GeoPark : 2025 Annual Report (Form 20-F)

About this update from Geopark Ltd

audit UNITED STATES SECURITIES AND EXCHANGE COMMISSION Washington, D.C. 20549 FORM 20-F (Mark One) REGISTRATION STATEMENT PURSUANT TO SECTION 12(b) OR (g) OF THE SECURITIES EXCHANGE ACT OF 1934 OR ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31, 2025 OR TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to OR SHELL COMPANY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 Date of event requiring this shell company report Commission file number: 001-36298 GEOPARK LIMITED (Exact name of Registrant as specified in its charter) Bermuda (Jurisdiction of incorporation) Calle 94 N° 11-30, 8 o floor Bogotá, Colombia (Address of principal executive offices) Maria Catalina Escobar Shareholder Value and Capital Markets Director GeoPark Limited Calle 94 N° 11-30, 8 o floor Bogotá, Colombia Phone: +57 601 743 2337 (Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person) Copies to: Maurice Blanco, Esq. Davis Polk & Wardwell LLP 450 Lexington Avenue New York, NY 10017 Phone: (212) 450 4000 Fax: (212) 701 5800 Securities registered or to be registered pursuant to Section 12(b) of the Act: Title of each class Trading Symbols Name of each exchange on which registered Common shares, par value US$0.001 per share Series A Preferred Shares Purchase Rights GPRK New York Stock Exchange New York Stock Exchange Securities registered or to be registered pursuant to Section 12(g) of the Act: None 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: 51,707,198 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 ☐ Accelerated filer ☒ Non-accelerated filer ☐ Emerging growth company ☐ 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 ☒ GEOPARK LIMITED ‌TABLE OF CONTENTS Glossary of oil and natural gas terms Page iii PRESENTATION OF FINANCIAL AND OTHER INFORMATION vii FORWARD-LOOKING STATEMENTS x SUMMARY xii PART I 1 ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS 1 A. Directors and senior management 1 B. Advisers 1 C. Auditors 1 ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE 1 A. Offer statistics 1 B. Method and expected timetable 1 ITEM 3. KEY INFORMATION 1 A. Reserved 1 B. Capitalization and indebtedness 1 C. Reasons for the offer and use of proceeds 1 D. Risk factors 1 ITEM 4. INFORMATION ON THE COMPANY 32 A. History and development of the company 32 B. Business Overview 38 C. Organizational structure 79 D. Property , p lant and equipment 79 ITEM 4A. UNRESOLVED STAFF COMMENTS 79 ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS 79 A. Operating results 79 B. Liquidity and capital resources 92 C. Research and development , p atents and licenses, etc. 97 D. Trend information 97 E. Critical accounting p olicies and estimates 97 ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES 98 A. Directors and executive officers 98 B. Compensation 102 C. Board practices 107 D. Employees 109 E. Share ownership 110 F. Disclosure of a registrant´s action to recover erroneously awarded compensation 111 ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS 111 A. Major shareholders 111 B. Related party transactions 111 C. Interests of Experts and Counsel 111 ITEM 8. FINANCIAL INFORMATION 112 A. Consolidated statements and other financial information 112 B. S ig nificant changes 112 ITEM 9. THE OFFER AND LISTING 112 A. Offering and listing details 112 B. Plan of distribution 113 C. Markets 113 D. Selling shareholders 113 E. Dilution 113 i F. Expenses of the issue 113 ITEM 10. ADDITIONAL INFORMATION 113 A. Share capital 113 B. Memorandum of association and bye-laws 113 C. Material contracts 122 D. Exchange controls 122 E. Taxation 122 F. Dividends and paying agents 125 G. Statement by experts 126 H. Documents on display 126 I. Subsidiary information 126 ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK 126 ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES 126 A. Debt securities 126 B. Warrants and r ig hts 126 C. Other securities 126 D. American Depositary Shares 126 PART II 126 ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES 126 A. Defaults 126 B. Arrears and delinquencies 126 ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS 127 ITEM 15. CONTROLS AND PROCEDURES 127 A. Disclosure Controls and Procedures 127 B. Management's Annual Report on Internal Control over Financial Reporting 127 C. Attestation Report of the Registered Public Accounting Firm 128 D. Changes in Internal Control over Financial Reporting 128 ITEM 16. RESERVED 128 ITEM 16A. Audit committee financial expert 128 ITEM 16B. Code of Ethics 128 ITEM 16C. Principal Accountant Fees and Services 128 ITEM 16D. Exemptions from the listing standards for audit committees 129 ITEM 16E. Purchases of equi ty securities by the issuer and affiliated purchasers. 130 ITEM 16F. Change in registrant's certifying accountant 130 ITEM 16G. Corporate g overnance 130 ITEM 16H. Mine safe ty disclosure 131 ITEM 16I. Disclosure Regarding Fore ig n Jurisdictions that Prevent Inspections 131 ITEM 16J. Insider trading p olicies 132 ITEM 16K. Cybersecuri ty 132 PART III 135 ITEM 17. Financial statements 135 ITEM 18. Financial statements 135 ITEM 19. Exhibits 135 Index to Consolidated Financial Statements F-1 ii ‌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 "lightness" 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. "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. "horizontal well" means a well that is drilled vertically and then horizontally within a reservoir formation to increase contact with the producing zone. "hydraulic fracturing" means a stimulation technique that involves injecting water, sand and additives at high pressure into a well to create fractures in the reservoir rock and enhance the flow of hydrocarbons. "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" 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. "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 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. "unconventional resources" means hydrocarbon accumulations that require specialized extraction techniques, such as horizontal drilling and hydraulic fracturing, typically including shale and other low-permeability reservoirs. "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 ‌PRESENTATION OF FINANCIAL AND OTHER INFORMATION Certain definitions Unless otherwise indicated or the context otherwise requires, all references in this annual report to: "GeoPark Limited," or the "Company" are to GeoPark Limited, an exempted company incorporated under the laws of Bermuda; "GeoPark," "we," "us," "our," the "Group" and words of a similar effect, are to GeoPark Limited together with its consolidated subsidiaries; "GeoPark Brazil" are to GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.; "Ecopetrol" are to Ecopetrol S.A.; "YPF" are to YPF S.A.; "ONGC" are to ONGC Videsh Limited, international petroleum company of India; "Colden" are to Colden Investments