Table of Contents
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
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from ______________________ to ___________________________
☐ 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, 8o floor
Bogotá, Colombia
(Address of principal executive offices)
Maria Catalina Escobar
Shareholder Value and Capital Markets Director
GeoPark Limited
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
GPRK
New York Stock Exchange
Series A Preferred Shares Purchase Rights
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:
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.
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).
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 Standardsas issued by the International AccountingStandards 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).
TABLE OF CONTENTS
Page
Glossary of oil and natural gas terms
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
A.
Directors and senior management
B.
Advisers
C.
Auditors
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
Offer statistics
Method and expected timetable
ITEM 3. KEY INFORMATION
Reserved
Capitalization and indebtedness
Reasons for the offer and use of proceeds
D.
Risk factors
ITEM 4. INFORMATION ON THE COMPANY
32
History and development of the company
Business Overview
38
Organizational structure
79
Property, plant and equipment
ITEM 4A. UNRESOLVED STAFF COMMENTS
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
Operating results
Liquidity and capital resources
92
Research and development, patents and licenses, etc.
97
Trend information
E.
Critical accounting policies and estimates
ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
98
Directors and executive officers
Compensation
102
Board practices
107
Employees
109
Share ownership
110
F.
Disclosure of a registrant´s action to recover erroneously awarded compensation
111
ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
Major shareholders
Related party transactions
Interests of Experts and Counsel
ITEM 8. FINANCIAL INFORMATION
112
Consolidated statements and other financial information
Significant changes
ITEM 9. THE OFFER AND LISTING
Offering and listing details
Plan of distribution
113
Markets
Selling shareholders
Dilution
i
Expenses of the issue
ITEM 10. ADDITIONAL INFORMATION
Share capital
Memorandum of association and bye-laws
Material contracts
122
Exchange controls
Taxation
Dividends and paying agents
125
G.
Statement by experts
126
H.
Documents on display
I.
Subsidiary information
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
Debt securities
Warrants and rights
Other securities
American Depositary Shares
PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
Defaults
Arrears and delinquencies
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
127
ITEM 15. CONTROLS AND PROCEDURES
Disclosure Controls and Procedures
Management’s Annual Report on Internal Control over Financial Reporting
Attestation Report of the Registered Public Accounting Firm
128
Changes in Internal Control over Financial Reporting
ITEM 16. RESERVED
ITEM 16A. Audit committee financial expert
ITEM 16B. Code of Ethics
ITEM 16C. Principal Accountant Fees and Services
ITEM 16D. Exemptions from the listing standards for audit committees
129
ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers.
130
ITEM 16F. Change in registrant’s certifying accountant
ITEM 16G. Corporate governance
ITEM 16H. Mine safety disclosure
131
ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
ITEM 16J. Insider trading policies
132
ITEM 16K. Cybersecurity
PART III
135
ITEM 17. Financial statements
ITEM 18. Financial statements
ITEM 19. Exhibits
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:
“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.
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“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
v
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.
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Certain definitions
Unless otherwise indicated or the context otherwise requires, all references in this annual report to:
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.
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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.
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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.
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:
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.
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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.
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A. Directors and senior management
Not applicable.
B. Advisers
C. Auditors
A. Offer statistics
B. Method and expected timetable
A. Reserved
B. Capitalization and indebtedness
C. Reasons for the offer and use of proceeds
D. Risk factors
Our business, financial condition and results of operations could be materially and adversely affected if any of the risks described below occur. As a result, the market price of our common shares could decline, and you could lose all or part of your investment. This annual report also contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements.” The risks below are not the only ones facing our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. The following risk factors have been grouped as follows:
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:
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.
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.
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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
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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
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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
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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.
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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
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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
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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.
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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.
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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.
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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:
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
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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:
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
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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 future net revenues from our proved reserves represents the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2025, we based estimated discounted future net revenues on the 12-month unweighted arithmetic average of the first day-of-the-month price for the preceding 12 months. Actual future net revenues will be affected by factors including actual prices we receive, actual development and production costs, the amount and timing of production, changes in governmental regulations and taxation and the geopolitical landscape. The timing of production and expenses will affect the timing and amount of future net revenues and thus actual value. In addition, the 10% discount factor used may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the industry.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced.
As of December 31, 2025, 77% of our net proved reserves are developed. Development of our undeveloped reserves may take longer and require higher levels of capital expenditures than we currently anticipate. Additionally, delays in the development of our reserves or increases in costs to drill and develop such reserves will reduce the standardized measure value of our estimated proved undeveloped reserves and future net revenues estimated for such reserves, and may result in some projects becoming uneconomic, causing the quantities associated with these uneconomic projects to no longer be classified as reserves. This was due to the uneconomic status of the reserves, given the proximity to the end of the concessions for these blocks, which does not allow for future capital investment in the blocks. There can be no assurance that we will not experience similar delays or increases in costs to drill and develop our reserves in the future, which could result in further reclassifications of our reserves.
We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Customers may experience financial problems that negatively affect creditworthiness, limiting our ability to collect amounts owed or enforce performance under contractual arrangements. Declining cash flows (including due to commodity price declines), reductions in borrowing bases under reserves-based credit facilities and lack of available debt or equity
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financing may reduce customers’ liquidity and ability to make payments or perform obligations. Some customers may be highly leveraged and subject to their own operating expenses, which may increase risk. Customers may also be subject to regulatory changes that could increase default risk. Financial problems could impair our assets, decrease operating cash flows, and reduce or curtail customers’ future use of our products and services, adversely affecting revenues and potentially leading to a reduction in reserves.
Our operations are subject to operating hazards, including external conditions such as extreme weather events or public order and risks inherent to oil and gas activities, which could expose us to potentially significant losses.
Our operations are subject to potential operating hazards, extreme weather conditions and risks inherent to drilling activities, seismic recording, exploration, production, development and transportation and storage of crude oil. These include, among others, explosions, fires, high winds, heat stress, drought, increased rainfall, flooding and fire weather, as well as car and truck accidents, labor disputes, social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures, property damage, spills and mechanical failures of equipment at our or third-party facilities. Any of these events could have a material adverse effect on our exploration and production operations or disrupt transportation or other process-related services provided by our third-party contractors. For example, in 2025, temporary blockades at the CPO-5 Block and flooding during the rainy season in the Llanos 34 Block in Colombia adversely affected production, including the temporary suspension of operations at the Jacana Sur well pad.
We seek to manage these risks through an integrated framework that assesses physical and transition climate risks and identifies adaptation measures. These measures include monitoring weather-related risks, reinforcing infrastructure, diversifying energy sources (including electrification, access to gas and renewable energy such as solar and biomass) and implementing crisis management and business continuity procedures. We also identify, monitor and address social and public-order-related risks that may arise in connection with operational disruptions, including those associated with protests, blockades or regional security conditions, through our Human Rights System, including its due diligence and grievance mechanisms. However, these measures may not be sufficient to prevent operational disruptions, damage to infrastructure, injuries, environmental harm, financial losses or adverse impacts on surrounding communities. We cannot assure that operating hazards or external conditions will not delay or restrict our activities or otherwise materially and adversely affect our business, financial condition and results of operations.
We are highly dependent on our leadership and specialized technical, exploration and operational talent, including geoscientists and unconventional resource experts, as well as on our ability to hire and retain new qualified personnel.
The ability, expertise, judgment and discretion of management and technical and engineering teams are key to discovering and developing oil and natural gas resources. Our performance and success depend to a large extent on key members of our management, technical, exploration and operational team, and their loss or departure would be detrimental to future success. Our ability to execute our strategy and manage anticipated growth, including expansion into new geographies and unconventional plays, depends on recruiting, integrating and retaining qualified personnel. Employee retention is influenced by the economic environment, competitive labor market conditions and in certain cases, the remote location of our operations, which may intensify competition for skilled professionals and increase turnover. Competition to hire employees in operational, technical and leadership roles is strong, and the supply of qualified employees is limited in the regions where we operate and throughout Latin America. Loss of key personnel or inability to hire and retain qualified personnel could have a material adverse effect on our business.
We and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs.
We operate in jurisdictions with extensive environmental, social, health and safety frameworks and permit regimes covering, among other matters, (i) emissions and discharges, (ii) handling, storage, transport and disposal of regulated materials, (iii) worker health and safety, (iv) biodiversity, water and land use, and (v) decommissioning. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry, which may arise unexpectedly and result in material adverse effects on our business, financial condition and results of operations. Non-compliance, regulatory changes or environmental incidents can trigger investigations, fines, civil or criminal liability, suspension or termination of concessions or contracts, operational interruptions and higher costs, any of which could have a material
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adverse effect on our business, financial condition and results of operations. In Colombia, environmental licenses are administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts on our E&P contracts. Non-governmental organizations or other stakeholders may also seek injunctions or other remedies to halt activities or impose penalties.
The Regional Agreement on Access to Information, Public Participation and Justice in Environmental Matters in Latin America and the Caribbean, also known as the Escazú Agreement, is an international human rights treaty that was signed by all the countries in which we operate and has been ratified by all except Brazil, where pressure has been growing for the government to ratify. Forthcoming regulations arising form the ratification of the Escazú Agreement may expand participation and information requirements, potentially lengthening approvals and increasing compliance obligations. Enhanced protections for environmental and human-rights defenders may also influence stakeholder dynamics and project timelines.
We are subject to national and regional environmental regulations and require specific permits to operate. We seek to support compliance with applicable requirements through an environmental management system and a dedicated environmental team. We file annual environmental reports which are public, and undergo yearly follow-up reviews by the authorities. While we seek full compliance, timing and factors beyond our control, such as consultation processes with different stakeholders that can exceed regulatory timelines, may lead to delays or instances of non-compliance. In such cases, we seek to report progress to regulators and define action plans to demonstrate our diligence to reduce the possibility of sanctions, penalties or fines related to delayed fulfillment of obligations. However, these measures may not be sufficient to avoid adverse outcomes and could have a material adverse effect on our business, financial condition or results of operations.
Releases of regulated substances, legacy contamination or waste-disposal practices may require costly remediation or facility retrofits, and we may be held liable for human exposure or damage to property, natural resources, sensitive areas or endangered species. We also face decommissioning (plugging and abandonment) obligations that may be substantial and increase over time as regulations and technical standards evolve. We manage these risks through operational integrity and environmental monitoring programs, contingency and emergency response plans, regular site inspections, maintenance activities, and remediation programs consistent with applicable regulations. Decommissioning obligations are addressed through long-term asset retirement planning and periodic review of cost estimates. Despite these measures, environmental incidents, liabilities or associated costs may still occur, and we can be responsible for environmental, social, health and safety liabilities arising from partners, predecessors and third-party contractors. We have adopted a Supplier Code of Conduct since 2023, under which we define the minimum obligations and behaviors expected from our contractors and suppliers, residual risk remains and insurance may not cover all losses, claims or interruptions. Delays in meeting offset or other permit conditions, particularly where multi-stakeholder consultations take longer than regulations contemplate, could result in sanctions or penalties.
Climate-related regulation and targets may also affect us. We expect continued and increasing attention to climate change, including regulation of GHG emissions such as methane and carbon dioxide and physical climate impacts in areas where we and our customers operate. Such developments could adversely impact our operations and the demand for our products. We target a 35 to 40 percent reduction in Scope 1 and 2 GHG emissions intensity by year-end 2025 and a 40 to 60 percent reduction by year-end 2030 versus a 2020 baseline, and we have a long-term ambition to reach net zero for Scopes 1 and 2 by 2050. Achieving these objectives depends on capital allocation, growth trajectories, project timing, the availability and commercial viability of reduction technologies and projects, permitting and third-party performance, as well as changes in the regulatory framework. These efforts will require capital expenditures and resources, and actual costs may differ, potentially materially, from current estimates. Failure to implement cost-effective strategies or to access necessary technologies or projects could jeopardize the achievement of these targets or ambitions and expose us to legal, regulatory, market or reputational risks.
Environmental, social, health and safety laws and regulations are complex and change frequently, and our costs of complying with such laws and regulations may adversely affect our results of operations and financial condition. Within applicable law, we engage with authorities, industry associations and other stakeholders through public consultations, institutional dialogue and technical working groups to provide input on proposed laws and regulations that may affect our business. These efforts are intended to support clear and workable rules, but do not prevent the adoption of regulations or
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decisions that could materially and adversely affect our business, financial condition and results of operations. See “Item 4. Information on the Company—B. Business Overview—Health, safety and environmental matters” and “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework.”
Changing investor sentiment towards fossil fuels and the global energy transition may affect our operations, impact the price of our common shares and limit our access to financing and insurance.
Factors including concerns about the contribution of fossil fuels to climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation, potential impacts on human rights, and the global shift towards lower-carbon energy sources have affected certain investors’ sentiments towards investing in the oil and gas industry. In addition, measures to accelerate the energy transition, such as the adoption of renewable energy, electric vehicles, alternative fuels, and stricter GHG emissions regulations, may reduce long-term demand for hydrocarbons and adversely impact commodity prices and the valuation of oil and gas assets.
As a result of these concerns, some institutional, retail, and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies, or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Although we have in place strong and robust social, environmental and governance practices, developing and implementing even broader policies and practices can involve significant costs and require a significant time commitment from our board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in our Company or not investing in our Company at all.
Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, our Company, may result in limiting our access to capital and insurance, increasing the cost of capital and insurance, and decreasing the price and liquidity of our common shares even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of our assets which may result in an impairment charge.
To address these risks, we maintain transparency and reporting programs aligned with recognized sustainability frameworks and indices; however, third-party assessments are based on their own methodologies and may change over time and may not reflect our future performance or risk profile.
For further information on the implementation of a decarbonization plan which allows us to manage our emissions through mitigation and compensation actions, which have helped to lower our emissions and, therefore, our susceptibility to negative impacts from these risks, see “Item 4.—B. Business Overview—Health, safety and environmental matters—Climate Change”.
Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations.
Hydraulic fracturing of unconventional oil and gas resources is a process that involves injecting water, sand, and small volumes of chemicals into the wellbore to fracture the hydrocarbon-bearing rock thousands of feet below the surface to facilitate a higher flow of hydrocarbons into the wellbore. We may eventually contemplate, after obtaining due environmental approvals, such use of hydraulic fracturing in the production of oil and natural gas from certain reservoirs. Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations.
In Colombia, during the second half of 2022, the Council of State (the highest administrative court) issued a decision by which it denied the claims that were seeking nullity of the regulation for “non-conventional hydrocarbons”. Therefore, the regulation for unconventional oil and gas resources in Colombia is in force and with full effects. However, the government is seeking to prohibit fracking techniques in Colombia and, during the second half of 2022, a bill of law to
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forbid fracking and exploitation of unconventional hydrocarbons was filed in Congress. The bill of law was not approved. In 2024, the Ministry of Environment filed a new bill of law with the same purpose. This is the sixth time this initiative has been filed in Congress since 2018. Currently, there is a new initiative ongoing and approval is uncertain. The Group is continuously monitoring any development in this matter.
In Argentina, our unconventional activities depend on the continued availability and acceptance of hydraulic fracturing and other stimulation techniques. These activities are subject to federal, provincial and municipal regulation and increasing scrutiny from regulators, communities and other stakeholders. Any new or more stringent laws or regulations, permitting requirements, limitations or bans applicable to hydraulic fracturing, water use, waste management, chemical disclosure or induced seismicity in Argentina could increase our costs, delay or restrict our ability to drill and complete wells, limit our recoverable reserves or otherwise adversely affect our unconventional development plans and the value of our Argentine assets.
We currently are not aware of any proposals in Argentina, or Brazil to regulate hydraulic fracturing beyond the regulations already in place. However, various initiatives in other countries with substantial shale gas resources have been or may be proposed or implemented to, among other things, regulate hydraulic fracturing practices, limit water withdrawals and water use, require disclosure of fracturing fluid constituents, restrict which additives may be used, or implement temporary or permanent bans on hydraulic fracturing. If any of the countries in which we operate adopts similar laws or regulations, which is something we cannot predict right now, such adoption could significantly increase the cost of, impede or cause delays in the implementation of any plans to use hydraulic fracturing for unconventional oil and gas resources.
Our indebtedness and other commercial obligations could adversely affect our financial health and our ability to raise additional capital and prevent us from fulfilling our obligations under our existing agreements and borrowing of additional funds.
As of December 31, 2025, the principal amount of our outstanding consolidated indebtedness was US$539.3 million, of which 82% corresponds to our Notes due 2030.
Our indebtedness could:
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The indentures governing our Notes due 2027 and Notes due 2030, include covenants restricting dividend payments and other shareholder distributions. For a description, see “Item 5. Operating and Financial Review and Prospects—B. Liquidity and Capital Resources—Indebtedness.”
As a result of these restrictive covenants, we are limited in the manner in which we conduct our business, and we may be unable to engage in favorable business activities or finance future operations or capital needs. We have in the past been unable to meet incurrence tests under the indenture governing our prior notes, which limited our ability to incur indebtedness. Failure to comply with the restrictive covenants included in our Notes due 2027 and our Notes due 2030 would not trigger an event of default.
Similar restrictions could apply to us and our subsidiaries when we refinance or enter into new debt agreements which could intensify the risks described above.
Our business could be negatively impacted by cybersecurity threats and related disruptions.
We rely on information technology systems, including systems which are managed or provided by third-party providers, to conduct our business and support our exploration, development, and production activities. We increasingly depend on digital technologies, such as applications, a cloud environment, mobile platforms, computers, and telecommunications systems. We collect, use, transmit, store, and otherwise process data using information technology systems, including systems owned and maintained by us or our third-party providers. These data include confidential information and intellectual property belonging to us or our customers or other business partners.
All information technology systems are subject to disruptions, outages, failures, and security breaches or incidents. A breach or failure of our digital infrastructure, control systems, or cyber defenses, or those of our third-party providers, as a result of negligence, intentional misconduct, or otherwise, could seriously disrupt our operations. We and our third-party providers have experienced, and expect to continue to experience, cybersecurity attacks. Cybersecurity attacks may range from employee or contractor error or misuse or unauthorized use of information technology systems or confidential information, to individual attempts to gain unauthorized access to these information systems, to sophisticated cybersecurity attacks, known as advanced persistent threats, any of which may target us directly or indirectly through our third-party providers. Despite employee training and other measures to mitigate vulnerabilities, our employees have been and will continue to be targeted by parties using fraudulent “spam”, “scam”, “phishing” and “spoofing” emails to misappropriate information or to introduce viruses or other malware programs to our technology environment. Cybersecurity attacks are increasing in number worldwide, and the attackers are increasingly organized and well-financed, or at times supported by state actors. Our industry is subject to fast-evolving risks from cyber-threat actors, including states, criminals, terrorists, hacktivists, and insiders. To the extent artificial intelligence capabilities improve and are increasingly adopted, they may be used to identify vulnerabilities and craft increasingly sophisticated cybersecurity attacks. Vulnerabilities may be introduced from the use of artificial intelligence by us, our customers, suppliers and other business partners and third-party providers.
We continuously devote significant resources to network security, data loss prevention, and other measures to protect our systems and data from unauthorized access or misuse, and we may be required to expend greater resources in the future, especially in the face of evolving and increasingly sophisticated cybersecurity threats and laws, regulations, and other actual and asserted obligations to which we are or may become subject relating to privacy, data protection, and cybersecurity.
We may be unable to anticipate, prevent, or remediate future attacks, vulnerabilities, breaches, or incidents, and in some instances, we may be unaware of vulnerabilities or cybersecurity breaches or incidents or their magnitude and effects, particularly as attackers are becoming increasingly able to circumvent controls and remove forensic evidence. Cybersecurity incidents may result in business disruption; delay in the development and delivery of our products; disruption of our production processes, internal communications, interactions with customers and suppliers and processing and reporting financial results; the theft or misappropriation of intellectual property; corruption, loss of, or inability to access (e.g., through ransomware or denial of service) confidential information, trade secrets, proprietary information, personal information, and other critical data (i.e., that of our company and our third-party providers and customers); reputational damage; private claims, demands, and litigation or regulatory investigations, enforcement actions, or other
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proceedings related to contractual or regulatory privacy, cybersecurity, data protection, or other confidentiality obligations; diminution in the value of our investment in research, development and engineering; and increased costs associated with the implementation of cybersecurity measures to detect, deter, protect against, and recover from such incidents. Furthermore, the need for rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and coordinated means, presents a challenge we must face and any delay or failure to detect cyber incidents could compound potential harms. This could result in significant and compounding losses due to the cost of remediation and reputational consequences.
As we expand into new jurisdictions, such as our recently initiated operations in Argentina, the integration of new sites, users, systems and local third-party providers into our corporate technology environment increases our overall cyber-risk exposure. New locations may present unforeseen vulnerabilities, including greater reliance on local networks and evolving regulatory and data-protection requirements. Even though we apply our corporate cybersecurity controls and risk-assessment protocols to these new operations, any cybersecurity incident affecting a newly integrated location or its local service providers could exacerbate the operational, financial and reputational impacts described above.
Our efforts to comply with, and changes to, laws, regulations, and contractual and other actual and asserted obligations concerning privacy, cybersecurity, and data protection, including developing restrictions on cross-border data transfer and data localization, could result in significant expense, and any actual or alleged failure to comply could result in inquiries, investigations, and other proceedings against us by regulatory authorities or other third parties. Customers and third-party providers increasingly demand rigorous contractual provisions regarding privacy, cybersecurity, data protection, confidentiality, and intellectual property, which may increase our overall compliance burden. With respect to certain potential incidents, such as a cyber-attack or data breach, we are covered under a cybersecurity insurance. However, no assurances can be made as to whether the insurance policy is sufficient in coverage or amount to cover all our potential liability.
The uncertainty of the impact an endemic or pandemic disease, such as the COVID-19 pandemic, may have, makes it impossible for us to identify all potential risks or estimate the ultimate adverse impact on our business.
A pandemic or endemic disease could adversely affect our business, financial condition, cash flows and results of operations by causing widespread economic and social disruption, reducing global demand for oil and gas, interrupting supply chains, and restricting our workforce’s ability to access and operate facilities. Uncertainty regarding the scope, duration and severity of any pandemic makes it impossible to identify all potential risks or estimate ultimate impact. The COVID-19 pandemic had a profound impact on the global economy, financial and commodities markets and the oil and gas industry, including a sharp decline in crude oil prices in 2020, and highlighted how pandemics can amplify other risk factors. Although we implemented measures to mitigate potential operational disruptions (such as remote working procedures), future outbreaks could materially and adversely affect our business and operations.
We operate in an industry with climate related risks.
The oil and gas industry is particularly exposed to risks arising from climate change and the energy transition, such as volatility of products prices, possible new regulations that may restrict our operations, or increase our costs to operate, and an increase in extreme weather events that affect our ability to operate. Moreover, our main producing assets are located in Colombia, where the risks related to the occurrence of natural hazards such as floodsand droughts are high and expected to increase in the following years.
