201, 1202(a) (1), (2), (3), (4), (8), and 1203(a) of Regulation S–K of the SEC; provided, however, that estimates of proved developed and proved undeveloped reserves are not presented at the beginning of the year. To the extent the above-enumerated rules, regulations, and statements require determinations of an accounting or legal nature, we, as engineers, are necessarily unable to express an opinion as to whether the above-described information is in accordance therewith or sufficient therefor. 6 DeGolyer and MacNaughton Summary of Conclusions DeGolyer and MacNaughton has performed an independent evaluation of the extent of the estimated net proved oil, condensate, and gas reserves of certain properties in which GeoPark has represented it holds an interest. The estimated net proved reserves, as of December 31, 2023, of the properties evaluated herein were based on the definition of proved reserves of the SEC and are summarized as follows, expressed in thousands of barrels (103bbl), millions of cubic feet (106ft3), and thousands of barrels of oil equivalent (103boe): Brazil Proved Developed Proved Undeveloped Total Proved Chile Proved Developed Proved Undeveloped Total Proved Colombia Proved Developed Proved Undeveloped Total Proved Ecuador Proved Developed Proved Undeveloped Total Proved Grand Total Proved Developed Proved Undeveloped Total Proved Estimated by DeGolyer and MacNaughton Net Proved Reserves as of December 31, 2023 Oil and Condensate (103bbl) Sales Gas (106ft3) Oil Equivalent (103boe) 28 0 28 619 479 8,888 0 8,888 9,956 855 1,098 10,811 43,120 16,225 59,345 1,017 1,278 2,295 1,075 0 1,075 0 0 0 44,784 17,982 19,919 855 1,509 0 1,509 2,278 622 2,900 43,299 16,225 59,524 1,017 1,278 2,295 48,103 18,125 62,766 20,774 66,228 Notes: 1. Sales gas reserves estimated herein were converted to oil equivalent using an energy equivalent factor of 6,000 cubic feet of gas per 1 barrel of oil equivalent. 2. Oil reserves include fuel oil quantities associated with the Platanillo field in Colombia. Fuel oil quantities were estimated to be 132 103bbl of the proved developed reserves and 158 103bbl of the total proved reserves. 7 DeGolyer and MacNaughton While the oil and gas industry may be subject to regulatory changes from time to time that could affect an industry participant’s ability to recover its reserves, we are not aware of any such governmental actions which would restrict the recovery of the December 31, 2023, estimated reserves. DeGolyer and MacNaughton is an independent petroleum engineering consulting firm that has been providing petroleum consulting services throughout the world since 1936. DeGolyer and MacNaughton does not have any financial interest, including stock ownership, in GeoPark. Our fees were not contingent on the results of our evaluation. This report has been prepared at the request of GeoPark. DeGolyer and MacNaughton has used all assumptions, data, procedures, and methods that it considers necessary and appropriate to prepare this report. Submitted, /s/ DeGolyer and MacNaughton DeGOLYER and MacNAUGHTON Texas Registered Engineering Firm F-716 /s/ Peter Laudon Peter Laudon, P.E., P.G. Vice President DeGolyer and MacNaughton 8 [SEAL] DeGolyer and MacNaughton CERTIFICATE of QUALIFICATION I, Peter Laudon, Petroleum Engineer with DeGolyer and MacNaughton, 5001 Spring Valley Road, Suite 800 East, Dallas, Texas, 75244 U.S.A., hereby certify: 1. That I am a Vice President with DeGolyer and MacNaughton, which firm did prepare the report of third party addressed to GeoPark dated March 1, 2024, and that I, as Vice President, was responsible for the preparation of this report of third party. 2. That I attended the University of Kansas, and that I graduated with a Bachelor of Science degree in Geology in the year 1988, and that I attended the University of Missouri at Rolla, and that I graduated with both a Master of Science degree in Geology in the year 1992 and a Bachelor of Science degree in Petroleum Engineering in the year 1995; that I am a Licensed Professional Geologist and that I am a Licensed Professional Engineer in the State of Texas; that I am a member of the American Association of Petroleum Geologists, the Society of Petroleum Engineers, the Society of Petroleum Evaluation Engineers, the Society of Professional Well Log Analysts, and the American Association of Petroleum Geologists; and that I have in excess of 29 years of experience in oil and gas reservoir studies and evaluations. [SEAL] /s/ Peter Laudon Peter Laudon, P.E., P.G. Vice President DeGolyer and MacNaughton 9 

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