S.A., an affiliate of Jaime Gilinski, who leads Grupo Gilinski; "Acquisition in Argentina's Vaca Muerta Formation" refers to our acquisition of operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Vaca Muerta shale formation in the Neuquén Basin in Argentina in 2025; "Unconsumated transaction in Argentina (Vaca Muerta)" refers to farm-out agreement in the Vaca Muerta shale formation in Argentina, previously announced in 2024, which was not consummated following the counterparty's withdrawal in May 2025; "PGR" or "Phoenix" are to Phoenix Global Resources; a subsidiary of Mercuria Energy Trading ("Mercuria"), together with its consolidated subsidiaries, such as Petrolera El Trebol S.A. ("PETSA"), Kilwer S.A. and Ketsal S.A.; "GyP" are to Gas y Petróleo de Neuquén S.A., the state owned entity of the Neuquén province in Argentina; "Petroecuador" are to the Ecuador Hydrocarbons Public Company (Empresa Pública de Hidrocarburos del Ecuador); "MSCI" are to Morgan Stanley Capital International; "Notes due 2027" are to our 2020 issuance of US$350.0 million aggregate principal amount and our 2021 additional issuance of US$150.0 million aggregate principal amount of 5.50% senior notes due 2027; "Notes due 2030" are to our 2025 issuance of US$550.0 million aggregate principal amount of 8.75% senior notes due 2030; "US$" and "U.S. dollar" are to the official currency of the United States of America; "AR$" and "Argentine pesos" are to the official currency of Argentina; " real ," " reais " and "R$" are to the official currency of Brazil; "ANH" are to the Colombian National Hydrocarbons Agency ( Agencia Nacional de Hidrocarburos ); "ANP" are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency ( Agência Nacional do Petróleo, Gás Natural e Biocombustíveis ); "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; "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; "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; "IFC" are to International Finance Corporation; and "OPEC" are to Organization of the Petroleum Exporting Countries. 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, 2025 and 2024 and for each of the years ended December 31, 2025, 2024 and 2023 (hereinafter "Consolidated Financial Statements"). Our Consolidated Financial Statements are presented in US$ and have been prepared in accordance with IFRS Accounting Standards ("IFRS"), as issued by the International Accounting Standards Board ("IASB"). Our Consolidated Financial Statements for the year ended December 31, 2025, have been audited by Ernst & Young Audit S.A.S., 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 2025," relate to our fiscal year ended on December 31 of that calendar year. viii 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 Group and the operating segments. We define Adjusted EBITDA as profit (loss) for the period (determined in accordance with the indenture governing our Notes due 2027, which does not give effect to the adoption of IFRS 16 Leases), before net finance results, 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 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 2025, 2024 and 2023. Oil and gas reserves and production information DeGolyer and MacNaughton 2025 Year-end Reserves Report The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia and Argentina is derived from estimates of the proved reserves as of December 31, 2025. 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 for blocks located in the Llanos and Putumayo Basins in Colombia, and in the Neuquén Basin in Argentina. 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. ‌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 using forward-looking words such as "anticipate," "believe," "could," "expect," "should," "plan," "intend," "will," "estimate" and "potential," among others. Forward-looking statements appear in several 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, Argentine 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; any future defaults in respect of our outstanding debt agreements; 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/or exchange rates in Colombia, Argentina, 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; weather and other natural phenomena; armed conflicts and heightened geopolitical tensions, including in the Middle East; 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; information technology failures; 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; potential impacts that tariffs may have on our cost structure, supply chain, and commodity markets; changes in the composition of our shareholder base, including the entry of new shareholders with significant stakes in the Company, as well as potential actions taken by third parties (or by a shareholder), including unsolicited acquisition proposals or attempts to acquire control, that may affect our corporate governance or strategic direction; the difficulty in integrating significant acquisitions, including the Acquisition in Argentina's Vaca Muerta Formation, 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 ‌SUMMARY This summary highlights certain information appearing elsewhere in this Annual Report. As this is a summary, it does not contain all the information you should consider in making an investment decision. You should read this entire Annual Report carefully before investing in the Company, including the risk factors and uncertainties set forth in "Item 3. Key Information- D. Risk factors." About Us We are a leading independent energy company with over 20 years of successful operations across Latin America and a long-term strategy to build a unique risk-balanced portfolio in the region's main basins. Our high-return core assets in Colombia's Llanos Basin demonstrate our exploration and operational strength. In Argentina, we have entered a new growth phase with Vaca Muerta, Latin America's fastest-growing play. Our long term strategic plan outlines a disciplined roadmap for value creation and is grounded in a two-fold approach that strengthens and maximizes the value of our core platform in Colombia while building a new, long-term growth engine in Argentina. Our disciplined capital allocation and financial management have enabled us to sustain strong margins, profitability, and a balanced capital structure year after year, providing flexibility to navigate market volatility while investing in high-value projects. Supported by our robust balance sheet, we have consistently rewarded our shareholders, returning close to US$320 million through dividends and buybacks since 2018. Promoting sustainable development has been part of our culture since our beginnings in the far south of the South American continent and influences all the decisions and actions we take, from strategic planning to daily operations. This commitment led to the creation of an integrated value system that guides all our activities across five interconnected