In 2022, we made a climate risk assessment for the entire company, which was updated in 2025. The results of this assessment indicate that the occurrence of physical risks could adversely affect approximately 10% of the company’s overall value (for purposes of this assessment, the net present value of projected free cash flows from the combined asset portfolio), while transition risks could potentially impact up to 29% of its value. Although mitigation measures have been adopted to address these risks, we are currently working on an integrated adaptation plan to further address potential gaps.
To address our exposure to energy costs volatility, during the second half of 2025, we entered into a derivative financial instrument to partially mitigate potential increases in electricity costs in Colombia resulting from droughts and reduced hydroelectric generation. This risk is particularly significant in the Llanos 34 Block, where electricity expenses
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represent a significant portion of our production and operating costs. This derivative was a contract for differences on the generation component of the electricity tariff, structured as a fixed-for-floating swap that settled financially against the wholesale spot market price.
Our operations may be affected by biodiversity-related constraints, indigenous peoples’ rights and prior consultation processes, and land and territorial claims.
Some of our operations are in or adjacent to areas with significant biodiversity value, including areas that may be considered for designation as conservation or protected areas. These conditions may require modifications to our plans to comply with environmental constraints and permitted land use, which could increase costs and delay timelines. We seek to mitigate these risks through detailed due diligence and project-specific environmental studies. However, factors outside our control, including local politics and political decisions, may affect outcomes.
In addition, we operate in culturally diverse areas with historical and current ties to indigenous peoples, which may require prior consultation processes under applicable law and regulations. These processes may cause delays, lead to claims (including by groups not certified by competent authorities), and increase the risk of disputes over agreements scope or requests for additional commitments. We have completed prior consultation processes for the Golondrina Development Area Project in the Llanos 86 and Llanos 104 Blocks, with resulting agreements formalized in 2025, and we are ensuring compliance with the commitments established. For the Nasua Development Area Project in the Coatí Block (Putumayo), five prior consultations are in the pre-consultation and opening stage and are expected to be completed by 2026. We seek to manage these risks through a differentiated engagement approach, including early social and environmental baseline studies, our Human Rights System and grievance mechanisms, and an internal protocol adopted in 2025 that guides consultation and engagement throughout the project lifecycle. These measures, however, may not be sufficient to prevent delays, disputes or claims.
Specifically in Putumayo, exploration blocks may entail significant biodiversity-management costs and reputational risk due to sensitive environmental conditions, legal requirements, and challenges related to overlapping territories and indigenous land titling processes (including processes under Colombia’s land restitution law). We design our projects applying the mitigation hierarchy and considering site-specific conditions to avoid or minimize impacts on sensitive ecosystems, forest coverage and ecosystem connectivity. We also engage with the Ministry of the Interior to identify recognized communities and establish measures to prevent and mitigate impacts, conduct human rights identification and analysis exercises and implement related roadmaps, and coordinate with environmental authorities, local governments and scientific institutions to align biodiversity measures with regional conservation priorities, while maintaining communication and participation processes with local communities. Nevertheless, these actions may not prevent delays, additional obligations, restrictions on activities, disputes, regulatory actions or reputational impacts, which could increase costs or limit our ability to operate in the Putumayo region and adversely affect our business, financial condition and results of operations.
U.S. trade tariffs may adversely affect our cost structure, supply chain, and commodity markets.
The U.S. government has maintained and, in some cases, increased or modified trade tariffs on a range of goods and services, contributing to increased uncertainty in global trade dynamics. While we do not directly import or export significant volumes of materials from or to the United States, our operations rely on equipment, technology, and services sourced globally, many of which may be affected by these measures. The resulting disruptions could lead to higher costs or delays in the procurement of critical inputs. Additionally, escalating trade tensions and broader shifts in trade policy could impact global commodity prices, potentially affecting the markets for the oil and gas we produce.
Moreover, changes in U.S. sanctions programs administered by the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC), including measures affecting Venezuela’s oil sector, and related policy developments could contribute to heightened volatility in global energy markets. Even if we do not have direct operations in Venezuela, such measures could indirectly affect us through their potential impact on regional supply and trade flows and, therefore, on benchmark oil prices (including Brent and WTI), as well as through potential disruptions to regional supply chains and service markets. Any resulting commodity price volatility, cost inflation, procurement delays, or constraints on the availability of equipment, technology or services could adversely affect our cost structure, project timelines and financial
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results. At the same time, evolving regulatory or geopolitical conditions affecting Venezuela could also create potential strategic opportunities in the region, which we may evaluate in accordance with our investment criteria and risk management framework.
As an example of the potential consequences, a sustained adverse price outlook or cost inflation could trigger impairment indicators under IFRS for certain cash-generating units and result in impairment charges, and heightened volatility may lead us to add commodity hedges. Future trade restrictions or related measures could require us to adopt cost-containment strategies that may adversely impact our workforce, operations, and overall competitiveness.
Risks relating to the countries in which we operate
Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future.
All of our current operations are located in South America. If local, regional or worldwide economic trends adversely affect the economy of any of the countries in which we have investments or operations, our financial condition and results of operations could be adversely affected.
Oil and natural gas exploration, development and production activities are subject to political and economic risks, including but not limited to changes in energy policies or in the personnel administering them changes in laws and policies governing the operations of foreign-based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals from regulators, foreign exchange restrictions, price controls, currency fluctuations, royalty increases and other risks arising from governmental action. Given the political and social context, the Group may also face risk of loss due to civil strife, acts of war and community-based actions, such as protests or blockades, guerilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. These challenges tend to be greater in developing markets, which represent a key part of our business footprint.
The main economic risks we face and may face in the future because of our operations in the countries in which we operate include:
In addition, our operations in these areas increase our exposure to risks of illegal armed group activities, social unrest, community protests or blockades, expropriation and other governmental actions that may disrupt our operations, require higher security or operating costs, restrict the movement of funds or limit repatriation of profits, lead to sanctions or limit access to markets, and negatively affect investors’ perception of the risk associated with our operations in these countries.
Some countries where we operate have experienced, and may continue to experience, political instability, and losses caused by these disruptions may not be covered by insurance.
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Colombia has experienced periods of unrest, including protests, strikes and road blockades, and its 2026 electoral cycle, which kicked off in 2025, has heightened the risk of renewed instability and policy changes affecting permitting, fiscal terms, community relations and security conditions. In Argentina, macroeconomic and policy uncertainty, including high inflation, recessions, significant exchange rate volatility, foreign-exchange controls, import restrictions, fiscal and external imbalances and a history of sovereign debt restructurings and reliance on multilateral financing, has adversely affected, and may continue to adversely affect, economic activity, access to credit and overall business conditions in the country. These factors, together with the risk of further tightening or modification of exchange controls and potential changes to hydrocarbons, tax and labor frameworks, may disrupt procurement and project schedules, increase our costs, constrain funding and limit the repatriation of cash from our Argentine operations, and could require us to revise our business plans and investment levels in the country. We are also subject to a complex labor regulatory framework and to the presence of powerful labor unions, especially in Argentina. The combination of evolving labor regulation, strong unionization and a relatively high level of labor litigation could increase our labor and compliance costs, expose us to additional claims and disputes, and adversely affect the continuity and efficiency of our operations in that country.
Our operations may also be adversely affected by laws and policies in the jurisdictions in which we do business, that affect foreign trade and taxation, and by changes in, or uncertainties in the application of, tax laws in these emerging economies, which may increase our tax liabilities. For example, the Colombian government (i) enacted a tax reform in 2022 that materially impacted oil producing companies by introducing a surtax on corporate income ranging from 0% to 15%, depending on average oil prices, and (ii) in 2025 implemented extraordinary tax measures through states of exception, including a special tax on the sale and export of hydrocarbons and an increased stamp tax rate on public and private documents that record the creation, modification, or extinction of obligations. Additionally, in late 2025 and early 2026, Colombia adopted further extraordinary measures under states‑of‑exception powers. In early 2026, the Colombian Constitutional Court provisionally suspended the nationwide emergency declaration and, as a consequence, ordered that the related tax measures decree would not produce effects pending a final constitutionality ruling. More recently, in February 2026, the Colombian Government declared a new regional State of Economic, Social and Ecological Emergency for 30 days in certain northern and Caribbean departments. Additional extraordinary measures, including temporary fiscal measures, may be adopted in connection with that emergency. These developments underscore the risk of rapid changes and legal uncertainty in the applicability of such measures, which could adversely affect our costs and cash flows. For further information, please see “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia—Regulatory framework—Tax regulations implemented in 2025 and subsequent events in 2026.”
Changes in any of these laws or policies, or in how they are implemented, may increase the volatility of domestic securities markets and securities issued abroad by companies operating in these countries, which could materially and adversely affect our financial position, results of operations and cash flows. Furthermore, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute. Changes in tax laws may result in increases in our tax payments, which could materially adversely affect our profitability, restrict our ability to do business in our existing and target markets and cause our results of operations to suffer. There can be no assurance that we will be able to maintain our projected cash flow and profitability following any increase in taxes applicable to us and to our operations.
We depend on maintaining good relations with the respective host governments and national and provincial oil companies in each of our countries of operation.
The success of our business and the effective operation of our fields in each country where we operate, depend on maintaining strong relationships and effective cooperation with government authorities and agencies, including national and provincial oil companies such as Ecopetrol, YPF, GyP, and Petrobras. A failure by us, the host governments, or the respective national and provincial oil companies to cooperate effectively could have an adverse impact on our business, operations and prospects.
We seek to manage this risk through regular engagement with host governments, regulatory authorities and national and provincial oil companies, including formal communication channels, joint committees and periodic operational reviews, and by implementing procedures to support compliance with contractual and regulatory obligations. We also participate in industry associations and forums to provide input on energy and regulatory matters that may affect our
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operations. However, these efforts may not be sufficient to prevent disagreements, changes in government policies or priorities, contract revisions, non-renewals or other adverse actions, any of which could materially and adversely affect our business, operations and prospects.
Oil and natural gas companies in Colombia, Argentina, and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries.
Under Colombian, Argentine, and Brazilian law, all hydrocarbon resources in these countries are owned by the respective sovereign. Although we have working and/or economic interests in blocks and generally have the power to make decisions regarding marketing of produced hydrocarbons, the governments have authority to determine rights, royalties or compensation for exploration and production. If governments restrict or prevent concessionaires from exploiting reserves, or interfere through regulations relating to restrictions on future exploration and production, price controls, export controls, foreign exchange controls, income taxes, expropriation, environmental legislation or health and safety, this could have a material adverse effect. We are also dependent on government approvals and permits to develop concessions, and changes in policies (including labor relations) or delays in approvals may delay operations or affect contractual arrangements or our ability to meet contractual obligations.
Oil and gas operators are subject to extensive regulation in the countries in which we operate.
The Colombian, Argentine, and Brazilian hydrocarbons industries are subject to extensive regulation and supervision by their respective governments in matters such as the environment, social responsibility, tort liability, health and safety, labor, the award of exploration and production contracts, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls, export and import restrictions, capital expenditures and required divestments. In some countries in which we operate, such as Colombia, we are required to pay a percentage of our expected production to the government as royalties. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia” and see Note 32.1 to our Consolidated Financial Statements.
In Colombia and Argentina, our operations are subject to complex and evolving hydrocarbons and energy regulations and, in the case of Argentina, to emergency measures and a high degree of government intervention, including tariff and price frameworks, domestic market supply obligations, export and import restrictions, subsidies and other regulatory mechanisms. Changes in, or uncertainties regarding the interpretation or enforcement of, these regulations and policies may delay or restrict our projects, increase our operating and capital costs, affect the economic viability of certain developments or restrict our ability to market and export our production, which could materially and adversely affect our business, financial condition, results of operations and cash flows in these jurisdictions.
Significant expenditures may be required to ensure our compliance with governmental regulations related to, among other things, licenses for drilling operations, environmental matters, drilling bonds, reports concerning operations, the spacing of wells, unitization of oil and natural gas accumulations, local content policy and taxation.
Our operations are subject to security, community and human rights risks that could adversely affect our business.
In certain countries where we operate, particularly in Colombia, internal security, community and human rights challenges have had and could continue to have adverse effects on the economy and our operations. Colombia faces persistent internal security and community-related challenges that may negatively affect the Colombian economy and materially disrupt our business. Armed groups, including dissident factions of the Revolutionary Armed Forces of Colombia (“FARC”), the National Liberation Army (“ELN”) and the Clan del Golfo, remain active in several regions and are involved in activities such as drug trafficking, extortion, illegal mining and kidnapping. In some cases, these groups have carried out actions against infrastructure, including oil and gas facilities and pipelines, causing environmental damage and operational disruptions. The ELN has continued to attack oil pipelines, resulting in environmental harm and interruptions to operations. These dynamics, together with broader political and social tensions, increase uncertainty and the risk of escalation.
Our operations are conducted in areas where security incidents, social unrest and community-related issues may interrupt or delay exploration and production activities, with risks varying by region. In Casanare and Meta, operations
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have been affected by blockades and social protests, while in Putumayo the presence of illegal armed groups linked to drug trafficking has contributed to population displacement, protests related to the eradication of illicit crops and risks associated with improvised explosive devices. Any intensification of these conditions could adversely affect our assets, employees, production levels and financial results.
In contrast, the security environment in Argentina remains generally under control within a national framework aimed at strengthening territorial control, combating drug trafficking and protecting critical infrastructure. In the province of Neuquén, where a significant portion of Argentina’s oil and gas activity is concentrated, identified risks—such as minor equipment theft, vandalism at remote facilities or occasional local protests—are monitored and managed through preventive plans coordinated with authorities and communities, allowing operations to be carried out without material disruption.
To address security, community and human rights risks across our operations, we conduct annual risk assessments that integrate incident analysis, social context and emerging threats. Since 2022, we have strengthened our security and human rights management framework, including requiring contractors and partners to operate in accordance with international standards and the Voluntary Principles on Security and Human Rights. Compliance with national laws and international human rights treaties, as well as engagement with authorities and communities, may require additional resources and could result in project delays. Any failure to effectively manage these risks could have a material adverse effect on our business, financial condition and results of operations.
Exposure to corruption and compliance risks in the jurisdictions in which we operate could adversely affect our business, financial condition, and reputation.
We operate in jurisdictions that have historically faced transparency challenges and are perceived as having high levels of corruption. Additionally, we are subject to various anti-corruption regulations, including the U.S. Foreign Corrupt Practices Act (FCPA), the UK Bribery Act and local anti-corruption and compliance laws in each of the countries where we operate. Enforcement of these regulations has intensified in recent years across the jurisdictions and sector in which we operate, resulting in significant investigations and sanctions against both public and private entities. The institutional and enforcement environment in the countries where we operate is characterized by complex and sometimes inconsistent application of laws and regulations, and a history of investigations involving public officials and private companies. Although we have policies and procedures designed to ensure compliance with applicable anti-corruption, anti-money laundering and other laws, we cannot assure you that our employees, contractors, suppliers, joint venture partners or other third parties with whom we do business will not take actions in violation of such laws and regulations. In addition, we may be adversely affected by investigations, enforcement actions, court decisions or changes in enforcement priorities in Argentina, even if we are not the target of such proceedings, for example, through delays in obtaining permits, revisions to contracts or reputational impacts on the oil and gas sector. Any such events could result in penalties, exclusion from public tenders, contractual disputes, reputational damage and other adverse consequences for our business.
Consequently, ethics and compliance breaches have been identified as part of our key strategic risks, reinforcing our commitment to a comprehensive Ethics and Compliance Program. This program includes ethics guidelines, risk-based due diligence, continuous monitoring and controls, a whistleblower mechanism, mandatory training programs, and oversight by both management and the board of directors to mitigate compliance-related risks. Despite these efforts, the materialization of such risks, including legal actions against our operations, directors, employees, or business partners, could result in substantial fines, sanctions, reputational damage, and restrictions on obtaining permits, licenses, or government contracts. Compliance failures could also impact our access to new business opportunities and capital markets, leading to operational disruptions, increased costs and adverse financial consequences. Additionally, evolving regulatory frameworks and shifting political dynamics in our operating jurisdictions may heighten legal risks and increase the complexity and cost of ensuring full adherence to anti-corruption and compliance requirements.
We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash.
We expect that a limited number of financial institutions in the countries in which we operate, as well as some institutions located in the United States, will hold all or most of our cash. Depending on our cash balance in any of our
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accounts at any given point in time, our balances may not be covered by government-backed deposit insurance programs in the event of default or failure of any bank with which we maintain a commercial relationship. The occurrence of any default or failure of any of the banks in which we have deposits could have a material adverse effect on our business, financial condition, results of operations and cash flows. For example, with regards to our accounts in the United States, while the U.S. Federal Deposit Insurance Corporation provides deposit insurance of US$250,000 per depositor, per insured bank, the amounts that we have in deposits in U.S. banks far exceed that insurance amount. Therefore, if the U.S. government does not impose measures to protect depositors in the event a bank in which our funds are held fails, we may lose all or a substantial portion of our deposits.
As of December 31, 2025, 96% of our cash and cash equivalents were maintained in banks ranked within investment grade category.
The Colombian government, through the ANH, announced it will not grant any new oil and gas exploration licenses.
The current Colombian government has expressed its intention to limit the future expansion of the oil and gas industry in the country. In line with this policy stance, the ANH has been instructed not to enter into new exploration contracts. Although these measures do not affect existing and already granted exploration or production contracts, it may affect our ability to access new acreage through concessions in Colombia, to the extent such decision is not revoked by this or future administrations.
Restrictions on foreign exchange and transfer of funds abroad in Argentina could adversely affect our liquidity and financial flexibility.
The Argentine government has historically implemented and may continue to impose capital controls and foreign exchange restrictions that limit the ability of companies operating in the country to access the official foreign exchange market for the purchase of foreign currency, transfer of funds abroad, and servicing of foreign currency-denominated obligations. These restrictions have included limitations on dividend payments, repayment of intercompany loans, and access to U.S. dollars for external debt servicing, all of which may create additional financial inefficiencies and increase costs related to the conversion of local currency into U.S. dollars.
Additionally, Argentina has experienced periods of high inflation and significant currency devaluation, leading to the emergence of multiple exchange rates, including parallel and unofficial markets. The disparity between the official and alternative exchange rates could result in financial inefficiencies, increased costs, and potential losses when converting local currency into U.S. dollars. In addition, authorities in Argentina may further tighten or modify existing foreign exchange restrictions, introduce new controls or maintain multiple exchange rate regimes for an extended period of time, which could exacerbate the disparity between the official and alternative exchange rates and further limit our ability to access foreign currency at commercially reasonable terms. Further regulatory changes could increase restrictions on foreign exchange transactions, which may adversely affect our ability to repatriate earnings, finance operations, and meet financial commitments in Argentina.
If capital controls become more restrictive or if access to foreign currency markets is further constrained, our liquidity, financial condition, and overall business operations in Argentina could be materially and adversely impacted.
Risks relating to our common shares
An active, liquid, and orderly trading market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell our common shares.
Our common shares began trading on the New York Stock Exchange (the “NYSE”) on February 7, 2014 and, as a result, have a limited trading history. We cannot predict the extent to which investor interest in our Company will maintain an active trading market on the NYSE or how liquid that market will be in the future. If an active, liquid and orderly market does not develop or is not sustained, you may have difficulty selling our common shares at the time or price you desire.
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The market price of our common shares may be volatile and may be influenced by a variety of factors, some of which are beyond our control, including: (i) our operating and financial performance, reserve estimates and identified drilling locations; (ii) quarterly variations in operating results and key financial indicators; (iii) changes in revenue or earnings estimates or reports by equity research analysts (including changes in analyst coverage); (iv) fluctuations in oil and gas prices and broader volatility in the energy sector and global securities markets; (v) the volume and liquidity of trading in our common shares; (vi) sales of our common shares by us or our shareholders, or the perception that such sales may occur, and future issuances of equity or other securities; (vii) litigation, personnel changes and Company announcements; (viii) changes in our dividend policy; (ix) domestic and international economic, legal and regulatory developments; (x) the release or expiration of transfer restrictions on our outstanding common shares; and (xi) changes in the composition of our shareholder base, including the entry of new shareholders with significant stakes in the Company, which may impact our corporate governance, strategic direction and the trading price of our common shares. In addition, volatility from stock deposit certificates in Argentina (CEDEARs) may arise because price differences may occur between the NYSE and the local market where the CEDEARs are traded.
Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors.
We are committed to return value to our shareholders. From 2018 to 2025, we distributed a total of US$322.9 million to our shareholders, consisting of US$200.1 million through share repurchases and US$122.8 million in cash dividends. However, our availability to continue making distributions to shareholders in the future will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. For example, on October 21, 2025, following the Acquisition in Argentina’s Vaca Muerta Formation, our board approved a revised dividend program totaling approximately US$6 million over the following four quarters (US$1.5 million per quarter; US$0.03 per share), beginning with the third quarter of 2025 results payout and ending with the second quarter of 2026 results payout. Dividends will be suspended commencing with the third quarter of 2026 results to align with increased Vaca Muerta capital expenditures, and will be reassessed once positive free cash flow resumes. Future dividends may be suspended, reduced or discontinued at any time.
Furthermore, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Companies Act, 1981 (as amended) of Bermuda (the “Companies Act”), we may not declare or pay a dividend or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become due; or (ii) that the realizable value of our assets would thereby be less than our liabilities. We are also subject to contractual restrictions under certain of our indebtedness. “Contributed surplus” is defined for purposes of section 54 of the Companies Act to include the proceeds arising from donated shares, credits resulting from the redemption or conversion of shares at less than the amount set up as nominal capital and donations of cash and other assets to the company.
Pursuant to the share purchase agreement entered into by and between GeoPark and Colden by virtue of which Colden acquired approximately 20% of GeoPark’s outstanding common shares (the “SPA”), for so long as Colden owns at least 15% of GeoPark’s outstanding common shares, we may not declare or pay dividends without approval by Colden, or at least one of the directors nominated by Colden. For more details on the SPA, please refer to “Item 4. Information on the Company—B. Business Overview—Recent Developments—Strategic Equity Investment by Grupo Gilinski.”
We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us.
As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenue and cash flow is distributions from our subsidiaries. Thus, our ability to service our debt, finance acquisitions and pay dividends to our stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash distributions to us. Our subsidiaries are and will be separate legal entities, and although they may be wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends, distributions or otherwise. The ability of our
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subsidiaries to distribute cash to us will also be subject to, among other things, restrictions that are contained in our subsidiaries’ financing and joint operations agreements, availability of sufficient funds in such subsidiaries and applicable state laws and regulatory restrictions. Claims of creditors of our subsidiaries generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our ability to grow, pursue business opportunities or make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially limited.
We may not be able to fully control the operations and the assets of our joint operations and we may not be able to make major decisions or take timely actions with respect to our joint operations unless our joint operation partners agree. We may, in the future, enter into joint operations agreements imposing additional restrictions on our ability to pay dividends.
Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline.