areas: Safety, Prosperity, Employees, Environment and Community Development ("SPEED"). A fundamental aspect of our culture and corporate identity is how we evaluate and steer performance beyond just financial metrics to also consider the impact on people, society and the planet. Our Assets Our diversified portfolio of assets is characterized by its high potential, operational efficiency, and significant growth prospects. Our main asset is a 45% working interest in the operated Llanos 34 Block in Colombia, acquired in 2012 with no reserves or production and which we have made a world-class asset that includes two of Colombia's top 12 producing oil fields, Jacana and Tigana. Now starting its process of natural decline, partially mitigated by secondary recovery initiatives including the initiation of a polymer injection project, the Llanos 34 Block produced 17,211 bopd at our working interest in 2025 and holds certified proved reserves of 36.5 mmboe as of December 31, 2025. Adjacent to the Llanos 34 Block lies the CPO-5 Block, where we acquired a 30% non-operated working interest in 2020. The block's Indico field ranks among Colombia's top 8 producing oil fields. Net production averaged 6,484 bopd in 2025 and certified proved reserves were 6.3 mmboe as of December 31, 2025. We also operate the Llanos 86, Llanos 87, Llanos 104, Llanos 123, and Llanos 124 Blocks in the Llanos Basin. Significant discoveries in the Llanos 123 Block include the Toritos, Saltador, and Bisbita oil fields, and the block's net production was 2,115 bopd during 2025. Elsewhere in Colombia, we hold several blocks in the underexplored Putumayo Basin, including our developed Platanillo Block. In 2025, we entered the Vaca Muerta shale formation in Argentina with operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks, marking our return to Neuquén and establishing GeoPark as an accredited unconventional operator in the prolific black oil window. This acquisition continues our history of generating value through inorganic opportunities, and has an immediate impact on production, reserves, and cash flow. We have 23 years of operational experience, business know-how and an active financial network in Argentina, which we can leverage to increase our portfolio in the country. Our Sustainability Approach Building on our SPEED value system, in 2025 we updated our sustainability framework, structured around three drivers: operational efficiency and decarbonization, risk and opportunity management, and multiplying positive impact in the value chain. This framework reinforces our commitment to sustainability, strengthens our capacity to manage climate, nature and social risks, and capture opportunities that generate long-term value and resilience. It also enhances our operational efficiency through an optimal use and management of water, energy, and waste, while extending the reach of our sustainability initiatives beyond our operations by engaging suppliers, contractors, communities, and partners across our value chain. xiii ‌PART I ‌ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS ‌Directors and senior management Not applicable. ‌Advisers Not applicable. ‌Auditors Not applicable. ‌ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE ‌Offer statistics Not applicable. ‌Method and expected timetable Not applicable. ‌ITEM 3. KEY INFORMATION ‌Reserved ‌Capitalization and indebtedness Not applicable. ‌Reasons for the offer and use of proceeds Not applicable. ‌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: Risks relating to our business; Risks relating to the countries in which we operate; and Risks relating to our common shares. 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: Risks relating to our business Our results are highly sensitive to crude oil and natural gas price volatility. A substantial or extended decline in prices, wider differentials, or higher transportation costs could materially and adversely affect our business, financial condition and results of operations and may require changes to our corporate strategy. Our ability to sustain production depends on replacing reserves and successfully identifying and developing commercial prospects, and our reserve estimates rely on assumptions that may prove inaccurate. Drilling and development activities are subject to subsurface uncertainty and execution risks, including well under-performance, cost overruns and delays, and we face competition for capital, acreage, services and talent as well as potential shortages or late delivery of key inputs and constraints in third-party infrastructure (including pipelines, trucking and ports), which may limit volumes and increase costs. Our business is capital-intensive and depends on continued access to funding. Adverse market conditions, higher interest rates, foreign-exchange fluctuations, indebtedness and covenant limitations could restrict our ability to finance capital programs on acceptable terms. Insurance may not cover all operating hazards. The present value of future net revenues from proved reserves (including SEC price-based measures) may differ materially from the current market value of those reserves. We are subject to obligations under E&P contracts, exploration permits, exploitation concessions and concession agreements (including minimum work, reporting and discovery declarations) to retain our interests; failure to comply may result in penalties or the loss or early termination of rights in undeveloped areas, and some rights are subject to expiration or early termination based on operating conditions. We may not control budgets, timing, costs or production rates in non-operated or non-wholly owned assets. Our strategy includes acquisitions, strategic investments, partnerships and alliances; completed acquisitions may be difficult to integrate and may divert management attention, dilute stockholder value or lead to impairments, and future or pending transactions may be delayed, re-priced, fail to close or otherwise not deliver expected benefits. We also derive a significant portion of revenues from a few key customers, exposing us to counterparty and credit risks, and U.S. trade tariffs or supply-chain constraints could adversely affect costs and market access. Our operations entail environmental, social, health and safety obligations that may result in material liabilities and costs and are exposed to operating hazards, including accidents, spills, public-order events and extreme weather. Transition and physical risks (including investor sentiment, access to financing, restrictions affecting unconventional activity, carbon and greenhouse-gas ("GHG") rules, demand shifts, floods, droughts and heat) could increase costs or limit activity. Legislation and regulatory initiatives relating to hydraulic fracturing and other unconventional drilling may increase future costs, cause delays or impede plans. We depend on key management and technical personnel, our IT/OT systems may face cybersecurity threats and disruptions, endemic or pandemic diseases may disrupt workforce availability, logistics and demand, and land access and community relations (including negotiations with indigenous communities and sensitive biodiversity areas, including certain Putumayo blocks) may cause delays, incremental costs and reputational risks. Risks relating to the countries in which we operate We operate in Colombia, Argentina and Brazil, where regulatory frameworks continue to evolve. Changes in fiscal regimes, royalties, windfall taxes, price controls, export restrictions, local-content rules, environmental standards and permitting processes can adversely affect project economics and timelines. Policy shifts, social unrest and judicial challenges may result in delays, sanctions or new operating restrictions. In certain areas, particularly in Colombia, security risks (including the presence of illegal armed groups and vandalism or sabotage of energy infrastructure) could disrupt operations and increase costs. Macroeconomic conditions, inflation and exchange-rate volatility-especially currency controls and import/payment restrictions in Argentina-can affect procurement, debt service, distribution of cash and the repatriation of dividends. Expropriation or nationalization, contract reviews, or changes to concession terms, while infrequent, remain potential risks, and heightened scrutiny of unconventional resources and hydraulic fracturing could further restrict or delay activities depending on local policy developments. Risks relating to our common shares Our share price may be volatile due to commodity price movements, operating updates, reserve revisions, capital allocation decisions, macroeconomic conditions, changes in the composition of our shareholder base and investor sentiment toward the energy sector. Future equity offerings, equity-linked instruments or compensation programs could dilute existing shareholders, and limited analyst coverage or market liquidity may amplify price movements. Dividends and other capital returns are discretionary and depend on our financial performance, legal restrictions and board decisions; we may reduce or suspend dividends at any time. Changes in the composition of our shareholder base, including the entry of new shareholders with significant stakes in the Company, as well as potential actions taken by third parties (or by a shareholder), including unsolicited acquisition proposals or attempts to acquire control, may affect our corporate governance or strategic direction and could affect trading price of our common shares or lead to disputes or litigation. In June 2025, our board adopted a limited-duration shareholder rights plan intended to protect long-term shareholder value in the face of rapid stock accumulation by a single investor; some market participants may view such measures negatively. Additionally, foreign exchange controls and other country restrictions may limit our ability to repatriate cash or make payments to shareholders in certain circumstances. Detailed Risk Factors Risks relating to our business Volatility or sustained declines in oil and natural gas prices could materially adversely affect our business, financial condition, results of operations and corporate strategy. Our revenues, cash flows, profitability, liquidity, access to capital and growth prospects are highly dependent on the prices we receive for our oil and natural gas production. Commodity prices have historically been volatile and are expected to remain subject to significant fluctuations driven by factors largely beyond our control, including: global and regional economic conditions and supply-demand balances, OPEC and non-OPEC producers (sometimes referred to as OPEC+) production policies, geopolitical developments, armed conflicts, sanctions or other regulatory actions affecting major producing regions, global inventory levels, weather events, natural disasters, transportation constraints, quality differentials, fiscal regimes, technological developments, the availability and pricing of alternative energy sources, and evolving environmental and climate-related regulation, including potential carbon pricing mechanisms. These factors and the volatility of the energy markets make future oil and natural gas price movements difficult to predict. For example, during the last six 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. In 2025, Brent crude oil prices fluctuated within a range of US$58.9 to US$82.0 per barrel and averaged US$68.2 per barrel for the year, reflecting, among other factors, geopolitical tensions in the Middle East, broader global uncertainties and concerns over a potential economic slowdown, while coordinated OPEC+ actions, including voluntary production cuts, supported relative market stability. For the year ended December 31, 2025, 96% of our revenues were derived from oil. In addition to fluctuations in Brent crude oil prices, our realized prices are also affected by regional crude oil differentials. For example, the Vasconia differential applicable to our Llanos Basin production averaged approximately negative US$2.3 per barrel in 2025, but widened to approximately negative US$5.3 per barrel in January 2026 and negative US$7.5 per barrel in February 2026. Over the same period, Brent crude oil prices moved from US$60.5 per barrel at the end of 2025 to US$72.5 per barrel at the end of February 2026, and continued to experience significant volatility in March 2026 amid heightened geopolitical and military tensions in the Middle East, including tensions involving the United States and Iran, and related concerns regarding potential disruptions to regional oil supply and shipping routes. Regional differentials may fluctuate due to local supply and demand dynamics, refinery demand, transportation, export capacity constraints and other market conditions, and may widen or narrow independently of Brent crude oil prices. Developments affecting crude oil production and exports in major producing countries, including changes in supply dynamics or export flows in countries such as Venezuela, may further contribute to volatility in both benchmark prices and regional crude differentials. A sustained widening of such differentials, if not fully offset by changes in Brent crude oil prices, could reduce our realized prices and adversely affect our revenues, cash flows and results of operations. Because a substantial portion of our revenues is derived from oil production and we expect our production mix to remain predominantly oil-weighted, our financial performance is particularly sensitive to changes in oil prices. Lower commodity prices may reduce revenues on a per-unit basis, limit volumes that can be produced economically, adversely affect the valuation of our reserves, and constrain our ability to generate sufficient operating cash flow. Prolonged periods of low or