We may issue additional common shares or convertible securities in the future, for example, to finance potential acquisitions of assets, which we intend to continue to pursue. Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. This could also impair our ability to raise additional capital through the sale of our equity securities. Under our memorandum of association, we are authorized to issue up to 5,171,949,000 common shares, of which 51,707,198 common shares were outstanding as of December 31, 2025. We cannot predict the size of future issuances of our common shares or the effect, if any, that future sales and issuances of shares would have on the market price of our common shares. For examples of purchase and sales of substantial amounts of our common shares, please refer to “— Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control”.
The adoption and implementation of our shareholder rights plan could lead to, among other adverse effects, dilution of shareholder value and negative market perception. Our shareholder rights plan could also deter acquisitions that may otherwise be beneficial to our shareholders.
On June 3, 2025, our board of directors adopted a limited-duration shareholder rights agreement (commonly referred to as a “Poison Pill” or a “Rights Plan”), further amended on March 5, 2026. For more details on the rights agreement, see “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
The Rights Plan could lead to significant dilution of our outstanding shares in the event of a triggering acquisition. This dilution could negatively impact the value of existing shares and reduce earnings per share for current shareholders.
Any potential acquirer could face substantial dilution as well, which could make it more difficult or costly for them to acquire a controlling interest in us. Further, the existence of the Rights Plan could be perceived by the market or potential investors as a defensive tactic to entrench current management and prevent beneficial acquisitions. This perception could negatively impact the market price of our securities or affect our reputation with investors, potentially resulting in reduced investor interest or a decline in the price of our securities. In addition, the Rights Plan could deter potential acquirers or strategic partners from pursuing acquisition opportunities, joint ventures, or other forms of strategic collaboration. This could limit our ability to engage in transactions that may otherwise be in our best interest or the best interests of our shareholders. The Rights Plan also grants substantial discretion to our board of directors to determine whether to trigger the Rights Plan. While our board of directors is expected to act in our and our shareholders’ best interests, there is a risk that such discretion could be perceived as self-serving, especially if our board of directors blocks a legitimate acquisition offer to protect its own position. This could lead to shareholder dissatisfaction or legal challenges.
As part of the investment in GeoPark by Colden, we have agreed to terminate the Rights Plan on or prior to our 2026 Annual Meeting of Shareholders.
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Provisions of the Notes due 2027 and Notes due 2030 could discourage an acquisition of us by a third party.
Certain provisions of the Notes due 2027 and Notes due 2030 could make it more difficult or more expensive for a third party to acquire us or may even prevent a third party from acquiring us. For example, upon the occurrence of a change of control, holders of the Notes due 2027 and Notes due 2030 will have the right, at their option, to require us to repurchase all of their notes at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts, if any) to the date of purchase. By discouraging an acquisition of us by a third party, these provisions could have the effect of depriving the holders of our common shares of an opportunity to sell their common shares at a premium over prevailing market prices.
Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control.
Certain members of our board of directors and our executive officers held 15.0% of our outstanding common shares as of March 19, 2026, holding the shares either directly or through privately held funds. As a result, these shareholders, if acting together, would be able to influence matters requiring approval by our shareholders, including the election of directors and the approval of amalgamations, mergers, or other extraordinary transactions. They may also have interests that differ from yours and may vote in a way with which you disagree, and which may be adverse to your interests. The concentration of ownership may have the effect of delaying, preventing, or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market price of our common shares. See “Item 7. Major Shareholders and Related Party Transactions—A. Major shareholders” for a more detailed description of our share ownership.
We may also be exposed to aggressive stakebuilding by third parties. The Rights Plan adopted by our board is designed to protect all shareholders in light of unusually rapid stock accumulation by a single investor. Under the plan, the rights become exercisable if any person or group acquires 12% or more of our outstanding common shares (including through derivatives), unless approved by the board (which was the case in connection with the Colden investment in GeoPark as further described below).
For example, in May 2025, Pampa Energy Inc. acquired a 10.17% shareholding in GeoPark, which it later reduced to 4.43% in September 2025. According to disclosures made by Pampa Energy Inc. during its third quarter 2025 earnings call, the company stated that it no longer had any equity exposure to GeoPark. In October 2025, Parex Resources Inc. publicly disclosed that it had acquired an approximately 11.8% shareholding in GeoPark in connection with an unsolicited acquisition proposal that, following an internal review and analysis, our board of directors unanimously determined significantly undervalued GeoPark and therefore rejected. In addition, in February 2026, Parex Resources Inc. announced the nomination of director candidates for election at the Company’s 2026 Annual Meeting of Shareholders.
Similarly, pursuant to the SPA dated as of March 5, 2026, whereby Colden acquired approximately 20% of GeoPark Limited’s outstanding common shares, Colden has certain board nomination and governance rights and imposes certain voting obligations. In particular, Colden has the right to nominate (i) three directors if Colden beneficially owns at least 28% of GeoPark’s outstanding common shares, (ii) two directors if Colden beneficially owns at least 15% but less than 28% of GeoPark’s outstanding common shares, and (iii) one director if Colden beneficially owns at least 7.5% but less than 15% of GeoPark’s outstanding common shares. Colden’s board nomination rights include certain rights with respect to representation on committees of the board (other than the audit committee) and the removal and replacement of Colden’s nominee directors. From the closing of the investment until the earlier of GeoPark’s second annual general meeting thereafter and the date when Colden no longer has the right to nominate any directors, Colden is obligated to vote its shares in accordance with the board’s recommendation with respect to the election or removal of directors. Furthermore, for so long as Colden owns at least 15% of GeoPark’s outstanding common shares, GeoPark may not take certain specified actions without approval by Colden or at least one of the directors nominated by Colden, including (subject to certain exceptions): (i) issuing equity or equity-linked securities in excess of 5% of GeoPark’s fully diluted share capital; (ii) amending GeoPark’s governing documents in a manner adverse to Colden; (iii) entering into, modifying or terminating certain related-party transactions; (iv) changing the board size; (v) declaring or paying dividends; and (vi) repurchasing or otherwise acquiring GeoPark’s outstanding share capital. In order to permit the acquisiton from Colden under the SPA, GeoPark Limited amended the Rights Plan. For more details on the rights agreement, see “Item 4. Information on the
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Company—B. Business Overview—Recent Developments—Strategic Equity Investment by Grupo Gilinski” and “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
These developments illustrate the potential for rapid changes in significant shareholdings, including changes in the composition of our shareholder base, which may lead to increased trading volatility and influence our governance and strategic direction. They may also result in potential misalignment between the interests of significant shareholders and those of our broader shareholder base.
Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price.
Shareholder activism has been increasing generally and in the energy industry specifically. Investors may attempt to effect changes to our business or governance, such as with respect to climate change or otherwise, by means such as shareholder proposals, public campaigns, proxy solicitations or other means. Such actions could adversely impact us by distracting the board and employees from core business operations, increasing advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of the business.
Recent shareholder activism and rapid stakebuilding activities may require us to adopt defensive measures and devote significant management time and resources to evaluating alternatives and responding to such actions, which could increase our costs and affect execution of our strategy. For example, in 2025 we experienced unusually rapid stock accumulation by certain investors and received an unsolicited acquisition proposal, which required additional advisory and other costs and management attention and may have affected trading dynamics and our stock price. See “—Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control” for additional context.
As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it.
As a foreign private issuer, the rules governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although we intend to report quarterly financial results and report certain material events, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly or current reports may contain less information than required under U.S. filings. In addition, we are exempt from the Section 14 proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Our exemption from Section 16 rules regarding sales of common shares by insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. For example, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales of our common shares. The periodic disclosure required of foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Information—H. Documents on display.”
As a foreign private issuer, we are exempt from complying with certain corporate governance requirements of the NYSE applicable to a U.S. issuer, including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve any equity issuance by us which represents 20% or more of our outstanding common shares. As the corporate governance standards applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under U.S. law and the NYSE rules as shareholders of companies that do not have such exemptions.
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There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make.
The permission of the Bermuda Monetary Authority is required, under the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of shares (which includes our common shares) of Bermuda companies to or from a non-resident of Bermuda for exchange control purposes, other than in cases where the Bermuda Monetary Authority has granted a general permission. The Bermuda Monetary Authority, in its notice to the public dated June 1, 2005, has granted a general permission for the issue and subsequent transfer of any securities of a Bermuda company from and/or to a non-resident of Bermuda for exchange control purposes for so long as any “Equity Securities” of the company (which would include our common shares) are listed on an “Appointed Stock Exchange” (which would include the New York Stock Exchange). In granting the general permission the Bermuda Monetary Authority accepts no responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this annual report. Any changes in the permission granted by the Bermuda Monetary Authority and related regulations could result in a delay or denial of any transfer of shares an investor might seek.
We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers.
We are incorporated as an exempted company under the laws of Bermuda and our assets are substantially located in Colombia and Argentina. In addition, several of our directors and executive officers reside outside the United States and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult or impossible to effect service of process within the United States upon us, or to recover against us on judgments of U.S. courts, including judgments predicated upon the civil liability provisions of the U.S. federal securities laws. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violation of U.S. federal securities laws because these laws have no extraterritorial application under Bermuda law and do not have force of law in Bermuda. However, a Bermuda court may impose civil liability, including the possibility of monetary damages, on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law.
There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. However, the courts of Bermuda would recognize any final and conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct procedures under the laws of Bermuda.
In addition, and irrespective of jurisdictional issues, the Bermuda courts will not enforce a U.S. federal securities law that is either penal or contrary to Bermuda public policy. An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, will not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, would not be available under Bermuda law or enforceable in a Bermuda court, as they would be contrary to Bermuda public policy.
The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia.
In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax established in article 90-3 of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad are taxed in Colombia when such transaction represents a transfer of assets located in Colombia (“Colombian Assets”). Although certain conditions and exemptions apply, corporate reorganizations shall monitor this new regulation. As we indirectly own Colombian Assets, the indirect transfer rules would apply to transfers of our common shares provided
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certain conditions outside of our control are met. If such conditions were present and as a result the indirect transfer rules were to apply to sales of our common shares, such sales would be subject to indirect transfer tax on the capital gain realized in connection with such sales. For a description of the indirect transfer rules and the conditions of their application see “Item 10. Additional Information—E. Taxation—Colombian tax on transfers of shares.”
Legislation enacted in Bermuda as to Economic Substance may affect our operations.
Pursuant to the Economic Substance Act 2018 (as amended) of Bermuda (the “ES Act”) that came into force on January 1, 2019, a registered entity other than an entity which is resident for tax purposes in certain jurisdictions outside Bermuda (“non-resident entity”) that carries on as a business any one or more of the “relevant activities” referred to in the ES Act must comply with economic substance requirements. The ES Act may require in-scope Bermuda entities which are engaged in such “relevant activities” to be directed and managed in Bermuda, have an adequate of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing, leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities.
The ES Act could affect how we operate our business, which could adversely affect our business, financial condition and results of operations. Although it is presently anticipated that the ES Act will have little material impact on us or our operations, as the legislation is new and remains subject to further clarification and interpretation, it is not currently possible to ascertain the precise impact of the ES Act on us.
A. History and development of the company
General
We were incorporated as an exempted company pursuant to the laws of Bermuda in February 2006. We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our principal executive office is located at Street 94 N° 11-30, 8th floor, Bogotá, Colombia, telephone number +57 601 743 2337.
The U.S. Securities and Exchange Commission (“SEC”) maintains an internet website that contains reports, proxy, information statements and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. Our website address is www.geo-park.com. The information contained on, or that can be accessed through, our website is not part of, and is not incorporated into, this annual report.
Our Company
We are a leading independent energy company with over 20 years of successful operations across Latin America and a long-term strategy that seeks to maintain a risk-balanced portfolio across the region’s main basins. We currently manage a portfolio of assets in Colombia and Argentina, combining low-cost, high-margin conventional production in Colombia, with an unconventional development platform in the Vaca Muerta formation in Argentina. This portfolio supports a business model focused on capital discipline, operational efficiency and long-term cash flow generation.
We are focused on growth through significant assets, basins, and plays, including our portfolio in Colombia and our recently acquired assets in the Vaca Muerta shale formation in Argentina. Our operations span both conventional and unconventional resources across a diversified regional footprint.
Colombia, our core producing base, provides cash flow supported by operational efficiencies and ongoing development opportunities. Production is primarily concentrated in the Llanos Basin, where we operate the Llanos 34 Block and participate in additional operated and non-operated assets, such as CPO-5.
Our unconventional development position in Vaca Muerta, Argentina is expected to contribute to scale and portfolio diversification over time, subject to market conditions and operational execution. Following the closing of the Acquisition in Argentina’s Vaca Muerta Formation in October 2025, we established a new unconventional operating platform in the Neuquén Basin.
During the year ended December 31, 2025, we produced a net average of 28,322 mboepd, of which 93.2%, 1.1%, 1.8% and 3.8% were, respectively, in Colombia, Argentina, Brazil and Ecuador, and of which 98.0% was oil.
Our performance targets focus on achieving sustainable growth by mid-term (2028) and long-term (2030). We seek to leverage a robust organic footprint complemented by strategic inorganic opportunities. Our financial strategy emphasizes maintaining reasonable debt levels with appropriate maturity profiles, supported by diversified financing sources and a proactive hedging strategy aligned with our cash flow needs.
We seek to deliver competitive shareholder returns while pursuing sustainable growth. Since 2018, we have returned around US$322.9 million to shareholders through buybacks and dividends. Dividend distributions are subject to board approval, in its sole discretion, and depend on a variety of factors, including but not limited to business performance, financial condition, growth plans and other considerations.
A clear set of priorities and key values have driven us through a two-decade track record of growth, sustainability performance and value delivery. Furthermore, our internal value system SPEED, which has been part of the Group’s culture since its inception, differentiates us from our peers, guides our decision-making process and is the basis for our value-generation approach to all our stakeholders.
Meeting the energy needs of a growing population while contributing to the energy transition requires us to conduct best-in-class oil and gas exploration and operation, to manage our assets in the most ethical and sustainable way, and to continue creating long-term value for our shareholders and all our stakeholders.
Our culture
Our culture is our binding force, which we protect and nurture to excel in delivering our business model.
Our culture was forged in the field when a small team began operating in remote blocks in southern Argentina and Chile, in demanding conditions that required resilience, collaboration and a strong sense of commitment. Since then, our people have been guided by a clear and enduring purpose – Creating Value and Giving Back – which shapes how we define success and how we make decisions. For GeoPark, results are measured not only in production, reserves and cash flow, but also in the health and safety of our people and the value we create for shareholders and the communities where we operate.
Our culture underpins our ability to execute our strategy, manage risk and adapt to changing operating and market conditions, and is articulated through a set of principles that guide everyday decisions and behavior across the Company:
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We view culture as a shared asset that must be understood, practiced and protected, particularly in times of uncertainty or pressure. It plays a central role in how we design and execute our strategy, how we attract and develop talent, how we build long-term relationships with stakeholders and how we seek to create value for all those connected to GeoPark.
Our business strategy
To protect the value of our core platform and position the company for renewed growth, we developed our long-term strategic plan. Such plan outlines a disciplined roadmap for potential value creation, grounded in a two-fold approach that is designed to strengthen and seek to maximize the value of our core platform in Colombia while seeking to develop a new long-term growth engine in Argentina.
Colombia remains our operational and financial backbone, providing cash generation, predictable performance, and a resilient base supported by disciplined capital allocation, enhanced recovery initiatives and sustained operational excellence.
At the same time, we are advancing the accelerated development of our unconventional position in Vaca Muerta, a strategic platform that is expected to expand and diversify our future production and cash flow profile, subject to market conditions and operational execution. Together, these two pillars form a balanced, returns-focused strategy that is designed to protect near-term value while supporting the upfront investments required to potentially transform the scale of the business, enhance long-term cash flow resilience, and deliver enduring, disciplined growth.
Our capital allocation framework is designed to balance disciplined growth, financial strength and shareholder returns, while maintaining flexibility to adapt to changing market conditions. We prioritize the allocation of capital to high-return organic investment opportunities, particularly in our core assets in Colombia and the development of our unconventional platform in Argentina. In parallel, we selectively evaluate inorganic opportunities that may enhance our portfolio, subject to strict financial and strategic criteria. We also maintain a focus on preserving a strong balance sheet, including through active liability management and deleveraging initiatives when appropriate. In addition, over time we seek to return capital to shareholders through a combination of share appreciation, dividends and occassional share repurchase programs, taking into account our financial position, market conditions and investment opportunities. This balanced approach is intended to support sustainable long-term value creation, while preserving capital discipline and financial flexibility across commodity price cycles.
Within this framework, we remain focused on consolidating and growing our core positions in Colombia and Argentina, while we continue to monitor opportunities across Latin America that are aligned with our operational capabilities and regional expertise. In this context, we are selectively monitoring developments in Venezuela. Recent regulatory actions, including the January 29, 2026 reform of the Hydrocarbons Law, together with evolving U.S. sanctions policy and the issuance of general and specific licenses by the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC), have introduced defined pathways for potential participation, enabling engagement in the oil and gas sector. Given Venezuela’s material hydrocarbon resource base distributed across its principal producing basins (including Maracaibo, Barinas-Apure, Orinoco and Eastern basins), the country may present potential long-term opportunities.
Any potential participation would be subject to strict compliance with applicable sanctions, export controls and regulatory requirements, and would depend on the availability and continued validity of relevant authorizations, including OFAC licenses. Such participation would also be contingent on the availability of appropriate legal and contractual protections and the enforceability of the applicable regulatory framework. While we are not currently conducting operations in Venezuela, any future involvement would depend on favourable geopolitical and regulatory conditions.
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2026 work plan and outlook
As part of our work program for 2026 (the “2026 Work Program”), we intend to optimize our portfolio by focusing on maximizing value and leveraging our differentiated asset base to support sustainable long-term growth. For further information on our capital allocation methodology, please see “—Our strengths— Capital allocation methodology.”
The 2026 Work Program is designed to protect near-term cash generation, accelerate the growth of GeoPark’s unconventional assets, and position us to scale production and value through 2028.
In 2026, we estimate capital expenditures ranging from US$190.0 million to US$220.0 million to support a production target of 27,000-30,000 boepd across Colombia (24,500-26,000 boepd), and Vaca Muerta (2,500-4,000 boepd), subject to market conditions and operational execution. Our production mix is anticipated to be approximately 97% oil and 3% natural gas, with 12% unconventional and 88% conventional. We plan to drill between 27 to 36 gross wells (including 6 to 8 gross exploration wells), with approximately 86% allocated to development activities and 14% to exploration and appraisal activities.
Medium-term (2026 – 2028) guidelines
In December 2025, we introduced updated medium-term guidelines for 2026–2028, intended to provide an operational and financial outlook aligned with our disciplined growth strategy. This execution roadmap through 2028 is anchored in a two-fold strategy that combines the protection and maximization of our core production and cash generation in Colombia with a renewed growth trajectory driven by our expanding position in Vaca Muerta, Argentina.
In Colombia, we are focused on sustaining and improving the performance of our flagship Llanos 34 Block and other key operated and non-operated assets. Production reached a positive inflection point in the fourth quarter of 2025 (earlier than the previously projected 2026), and volumes are anticipated to increase in 2026, supported by effective base optimization, enhanced recovery initiatives, and strong well performance. These efforts are further underpinned by the certified 22% increase in 2P Original Oil in Place (OOIP) in the Llanos 34 Block, which we believe supports a larger resource base and may strengthen the long-term production and economic outlook of the asset. Colombia is expected to remain a key foundation for generating sustainable free cash flow, balance sheet strength, and shareholder returns.
In Vaca Muerta, Argentina, with the successful integration of the Loma Jarillosa Este and Puesto Silva Oeste Blocks, we are confident that we can unlock significant long-term growth from our position in unconventional resources in the Neuquén Basin. Our team is focusing on accelerating drilling activity to deliver a step-change in production and cash flow.
The plan anticipates a steady increase in production from approximately 27,000–30,000 boepd in 2026 to 44,000–46,000 boepd by 2028, supported by a balanced capital program of US$190–220 million in 2026, scaling to US$350–380 million in 2028. This medium-term guidance underscores our commitment to delivering sustainable growth, enhancing cash flow generation, and maintaining financial resilience while advancing development across operated and non-operated assets.
These guidelines are reviewed periodically to reflect evolving business dynamics, new developments, and changes in market, regulatory, and operational conditions. As a result, actual outcomes may differ from current expectations, and alternative scenarios may be considered as circumstances evolve.
History
We were founded in 2002. We are a leading independent energy company with operations in Latin America. During 2025, we had operations or held working interests in Colombia, Argentina, Brazil, and Ecuador.
Our history can be summarized by our growth in each country and our performance in the capital markets:
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Colombia
We entered the Colombian market in 2012 through an acquisition that provided an attractive platform of reserves and resources, including a 45% operated working interest in the Llanos 34 Block. At the time of acquisition, the Llanos 34 Block had no production or reserves. Through our disciplined operational execution and exploration expertise, we transformed the Llanos 34 Block into one of the most prolific oil blocks in Colombia, discovering 13 oil fields and drilling over 245 wells. As of December 31, 2025, the block has produced more than 198 million barrels of oil, with a gross daily production of over 38,000 bopd, and the block’s Jacana and Tigana fields ranking among Colombia’s top 12 producing oil fields.
During 2019, jointly with Hocol, an affiliate of Ecopetrol, we acquired five low-cost, low-risk and high-potential exploration blocks in the Llanos Basin, surrounding the Llanos 34 Block. Since 2023, we have drilled and brought into production oil exploration wells in the Llanos 87 and Llanos 123 Blocks, transitioning them from exploratory blocks to production, contributing 2,243 boepd to our net average production for the year ended December 31, 2025 (4,486 boepd gross). Additionally, in the Llanos 86 and Llanos 104 Blocks, the completion of 3D seismic acquisition and processing, along with the approval of environmental licenses, enabled the identification of new drilling opportunities.
In January 2020, we acquired a group of companies which owned thirteen production, development, and exploration blocks in Colombia, distributed as follows: twelve operated blocks in the Putumayo basin (including the producing Platanillo Block) and one non-operated block in the Llanos basin (the producing CPO-5 Block), a cross-border oil pipeline from Colombia to Ecuador and transportation rights through the Ecuadorian pipelines to the port of Esmeraldas. Through targeted investments and optimized field operations, the CPO-5 Block has grown from a gross production level of approximately 8,120 bopd in December 2019 to an average gross production of 21,615 bopd during the year ended December 31, 2025 (net production of 6,484 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 8 producing oil fields.
During the year ended December 31, 2025, based on statistics published by the ANH, we were among the three largest private oil operators in Colombia.
Argentina
In October 2025, we entered the Vaca Muerta shale formation in Argentina with operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta and has produced 1,234 boepd during the fourth quarter of 2025.
Brazil
Since 2013, we have participated in several Bid Rounds promoted by the Brazilian ANP. In 2014, we acquired a 10% non-operated working interest in the BCAM-40 Concession, which included an interest in the Manati gas field operated by Petrobras. Although we continue to hold certain exploratory blocks in Brazil, in March 2025 we entered into an agreement to divest our interest in the BCAM-40 Concession, with the transfer of the working interest in December 2025.
Ecuador
In May 2019, we signed participation contracts for a 50% operated working interest in the Espejo Block and a 50% non-operated working interest in the Perico Block in Ecuador. Since then, we have advanced exploration and development activities, transitioning these assets from exploration to production in 2022, when we recorded our first oil sales following the successful exploration campaign in the Perico Block. In July 2025, we entered into an agreement to divest our interests in both blocks, and the transaction closed in December 2025.
Other Latin American countries
During our history as operators, we have also had operations in Chile and Peru, and we have participated in bid rounds in Mexico. As of the date of this annual report, we do not have operations in these countries.
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Funding
In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares.
Between 2005 and 2025, we raised approximately US$200 million in equity offerings at the holding company level and over US$2.2 billion through debt arrangements with multilateral agencies such as the IFC, prepayment facilities, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.
In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The Notes due 2027 are fully and unconditionally guaranteed by GeoPark Colombia, S.L.U. The Notes due 2027, which were partially repurchased for a nominal amount of US$405.3 million in January 2025, mature on January 17, 2027.
In May 2024, we executed an offtake and prepayment agreement with Vitol C.I. Colombia S.A.S. (“Vitol”), one of the world’s leading energy and commodity companies. The offtake agreement provides for GeoPark to sell and deliver production from the Llanos 34 Block in Colombia to Vitol. As part of this transaction, we obtained access to committed funding from Vitol. Amounts drawn under this prepayment facility can be repaid through future oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.75% per annum. In November 2024, we drew US$152.0 million under this prepayment agreement. During 2025, we repaid US$142.2 million in cash and US$7.6 million in kind from that amount and, as of December 31, 2025, US$2.2 million remained outstanding. In January 2026, we renewed this offtake and prepayment agreement, extending its term through December 31, 2028 and expanding deliveries to include Llanos 34 (beginning January 2026) and CPO-5 and Llanos 123 (beginning May 2026). The renewed facility provides committed funding with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million), available to be drawn until June 30, 2027 (subject to certain conditions), at a SOFR risk-free rate plus a margin of 3.50% per annum. Amounts drawn may be repaid through future oil deliveries or prepaid at any time without penalty.
During the third quarter of 2024, our wholly owned subsidiary GeoPark Argentina S.A., obtained an “AA+(arg)” credit rating from Fitch Ratings’ local Argentine affiliate, FIX, and received approval from the Argentine securities regulator (Comisión Nacional de Valores, or “CNV” by its Spanish acronym) for the creation of a program to issue up to US$500.0 million in debt securities over the next five years, providing strategic financial flexibility to support the future development of the Argentine assets in the Vaca Muerta shale formation.
On November 29, 2024, GeoPark Colombia S.A.S., as borrower, and GeoPark Limited, as guarantor, signed a senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. as mandated lead arrangers and bookrunners, which provides us with access to up to US$100.0 million, with an availability period until May 2026 and with a final maturity in September 2026. As of the date of this annual report, we have not drawn any amount under this credit facility.
On December 3, 2024, GeoPark Argentina S.A., executed a promissory note with AdCap Securities Argentina S.A. for an amount in local currency equivalent to US$10.0 million, minus interests and other issuance costs, which were deducted at the execution date. The interest rate was 3% per annum and final maturity was July 3, 2025.
On January 31, 2025, we issued US$550.0 million aggregate principal amount of 8.75% senior notes due 2030 (the “Notes due 2030”). The net proceeds from the Notes due 2030 were used to repurchase a portion of our Notes due 2027 for a nominal amount of US$405.3 million, to repay part of the abovementioned prepayment drawn from Vitol and, the remainder was used for general corporate purposes, including capital expenditures. From June to October 2025, we executed a deleveraging process by repurchasing through open market transactions and cancelling with the trustee a nominal amount of US$108.3 million of our Notes due 2030.
In August 2025, we executed an offtake and prepayment agreement with BP Products North America Inc. (“BP”). Under this arrangement, GeoPark agreed to sell and deliver, on an FOB Coveñas basis, crude oil production from the CPO-
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5, Llanos 87 and Llanos 123 blocks for a 12-month term starting on August 1, 2025 with the option for unilateral early termination after nine months. As part of this transaction, BP made available a committed prepayment facility of up to US$50.0 million, which decreases over the life of the agreement through monthly step-downs until April 2026. Amounts drawn under the prepayment facility may be amortized through future crude oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.50% per annum. In January 2026, we drew US$15.0 million from the prepayment facility.
On December 24, 2025, we executed a loan agreement with Bancolombia Panamá, S.A. for US$3.0 million to finance sustainable capital requirements associated to the Orinoquia Regenera project in Colombia. The loan carries a variable interest rate of SOFR risk-free rate plus a margin of 1.8% per annum and matures on December 20, 2029. Principal is repayable semi-annually in equal installments following a grace period of two years, and interest is payable semi-annually on the outstanding balance.
In addition, after the balance sheet date, we entered into additional short-term bank financings. For further information please see “Item 4. Information on the Company—B. Business Overview— Recent Developments— Funding.”
B. Business Overview
We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. We continually evaluate the potential acquisition of strategic assets that will allow us to continue growing our business in line with our recent operating and financial successes. Since our inception, we have supported our growth through our prospect development efforts, drilling program, long-term strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and engineers, including professionals with specialized expertise in the geology of Colombia, Argentina and Brazil.
Our assets
We have a portfolio of assets that includes working and/or economic interests in 24 onshore hydrocarbon blocks, including 6 in production as of December 31, 2025, and provides the ability to quickly optimize capital allocation as market conditions change. Our assets give us access to over three million gross exploratory and productive acres.
According to the D&M Reserves Report, as of December 31, 2025, the blocks in Colombia and Argentina, in which we have working interests had 58.6 mmboe of net proved reserves, with 81.0%, 19.0% of such net proved reserves located in Colombia and Argentina, respectively. For further information about the reserves certification process, please see “—Oil and natural gas reserves and production.”
The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2025.
For the year ended December 31, 2025
Oil
Revenues
Gas
equivalent
(in thousands
% of total
Country
(mmbbl)
(bcf)
(mmboe)
% Oil
of US$)
revenues
47.5
—
100.0
%
461,418
93.7
10.7
2.5
11.1
96.2
5,783
1.2
6,435
1.3
18,463
3.7
Other
419
0.1
Total
58.2
58.6
99.3
492,518
We produced a net average of 28.2 mboepd during the year ended December 31, 2025, of which 93.2%, 1.1%, 1.8% and 3.8%, were in Colombia, Argentina, Brazil and Ecuador, respectively, and of which 98.0% was oil.
The following table sets forth our average net production during the last five years, as measured by boepd.
For the year ended December 31,
2025
2024
2023
2022
2021
Average net production (mboepd)
28.2
33.9
36.6
38.6
37.6
% oil
98%
99%
93%
91%
86%
The following table sets forth our production of oil and natural gas in the blocks in which we had a working and/or economic interest during the year ended December 31, 2025.
Average daily production
Argentina (1)
Oil production
Total crude oil production (bopd)
26,297
287
1,078
27,670
Natural gas production
Total natural gas production (mcf/day)
154
146
3,080
3,380
Oil and natural gas production
Total oil and natural gas production (mboepd)
26,323
311
521
28,233
Acquisition in Argentina’s Vaca Muerta Formation
On September 25, 2025, we entered into an agreement to acquire a 100% operated working interest in the Loma Jarillosa Este and Puesto Silva Oeste Blocks located in the Neuquen Province, Argentina, targeting black oil in the Vaca Muerta formation. The transaction is consistent with our strategic intent to establish a position in Vaca Muerta, one of the world’s most prolific unconventional oil and gas plays.
Additionally, a new unconventional exploitation concession for the Puesto Silva Oeste Block was issued for a 35-year term, requiring us to transfer a 5% economic interest to the provincial state-owned company, GyP, resulting in a 95% economic interest in the Puesto Silva Oeste Block. GeoPark will carry GyP’s portion of the capital expenditures in the Puesto Silva Oeste Block on a fully recoverable basis from up to 100% of GyP’s share of production.
The agreement established a cash consideration of US$115.0 million, subject to an interim period adjustment related to the net cash flows from operations since January 1, 2025 (the effective date of the acquisition). On September 25, 2025, we granted a security deposit of US$22.7 million. Subsequently, the transaction closed on October 16, 2025, upon which we acquired control of the assets and paid the remaining US$92.3 million of consideration, plus the interim period adjustment of US$0.5 million.
The Loma Jarillosa Este concession covers 6,054 acres and expires in 2057, while the Puesto Silva Oeste concession covers 6,301 acres and expires in 2060. Production from these blocks was approximately 1,494 boepd between October 16, 2025 and December 31, 2025, composed of 92% oil and 8% gas. According to the D&M Reserves Report, as of December 31, 2025, the acquired assets contained estimated proved reserves of 11.1 mmboe.
This transaction marks our entry as operator in the Vaca Muerta formation, expanding our presence in Argentina and strengthening our position in one of Latin America’s most prolific hydrocarbon basins.
Portfolio Optimization
We review our asset portfolio on a regular basis to ensure alignment with our strategic objectives. Through this continuous assessment, certain assets may be identified as non-core due to their performance, strategic relevance, or prevailing market conditions. As a result of these evaluations, during 2025, we divested non-core assets in Colombia (the
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Llanos 32 Block), Ecuador (the Perico and Espejo Blocks) and Brazil (the Manati gas field). These divestments allow us to concentrate our resources on our core assets, enhancing our operational focus and efficiency. These initiatives further strengthen our balance sheet, simplify our cost structure, and are fully aligned with our long-term plan to build a highly profitable, dependable, and sustainable oil and gas portfolio in Latin America.
Our strengths
We believe that we benefit from the following competitive strengths:
High quality and diversified asset base built through a successful track record of organic growth and acquisitions
Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys in Latin America. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited assets and turn them into valuable, productive assets, and to allocate resources effectively based on prevailing conditions. Furthermore, our recent Acquisition in Argentina’s Vaca Muerta Formation gives us access to one of the world’s most promising unconventional plays, amplifying our diversified portfolio. For further information on our organic growth and acquisitions in each country, see “—A. History and Development of the Company—History” and “—Our operations.”
Significant drilling inventory and resource potential from existing asset base
Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological formations, which provide several attractive opportunities with varying levels of risk. Our drilling inventory and our development plans target locations that provide attractive economics and support a predictable production profile, as demonstrated by our expansions in Colombia. Our geoscience team continues to identify new potential accumulations and expand our inventory of prospects and drilling opportunities.
Risk-balanced asset portfolio
We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In general, when we acquire assets we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term possibility of production, to generate cash flows; (ii) an inventory of adjacent low-risk prospects that can offer medium-term upside for steady growth; and (iii) a periphery of higher-risk projects which have a potential to generate significant upside in the long run.
For example, our recent Acquisition in Argentina’s Vaca Muerta Formation includes proven production and reserves to provide us with a cash flow base and significant development upside. We believe that this acquisition firmly fits within our growth strategy by securing value accretive access to competitively advantaged assets, in big plays, and big proven basins to build and deliver a highly profitable, dependable, and sustainable oil and gas portfolio across Latin America.
We believe this approach will allow us to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside potential. See “—Our operations.”
Capital allocation methodology
Our multi-country platform and asset portfolio is managed through our capital allocation methodology, which also allows us to quickly adapt and grow. We prioritize capital expenditures in core assets and high-return projects that have the greatest impact on production, reserves growth, and cash flow generation, carefully considering their break-even price to remain resilient in the event of an oil price drop. All projects undergo a rigorous evaluation process based on expected returns, payback periods, and alignment with current market conditions. Under this methodology, we rank all of the projects based on economic, technical, environmental, social and corporate governance and strategic criteria, for the purpose of comparing projects. This also creates opportunities for improvements in projects that can, in turn, improve their
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ranking. We then select projects that meet the highest technical and economic standards, aligning with our strategy and prevailing market dynamics.
Also, our capital allocation process leverages multiple pricing scenarios, which are deliberately set below market expectations to stress-test the resilience of our projects. This approach ensures that the projects included in our business plan can be resilient if price declines or scenarios where performance falls short of expectations. By proactively preparing for adverse conditions, we enhance the robustness of our capital plan and the sustainability of our investments. Finally, once the production and reserve growth targets are defined, we agree on the amount of capital to be invested and allocate that capital to the highest value-adding projects. Additionally, given the inherent oil price volatility, we design our work programs to be flexible, which means that they can be increased or decreased depending on the oil price scenario.
Strong cash flow generation and funding
We benefit from a strong cash flow from operating activities. For the year ended December 31, 2025, cash flows from operating activities, excluding income tax payments of US$96.9 million and repayment of an advance payment drawn from Vitol of US$149.8 million, were US$261.4 million. Our cash flows from operating activities plays a significant role in funding our capital expenditures, inorganic acquisition, deleveraging process and shareholders return.
We also have historically benefited from access to debt and equity capital markets, as well as other funding sources, which have provided us with funds to finance our organic growth and the pursuit of potential new opportunities. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.”
Maintain financial strength
We seek to maintain a prudent and sustainable capital structure and a strong financial position to allow us to maximize the development of our assets and capitalize on business opportunities as they arise. We intend to remain financially disciplined by limiting substantially all our debt incurrence to identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition to the international capital markets.
We believe that maintaining a disciplined capital structure and a conservative financial philosophy, including limiting debt incurrence to specified projects with defined repayment sources and using financial hedges, positions us to preserve liquidity and remain flexible in volatile commodity price environments. In 2025, we also implemented cost-efficiency initiatives, including workforce and structural cost reductions, further simplifying our cost base in line with our long-term plan. This financial flexibility enabled us to pursue new opportunities, including our transformative acquisition in the Vaca Muerta formation in Argentina. As of December 31, 2025, we had US$553.5 million of total outstanding financial indebtedness, 82% of which was scheduled to mature in January 2030, and maintained a net debt to Adjusted EBITDA ratio below 2x.
Pursue strategic acquisitions in Latin America
We have historically benefited from, and intend to continue to grow through, strategic acquisitions in Latin America. These acquisitions have provided us with additional attractive platforms in the region. Our expanded operating footprint in Colombia and Argentina, together with our strong partnerships and proven execution capabilities, positions us as a regional consolidator. We intend to continue to grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix of oil and gas-producing assets (though we expect to remain weighted towards oil) and focusing on both assets and corporate targets.
Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become one of the three largest private oil operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30.0 million and have achieved 1P reserve PV-10 of US$428.8 million as of December 31, 2025.
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In January 2020, we acquired a group of companies which owned thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and the non-operated CPO-5 Block in the Llanos Basin) and a cross-border oil pipeline from Colombia to Ecuador named OBA. Through targeted investments and optimized field operations, the CPO-5 Block has grown from a gross production level of approximately 8,120 bopd in December 2019, to an average gross production of 21,615 bopd during the year ended December 31, 2025 (net production of 6,484 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 8 producing oil fields.
In October 2025, we entered the Vaca Muerta shale formation in Argentina with operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta, with estimated recoverable resources of more than 60 million gross barrels of oil, and produced 1,584 boepd in December 2025. This acquisition provides immediate production, reserves, and long-term growth opportunities.
Maintain a high degree of operatorship to control production costs
As of the date of this annual report, we are and intend to continue to be the operator of a majority of the blocks and concessions in which we have working interests, including our world-class Llanos 34 Block, which was acquired in 2012 with no reserves or production and currently includes two of Colombia’s top 12 producing oil fields, Jacana and Tigana. Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically and efficiently within a diversified asset portfolio. We believe that this strategy has allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and our talented technical, operating and management teams.
Long-term strategic partnerships and strong strategic relationships provide us with additional funding flexibility to pursue further acquisitions
We benefit from a number of strong partnerships and relationships. In Colombia, we maintain long-standing partnerships with Ecopetrol, the Colombian state-owned oil and gas company, including through its subsidiary Hocol, which is our partner in several blocks in the Llanos Basin. In Argentina, we operate in partnership with GyP, the provincial energy company of Neuquén, reinforcing our institutional relationship with the province in which our Vaca Muerta assets are located. In addition, our long-standing partnership with Parex Resources in the Llanos 34 Block has been instrumental in the development and growth of this flagship asset. Our commercial relationships with customers have also enabled us to enter into offtake and prepayment agreements with Vitol, Trafigura and BP in recent years, which have served as important sources of financing.
Maintain our commitment to environmental, safety, human rights and social responsibility
An important component of our business strategy is our corporate approach and commitment to our safety, environmental and social responsibilities, which is embodied in decisions that are guided by our Sustainability Framework and internal safety, environmental and social responsibility policies. We see this as a fundamental element in securing business initiatives for long-term growth. Our commitment to sustainable development has allowed us to generate positive impacts in the territories in which we operate, with important contributions to the protection of biodiversity and the environment, as well as to the wellbeing and reduction of multidimensional poverty in neighboring communities. We maintain a social license to operate, based on the construction and maintenance of mutually beneficial relationships with local communities, the return of value as allies for their social and economic development, the respect for their human rights and the care and preservation of the environment.
Our internal values program, SPEED, was developed in accordance with several international quality standards, including ISO 14001 (for environmental management issues), ISO 45001 (for occupational health and safety management issues), ISO 26000 (for social responsibility and workers’ rights issues), IFC guidelines for social and environmental performance, and guidelines from associations including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.”
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In 2025 we updated our sustainability framework, which articulates the following three key drivers into our operations and decision-making processes, ensuring long-term viability of the business and a shared positive impact:
1. Operational efficiency and decarbonization: our focus is on creating greater efficiencies in water, energy and waste management as well as reducing the carbon footprint of our operations.
2. Risk and opportunities management : we prioritize de adequate management of social, climate and nature related risks and we capture opportunities that generate value and make us more resilient in the long term.
3. Impact multiplier along the value chain: our sustainability initiatives go beyond our operations, engaging with our neighbors, supply chain and partners, to push forward energy transition and nature solutions.
Our Environmental Management System (“EMS”) has been certified under the ISO 14001:2015 standard since 2017. In 2023, the company successfully renewed this certification, which remains valid until August 2026. Covering the exploration and production activities in Colombia.
Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-1 standard of the Colombian Institute of Technical Standards and Certification (“ICONTEC”). GeoPark was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions of greenhouse gases and help the countries where we operate meet their commitments under the Paris Agreement. During 2025, we continued to incorporate clean energy sources in our operations, and implemented energy efficiency measures, while also managing our methane emissions in accordance with our decarbonization targets.
In 2024, a corporate water footprint assessment was carried out in accordance with ISO 14046:2015 for the first time. The footprint was verified by ICONTEC. GeoPark is the first oil and gas company in Colombia in implementing and obtaining an external verification of the water footprint assessment, which provides a comprehensive view of the quantity and quality of water used directly and indirectly in our operations.
In 2024, GeoPark received multiple national recognitions for its leadership in environmental sustainability. The company won first place from the Colombian Oil and Gas Association (“ACP”) in the Climate Change and Decarbonization Management and Circularity Models Implementation categories and was a finalist in Partnerships for Sustainable Development. Additionally, GeoPark earned two awards for ranking among the top 10 contributors to Colombia’s biodiversity information system, recognizing its impact on biodiversity data use and its efforts to strengthen open data reporting capacities.
In 2025, GeoPark received Ecuador’s Green Initiative award from the Ministry of Environment and Energy for its Reforestation of native species in Llano Grande and Laguna Seca project, which restored ecosystems affected by forest fires in 2024 and strengthened local biodiversity and ecological resilience.
Our Sustainable Housing program has been recognized among the most important public, private, and international cooperation initiatives contributing to poverty reduction in Colombia. More than 2,000 families living near our areas of operation have benefited from this program, which we have implemented in partnership with the Minuto de Dios Corporation. We continue strengthening this initiative to expand its positive impact and promote sustainable community development
GeoPark was named as one of the top benchmark Companies in the 2025 Impact Business Leadership special report published by EAFIT University as part of the institution’s 65th anniversary. GeoPark placed sixth in the general ranking and tenth in economic value and corporate governance, consolidating its position among the leading companies in sustainability and responsible leadership in Colombia.
Additionally, in 2025, MSCI Ratings Assessment recognized us as an ESG ‘leader’ by upgrading our rating to “AA”. In 2025 we participated for the fourth time in the Dow Jones Sustainability Index (DJSI), and in the S&P Global Corporate
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Sustainability Assessment (CSA) which led to S&P including GeoPark in its 2025 Sustainability yearbook and recognizing us as the “Industry Mover” for the Oil & Gas Upstream & Integrated sector.
Our approach on human rights seeks to conduct business in a way that is consistent with the UN Guiding Principles, the ten UN Global Compact Principles and the Voluntary Principles on Security and Human Rights. Our commitment to these standards is reflected in our SPEED program, as well as in all our policies and procedures. Human rights aspects are integrated into internal management processes, tools, communications, contracts, and trainings.
During 2024, we consolidated our human rights system, which is based on the following pillars: i) human rights policy, ii) human rights due diligence process, iii) grievance mechanisms, iv) human rights governance, v) communication and reporting, and vi) training and capacity building.
The highlights of this consolidation process were:
Furthermore, in 2024, we focused on working with actors in our value chain in human rights capacity building and training.
As part of our commitment to sustainable development and the sustainability development goals, we joined the United Nations Global Compact in 2023.
To be even closer to our neighbors in Colombia, we opened a “Cuentame” office in Puerto Asis (Putumayo) in 2021, one in Tauramena (Casanare) in 2023, and one in Villanueva (Casanare) in 2024. The offices are open to the community, and through them GeoPark seeks to continue strengthening dialogue with all its stakeholders and encourage active community participation so that all neighbors can share proposals and ideas to promote harmonious coexistence and good neighborliness.
For further information related to health, safety and environmental matters, please see “—Health, safety and environmental matters.”
Transparency, ethics and anti-corruption
Transparency is a cornerstone of good governance and it is embodied in our corporate values. Transparency allows business to prosper in a predictable and competitive environment. We believe that doing business in an ethical and transparent manner is a prerequisite for sustainable business. We have zero-tolerance policy towards all forms of corruption. This policy is embedded across our Company through our corporate values, our Code of Ethics (Our Code), and our Ethics and Compliance Program. They prohibit all forms of corruption and bribery and reflect our values and our commitment to high ethical standards in business activities; they apply to all our employees, board members and third parties that act on behalf of the Group.
Our Ethics and Compliance Program is a structured system of policies, procedures, and controls designed to promote ethical behavior, transparency, and compliance across the organization. It seeks to prevent, detect, and address any action that could contravene laws, internal regulations, or ethical principles, while strengthening the Group’s integrity culture and protecting its reputation. The program includes periodic risk assessments, policy development, employee training, third-party due diligence, and communication initiatives that reinforce ethical awareness and responsible business conduct throughout all jurisdictions where GeoPark operates. It also includes an independently operated Ethics Line, a secure and
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confidential reporting channel available 24/7 enabling employees, contractors, and third parties to report potential misconduct in good faith and without fear of retaliation.