volatile prices could require us to curtail or defer capital expenditures, revise our work programs, delay development and drilling activities, or reconsider the timing or feasibility of exploration, appraisal and acquisition opportunities. Our ability to fund capital expenditures relies in part on oil prices remaining near our planning assumptions, together with continued production performance and access to external financing. Lower prices may adversely affect our debt capacity and liquidity, including compliance with financial covenants, borrowing base availability, access to prepayment agreements, and overall financial flexibility. If operating cash flows and available cash resources are insufficient to fund planned investments, we may need to further reduce capital spending, seek additional financing or divest assets, which could negatively affect our growth prospects, investor confidence and share price. In periods of lower commodity prices, we may implement cost-containment measures, including renegotiations or reductions of service and supply contracts, which could expose us to claims, disputes or operational disruptions. Adverse price conditions may also impact the financial health of suppliers and contractors and their ability to provide services critical to our operations. Our budgeting, capital allocation and strategic planning processes rely on assumptions regarding commodity prices, production levels, drilling success rates, development costs, the timing of third-party projects, availability of equipment and qualified personnel, and access to financing. These assumptions are inherently uncertain and subject to significant business, economic, political and regulatory risks. If actual conditions differ materially from our assumptions, our capital requirements and liquidity needs could increase. We use derivative financial instruments as part of our commodity risk management strategy to partially mitigate exposure to oil price volatility. However, these instruments may limit our ability to benefit fully from increases in oil prices during periods of heightened market volatility, including those arising from geopolitical developments affecting global energy supply, such as the market conditions described above. In addition, adverse movements in the market value of our derivative positions may require us to post cash collateral, which could affect short-term liquidity during periods of heightened volatility. In addition, in certain jurisdictions where we operate, higher oil prices may result in increased government take through royalties, contractual mechanisms and tax surcharges, which may reduce net margins. 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 and field maturity. Accordingly, our current proved reserves will decline as these reserves are produced. As of December 31, 2025, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia and Argentina was 5.7 years. According to the D&M Reserves Report estimates, if on January 1, 2026, we ceased all drilling activities, our proved developed producing reserves base would decline by 4% and 25% during the first year in Colombia and Argentina, respectively. A significant portion of our production comes from relatively mature fields, such as our core Llanos 34 Block, which requires continuous investment in drilling, secondary and tertiary recovery methods, and infrastructure optimization to sustain output. Unexpected reservoir performance issues, such as lower-than-anticipated recovery rates or technical challenges in implementing enhanced recovery techniques, could negatively impact our ability to meet production targets and replenish reserves. 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. Due to the nature of the oil and gas industry, a significant portion of our revenue is derived from a few key clients. For example, in 2025, three clients represented 96% of revenue for our Colombian subsidiaries, accounting for 90% of our consolidated revenue. This client concentration is typical in the industry, where large-scale operations, logistical factors, and long-term contracts often lead to stable yet limited customer relationships. We actively manage counterparty credit risk by regularly assessing clients' credit profiles and including early payment terms in certain contracts to reduce potential exposure. To ensure competitive terms, we conduct regular market surveys and hold open tenders in an attempt to secure the best available offers and aiming to mitigate risks associated with having a limited customer base. Our primary customers are top-tier traders and producers, aligning with industry standards. 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, Argentina 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. For instance, during 2025, the Colombian peso appreciated by approximately 15% against the U.S. dollar, increasing the U.S. dollar equivalent of our local-currency costs in Colombia. 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 currency fluctuations particularly in connection with income tax payments and other recurring obligations. In November 2024, we entered into a derivative financial instrument with a local bank in Colombia, for an amount equivalent to US$50.0 million, in order to anticipate any currency fluctuation with respect to a portion of the estimated income taxes to be paid in May and June 2025. Additionally, in April 2025, we entered into derivative financial instruments with local banks in Colombia, for an amount equivalent to US$30.0 million (allocated at US$5.0 million per month during the second half of 2025), to partially mitigate potential currency fluctuations and protect our exposure to the Colombian peso arising from our regular business operations. However, these instruments do not cover all of our foreign exchange exposure, and extreme currency volatility, particularly in Argentina, could still materially affect our financial condition and operating results. 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 infrastructure to take advantage of our reserves. Exploration and production are subject to numerous risks beyond our control, including the risk that exploration will not identify commercially viable quantities of oil or natural gas. Our decisions to purchase, explore, develop or exploit prospects depend in part on seismic and other data and related analyses and studies, the results of which are often inconclusive or subject to varying interpretations. The marketability of production may be affected by factors beyond our control, including proximity from the production sites to the transportation points and capacity of such transportation, availability of processing facilities and equipment, and government laws and regulations relating to oil prices, sale restrictions, taxes, governmental stake, allowable production, imports and exports, environmental protection and health and safety. These factors may have a material adverse effect. There can be no assurance that drilling programs will produce quantities or costs anticipated, that producing projects will not cease production, or that we will be able to market production. 