The program’s execution and implementation are led by the Compliance Department, under the direction of the Corporate Governance and Compliance Manager, who presents quarterly reports to the Audit Committee. The board’s Audit Committee oversees the effectiveness of the Ethics and Compliance Program, evaluates its controls and risk mitigation measures, and supervises the continuous improvement plans aimed at strengthening our ethical culture and ensuring transparent and compliant operations.
Highly committed founding shareholder and technical and management teams with proven industry expertise and technically-driven culture
Management and operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture, which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience on finding and developing oil and gas fields.
In addition, we strive to provide a safe and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals. We also believe in the importance of local knowledge for operational success, which is why we continue to focus on securing local talent as we expand into new locations, through our Colombian, Argentine and Brazilian acquisitions.
Our management and operating team have an average experience in the energy industry of more than 25 years in companies such as Ecopetrol, Chevron, BP, Shell, Petrobras, Pluspetrol, Pan American Energy, Total and YPF, among others. Throughout our history, our management and operating team has had success in unlocking unexploited value from previously underdeveloped assets.
One of our founding shareholders and current Vice Chairman of the board, Mr. James F. Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, drilling and production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and capital raising for the industry. As of March 19, 2026, Mr. Park held 13.6% of our outstanding common shares.
In addition, as of March 19, 2026, our executive officers owned 0.6% of our outstanding common shares. Ownership of our shares by our executive directors and executive officers aligns their interests with those of our shareholders and helps retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management and Employees—B. Compensation.”
Innovation
We have fostered a company-wide innovation culture that integrates technology, data and process improvements into our daily operations. In 2025, we continued to execute our innovation agenda through three primary areas of focus: data, processes and culture, with a particular emphasis on the organizational adoption of innovation, technology and artificial intelligence. These efforts were directed at improving the reliability of information used across the Group, increasing operational efficiency and strengthening internal competencies related to digital tools and artificial intelligence.
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Artificial intelligence (“AI”) played an increasing role within this workstream. We progressed the development of an AI-first strategy, including the initial phase of an AI video-analytics solution intended to assist with safety observations and the development of an AI governance framework to help ensure that initiatives remain within defined guardrails. Employees also used internally developed AI assistants for certain repetitive analytical and documentation tasks. Based on internal estimates, data and AI initiatives delivered cumulative time savings during the year equivalent to approximately 12.5 full-time equivalent positions.
These activities contributed to the continued development of technology-enabled capabilities within the Group and supported our broader efforts to improve the quality of information, streamline selected processes and build internal proficiency in digital and AI-related tools.
Recent Developments
Proposed acquisition of Frontera Energy’s Colombian E&P assets (not consummated)
On January 29, 2026, we entered into an agreement with Frontera Energy Corporation (“Frontera”) to acquire 100% of Frontera Petroleum International Holdings B.V. (“Frontera International”), which consisted exclusively of oil and gas exploration and production assets in Colombia. On February 2, 2026, we paid an initial deposit of US$75.0 million, with the remaining balance payable at closing, subject to regulatory approvals and customary closing conditions.
On March 5, 2026, Frontera announced that its board of directors had determined that a binding offer from Parex Resources Inc. to acquire the Frontera E&P Assets constituted a “Superior Proposal” under the arrangement agreement with GeoPark, and that the five-business-day matching period had commenced.
Following such notification and after evaluating our match right, on March 9, 2026, we announced our decision not to raise our offer for Frontera’s Colombian E&P assets. As a result, we became entitled to receive the return of the deposit previously placed in escrow, plus any accrued interest, and a US$25.0 million break-up fee, in each case pursuant to the terms of the arrangement agreement.
Offtake and prepayment agreements with Vitol
In January 2026, we renewed our offtake and prepayment agreement with Vitol, extending its term through December 31, 2028. The new terms take effect in January 2026, with deliveries beginning in January 2026 for Llanos 34 and in May 2026 for CPO-5 and Llanos 123, and remaining in force through December 31, 2028. As part of this transaction, we obtained access to committed funding from Vitol with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million) at a SOFR risk-free rate plus a margin of 3.50% per annum. The committed funds are available for drawn until June 30, 2027, subject to certain conditions. Amounts drawn under this prepayment facility may be repaid through future oil deliveries or prepaid at any time without penalty.
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We obtained two short-term loans from Bancolombia Panamá, S.A. totaling US$25.0 million (US$17.0 million and US$8.0 million). The loans were disbursed in January 23, 2026. In February 2026, the terms of these loans were amended, and the loans were restructured to bear interest at a fixed annual rate of 5.06320% and to mature on February 3, 2027.
In addition, in February 2026, we obtained one short-term loan from Citibank Colombia S.A. in an aggregate principal amount of Colombian Pesos 145,280 million (equivalent to US$40.0 million). The loan was disbursed on February 6, 2026, bears interest at a floating rate of IBR (the Colombian interbank reference rate) plus 1.53% per annum, and matures on February 3, 2027. In connection with this borrowing, we entered into a cross-currency swap arrangement with Citibank N.A., New York to hedge the foreign exchange exposure associated with the loan and to secure the Colombian peso cash flows required to service principal and interest payments.
Finally, in February 2026, we entered into an unsecured committed credit facility with Banco de Galicia y Buenos Aires S.A. for up to US$49.0 million to finance working capital and capital expenditures in Argentina. The facility has a six-month availability period from signing, and borrowings thereunder may have terms of 24 months from the date of disbursement. The interest rate is 8.75% per annum on amounts drawn. As of the date of this annual report, no amounts have been drawn under this facility.
Strategic Equity Investment by Grupo Gilinski
Share Purchase Agreement
On March 5, 2026, GeoPark Limited entered into a Share Purchase Agreement (the “SPA”) with Colden, an affiliate of Jaime Gilinski, who leads Grupo Gilinski. Under the SPA, Colden invested approximately US$107.0 million to acquire 12,876,053 newly issued common shares of the Company at a price of US$8.31 per share. Immediately following the closing of the investment, Colden held approximately 20% of the Company’s outstanding common shares and was the Company’s largest shareholder.
The SPA contains certain representations and warranties by the Company and Colden, which the Company believes are customary for transactions of this type, as well as certain indemnification obligations relating to breaches of such representations and warranties and covenants by the Company.
Board Nomination, Voting Obligations and Governance Rights
Pursuant to the SPA, Colden has the right to nominate (i) three directors if Colden beneficially owns at least 28% of the Company’s outstanding common shares, (ii) two directors if Colden beneficially owns at least 15% but less than 28% of the Company’s outstanding common shares, and (iii) one director if Colden beneficially owns at least 7.5% but less than 15% of the Company’s outstanding common shares. Colden is entitled to nominate two directors based on its share ownership immediately following the closing of the investment. Subject to compliance with applicable law, NYSE requirements and certain corporate governance policies of the Company, the Company will include the Colden nominees in the slate of nominees recommended by the board at shareholder meetings at which directors are to be elected. One of Colden’s nominees, Gabriel Gilinski, was appointed to fill a then-existing vacancy on the board with an initial term expiring at the Company’s 2026 Annual Meeting. Colden’s board nomination rights include certain customary rights with respect to representation on committees of the board (other than the Audit Committee) and the removal and replacement of Colden’s nominee directors. If at any time Colden is entitled to nominate three directors, at least one such nominee must qualify as an independent director pursuant to applicable law, NYSE regulations and the Company’s independence criteria.
From the closing of the investment until the earlier of the Company’s second annual general meeting thereafter and the date when Colden no longer has the right to nominate any directors, Colden is obligated to vote its shares in accordance with the board’s recommendation with respect to the election or removal of directors.
For so long as Colden owns at least 15% of the Company’s outstanding common shares, the Company may not take certain specified actions without approval by Colden or at least one of the directors nominated by Colden , including
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(subject to certain exceptions): (i) issuing equity or equity-linked securities in excess of 5% of the Company’s fully diluted share capital; (ii) amending the Company’s governing documents in a manner adverse to Colden; (iii) entering into, modifying or terminating certain related-party transactions; (iv) changing the board size; (v) declaring or paying dividends; and (vi) repurchasing or otherwise acquiring the Company’s outstanding share capital.
Lock-Up, Ownership Limitations and Registration Rights
Under the SPA, from the closing of the investment until 18 months thereafter, Colden and its affiliates may not transfer any common shares of the Company without the Company’s prior written consent, subject to limited exceptions. Until the first anniversary of the closing of the investment, Colden is not permitted to acquire more than 32% of the Company’s outstanding common shares without the prior consent of the board. The SPA includes customary registration rights for Colden with respect to the common shares acquired in the investment.
Rights Agreement Amendment
In connection with the investment, the Company amended the Rights Agreement, by and between the Company and Computershare Trust Company, N.A., dated June 3, 2025 (the “Rights Agreement”), to provide that Colden will not be deemed an “Acquiring Person” under the Rights Agreement in the event of Colden’s acquisition of beneficial ownership of common shares so long as, after giving effect to such acquisition, Colden and its affiliates beneficially own no more than 32% of the outstanding common shares. Under the SPA, the Company agreed to terminate the Rights Agreement on or prior to the 2026 Annual Meeting and not to adopt a shareholder rights plan or take similar measures in the future with the purpose of preventing Colden from (i) acquiring up to 32% of the Company’s outstanding common shares or (ii) making a tender offer for all of the Company’s outstanding share capital.
Further acquisitions by Grupo Gilinski
On March 9, 2026, Spaldy Investments Limited, a business company that operates under the laws of the British Virgin Islands, deemed to be beneficially owned by Jaime Gilinski, acquired 200,000 of the Company’s common shares in the open market, at a weighted average price of US$8.83 per share, for an aggregate purchase price of US$1.8 million.
Between March 11, 2026 and March 19, 2026, Colden acquired a total of 3,587,190 common shares of the Company in the open market, at prices ranging from US$8.58 to US$10.20 per share, for an aggregate purchase price of US$32.9 million.
Recent Oil Price Volatility
In March 2026, oil prices experienced increased volatility, including a sharp rise in Brent crude oil prices, driven primarily by heightened geopolitical tensions in the Middle East and concerns regarding potential disruptions to global oil supply and transportation routes.
While higher oil prices may positively impact revenues, the overall financial effect on the Group may be partially offset, or in certain scenarios adversely affected, by the combined impact of existing hedging arrangements and higher government take in certain jurisdictions. In particular, higher price environments may result in increased royalties, price-linked contractual and fiscal mechanisms and tax surcharges, while realized prices may be capped by hedge ceilings.
Market conditions remain uncertain, and there can be no assurance as to the duration or sustainability of current price levels.
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Our operations
Operations in Colombia
Our Colombian assets currently give us access to 3,257,000 gross exploratory and productive acres across 18 blocks in what we believe to be one of South America’s most attractive oil and gas geographies. Since we entered Colombia in 2012, we have achieved successful exploration and development activities at our operated Llanos 34 Block, which as of December 31, 2025, accounts for 61.0% of our production and 62.2% of our proved reserves.
Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues from a given block based on bilateral agreements with the concessionaires.
The map below illustrates the location of the blocks in Colombia where we hold working and/or economic interests.
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The table below summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2025.
Gross acres
(thousand
Working
Production
Concession
Block
acres)
interest(1)
Partners(2)
Operator
(boepd)
Basin
expiration year
Coatí
15.6
100%
GeoPark
Putumayo
Evaluation: Currently suspended
CPO-4-1
148.3
50%
Parex
Llanos
Exploration: 2028
CPO-5
490.8
30%
ONGC Videsh
6,484
Exploration: 2025
Exploitation: 2042-2045(3)
Llanos 34
59.1
45%
Verano Energy
17,211
Exploitation: 2039-2045(3)
Llanos 86
255.5
Hocol
Exploration: 2026
Llanos 87
107.6
Exploration: 2023
Llanos 104
274.8
Llanos 123
88.3
2,115
Exploration: 2024
Llanos 124
27.6
Mecaya
74.1
Sierracol Energy
Exploration: Currently suspended
Platanillo
27.5
175
Exploitation: 2033(3)
PUT-8
102.8
PUT-9
121.5
PUT-14
114.6
In process of termination
PUT-36
148.0
Tacacho
589.0
Termination requested
Terecay
586.6
As of December 31, 2025, we had net proved reserves of 45.4 mmboe in various blocks in the Llanos Basin, with the Llanos 34 Block representing 80.4% of those reserves, and 2.1 mmboe in the Platanillo Block in the Putumayo Basin.
We previously held an indirect economic interest in the Abanico Block in Colombia through an association contract. The term of the Abanico Association Contract expired in October 2024, and the termination process with the operator is currently ongoing. This interest did not have a material impact on our operations or results during the year ended December 31, 2025.
For further information of each E&P Contract in Colombia, please see “—Significant Agreements.”
Operations in Argentina
In October 2025, we entered the Vaca Muerta shale formation in Argentina with a 100% operated working interest in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. In the case of Puesto Silva Oeste Block, GeoPark holds an 95% of the economic interest on the Block while the remaining 5% is held by GyP. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta, with estimated recoverable resources of more than 60 million gross barrels of oil, and produced 1,584 boepd in December 2025. This acquisition provides immediate production, reserves, and long-term growth opportunities. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina’s Vaca Muerta Formation.”
In May 2024, we had entered into a farm-out agreement for the acquisition of non-operated working interests in four unconventional blocks in the Vaca Muerta formation. However, in May 2025, the seller exercised its contractual right to withdraw from the transaction, and as a result the acquisition was not completed. All advance payments previously made by us were fully reimbursed.
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The map below illustrates the location of the blocks in Argentina where we hold working interests.
The table below summarizes information about the blocks in Argentina in which we had working interests as of and for the year ended December 31, 2025.
Gross
acres
Expiration
interest (1)
concession year
Loma Jarillosa Este
6.1
304
Neuquén
Exploitation: 2057
Puesto Silva Oeste
6.3
95%
GyP
Exploitation: 2060
For further information, please see “—Significant Agreements.”
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Operations in Brazil
In March 2025, we entered into an agreement to divest our 10% non-operated working interest in the Manati gas field, with the transfer of the working interest in December 2025. During 2025, the Manati gas field produced 521 boepd. In addition, in June 2025, we relinquished the POT-T-785 Block upon completion of all contractual exploration commitments. The ANP has granted approval for the relinquishment; however, approval regarding local content commitments is still pending. After this divestment and relinquishment, our Brazilian assets give us access to 30,700 of gross exploratory acres across 4 exploratory blocks.
The following table sets forth information as of December 31, 2025, on our concessions in Brazil in which we have a current or future working interest:
REC-T 58
7.8
Recôncavo
Exploitation: 2052
REC-T 67
7.7
REC-T 77
POT-T 834
7.5
Potiguar
Operations in Ecuador
In July 2025, we entered into an agreement to sell our 50% working interests in the Perico and Espejo Blocks. The divestment transaction closed in December 2025. During 2025, the Perico and Espejo Blocks produced 1,078 boepd.
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Oil and natural gas reserves and production
Our reserves
The following table sets forth our oil and natural gas net proved reserves as of December 31, 2025, which is based on the D&M Reserves Report.
Net proved reserves
As of December 31, 2025
Total net
proved
Natural gas
reserves
(mmboe)(1)
Net proved developed
43.4
1.8
0.4
1.9
Total net proved developed
45.2
45.3
99.8
Net proved undeveloped
4.1
8.9
2.1
9.2
Total net proved undeveloped (2)
13.0
13.3
97.4
Total net proved
We had net proved reserves of 58.6 mmboe at December 31, 2025, compared to net proved reserves of 58.4 mmboe as of December 31, 2024.
The 0.3% increase in net proved reserves in 2025 is mainly attributable to:
This was partially offset by:
During the year ended December 31, 2025, we had 1.3 mmboe of our proved undeveloped reserves from December 31, 2024, converted to proved developed reserves due to development drilling in the Llanos 123 and Llanos 34 Blocks in Colombia. For further information relating to the reconciliation of our net proved reserves for the years ended December 31, 2025, 2024 and 2023, please see Table 5 included in Note 37 (unaudited) to our Consolidated Financial Statements.
Internal controls over reserves estimation process
We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimating process and who have knowledge of the specific properties under evaluation. Our
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Chief Exploration and Development Officer, Rodrigo Dalle Fiore, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our reserves estimation. He has over 20 years of experience in Latin America’s oil and gas industry, with a strong background in unconventional resources, strategic growth, and operational leadership. See “Item 6. Directors, Senior Management and Employees—A. Directors and executive officers.”
In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives:
Throughout each fiscal year, our technical team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally-generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer and management bias.
Recognizing that reserves estimates are based on interpretations and judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified Reserves Engineer sends a preliminary copy of the reserves report to be reviewed by the Corporate Reserves team, the Executive Committee (integrated by the Chief Executive Officer, Chief Financial Officer, Chief Exploration and Development Officer, Chief Operating Officer and Chief People Officer) and the Technical Committee (composed by four technical experts of our board of directors). A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be reviewed and analyzed by the Technical Committee which recommends to the board of directors to approve its disclosure and publication. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees of our board of directors.”
Independent reserves engineers and geoscience professionals
Reserves estimates as of December 31, 2025, for Colombia and Argentina included elsewhere in this annual report are based on the D&M Reserves Report, dated March 3, 2026, and effective as of December 31, 2025. The D&M Reserves Report, a copy of which has been filed as an exhibit to this annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines, including Rule 4-10(a)(1)-(32) of Regulation S-X, at our request in order to estimate reserves and for the areas and period indicated therein.
DeGolyer and MacNaughton Corp. (“DeGolyer and MacNaughton” or “D&M), a Delaware corporation with offices in Dallas, Houston, Buenos Aires, Madrid, Algiers, Baku, Astana and New Delhi, has been providing consulting services to the oil and gas industry since 1936. The firm has more than 180 professionals, including engineers, geologists, geophysicists, petrophysicists and economists, engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
The D&M Reserves Report covered 100% of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton relied on information furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, and agreements relating to current and future operations of the fields and sales of production, without independent verification of the
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accuracy and completeness of such information and data, except that if, in the course of its examination, any information appeared to be inconsistent or insufficient, it did not rely on such information until it had satisfactorily resolved its questions or independently verified such information.
DeGolyer and MacNaughton independently prepared reserves estimates in accordance with SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years under existing economic and operating conditions, consistent with Rule 4-10(a) of Regulation S-X. The reserves estimates were prepared using appropriate geologic and petroleum engineering principles and techniques consistent with generally accepted industry practices, including those set forth in the standards of the Society of Petroleum Engineers. The method or combination of methods used in the analysis of each reservoir was selected based on the maturity of the reservoir, quality and completeness of available data, and production performance, and reflects the independent judgment of DeGolyer and MacNaughton.
D&M’s primary economic assumptions included oil and gas sales prices determined in accordance with SEC guidelines, as well as future expenditures and other economic inputs (including working interests, royalties and taxes) provided by us. The reserves estimates were limited to the economic life of the properties or the applicable concession terms, whichever occurs first. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation and used all methods and procedures that it considered necessary under the circumstances.
However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning the oil and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates.
Technology used in reserves estimation
According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
There are various generally accepted methodologies for estimating reserves including volumetrics, decline curve analysis, material balance, simulation models and analogies. In practice, reserves estimates are typically based on a combination of these methods, selected as appropriate depending on the geological characteristics of the reservoir, its stage of development, production history and the quality and completeness of available data. For unconventional reservoirs, performance-based methodologies may be applied, including production diagnostics, decline-curve analysis and, where appropriate, model-based analysis. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. It may be appropriate to employ several methods in reaching an estimate for a given property.
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Estimates are prepared using all available information, including open- and cased-hole logs, core analyses, geologic and structure maps, seismic interpretation, production and injection data, and pressure test analysis. Supporting data, such as working interests, royalties, operating costs and development plans, are incorporated into the evaluation and updated when such information materially changes.
Proved undeveloped reserves
As of December 31, 2025, we had 13.3 mmboe in proved undeveloped reserves, a increase of 6.5 mmboe, or 96%, compared to our December 31, 2024, proved undeveloped reserves of 6.8 mmboe. Changes for the year ended December 31, 2025, include:
Of our 13.3 mmboe of net proved undeveloped reserves, 4.1 mmboe (30.6%) and 9.2 mmboe (69.4%) were located in Colombia and Argentina, respectively.
During 2025, we incurred approximately US$5.5 million in capital expenditures in Colombia to convert such proved undeveloped reserves to proved developed reserves.
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Production, revenues and price history
The following table sets forth certain information on our production of oil and natural gas in the countries in which we operate, for each of the years ended December 31, 2025, 2024 and 2023.
Average daily production(1)
As of December 31,
Chile (2)
Chile
Average crude oil production (bopd)
31,867
1,668
32,795
926
221
Average sales price of crude oil (US$/bbl)
59.0
55.1
75.6
62.3
65.8
96.1
69.8
66.8
82.1
69.9
68.0
Natural Gas production
Average natural gas production (mcfpd)
685
1,313
363
573
6,065
8,993
Average sales price of natural gas (US$/mcf)
0.8
4.2
7.2
5.9
3.2
3.9
6.5
3.4
Oil and gas production cost
Average operating cost (US$/boe)
15.0
31.5
18.0
26.2
14.1
48.2
21.8
20.6
11.5
10.9
37.5
Average royalties and economic rights in cash (US$/boe)
1.1
1.5
2.8
0.6
7.9
3.1
0.9
Average production cost (US$/boe)(3)
16.0
38.0
19.4
15.2
50.9
21.2
14.0
13.9
The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Argentina, Brazil, Ecuador and Chile for each of the years ended December 31, 2025, 2024 and 2023.
Mbbl
MMcf
Tigana oil field (1)
2,652
3,865
3,904
Jacana oil field (1)
3,096
3,534
4,411
Rest of Colombia
3,850
4,264
251
3,655
209
Loma Jarillosa Este (1)
Rest of Argentina
1,124
481
2,214
394
610
338
133
81
3,283
10,100
1,234
12,277
864
12,395
5,705
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Drilling activities
The following table sets forth the exploratory wells we drilled during the years ended December 31, 2025, 2024 and 2023.
Exploratory wells(1)
Productive(2)
9.0
5.0
7.0
3.0
Net
4.5
3.3
Dry(3)
1.0
2.0
6.0
0.5
10.0
11.0
4.7
The following table sets forth the development wells we drilled during the years ended December 31, 2025, 2024 and 2023.
Development wells
Productive(1)
21.0
25.0
2.7
8.7
11.8
Dry(2)
0.3
22.0
32.0
15.5
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Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in Colombia, Argentina and Brazil as of December 31, 2025.
Acreage(1)
(in thousands of acres)
Total developed acreage
24.1
12.6
Total undeveloped acreage
3,207.6
11.2
30.7
1,581.0
10.8
Total developed and undeveloped acreage
3,231.7
12.4
1,593.6
12.0
Productive wells
The following table sets forth our total gross and net productive wells as of February 28, 2026. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Productive wells(1)
Oil wells
229.0
113.4
Present activities
From January 1, 2026, to February 28, 2026, we produced a net average of approximately 26,911 mboepd from our operations in Colombia and Argentina.
The main highlights of the activity during January and February 2026 are detailed as follows:
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Marketing and delivery commitments
Our production in Colombia primarily consists of crude oil which is sold according to price formulas based on market reference indexes (Brent price, Vasconia and Oriente differential) and discounts that consider transportation costs and quality adjustments.
Our sales strategy is aimed at securing the highest available pricing for our production while securing a reliable and safe path to market. To that end, we focus on developing synergies and strategic partnerships with clients and the national transport systems, to obtain a reduction in costs and increase revenues by making use of the best alternatives available.
We maintain a broad customer base for our Colombian crude, reducing the risk of dependency on any single client. While the loss of a customer could temporarily impact production and sales in a given block, we believe that the availability of alternative buyers for Colombian crude allows us to quickly identify a substitute customer, minimizing potential disruptions.
In 2025, we continued executing commercial agreements for the sale of our Colombian production under competitive market terms. The most relevant arrangements include the following:
In January 2026, we renewed our offtake and prepayment agreement with Vitol, extending its term through December 31, 2028. The new terms take effect in January 2026, with deliveries beginning in January 2026 for Llanos 34 and in May 2026 for CPO-5 and Llanos 123, and remaining in force through December 31, 2028. As part of this transaction, we obtained access to committed funding from Vitol with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million) at a SOFR risk-free rate plus a margin of 3.50% per annum. The committed funds are available to be drawn until June 30, 2027, subject to certain conditions. Amounts drawn under this prepayment facility may be repaid through future oil deliveries or prepaid at any time without penalty.
In connection with this new commercial arrangement, GeoPark secured the necessary transportation capacity in the Oleoductos de Colombia (“ODC”) system, ensuring the full evacuation of contracted volumes from the producing fields to the Coveñas marine terminal. These transportation agreements guarantee operational continuity and delivery reliability under the FOB Coveñas terms.
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Regarding the transportation infrastructure, we can highlight the following:
Crude oil from our operated assets in Argentina is sold under pricing formulas referenced to Brent and adjusted by the Medanito differential, the Neuquén Basin benchmark. Realized prices also reflect quality and logistics adjustments, including API gravity, treatment costs and transportation to regional hubs. As these fields are not yet connected to the pipeline network, crude oil is currently evacuated by truck, which we seek to optimize while advancing long-term midstream solutions. Our commercial strategy focuses on maximizing netbacks through improved evacuation efficiency, securing future pipeline capacity and developing direct relationships with local refiners and traders.
Following the acquisition, we entered into a transitional marketing arrangement with Pluspetrol S.A. (“Pluspetrol”) under two complementary agreements signed on October 16, 2025. Under the first agreement, a commission-based marketing arrangement, Pluspetrol provides marketing services for all crude oil produced. Under the second agreement, Pluspetrol may purchase any unallocated volumes of up to 200 cubic meters per day under a formula linked to export-parity Medanito prices and applicable treatment and transportation costs. These agreements were initially signed through January 31, 2026. On that date, we only extended the commission-based marketing agreement until September 30, 2026, limiting it to 65% of the production from the Loma Jarillosa Este Block. For the remaining 35% of the production from the Loma Jarillosa Este Block and 100% of the production from the Puesto Silva Oeste Block, we sell to Trafigura Argentina S.A. at wellhead. Both agreements include automatic quarterly extensions unless either party provides 45 days' notice. While this structure is designed to ensure uninterrupted offtake during the transition period, we are simultaneously developing our own commercial platform, including direct market relationships and firm transportation arrangements, to assume full commercialization once the Pluspetrol S.A. and Trafigura Argentina S.A. agreements conclude.
Our production in Brazil, until the divestment of our working interest in the Manati field in December 2025, consisted of natural gas, condensate and crude oil. Natural gas production was sold through a long-term agreement with Petrobras,
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which provided for the delivery and transportation of the gas produced in the Manati field to the EVF gas treatment plant in the State of Bahia. In 2025, the condensate produced in the Manati field was subject to a condensate purchase agreement with H.L Oil Industrias de Transformacao LTDA.
Ecuador has a well-developed crude oil market with broad access to international markets and an extensive pipeline transportation system. Our oil production, until the divestment of our working interests in the Perico and Espejo Blocks in December 2025, was transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of our sales were exported on a competitive basis to industry leading participants including traders, refineries, and other producers. The oil price was linked to Brent and adjusted by a differential that varied month to month and resembled Oriente crude reference price.
Corporate
GeoPark Limited, our holding company incorporated under the laws of Bermuda, has a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside our Putumayo Basin production. Sales of this crude oil purchased from third parties accounted for 0.1% of our consolidated revenue in 2025.
Significant Agreements
E&P contracts
We have entered into E&P contracts that grant us the right to explore and operate in eighteen blocks in which we hold working interests. These E&P contracts are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and (2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable. Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties to the relevant E&P contract. The exploitation period for an area may be extended until such time as such area is no longer commercially viable and certain other conditions are met.
Pursuant to our E&P contracts, we are required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a field-by-field basis. See Note 32.1 to our Consolidated Financial Statements.
Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P contract governing such area, the ANH is entitled to receive a “windfall profit”, to be paid periodically, calculated pursuant to such E&P contract.
In each of the exploration and exploitation periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P contract.
Our E&P contracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses, ANH regulation or termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian law, if certain conditions
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are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government during a certain period. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our contracts 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.”
Eastern Llanos Basin:
Llanos 34 Block E&P contract. On March 13, 2009, the E&P contract was awarded to Unión Temporal Llanos 34, currently integrated by GeoPark Colombia S.A.S. with 45%, and Verano Limited (a subsidiary of Parex Energy) with 55% working interest. The Llanos 34 Block E&P contract provides a 24-year exploitation period for each production area, beginning on the date of a commercial declaration. The exploitation period may be extended for periods of up to 10 years at a time if certain conditions are met and subject to ANH approval. As of the date of this annual report there are production areas for the Aruco, Chachalaca, Chiricoca, Curucucu, Guaco, Jacamar, Jacana, Max, Tarotaro, Tigana, Tigui, Tilo and Tua fields.
Pursuant to the Llanos 34 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P contract. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the Llanos 34 Block E&P contract, when the accumulated production of each commercial field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. See Note 32.1 to our Consolidated Financial Statements.
Llanos 32 Block. We had a 12.5% working interest in the Llanos 32 Block. Verano Energy is the operator of this block and had an 87.5% working interest. Economic rights to the ANH are similar to those under the Llanos 34 Block. On March 14, 2025, we transfered our non-operated working interest in the Llanos 32 Block to the joint operation partner for a total consideration of US$19.0 million, minus working capital adjustment of US$3.7 million. The assignment was formalized through an amendment to the E&P Contract in November 2025.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico Block. We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement. In October 11, 2024, the Abanico Block association contract’s term expired and the termination process is ongoing with the operator.
Llanos 86, Llanos 87, Llanos 104, Llanos 123 and Llanos 124 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest, executed E&P contracts over these blocks in 2019, as a result of the Permanent Competitive Process launched by ANH. We are the operator of these contracts. In these E&P contracts, we are required to pay subsurface rights to the ANH, calculated based on the total acreage of the blocks, or the remaining area if in case of relinquishment had taken place. There is also an additional annual 25% markup of said subsurface rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to legal royalties, the ANH is entitled to receive a percentage of total production net of royalties, at the delivery point (multiplied by a factor set in the contract and based on international oil prices). That percentage is 2% in the Llanos 86, 3% in the Llanos 87 E&P contract and Llanos 104 E&P contracts and 1% in the Llanos 123 and Llanos 124 E&P contracts. There is an additional 5-10% share payable to the ANH applicable upon extensions to the production period and when the accumulated gross aggregate production of the area of the contract exceeds 5 million barrels and the WTI exceeds a defined price. ANH becomes entitled to an additional share on production in accordance with a formula set in the contract.
In the Llanos 86 and Llanos 104 Blocks, the completion of 3D seismic acquisition and processing, along with the approval of environmental licenses, enabled the identification of drilling opportunities, such as Matraquero and Vencejo in the Llanos 104 Block, already drilled, and Tijereta in the Llanos 86 Block, which is planned to be drilled in the first half of 2026.
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In the Llanos 87 Block, after fulfilling the total exploration investments committed in the block, we made two discoveries: Tororoi and Zorzal. Accordingly, we are currently conducting an evaluation program approved by the ANH, which remains in effect through April 27, 2026.
The Llanos 123 Block, after fulfilling the total exploration investments committed in the block, in September 2025, we submitted to the ANH the declaration of commerciality of the Toritos and Saltador areas under evaluation.
In the Llanos 124 Block, as of the date of this annual report, the total investments needed to fulfill the exploratory activities committed in the block have already been incurred.
CPO-5 Block E&P contract. We hold a 30% working interest and the operator is ONGC Videsh. As of the date of this annual report, the contract is in phase 2 of the exploration period, with no outstanding investment commitments. There are two commercial fields called Mariposa and Indico, and we also drilled and put into production exploration wells in the evaluation areas La Urraca and Halcon.
Pursuant to the CPO-5 Block E&P contract and applicable law, we are required to pay royalties to the ANH based on hydrocarbons produced in the CPO-5 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the CPO-5 Block E&P contract. The ANH also has an additional economic right equivalent to 23% of production, net of royalties. In accordance with the CPO-5 Block E&P contract, when the accumulated production of each commercial field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this annual report, the contract is in phase 1 of the exploration period and our investment commitment consists of drilling one exploratory well for US$2.9 million, at GeoPark’s working interest, before September 19, 2028.
Pursuant to CPO-4-1 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the CPO-4-1 Block. Additionally, we are required to pay a surface and subsoil usage fee to the ANH. We are required to comply with the VEE (economic value for exclusivity) equivalent to the commitments for the exploratory period; however, if we do not perform such commitments, the VEE amount calculated as provided in the CPO-4-1 E&P contract, must be paid to the ANH. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the CPO-4-1 Block E&P contract, when the accumulated production of the area of the contract, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo Basin:
Coati Block E&P contract. We are the operator of and have a 100% working interest in the Coati Block. The Coati Block has an evaluation area, declared in September 2006, in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coati-1 well. Pursuant to the Coati Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Coati Block E&P contract. In accordance with the Coati Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. As of the date of this annual report, investment commitments in the exploration area consist of 3D seismic and 2D seismic acquisition for US$4.5 million. On November 3, 2022, GeoPark submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and transfer the pending commitments to other E&P contracts. We have completed the transfer of the pending commitments in the block and the ANH approval is pending. On October 21, 2024, the relinquishment of the area associated with the exploration period was formalized with the ANH. The evaluation area is currently suspended.
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Mecaya Block E&P contract. We are the operator of and have a 50% working interest in the Mecaya Block. Sierracol Energy is the owner of the remaining 50% working interest in the contract. In December 2010, the former operator declared an evaluation area and presented an evaluation program for the Mecaya-1 well (Mecaya Evaluation Program). As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, and its remaining exploration commitment consists of the acquisition of 52.2 sq. km. of 3D seismic or 1 exploration well for an amount of US$0.6 million, at our working interest. Both the unified phases 1 and 2 and the evaluation program are currently suspended due to force majeure events (relating to prior consultations).
Pursuant to the Mecaya Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Mecaya Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Mecaya Block E&P contract. In accordance with the Mecaya Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Platanillo Block E&P contract. We are the operator of and have a 100% working interest in the Platanillo Block since its acquisition in 2020. The commercial exploitation started on September 11, 2009. Pursuant to the Platanillo Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Platanillo Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Platanillo Block E&P contract. In accordance with the Platanillo Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. During the first nine months of 2025, operations at all wells in the Platanillo Field were suspended, with operations resuming on October 15, 2025.
Putumayo 8 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 8 Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period. As of the date of this annual report, two of the three committed exploratory wells had been drilled during 2025, and one well remains outstanding to be fulfilled by July 25, 2026. On September 5, 2025, the evaluation program for the Bienparado Sur well was submitted to the ANH for an initial term of one year. In September 2025, the ANH approved the accreditation of the 3D seismic acquired by the partners, and therefore the seismic commitment has been fully satisfied. In addition, the two environmental licensing processes initiated in 2023 have been concluded, and both projects now have duly granted environmental licenses: Bienparado in 2024 and Nyctibius in 2025.
Pursuant to the Putumayo 8 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 8 Block E&P contract. The ANH also has an additional economic right equivalent to 2% of production, net of royalties. In accordance with the Putumayo 8 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 9 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 9 Block. Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, which has investment commitments of US$4.4 million at our working interest, corresponding to drilling of two exploration wells and the acquisition of 126.25 sq. km. of 3D seismic. This contract is suspended since June 25, 2019, due to the occurrence of a force majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). In this context, on January 2, 2026, we submitted to the ANH a request for termination of the E&P contract by mutual agreement.
Putumayo 14 Block E&P contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block. On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer
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the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers, ANH will proceed with the contract’s termination. As of the date of this annual report, the total investment needed to fulfill the commitments has already been incurred and the ANH approval is pending.
Putumayo 36 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 36 Block. Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, which is suspended since April 1, 2020 due to the occurrence of a force majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). On September 19, 2025, the partners approved, by vote, a strategy to accredit the commitments associated with Phase 1 of the exploration period (3D seismic acquisition and two exploratory wells), without such approval necessarily implying the termination thereof. A portion of the investment needed to fulfill our working interest commitment has already been incurred through the drilling of two wells in the Llanos 123 Block, leaving a remaining commitment of approximately US$2.0 million. The partner, in turn, must accredit the value corresponding to its own working interest.
Tacacho and Terecay Blocks E&P contracts. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks. Sierracol Energy is the owner of the remaining 50% working interest in each E&P contract. The contracts are in phase 1 of the exploration period, which are currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area. The outstanding investment commitments consist of 2D seismic acquisition, processing and interpretation for US$4.1 million at our working interest. On September 21, 2022, we submitted to the ANH requests for termination of the E&P contracts. As of the date of this annual report, the requests are under review by the ANH.
Overriding Royalty Agreements
We are obligated to pay an overriding royalty of 4% and 2.5%, plus a 20% grossing up over the overriding royalty, to the previous owners of the Llanos 34 and the CPO-5 Blocks, respectively, based on the production and sale of hydrocarbons discovered in the blocks. During 2025, the Group has accrued US$18.3 million in relation to these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they are exploratory blocks with no production during 2025, these agreements had no impact on our results.
Overview of Unconventional Concessions
Loma Jarillosa Este Unconventional Concession
The Loma Jarillosa Este unconventional exploitation concession (Concesión de Explotación No Convencional de Hidrocarburos, or “CENCH”) is located in the Province of Neuquén, Argentina, and was granted for a 35-year term until 2057 over an area of approximately 24.5 square kilometers, in accordance with the Federal Hydrocarbons Law. Pluspetrol S.A. originally held 100% of the working interest in the concession and subsequently assigned its entire interest to GeoPark Argentina S.A., which became the operator.
As part of this assignment, GeoPark agreed to a continuing development plan that includes:
(i)A firm commitment for 2025 of US$4.8 million for well interventions and enhancements to the Loma Jarillosa Este facilities. In subsequent years, additional work programs may be submitted and approved as firm commitments.
(ii)During years 2 and 3 of the Continuing Development Plan, the activities will consist of drilling 7 horizontal wells, completion of 9 horizontal wells, and the commissioning of five 5 horizontal wells.
(iii)The entire Development Plan proposed by GeoPark is composed of a total of 29 horizontal wells aiming at maximizing the extraction of unconventional resources from the Cocina and Organico Inferior levels of the Vaca Muerta Formation.
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Puesto Silva Oeste Unconventional Concession
In the Puesto Silva Oeste area, also located in the Province of Neuquén, Pluspetrol S.A. assigned to GeoPark Argentina S.A. its 100% working interest in the existing hydrocarbons exploitation concession. In connection with this assignment, the Province of Neuquén granted a new 35-year unconventional exploitation concession (the “PSO CENCH”), as well as an authorization to transport natural gas from Puesto Silva Oeste to the NEUBA II pipeline. This transportation authorization remains associated with the PSO CENCH.
Under the terms of the assignment, GeoPark Argentina S.A. granted GyP a fully carried 5% participation in the economic rights of the PSO CENCH. This participation entitles GyP to 5% of net production revenues from the concession, without operational responsibility, for the entire duration of the PSO CENCH. The fully carried participation is recoverable in full by GeoPark, through the allocation of up to 100% of GyP’s share of production.
The PSO CENCH includes a Pilot Plan that provides for:
(i)the drilling, completion, and production start-up of one horizontal well with a 2,500-meter lateral section and 42 fracture stages; and
(ii)in the event that after 8 months from the production start-up of the committed well, the production profile recorded is equal to or greater than the estimated levels, the contingent drilling, completion, and production start-up of up to 2 additional wells targeting the Vaca Muerta formation will be triggered as an additional commitment.
The investment commitments under the PSO Pilot Plan shall be executed within a term of 3 years as from the effective date of the CENCH, in line with the proposed work schedule. The investment associated with the proposed Pilot Plan is US14.5 million. Parallel to the Pilot Plan, we shall construct and commission a central processing facility in the area.
Overview of concession agreements
Oil and gas activities in Brazil are governed primarily by the Brazilian Petroleum Law and regulated by the National Agency of Petroleum, Natural Gas and Biofuels (“ANP”). Under this framework, exploration and production activities are conducted pursuant to concession agreements, which generally provide for an exploration phase followed, upon a declaration of commercial viability, by a development and production phase. Concession agreements are subject to ANP oversight and require compliance with applicable technical, operational, environmental and financial obligations.
BCAM-40 Concession Agreement.
The BCAM 40 Concession Agreement, which included the Manati gas field, was the only producing asset in Brazil in which we held an interest. In December 2025, we divested our 10% non-operated working interest in the BCAM 40 Concession Agreement, and as a result, we no longer have any producing assets in Brazil.
Exploration blocks.
We currently hold operated interests in four exploratory blocks awarded in the ANP’s First Open Acreage Bid Round, located in the Potiguar Basin (Block POT-T-834) and the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). These blocks are at an early exploration stage and are subject to limited minimum work commitments. As of December 31, 2025, the estimated remaining exploration commitments to be executed before August 2026 amounted to approximately US$0.5 million.
Title to properties
In each of the countries in which we operate, the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private investors for
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the exploration or production of any hydrocarbon reserves. In Colombia, Argentina and Brazil, local governments grant such rights through E&P contracts, exploration permits, exploitation concessions and concession agreements, respectively. See “Item 3. Key Information—D. Risk factors—Risks relating to the countries in which we operate— Oil and natural gas companies in Colombia, Argentina and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries.” Other than as specified in this annual report, we believe that we have satisfactory rights to exploit or benefit economically from the oil and gas reserves in the blocks in which we have an interest in accordance with standards generally accepted in the international oil and gas industry. Our E&P contracts, exploration permits, exploitation concessions and concession agreements are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.”
Our customers
In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. In 2025, the oil and gas production was sold to three clients that concentrated 96% of the Colombian subsidiaries’ revenue. During 2024 and 2025, we executed offtake and prepayment agreements with Vitol, Trafigura and BP to sell production from our producing blocks in the Llanos Basin, mainly Llanos 34, Llanos 123 and CPO-5. We managed the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure, such as the offtake and prepayment agreements with Vitol, Trafigura and BP. For further information, please see Note 3 to our Consolidated Financial Statements.
In Argentina, our crude oil production is transported by truck and sold to local refineries, offtakers and/or third-party operators. Our initial crude’s sale and evacuation was implemented by two short-term complementary agreements entered with Pluspetrol. Under a sales agency agreement, Pluspetrol acted as our sales agent to market all crude produced from the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the domestic market, coordinating lifting, invoicing, and collections on our behalf during the contractual term, renewable quarterly. And any unsold daily production volumes were purchased directly by Pluspetrol under a Crude Sale Agreement delivered at the Centenario treatment plant.
In Brazil, all our gas produced in the Manati field was sold to Petrobras. In Ecuador, 100% of our sales were exported on a competitive basis to industry leading participants including traders and other producers.
Seasonality
Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not played a significant role in our ability to conduct our operations, including drilling and completion activities.
Our competition
The oil and gas industry is competitive, and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring and developing licenses in the countries where we operate or plan to operate.
Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Competition in the oil and
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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 may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.
Health, safety and environmental matters
We are genuinely committed to ensuring that everyone returns home safely and to preventing environmental impacts derived from our operations. Our actions are guided by compliance with applicable laws, industry best practices, and international standards related to environmental, health, and safety performance. We work hand in hand with our suppliers and contractors to transfer best health, safety and environmental practices throughout our value chain, reinforcing our shared responsibility for safety and environmental protection. This commitment is reflected in binding contractual agreements, regular performance evaluations, compliance reviews, and continuous capacity building to strengthen our health, safety, and environmental culture across all operations.
Our Health and Safety Management Plan focus on strengthening leadership at all organizational levels and fostering safe and informed decision-making. Through the implementation of systematic health and safety management tools, we reinforce risk awareness and operational discipline. The updated Work Permit System provides greater clarity in roles, responsibilities, and authorities across operations, contributing to a stronger safety culture. We have also enhanced contractor management throughout their entire lifecycle, ensuring alignment with our corporate standards of excellence. In our administrative environments, we promote a robust health and safety culture and implement initiatives that foster comprehensive well-being, integrating physical, mental, and social health.
We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and actions that ensure respect and protection of the environment in the territories where we operate.
Across all countries where we operate, we ensure compliance with applicable health, safety and environmental requirements. All our operations have the necessary environmental licenses and permits as required by local legislation, based on environmental studies with citizen participation to define management measures and impact mitigation strategies.
Our Environmental Management System (EMS), certified under the ISO standard: 14001:2015 for our operations in Colombia, defines programs for the integral management of water resources; solid and liquid waste management; atmospheric emissions and energy; biodiversity and ecosystem services and training and awareness regarding the protection of the environment for employees and suppliers. In addition, it defines the roles and responsibilities of management regarding the performance of our environmental issues.
Our corporate environmental commitment is mainly based on the management of the following topics:
Integral water management
Our integral water management program is based on the following water principles and objectives: (i) considering water-related risks and opportunities during the planning and execution of our projects, (ii) ensuring sustainable water management by reducing, reusing and optimizing water consumption in our operations, and (iii) innovating, and implementing best practices to ensure zero wastewater discharges into surface water bodies.
We are committed to eliminate any natural surface waterbody withdrawal in all our permanent operations (fields under development) during 2025, as well as continuing to maintain zero direct discharges into surface water sources.