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. We have 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. 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-Our business strategy." We incurred capital expenditures of US$98.4 million and US$191.3 million during the years ended December 31, 2025 and 2024, 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 particular, our capital allocation is expected to increasingly reflect the development of our unconventional assets in Argentina, which may require significant and sustained investment levels and is subject to execution, market and country-specific risks. 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 during the COVID-19 pandemic in 2020, we reduced our capital expenditures program for that year by approximately 60% from prior preliminary estimates. 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, and our operations may be disrupted by risks and hazards beyond our control that are common among oil and gas companies, including environmental hazards, blowouts, industrial accidents, occupational safety and health hazards, technical failures, labor disputes, social protests or blockades, unexpected geological formations, flooding, earthquakes, weather-related interruptions, explosions and other accidents. While we believe we maintain customary insurance coverage for companies engaged in similar operations, we are not fully insured against all risks in our business. Insurance may contain significant exclusions and limitations, and we may elect not to obtain certain non-mandatory coverage if the cost is excessive relative to the risks presented. Uninsured or underinsured events and related losses or liabilities 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 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, between March 2024 and May 2025, our production in Brazil was negatively impacted due to an unplanned maintenance of the Manati gas field platform following a request to the operator from the ANP. In Colombia, during 2025, our production from the Indico field in the CPO-5 Block was affected by 10 community blockades for a total of 42 days, which contributed to a quarter-on-quarter decrease in average production and delays in our development plans for that field. On the other hand, the drilling costs for the Tigui-53 well in the Llanos 34 Block in Colombia, included costs overruns caused by operational issues of US$2.2 million. 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 in Colombia, which was temporary blocked adversely affecting production. 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 major oil and gas companies, including state-owned companies with greater financial and technical resources, and we compete for licenses and properties in the countries where we operate. Competitors may be able to pay more for properties and prospects, evaluate and bid for a greater number of opportunities, and offer more competitive compensation packages to attract and retain qualified personnel. There is also substantial competition for capital available for investment in the oil and natural gas industry. As a result, we may not be able to compete successfully in acquiring prospective reserves, developing reserves, marketing hydrocarbons, retaining 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 as of December 31, 2025 is based on the D&M Reserves Report. Although classified as "proved reserves," the reserves estimate set forth in the D&M Reserves Report 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 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 offloading 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, oil transportation logistics present ongoing challenges for producers due to the country's geographic complexities, road conditions for trucking, and limitations in pipeline infrastructure, including storage and offloading facilities. To address these challenges, we, along with our partner in the Llanos 34 Block, have developed the Oleoducto del Casanare Pipeline ("ODCA") to transport crude oil from key fields in the block and surrounding areas. This infrastructure has been a strategic solution to lower transportation costs, reduce blockade risks, and enhance our sustainability efforts by lowering carbon emissions. In 2025, we faced repeated disruptions due to strikes by local communities demanding attention to their needs, blocking routes essential for transporting crude oil by tanker trucks. While we have maintained production levels by utilizing alternative evacuation options, such as the ODCA pipeline, our market access could be significantly hindered if both trucking and pipeline options are compromised simultaneously. Such disruptions could materially impact our business, financial condition, and operating results. 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, which connects to the Ecuadorian pipeline system. However, our logistics chain remains subject to cross-border regulatory frameworks, commercial conditions and operational factors in both Colombia and Ecuador. For example, in early 2026 certain regulatory measures adopted in Ecuador affected the economics of crude oil deliveries through this route, requiring us to temporarily redirect certain volumes to alternative delivery points within Colombia, which involved higher transportation costs. Trucking remains a component of our crude oil delivery strategy, and while in 2025 we successfully used alternative delivery points and trucking to avoid production setbacks, we cannot assure that we will continue to be able to do so in the future. In Argentina, our assets in the Neuquén Basin are not connected to the regional pipeline network, which requires us to rely on trucking for the evacuation of crude oil to refineries and to delivery points that enable subsequent transportation through third-party pipeline systems to port facilities. This dependence on trucking exposes us to risks associated with road availability, strikes, weather conditions, equipment constraints, third-party service performance and potential congestion at receiving facilities. These risks are compounded by the fact that the regional pipeline system and certain downstream facilities operate with limited spare capacity. To mitigate these risks, we have entered into commercial arrangements with buyers that possess substantial and diversified logistics capabilities, which provide operational redundancy and enable us to indirectly access capacity within the regional pipeline network through these strategic partners. These arrangements support continuity of offtake and reduce our exposure to transportation bottlenecks. However, these measures may not fully eliminate the risks associated with limited infrastructure, interruptions in trucking services or restrictions in third-party pipeline or port operations. Any disruption or delay affecting these logistics chains could adversely affect our ability to transport crude oil and, in turn, our production levels, operating costs and financial results. 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. Our projects require timely easements, rights-of-way and site access agreements with landowners and local communities, including indigenous communities. If acceptable terms cannot be reached, we may need to seek judicial intervention through judicial mechanisms for enforcement of easements, which can be time-consuming, costly and delay operations. Even where agreements exist, negotiations may be prolonged or reopened; community expectations beyond legal requirements, prompts requests for additional compensation, social investments or infrastructure and, at times, protests or temporary blockades. In Colombia, these dynamics are more pronounced. Rising expectations from landowners and other stakeholders (including workers' associations and unions), potential reforms that may broaden participatory requirements for hydrocarbons projects, and social unrest can affect timelines and costs. In Putumayo, the presence of illegal groups and tensions related to illicit-crop eradication efforts have led to pressure tactics aimed at influencing government action. Communities may expect operators to repair or improve public roads or address basic needs typically funded by the government; authorities may impose or maintain access restrictions in response to protests or public-order events. Land restitution proceedings can also delay access to future sites. In Argentina (particularly in provinces such as Neuquén), surface access and rights-of-way typically require provincial and municipal permits and agreements with landowners, and projects may also require consultation with local and indigenous communities. Administrative or judicial challenges to environmental or access approvals, and labor actions by sector unions can delay mobilization and construction or constrain operations. To manage this risk, we maintain continuous and transparent dialogue with landowners, local and indigenous communities, authorities, and other stakeholders. We have developed a Human Rights System based on international standards, including the UN Guiding Principles on Business and Human Rights (the "UN Guiding Principles"), designed to help us integrate human rights considerations into project planning, land access negotiations, community engagement and operational decision-making. While the system provides a framework to support respectful and constructive engagement with landowners, local communities and indigenous peoples, outcomes depend on contextual factors outside our control, including evolving regulatory requirements, local expectations, and regional security dynamics. We cannot assure that disputes with landowners or communities, or related proceedings in any jurisdiction, will not delay or restrict our activities, require additional payments or commitments, or otherwise materially and adversely affect our business, financial condition and results of operations. Under the terms of some of our various E&P contracts, exploration permits, exploitation concessions 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, exploration permits, exploitation concessions 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, exploration permits, exploitation concessions and concession agreements over such areas may fluctuate and may increase significantly, including as a result of higher minimum work commitments, increased surface fees or royalties, inflationary pressures, additional regulatory or environmental requirements, or changes in applicable laws or contractual terms. 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, during the last couple of years, we have 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-Significant Agreements." Historically, a significant portion of our reserves and production has been derived from Colombia, particularly blocks in the Llanos and Putumayo Basins. In 2025, Argentina has become a growing contributor to our portfolio. For the year ended December 31, 2025, the different blocks in the Llanos Basin contained 77.4% of our net proved reserves and generated 92.6% of our production, the Platanillo Block in the Putumayo Basin contained 3.6% of our net proved reserves and generated 0.6% of our production, and the Loma Jarillosa Este and Puesto Silva Oeste Blocks in Argentina contained 19.0% of our net proved reserves and generated 1.1% of our production. While our continuing expansion with new exploratory blocks and inorganic opportunities incorporated in our portfolio, 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 and/or rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our E&P contracts, exploration permits, exploitation concessions and concession agreements are subject to early termination in certain circumstances. Under certain E&P contracts, exploration permits, exploitation concessions 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 termination of our E&P contracts, exploration permits, exploitation concessions and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2025, the aggregate outstanding amount of this potential liability for guarantees was US$58.0 million, mainly related to capital commitments in the Llanos 34, CPO-5, PUT-8, Llanos 86, Llanos 104 and CPO 4-1 Blocks in Colombia, and the Espejo and Perico Blocks in Ecuador (pending release at year-end following the divestment in December 2025). See "Item 4. Information on the Company-B. Business Overview-Significant Agreements" and Note 32.2 to our Consolidated Financial Statements. Additionally, certain E&P contracts, exploration permits, exploitation concessions and concession agreements to which we are or may in the future become a party are subject to set expiration dates. Although some of these agreements allow for exploration extensions and we may want to extend their term beyond their original expiration dates, there is no assurance that we can do so on terms that are acceptable to us or at all. 