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In 2024, we conducted our first comprehensive water footprint assessment in all our operated blocks in Colombia and Ecuador, following the NTC-ISO 14046:2017 methodology and verified by Colombia’s Standards Institute (ICONTEC). The evaluation covered both direct and indirect water use and assessed impacts on water availability and quality, establishing a corporate baseline to guide future goals and actions for sustainable water management across our operations. In 2025, for the second consecutive year, we carried out the verification of our corporate water footprint assessment for the previous year, reaffirming our commitment to responsible and sustainable water resource management, as well as to the continuous improvement of water use efficiency in our operations.
During 2025, in Colombia, we maintained our commitment to avoiding the use natural surface water sources in our permanent operations, and we did not carry out any type of wastewater discharge into surface waterbodies, to avoid any potential conflict with the other users of this resource due to its quality or quantity
As a contribution to the water-shed in which we capture the water required for the operations in the Llanos 34 Block in Colombia, we completed the construction of the sewerage system and the water waste treatment plant for a local town over 1,300 residents, enhancing the quality of life of its inhabitants and improving the water quality of the river receiving the discharge.
Biodiversity
Through our biodiversity management, we articulate our efforts to avoid, mitigate and eliminate any impact that may represent a material risk to the biodiversity of the environment where we operate, applying the mitigation hierarchy to protect nature and use it sustainably. We recognize the importance of biodiversity in the areas of our interest since the planning stage of our projects. We are committed to avoiding operations in legally protected areas and taking into account biodiversity value and ecosystem services as a driver to design, plan and execute our projects. We are also taking a no-deforestation and no-net-loss approach to biodiversity. The following action lines guide our decision making related to biodiversity; i) green infrastructure, sustainable use and connectivity, ii) conservation of species of wild flora and fauna, iii) strengthening protected areas in the countries we operate, and iv) biodiversity knowledge management.
In addition, we compensate for our residual impact on biodiversity and, we participate and promote programs related to the rehabilitation, restoration, and conservation of high value ecosystems through strategic alliances for the conservation of biodiversity, strengthening social and cultural connections with nature, and promoting knowledge of the natural wealth of the countries we operate in.
Some of the projects related to biodiversity that contribute to the reduction of biodiversity loss, the promotion of conservation of the environment and the stability of ecosystems during 2025, included:
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Climate change
Our response to climate change is contained in our decarbonization plan, which contains the following targets announced in November 2021, following approval of our board of directors:
All our abovementioned goals are defined against a 2020 baseline.
These goals take into account the execution of some operational and environmental projects. The following projects represent our most relevant achievements in Colombia during 2025:
Medium-term actions include additional energy efficiency measures, small-scale renewable projects, further energy diversification alternatives, management of methane emissions, potential participation in carbon markets, reforestation and afforestation initiatives, among others.
As of the date of this annual report, we have other ongoing environmental initiatives related to climate adaptation, such as, in Colombia, we continue the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía, in the hydrographic zone of the Meta River, which will contribute to improve water management, comprehensive risk management and climate change adaptation.
Integral waste management and circular economy
Regarding the proper management of solid waste generated by our activities, we focus our management on the principles of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with applicable regulations. In 2025, we continued strengthening our circular economy strategic plan and the roadmap for its implementation. As part of this plan, we are carrying out more than 8 circular initiatives as part of the three (3) circularity models that we have prioritized: i) water management, ii) waste management, and iii) use of gas.
In 2024, we were recognized by the ACP with the Sustainability Facts award in the implementation of circular models category, for the results of the circular economy strategic plan through which we promote the efficient management of
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resource consumption, the maintenance of the value of products and materials, and the minimization of waste generation in our operations.
Spill Management
In 2025, we had zero recordable hydrocarbon spills (>=1Bbl uncontained) in our operations.
Our HS Plan
Our Health and Safety Management System (HSMS) remain certified under the ISO 45001:2018 standard, encompassing all our operations in Colombia. With the expansion of our operations into Argentina, we have extended the implementation of our HSMS to this new operation, reaffirming our corporate commitment to excellence in health and safety performance throughout the region.
Our Health and Safety Management Plan is designed to implement realistic, practical, and globally recognized programs that strengthen leadership, operational discipline, and risk awareness across the organization. Guided by international standards (IOGP / IPIECA / IADC / ARPEL) and our SPEED philosophy, we aim to foster shared ownership of health and safety, embedding it into every level of decision-making and every aspect of our operations.
In 2025, our strategy focused on four key areas that form the foundation of our health and safety (“HS”) management:
Our HS Policy
Our Health and Safety Policy seeks to meet or exceed all applicable regulations in the countries where we operate. We believe that oil and gas can be produced safely and responsibly, safeguarding people’s well-being and protecting the environment. Within our SPEED philosophy, a dedicated and highly trained team leads the implementation of best HS practices, ensuring compliance with the standards established by our board of directors and providing continuous training and support to all employees and contractors.
Since 2024, health and safety performance has become a recurring topic of review for the board’s Sustainability Committee (SPEED Committee), reinforcing the integration of HS into our corporate governance and comprehensive sustainability management.
Our health and safety practices and outcomes
We continuously improve and update management tools to strengthen our health and safety policy. Our programs are designed to identify, evaluate, and control risks that could affect the health and safety of employees, contractors, and visitors. Among our core programs are: Proactive Observation Program (POP), Authority to stop an activity (ADA), Safety
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Operational Standard (SOS), Management of Change (MOC), Incident Reporting and Investigation System (IRIS), Road Transportation Safety (RTS), and the business continuity master plan (PMCN).
In 2025, we achieved significant milestones that demonstrate our commitment to continuous improvement and operational excellence:
As of December 31, 2025, and for the preceding twelve months, our HS performance indicators were as follows:
Certain Bermuda law considerations
We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.
Insurance
We maintain insurance coverage of types and amounts that we believe to be customary and reasonable for companies of our size and with similar operations in the oil and gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive.
Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, cyber security, director’s and officer’s liability and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business.”
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Industry and regulatory framework
Regulation of the oil and gas industry
The ANH administers Colombia’s upstream acreage and awards areas primarily through exploration and production contracts (“E&P contracts”) and technical evaluation agreements (“TEAs”). The contractual framework has been updated through successive ANH agreements; E&P contracts entered into in recent years are governed principally by Agreement 002 of 2017 (as compiled by Agreement 009 of 2021), while earlier contracts remain subject to the regulations in effect at the time they were executed. In September 2023, the ANH issued Agreement 06 of 2023 to promote exploration by, among other measures, allowing extensions of exploration and evaluation periods in exchange for additional exploration commitments.
Regulatory framework
Regulation of exploration and production activities
Under Colombian law, the state is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is responsible for national energy policy, and the ANH administers the granting and oversight of upstream contractual rights. The Petroleum Code (Decree Law 1056 of 1953) and related regulations establish general requirements applicable to hydrocarbon activities, which are implemented in practice through E&P contracts and TEAs.
E&P contractors are generally required to pay royalties (in kind or in cash as instructed by the ANH) and, depending on the applicable contract, additional economic rights in favor of the ANH (including the participating interest in production commonly referred to as the ‘X factor’), as well as other contractual economic provisions. Contractors may also undertake community-related obligations in the area of influence of the projects (Proyectos en Beneficio de las Comunidades, “PBC”)
In connection with the ANH’s Ronda Colombia 2021, the ANH introduced additional bid parameters, including an ‘Exclusivity Economic Value’ (EEV) concept linked to exploration commitments. We did not participate in that round; however, we subsequently received a 50% non-operated working interest in the CPO4-1 E&P contract through a transfer from Parex.
The Tax Statute and Law 9 of 1991 provide the primary features of the oil and gas industry’s tax and foreign exchange system in Colombia. Generally, national taxes under the general tax statute apply to all taxpayers, regardless of industry.
The latest tax reform was enacted in December 2022, including modifications to the corporate income tax rate and the tax treatment of royalties, in-kind and in cash. However, in November 2023, the Constitutional Court ruled that the modification that prohibited the deduction of royalties is unconstitutional, and such deductions are allowed as was the case until 2022.
The main taxes currently in effect are the income tax (35%, plus a surtax for companies developing crude oil extractive activities from 2023 onwards, ranging between 0% and 15%, depending on the Brent crude oil price level), capital gains tax (15%), sales or value added tax (19%), and the tax on financial transactions (0.4%).
Additional regional taxes also apply with some special rules for the companies belonging to the oil and gas industry. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax.
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Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment in Colombia. Resolution 1/2018 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing exchange operations. Articles 94 to 97 of Resolution 1 provide for a special exchange regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies.
Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Central Bank and Ministry of Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 1 and may not be able to access the special exchange regime for a period of 10 years.
Tax regulations implemented in 2025 and subsequent events in 2026
On February 14, 2025, Colombia’s Ministry of Finance issued Decree No. 0175 of 2025 in connection with the state of internal commotion declared in certain regions, introducing (i) a 1% special tax on the first sale or export of crude oil and coal (based on sale value for domestic transactions and FOB value for exports) and (ii) a temporary increase of the stamp tax rate from 0% to 1% on certain public instruments and private documents recording obligations above approximately COP 298 million (approximatellyIn 2024, Argentina enacted Law No. 27,742 (the ‘Ley de Bases’), US$ 0.07 million), with these measures applying through December 31, 2025.
In December 2025, the Government declared a nationwide State of Economic and Social Emergency and adopted additional fiscal measures, including a temporary tax on sale or export of hydrocarbons and restrictions affecting the deductibility of royalty payments; however, on January 29, 2026, the Constitutional Court ordered the provisional suspension and, as a consequence, ordered that the additional fiscal measures would not produce effects as of that date pending a final ruling.
More recently, in February 2026, the Government declared a new regional State of Economic, Social and Ecological Emergency for 30 days and subsequently adopted a temporary net worth tax for legal entities for tax year 2026, applicable to entities with net worth above a specified threshold as of March 1, 2026. While the general rate is 0.5%, for companies in the mining-energy sector (including oil and gas) such as us, the applicable rate is 1.6%. The tax is payable in two equal installments (50% due on April 1, 2026 and 50% due on May 4, 2026).
Environmental
Hydrocarbon operations are subject to national comprehensive environmental regulations issued by the Ministry of Environment and Sustainable Development. The permits required for exploration and exploitation activities are granted and followed by ANLA which is an independent entity. Colombian environmental legislation is very robust, and oil and gas is one of the most regulated sectors including seismic programs, exploration, production, transportation of hydrocarbons, decommissioning, restoration and remediation stages.
Decree 1076 of 2015 and further modifications, compile the country’s environmental legal framework prioritizing the recognition of sensitive areas, the country’s biodiversity, the mitigation hierarchy of impacts, the implementation of the best practices of environmental management, the liquid effluent disposal thresholds, the minimum offset measures requirements, among others, in order to achieve the development of the activity with an adequate care of the environment.
Hydrocarbon activities in Argentina are primarily governed by the Federal Hydrocarbons Law No. 17,319, as amended, which establishes a concession-based system for the exploration and exploitation of oil and gas resources. Following constitutional and legislative reforms, jurisdiction over onshore hydrocarbon resources is vested in the provincial states, which grant exploration permits and exploitation concessions within their territories.
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In 2024, Argentina enacted Law No. 27,742 (the ‘Ley de Bases’), which introduced, among other measures, the Incentive Regime for Large Investments (‘RIGI’). In February 2026, Argentina issued a regulation extending the RIGI incentive regime to onshore upstream oil and gas. We are evaluating its potential applicability to our development plans in the Loma Jarillosa Este and Puesto Silva Oeste Blocks, subject to meeting eligibility requirements and regulatory interpretation by the authorities.
Hydrocarbon Income Maximization and Exports
Argentina has historically implemented policies prioritizing domestic hydrocarbon supply, including export restrictions and price controls. Recent regulatory changes have shifted this approach toward promoting investment and maximizing income from hydrocarbon exploitation. Exports of crude oil and hydrocarbon products are generally permitted, subject to regulatory notification and the absence of objections by the Energy Secretariat based on supply security considerations.
Hydrocarbon Exploitation Concessions Terms
Argentina law provides for different types of hydrocarbons exploitation concessions: (i) 25-years conventional concessions; (ii) 35-years unconventional hydrocarbon concessions and (iii) 30-years offshore concessions.
With regards to royalties, while historically a fixed or standardized royalty was foreseen for all concessions, an important modification was introduced by Section IV of the Ley de Bases in the selection procedures, since, although the competitive scheme is maintained, the bidding among the interested parties will be based on the royalty offered. In this scheme, the State will set a reference price based on international markets, and its real value will be estimated by adjusting the values in accordance with the U.S. Consumer Price Index. In this way, the bidder will have to quote a base royalty of 15% with an adjustment (which may be positive or negative) and this will compose the royalty offered for the whole course of the concession. The novelty is that the royalty offered will be maintained if the reference price does not change by more or less than 50% with respect to the price in force at the time of award. If the reference price increases by more than 50%, the concessionaire will pay double the royalty offered for the duration of such increase and, vice versa, will pay half if the reference price decreases by more than 50%.
The payment of an extension bonus to the government is also provided for a maximum amount equal to 2% of the remaining proven reserves at the end of effective term of the concession valued at the average basin price applicable to the respective hydrocarbons during the immediate past 2 years.
Regulation of transportation activities
Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial states or the federal government, depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other fixed facilities necessary for the transportation of oil, gas and by-products.
Transportation facilities with surplus capacity must transport third parties’ hydrocarbons on an open-access basis, for a fee which is the same for all users on similar terms.
Crude oil and natural gas transportation in Argentina is carried out primarily through a limited number of common carrier pipeline systems, which continue to operate today. In order to promote the expansion of transportation capacity, regulations adopted in 2019 allow shippers to reserve capacity in new or expanded pipelines through freely negotiated capacity reservation agreements.
Exploitation concessionaires are subject to the general federal and provincial tax regime. For our Argentine operations, the most relevant federal taxes include corporate income tax at a 35% rate (based on our applicable taxable income threshold), value-added tax (21%), and the tax on debits and credits in bank accounts, which generally applies
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to debits and credits in Argentine bank accounts (typically 0.6% on debits and 0.6% on credits, with certain transactions subject to higher or reduced rates and with limited creditability against income tax in specific cases). Provincial taxes generally include turnover tax (rates vary by jurisdiction and activity) and stamp tax.
Since May 2020, export duties are exempted as long as the international Brent crude oil price is equal to or lower than US$45 per bbl, progressively increasing as the reference price rises up to 8%, a ceiling to be recognized when Brent is equal to or higher than US$60 per bbl (as per DNU No. 488/20). During 2025, the rate remained at 8%.
Argentine resident individuals and undivided estates, foreign individuals and undivided estates, and foreign entities are subject to a 0.5% personal assets tax on the value of shares issued by Argentine entities held as of December 31 of each year, which is assessed on the Argentine issuer as a substitute taxpayer and calculated based on the proportional net worth value derived from the issuer’s financial statements; the issuer is generally entitled to seek reimbursement from the relevant shareholders, including through dividend withholding or enforcement against the shares.
Tax Benefits of Negotiable Obligations (“ONs”)
Negotiable Obligations (“ONs”) in Argentina are governed by Law 23,576, which provides several tax advantages for issuers and subscribers.
For issuers, the key benefits include:
For subscribers:
These benefits encourage the use of ONs as a financing tool, offering tax efficiencies for both companies in the hydrocarbon sector and international investors, further enhancing Argentina’s investment attractiveness.
Foreign Exchange Restrictions
The Argentine government has historically implemented foreign exchange controls and restrictions on the transfer of funds in and out of the country. These measures are frequently adjusted based on macroeconomic conditions, foreign currency reserves, and government policies.
As of the date of this annual report, regulations require companies operating in Argentina to comply with the applicable requirements and conditions established by the Argentine Central Bank (BCRA) to access the official foreign exchange market (MULC) for payments abroad, including dividend distributions, repayment of intercompany loans, and external debt servicing. Certain transactions, such as payments for imports, may be conducted through the MULC but are subject to regulatory conditions and, in some cases, delays.
Despite these restrictions, companies can transfer funds abroad through alternative mechanisms permitted under the current regulatory framework. These include financing structures, capital contributions, and transactions conducted at
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financial market exchange rates. Additionally, companies operating under certain promotional regimes, particularly in the hydrocarbon sector, may access preferential foreign exchange conditions, allowing for improved financial planning and operational efficiency. However, differences between the official exchange rate and financial market exchange rates may result in additional costs.
The current Argentine government has publicly expressed its intention to gradually ease foreign exchange restrictions as part of broader economic stabilization efforts. Future regulatory changes could modify access to foreign currency and the conditions under which companies operate in the exchange market, potentially increasing flexibility in capital flows over time.
Hydrocarbon operations are subject to concurrent national and provincial environmental statutes and regulations, and to the concurrent jurisdiction of national and provincial environmental and hydrocarbon enforcement authorities. The different hydrocarbon producing provincial states have enacted and enforced comprehensive environmental decommissioning, restoration and remediation frameworks.
Law No. 27,007 provided that the federal state and provincial states will tend to the establishment of a uniform environmental legislation whose priority objective will be to apply the best practices of environmental management to the tasks of exploration, exploitation and/or transportation of hydrocarbons in order to achieve the development of the activity with adequate care of the environment.
These laws and regulations address national environmental issues, including liquid effluent disposal, investigation and cleanup of hazardous substances, natural resource damage claims and tort liability with respect to toxic substances. Provincial regulations may be enacted to complement these national laws and regulations.
Oil and gas activities in Brazil are governed primarily by the Brazilian Federal Constitution and the Brazilian Petroleum Law, which allow private and state-owned companies to engage in the exploration and production of hydrocarbons under a concession-based regime. The sector is regulated and supervised by the National Agency of Petroleum, Natural Gas and Biofuels (“ANP”), which is responsible for awarding concession rights, overseeing compliance with concession agreements and enforcing applicable technical, operational and environmental regulations.
Exploration and production activities are carried out pursuant to concession agreements granted by the ANP through competitive processes. Such concession agreements establish the rights and obligations of concessionaires, including exploration and production terms, requirements for the return of areas, guarantees to secure performance, and conditions for the transfer or assignment of participation interests, which are generally subject to ANP approval.
Taxation and government take
Concessionaires in Brazil are subject to a government take primarily comprised of royalties and, in certain cases, a special participation fee applicable to fields with higher production levels or profitability. Royalties generally range between 5% and 10% of production, calculated based on reference prices established by the ANP. The special participation fee, when applicable, may reach up to 40% of net revenues, depending on production volumes, field characteristics and location.
In addition to government take, oil and gas activities are subject to direct federal taxes, including corporate income tax, currently levied at a combined rate of approximately 34% (comprising a 25% corporate income tax and a 9% social contribution on net profit), calculated on taxable income.
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Upstream operations are also subject to indirect taxes, which may represent a significant cost component. These include the state value-added tax (ICMS), generally levied at rates ranging from 17% to 20% on local transactions, as well as federal social contribution taxes on gross revenues (PIS and COFINS), which under the non-cumulative regime are levied at a combined nominal rate of 9.25%, subject to the availability of tax credits depending on the nature of the activity and expenditures.
Tax incentives
In 2018, GeoPark Brazil was granted a tax incentive by the Superintendence for the Development of the Northeast (“SUDENE”), which provided for a 75% reduction in corporate income tax and related surcharges on qualifying profits derived from exploration activities in the SUDENE operating area. This incentive was granted for a ten-year period, subject to compliance with certain investment, operational, labor and environmental requirements.
Regulatory and tax framework
Hydrocarbon operations in Ecuador are conducted under service contracts or production-sharing contracts regulated by the Ministry of Energy and supervised by Agency for Regulation and Control of Hydrocarbons (“ARCH”). The State retains ownership of hydrocarbons and receives its economic participation through its share of production and applicable taxes. Contractors are subject to a 25% corporate income tax (reduced to 20% for the Espejo Consortium under an investment agreement), 15% employee profit-sharing, 15% VAT (non-creditable), and a 5% tax on foreign currency outflows, among other levies.
C. Organizational structure
We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 19 (“Subsidiary undertakings”) to our Consolidated Financial Statements.
D. Property, plant and equipment
See “—B. Business Overview—Title to properties.”
A. Operating results
The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto.
The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking statements.”
Factors affecting our results of operations
We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following:
Discovery and exploitation of reserves
Our results of operations depend on our level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce.
Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business, results of operations and financial condition.
Oil and gas revenue and international prices
Our revenues are derived from the sale of our oil and natural gas production, as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions, and a variety of additional factors. For example, during the six-year period from March 1, 2020, to February 28, 2026, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel.
Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price is based on Brent, adjusted by a differential linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin that is transported through Ecuador. In Argentina, the Medanito crude reference price is the marker commonly used in the Neuquén Basin. The reference price is also further adjusted for marketing and quality discounts, considering factors such as API gravity, viscosity, sulphur content, delivery point and transport costs.
We seek to partially mitigate our exposure to crude oil price volatility using derivatives by hedging a portion of our production for a limited period going forward. We use a combination of options to manage our production’s exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. For further information related to Commodity Risk Management Contracts, please see Note 7.1 to our Consolidated Financial Statements.
If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$8.2 million (US$24.8 million in 2024).
Funding for our capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program which would cause us to further decrease our work program, which could harm our business outlook, investor confidence and our share price. If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase our work and investment program and thereby further increase oil and gas production.
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Production and operating costs
Our production and operating costs consist primarily of expenses associated with the production of oil and gas, the most significant of which are facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and economic rights in cash, and consumables, among others. Our production costs may vary as a consequence of the increase or decrease of commodity prices and other factors, such as the increase in energy costs that peaked during 2023 and 2024 due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. We have historically not hedged our costs to protect against fluctuations. However, during the second half of 2025, we entered into a derivative financial instrument to partially mitigate the impact of potential higher electricity costs in Colombia resulting from droughts and reduced hydroelectric generation, particularly in the Llanos 34 Block, where electricity expenses represent a significant portion of our production and operating costs.
Availability and reliability of infrastructure
Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.”
Production levels
Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and oil and natural gas prices.
We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.”
Contractual obligations
In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P contracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various E&P contracts, 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.”
Acquisitions
As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally incorporate our acquired business into our results of operations at or around the date of closing.
In October 2025, we acquired operated working interests in two blocks in the in the Vaca Muerta formation in Argentina. This acquisition provides immediate production, reserves, and long-term growth opportunities. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina’s Vaca Muerta Formation.”
Functional and presentational currency
Our Consolidated Financial Statements are presented in US$, which is our presentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is the real.
Geographical segment reporting
In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non- Argentine, non-Brazilian, non-Ecuadorian and non-Chilean operations, primarily consisting of our corporate head office operations.
As of December 31, 2025, we divided our business into four geographical segments—Colombia, Argentina, Brazil and Ecuador—that corresponded to our principal jurisdictions of operation. Activities not falling into these four geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment.
Description of principal line items
The following is a brief description of the principal line items of our consolidated statement of income.