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 Argentina, hydrocarbon exploration permits and exploitation concessions are subject to termination for: (a) failure to pay any annual license fees within three months after they are due; (b) failure to pay royalties within three months after they are due; (c) material and unjustified failure to comply with the specified obligations in respect to productivity, conservation, investments, works or special benefits, including obligations arising under exploration permits and exploitation concessions or related agreements with provincial authorities; (d) repeated infringement of the obligations to submit demandable information, to facilitate inspections by the competent authority or to employ the proper techniques for the execution of the works; (e) failure to request an exploitation concession after a commercial discovery or to submit a development program after obtaining an exploitation concession; (f) the bankruptcy of the holder declared by a court; (g) the death or liquidation of the holder; or, (h) failure to comply with the obligation to transport hydrocarbons for third parties under open access conditions or repeated infringement of the tariff regime approved for such transport. Before declaring the termination under any of the grounds provided under items (a), (b), (c), (d), (e), or (h), notice shall be served, requiring the holder to remedy any such infringement. Upon expiration, relinquishment or termination of any permit or concession, the holder of such permit or concession may be required to surrender to the government the acreage and comply with applicable obligations regarding the retirement/abandonment of facilities and wells and the restoration of the area, as applicable. 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, exploration permits, exploitation concessions 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". 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 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. 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 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 operation. 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, during 2025, temporary blockades in the CPO-5 Block, adversely affected its production. Acquisitions that we have completed, including the Acquisition in Argentina's Vaca Muerta Formation, and any future acquisitions, strategic investments, partnerships, or alliances could be difficult to integrate, 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 where we do not currently operate. The successful acquisition and integration of producing properties, including the Acquisition in Argentina's Vaca Muerta Formation, 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 are often not entitled to contractual indemnification for environmental or other liabilities and acquire properties on an "as is" basis, which could also expose us to unknown or unforeseen liabilities. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller might not be able to fulfill its contractual obligations. There can be no assurance that unforeseen 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 the 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; 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; challenge and cost of obtaining sufficient financing required to complete the acquisitions and strategic transactions; tax implications and potential liabilities related to the acquisitions and strategic transactions; complexities, liabilities or additional costs associated with transaction payments due to capital controls; regulatory and legal challenges in the host countries, including worsening fiscal conditions, difficulty in obtaining regulatory approvals or environmental licenses, among others, which can materially affect the benefits expected from the acquisitions and strategic transactions; additional capital needs and cost overruns which may detract from available capital to deploy in other projects in our portfolio; 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. Additionally, we may incur one-off transaction-related costs, such as financing and due diligence expenses, even if a proposed acquisition is not completed, as was the case with the proposed acquisition of certain Repsol exploration and production assets in Colombia and the Unconsummated transaction in Argentina (Vaca Muerta), both in 2024. Moreover, if we fail to properly evaluate acquisitions, including the Acquisition in Argentina's Vaca Muerta Formation, 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. The Acquisition in Argentina's Vaca Muerta Formation broadens the scope of the risk factors related to our business, industry, and the countries in which we operate as such risk factors relate to operating in Argentina where we did not have operations immediately before the Acquisition in Argentina's Vaca Muerta Formation. Some of these risks include, but are not limited to, risks related to (i) the ability to replace our oil and natural gas reserves and continued identification of productive fields, (ii) our revenues being derived from sales to a few key customers, (iii) fluctuations in foreign currency exchange rates and restrictions or additional costs associated to the access to foreign currency, (iv) exploration and production of oil and natural gas, (v) insurance of oil and gas operations, (vi) potential cost overruns and delays in oil projects, (vii) difficulties to attract capital, acquire properties, marketing oil and securing trained personnel, (viii) estimated reserves being based on assumptions that may prove inaccurate, (ix) availability and access to needed equipment, infrastructure and evacuation capacity in a timely manner, (x) difficulties in negotiations with landowners and local communities, including additional investment and demands imposed by local communities and potential blockades derived thereof, (xi) our contracts being subject to contractual expiration dates and operating conditions, and in certain circumstances, subject to early termination or additional costs or commitments associated to the term extension, (xii) not being the sole owner of all our licensed areas and not holding all the working interests in some of our licensed areas, (xiii) development of our proved undeveloped reserves potentially taking longer and requiring higher levels of capital expenditures than expected, (xiv) our operations being subject to numerous environmental, social, health and safety laws, regulations, and rulings, which may result in material liabilities and costs, (xv) climate change, (xvi) political and economic circumstances, including increased exposure to the Argentine legal, fiscal, regulatory and economic systems, (xvii) maintaining good relations with host countries, local/provincial government and national oil companies in the countries where we operate, (xviii) operating and having working and/or economic interest over, yet not owning the oil and natural gas reserves in the countries where we operate, (xix) oil and gas operators being subject to extensive regulation, and (xx) exchange control regulations that could limit the ability to freely make payments and transfers outside Argentina, subject to certain conditions, including certain restrictions on access to the foreign exchange market to as well as requirements to repatriate and settle export proceeds in the official exchange market within specified timeframes. 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. It should not be assumed that the present value of ...

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