Revenue
Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipeline or other delivery mechanism and the customer accepts the product. Consequently, our performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place.
Commodity risk management contracts are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the Revenue line item in the Consolidated Statement of Income.
Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, royalties and economic rights in cash are also included within this account. For a description of our production and operating costs, see “—Factors affecting our results of operations.”
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Depreciation
Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.
Geological and geophysical expenses
Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies.
Administrative expenses
Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions.
Selling expenses
Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs and selling taxes.
Write-off of unsuccessful exploration efforts
Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending on whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. During 2025, we recognized write-off of unsuccessful exploration efforts of US$13.4 million (US$14.8 million in 2024). See Note 18 to our Consolidated Financial Statements.
Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value minus costs to sell and value in use.
During 2025, we recognized an impairment loss of US$31.0 million in the Perico and Espejo Blocks in Ecuador due to the known selling price of the related net assets in the context of their divestment transaction. No impairment losses were recognized or reversed in 2024. See Notes 18 and 35 to our Consolidated Financial Statements.
Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses.
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Recent accounting pronouncements
See Note 2.1.1 to our Consolidated Financial Statements.
Results of operations
The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes.
In preparation for continued volatility, we have developed a capital expenditure program for 2026 which is subject to change as a result of market conditions, developments regarding our business, results of operations and financial condition, and other factors. See “Item 4. Information on the Company—B. Business Overview—Our business strategy —2026 work plan and outlook.”
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Year ended December 31, 2025, compared to year ended December 31, 2024
The following table summarizes certain of our financial and operating data for the years ended December 31, 2025 and 2024.
% Change from
prior year
(in thousands of US$, except for percentages)
Sale of crude oil
472,054
648,670
(27)
Sale of purchased crude oil
7,177
(94)
Sale of gas
6,251
5,076
Commodity risk management contracts designated as cash flow hedges
13,794
(85)
(16,328)
660,838
(25)
(141,059)
(164,034)
(14)
(10,538)
(12,595)
(16)
(40,544)
(49,534)
(18)
(20,909)
(14,914)
(117,190)
(130,659)
(10)
(13,422)
(14,779)
(9)
Impairment loss recognized for non-financial assets
(30,989)
100
Other expenses
(7,324)
(777)
843
Operating profit
110,543
273,546
(60)
Financial expenses
(76,324)
(51,551)
Financial income
21,718
8,016
171
Foreign exchange gain (loss)
(7,286)
12,160
(160)
Profit before income tax
48,651
242,171
(80)
Income tax expense
1,016
(145,792)
(101)
Profit for the year
49,667
96,379
(48)
Net production volumes
Oil (mbbl)(2)
Gas (mcf)(3)
Total net production (mboe)
10,305
12,421
(17)
Average net production (boepd)
33,937
Average realized sales price
Oil (US$ per bbl)
66.0
Gas (US$ per mmcf)
(30)
Average unit costs per boe (US$)
Operating cost
Royalties and economic rights in cash
Production costs(1)
16.6
16.3
(1)
4.8
4.9
(3)
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The following table summarizes certain financial data.
(in thousands of US$)
619,762
2,934
30,567
398
(110,030)
(2,096)
(246)
(4,818)
(121,143)
(1,214)
(8,290)
(2)
Impairment and write-off
(44,411)
(6,909)
(156)
(7,714)
For the year ended December 31, 2025, crude oil sales, including commodity risk management contracts, remained our principal source of revenue, accounting for 98.6% of our total revenue, followed by gas sales of 1.3% and purchased crude oil sales of 0.1%. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2024, to the year ended December 31, 2025.
For the year ended
December 31,
Consolidated
Year ended December 31,
Change from prior year
By country
(158,344)
(26)
3,501
119
(12,104)
(40)
(398)
(100)
(6,758)
(168,320)
Revenue decreased 25%, from US$660.8 million for the year ended December 31, 2024, to US$492.5 million for the year ended December 31, 2025. This decline was primarily driven by lower sales volumes and lower realized prices during the year. Crude oil sales decreased mainly as a result of a reduction in volumes sold —from 9.8 mmbbl in 2024 to 8.2 mmbbl in 2025— together with lower realized price, resulting in net oil revenue of US$472.1 million for the year ended December 31, 2025, compared to US$648.7 million for the year ended December 31, 2024. This decrease was partially mitigated by the positive effect of the commodity risk management contracts in place during the year. Gas sales increased to US$6.3 million for the year ended December 31, 2025, from US$5.1 million for the year ended December 31, 2024, primarily due to the reactivation of the Manati gas field in Brazil in May 2025, partially offset by the divestment of the Llanos 32 Block in Colombia in March 2025.
The US$168.3 million decrease in total net revenue is explained by i) a decrease of US$158.3 million in Colombia (largely due to lower oil deliveries and lower realized prices); ii) an increase of US$5.8 million in Argentina (from the acquisition of working interests in two blocks in the Vaca Muerta formation in October 2025); iii) an increase of US$3.5 million in Brazil (resulting from higher gas deliveries due to the reactivation of the Manati gas field in May 2025, net of lower realized prices); iv) a decrease of US$12.1 million in Ecuador (driven by lower oil deliveries and lower realized
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prices); v) a decrease of US$0.4 million in Chile (following the divestment of operations in January 2024); and vi) a decrease of US$6.8 million from the trading activities of the holding company, GeoPark Limited.
Revenue from our Colombian operations for the year ended December 31, 2025, was US$461.4 million, representing 93.7% of total consolidated sales, compared to US$619.8 million for the year ended December 31, 2024 (93.8% of total consolidated sales). The decrease was primarily driven by a lower average realized price per barrel of crude oil from US$65.8 per barrel in 2024 to US$57.3 per barrel in 2025, mainly reflecting lower reference international prices. In addition, oil deliveries decreased from 9.4 mmbbl in 2024 to 7.8 mmbbl in 2025, mainly impacted by a natural decline in the Llanos 34 Block. These effects were partially offset by commodity risk management gains of $13.8 million recognized during the year.
Revenue from our operations in Argentina totaled US$5.8 million, reflecting deliveries from the Loma Jarillosa Este and Puesto Silva Oeste Blocks, which we acquired in October 2025.
Revenue from Brazilian operations for the year ended December 31, 2025, was US$6.4 million, representing a 119% increase compared to US$2.9 million for the year ended December 31, 2024. This increase was primarily due to higher gas deliveries (from 0.08 mmboe in 2024 to 0.25 mmboe in 2025), following the reactivation of production at the non-operated Manati gas field in May 2025. The share of total revenue from Brazil rose from 0.4% in 2024 to 1.3% in 2025.
Revenue from Ecuador for the year ended December 31, 2025, was US$18.5 million, a 40% decrease from US$30.6 million for the year ended December 31, 2024. This reduction was driven by lower realized oil prices from US$69.8 per barrel in 2024 to US$62.3 per barrel in 2025, mainly reflecting lower reference international prices. In addition, oil deliveries decreased from 0.4 mmbbl in 2024 to 0.3 mmbbl in 2025 in 2025, due to the blocks in Ecuador were divested in December 2025. The contribution of Ecuador to our total revenue was reduced from 4.6% in 2024 to 3.7% in 2025.
Revenue from the trading activities performed by our holding company, GeoPark Limited, for the year ended December 31, 2025, was US$0.4 million, compared to US$7.2 million for the year ended December 31, 2024. This represented 0.1% of total revenue in 2025, down from 1.1% in 2024.
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The following table summarizes our production and operating costs for the years ended December 31, 2025 and 2024.
% Change
from prior year
Consolidated (including Colombia, Argentina, Brazil, Ecuador, Chile and Other)
Royalties in cash
(6,195)
(4,189)
Economic rights in cash
(3,079)
(6,484)
(53)
Staff costs and share-based payments
(16,004)
(16,344)
Well and facilities maintenance
(25,675)
(25,631)
0
Operation and maintenance
(8,239)
(8,936)
(8)
Consumables
(31,398)
(36,868)
(15)
Equipment rental
(7,511)
(5,716)
Transportation costs
(4,095)
(5,409)
(24)
Field camp
(4,822)
(6,401)
Safety and insurance costs
(4,213)
(4,937)
Personnel transportation
(2,393)
(3,586)
(33)
Consultant fees
(3,120)
(3,893)
(20)
Gas plant costs
(1,857)
(1,753)
Non-operated blocks costs
(19,697)
(22,305)
(12)
Crude oil stock variation
747
(976)
(177)
Purchased crude oil
(317)
(6,274)
(95)
Other costs
(3,191)
(4,332)
(5,131)
(699)
(365)
(3,953)
(224)
(14,509)
(1,485)
(16,337)
(5)
(22,991)
(301)
(2,365)
(23,524)
(1,764)
(343)
(7,278)
(794)
(167)
(8,747)
(189)
(31,196)
(178)
(36,502)
(318)
(6,829)
(79)
(603)
(5,138)
(578)
(3,783)
(141)
(171)
(5,359)
(55)
(4,538)
(260)
(6,369)
(3,897)
(87)
(66)
(163)
(4,742)
(187)
(6)
(2,312)
(64)
(3,556)
(13)
(3,085)
(35)
(3,778)
(37)
(78)
(131)
(1,726)
(138)
(1,615)
(13,065)
(90)
(6,542)
(14,515)
(112)
(7,678)
601
(7)
153
(357)
(619)
(2,791)
(244)
(4,135)
(199)
(58)
(124,014)
(4,097)
(4,856)
(7,775)
(143,634)
(4,140)
(9,549)
(437)
Consolidated production and operating costs decreased 14%, from US$164.0 million for the year ended December 31, 2024, to US$141.1 million for the year ended December 31, 2025, primarily due to lower purchased crude oil, lower energy costs compared to the elevated levels experienced in 2024, and cost-efficiency initiatives implemented by the Group during the year, partially offset by operating costs from blocks acquired in Argentina in 2025.
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Production and operating costs in Colombia decreased by 14%, to US$124.0 million for the year ended December 31, 2025, as compared to US$143.6 million for the year ended December 31, 2024, primarily due to reduced energy, community, and technical consultancy expenses in the Llanos 34 Block, as well as cost-efficiency initiatives implemented by the Group during the year.
Production and operating costs in Argentina of US$4.1 million resulted from the takeover of operations at the Loma Jarillosa Este and Puesto Silva Oeste Blocks on October 16, 2025, including ramp-up operating costs associated with the start-up and initial operation of these blocks.
Production and operating costs in Brazil increased by 17%, to US$4.9 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024, mainly resulting from facilities maintenance in the Manati gas field.
Production and operating costs in Ecuador decreased by 19%, to US$7.8 million for the year ended December 31, 2025, compared to US$9.5 million the year ended December 31, 2024, primarily due to lower activity in the non-operated Perico Block.
Purchases of crude oil for the trading operation performed by the holding company, GeoPark Limited, amounted to US$0.3 million and US$6.3 million for the years ended December 31, 2025, and 2024, respectively.
Geological and geophysical expenses decreased by 16%, from US$12.6 million for the year ended December 31, 2024, to US$10.5 million for the year ended December 31, 2025, primarily as the result of cost-efficiency measures implemented to align the organizational structure with the Group's strategic objectives and operational requirements.
Administrative costs
Administrative costs decreased by 18%, from US$49.5 million for the year ended December 31, 2024, to US$40.5 million for the year ended December 31, 2025, primarily reflecting lower ongoing corporate and back-office expenses, including the impact of workforce reductions implemented as part of the Group’s cost-efficiency measures during the year.
(18,041)
(11,840)
(6,201)
(715)
(2,153)
(3,074)
921
(5,995)
Selling expenses increased by 40%, from US$14.9 million for the year ended December 31, 2024, to US$20.9 million for the year ended December 31, 2025, primarily due to deliveries at different sales points in the CPO-5 and Llanos 123 Blocks in Colombia, including the shift to export delivery locations under a new commercial agreement with BP from August 2025. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses.
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11,113
(2,086)
20,860
968
3,472
(42)
13,469
Depreciation charges decreased by 10% from US$130.7 million for the year ended December 31, 2024, to US$117.2 million for the year ended December 31, 2025, primarily due to lower production in Colombia, mainly in the Llanos 34 Block, in addition to the divestment of the Manati gas field in Brazil, and the Perico and the Espejo Blocks in Ecuador. These factors were partially offset by the incorporation of the Loma Jarillosa Este and Puesto Silva Oeste Blocks in Argentina.
155,710
298,158
(142,448)
(8,224)
(5,052)
(3,172)
6,147
(7,159)
13,306
(186)
(30,542)
(1,102)
(29,440)
2,672
(116)
116
(12,548)
(11,183)
(1,365)
(163,003)
We recorded an operating profit of US$110.5 million for the year ended December 31, 2025, compared to US$273.5 million for the year ended December 31, 2024, as a result of the reasons described above.
In 2025, we recorded write-offs of unsuccessful exploration efforts of US$13.4 million, which corresponded to one exploratory well drilled in the PUT-8 Block in Colombia and other exploration costs incurred in previous years in the Putumayo Basin in Colombia. In 2024, we recorded write-offs of unsuccessful exploration efforts of US$14.8 million, which corresponded to two exploratory wells drilled in the CPO-5 Block in Colombia and two exploratory wells drilled in the Espejo Block in Ecuador.
During 2025, we also recognized an impairment loss of US$31.0 million in the Perico and Espejo Blocks due to the known selling price of the related net assets in the context of their divestment transaction.
In addition, during 2025 we incurred one-off termination costs of US$7.7 million in connection with cost efficiency measures implemented during the year.
Net financial expense was US$54.6 million for the year ended December 31, 2025, compared to US$43.5 million for the year ended December 31, 2024. The increase was mainly driven by higher recurring interest expense associated with the Notes due 2030 issued in early 2025, which bear an interest rate of 8.75%. Interest expense and amortization of debt issue costs totaled US$49.3 million in 2025, compared to US$31.1 million in 2024. Net financial expense also included a one-off non-cash charge of US$6.2 million related to the accelerated amortization of deferred issuance costs associated with the Notes due 2027 which were partially repurchased in January 2025, partially offset by a one-off gain of US$10.2 million from the repurchase of Notes due 2030 below par value between June and October 2025. For further information
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about these transactions, please see “Item 4. Information on the Company—A. History and development of the company—Funding”.
Foreign exchange loss was US$7.3 million for the year ended December 31, 2025, compared to a foreign exchange gain of US$12.2 million for the year ended December 31, 2024. In both years, these results mainly reflected the impact of fluctuations in the Colombian peso on liabilities denominated in local currency, including income tax payable, provisions for asset retirement obligations and other environmental liabilities, as well as lease liabilities. The Colombian Peso revalued by 15% in 2025 and devalued by 15% in 2024. This loss was partially offset by currency risk management gains of US$3.2 million recognized during the year.
141,604
302,277
(160,673)
(3,982)
(4,202)
220
7,202
(9,620)
16,822
(175)
(30,815)
(1,506)
(29,309)
1,946
(82)
(65,358)
(44,696)
(20,662)
(193,520)
For the year ended December 31, 2025, we recorded a profit before income tax of US$48.7 million, compared to a profit of US$242.2 million for the year ended December 31, 2024, primarily due to the reasons mentioned above.
(10,327)
(141,525)
131,198
(93)
10,838
(1,287)
(1,041)
423
(173)
(2,686)
2,513
1,965
(1,335)
3,300
(247)
146,808
Our consolidated effective tax rate was (2)% for the year ended December 31, 2025, compared to 60% in 2024, primarily reflecting a lower profit before income tax for the year, the impact of the revaluation of the Colombian peso on the tax bases of property, plant and equipment, the recognition of deferred tax assets related to previously unrecognized tax loss carryforwards in Argentina, which became recoverable as a result of the acquisition in the Vaca Muerta formation, and the reversal of deferred tax liabilities in Spain following the relocation of GeoPark Colombia S.L.U. from Madrid to Bizkaia (Basque Country) in 2025.
In 2025 and 2024, the statutory income tax rate in Colombia was 35%, though a tax surcharge is also applicable, impacting companies engaged in the extraction of crude oil like GeoPark. The tax surcharge varies from zero to 15%, depending on different Brent oil prices. The applicable surcharge for 2025 and 2024 was 0% and 10%, respectively.
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131,277
160,752
(29,475)
6,856
11,058
(263)
5,915
(9,866)
15,781
(30,988)
(4,192)
(26,796)
639
(63,393)
(46,031)
(17,362)
(46,712)
For the year ended December 31, 2025, we recorded a net profit of US$49.7 million as a result of the reasons described above, compared to a net profit of US$96.4 million for the year ended December 31, 2024.
Year ended December 31, 2024, compared to year ended December 31, 2023
For a discussion of the results of our operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2024, compared to the year ended December 31, 2023” in our Annual Report on Form 20-F for the year ended December 31, 2024.
B. Liquidity and capital resources
Overview
Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including changes in oil and natural gas prices and our ability to generate cash flows from our operations, our capital expenditure requirements, the level of our outstanding indebtedness and the interest we have to pay on this indebtedness, and changes in exchange rates which will impact our generation of cash flows from operations when measured in US$.
We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all.
Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash generated by our operations. We have also in the past entered into offtake and prepayment agreements. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.”
We believe that our current operations and 2026 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, oil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the Company—B. Business Overview— Our business strategy.”
Capital expenditures
In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview— Our business strategy”.
In the year ended December 31, 2025, we had total capital expenditures related to the purchase of property, plant and equipment of US$98.4 million (US$96.7 million, US$1.4 million, US$0.1 million and US$0.2 million, in Colombia, Argentina, Brazil and Ecuador, respectively).
In the year ended December 31, 2024, we had total capital expenditures related to the purchase of property, plant and equipment of US$191.3 million (US$167.0 million and US$24.1 million in Colombia and Ecuador, respectively).
Cash flows
The following table sets forth our cash flows for the periods indicated:
Cash flows from (used in)
Operating activities
14,705
471,031
300,938
Investing activities
(155,495)
(226,855)
(198,590)
Financing activities
(36,122)
(99,240)
(98,721)
Net (decrease) increase in cash and cash equivalents
(176,912)
144,936
3,627
Cash flows from operating activities
For the year ended December 31, 2025, cash flows from operating activities were US$14.7 million compared to US$471.0 million for the year ended December 31, 2024. This variation was mainly from the repayment in 2025 of most of the oil sales prepayment of US$152 million drawn from the offtake and prepayment agreement with Vitol in November 2024, in addition to higher income tax for the year 2024 paid in 2025 and lower revenues reflecting lower deliveries and oil and gas prices in 2025.
For the year ended December 31, 2024, cash flows from operating activities were US$471.0 million, a 57% increase from US$300.9 million for the year ended December 31, 2023, mainly resulting from an oil sales prepayment of US$152 million drawn from the offtake and prepayment agreement with Vitol in November 2024, as well as lower income tax paid, which was driven by: i) a decrease in the accrual of income taxes for the year 2023 to be paid in 2024 (due to lower taxable results in 2023, as compared to 2022), and ii) a reduction of the rates of self-withholding taxes and withholding taxes from clients applicable to companies engaged in the extraction of crude oil like GeoPark. Those effects were partially offset by lower operating results from operations.
Cash flows used in investing activities
For the year ended December 31, 2025, cash flows used in investing activities were US$155.5 million, a 31% decrease from US$226.9 million for the year ended December 31, 2024. This decrease primarily reflected lower capital expenditures in Colombia and Ecuador, the reimbursement of the US$38 million advance payment made in 2024 for the Unconsummated transaction in Argentina (Vaca Muerta), and the proceeds from divestments executed during the year. These effects were partially offset by the payment of US$115.5 million for the Acquisition in Argentina’s Vaca Muerta Formation.
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For the year ended December 31, 2024, cash flows used in investing activities were US$226.9 million, a 14% increase from US$198.6 million for the year ended December 31, 2023. This variation is primarily explained by the advance payment of US$38 million for the Unconsumated transaction in Argentina (Vaca Muerta) in May 2024.
Cash flows used in financing activities
Cash flows used in financing activities were US$36.1 million for the year ended December 31, 2025, compared to US$99.2 million used in financing activities for the year ended December 31, 2024. This decrease primarily reflected the absence of significant repurchase of own common shares in 2025 compared to 2024, lower dividends distributed and lower lease payments during the year, as well as the impact of liability management transactions carried out in 2025, which included the issuance of US$550.0 million aggregate principal amount of Notes due 2030, bearing an interest rate of 8.75%, the repurchase of US$405.3 million aggregate principal amount of Notes due 2027, which bore an interest rate of 5.5%, both in early 2025, and the repurchase of US$108.3 million aggregate principal amount of Notes due 2030 between June and October 2025. While these transactions reduced near-term refinancing risk and improved liquidity, they also resulted in higher recurring interest expense due to the higher coupon on the Notes due 2030.
Cash flows used in financing activities were US$99.2 million for the year ended December 31, 2024, compared to US$98.7 million used in financing activities for the year ended December 31, 2023. This variation was mainly related to higher repurchase of own common shares, partially offset by proceeds from a short-term financial loan granted in Argentina and lower lease payments.
Indebtedness
As of December 31, 2025, and 2024, we had total outstanding indebtedness of US$553.5 million and US$514.3 million, respectively, as set forth in the table below.
Notes due 2030
454,305
Notes due 2027
96,242
504,535
Local debt in Colombia
3,000
Local debt in Argentina
9,798
553,547
514,333
Our outstanding indebtedness as of December 31, 2025 is described below.
In January 2025, we issued US$550.0 million aggregate principal amount of 8.75% senior notes due 2030 (the “Notes due 2030”). We used the net proceeds of the offering to repurchase a portion of our Notes due 2027 for a nominal amount of US$405.3 million through a concurrent tender offer, to partially repay the prepayment drawn from the offtake and prepayment agreement with Vitol, and the remainder for general corporate purposes, including capital expenditures. This transaction improved our financial profile by extending our debt maturities.
Ranking
The Notes due 2030 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U., GeoPark Colombia S.A.S and GeoPark Argentina S.A. (the “Guarantors”). The Notes due 2030 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantors (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of
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payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantors; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantors and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
Optional redemption
We may, at our option, redeem all or part of the Notes due 2030, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 31 of the years indicated below:
Year
Percentage
2027
104.375
2028
102.188
2029 and after
100.000
Change of control
Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2030, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2030 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2030 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption.
Covenants
The indenture governing the Notes due 2030 includes incurrence test covenants that provide, among other things, that the Net Debt to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes due 2030. Incurrence covenants as opposed to maintenance covenants must be tested before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others.
Events of default
Events of default under the indentures governing the Notes due 2030 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2030; cross payment default relating to debt with a principal amount of US$50.0 million or more, and cross-acceleration default following a judgment for US$50.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2030 to become or to be declared due and payable.
In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. Final maturity will be January 17, 2027. On January 31, 2025, we repurchased a portion of our Notes due 2027 for a nominal amount of US$405.3 million through a concurrent tender offer.
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The Notes due 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U. (the “Guarantor”). The Notes due 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantor (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantor; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantor and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
We had the option to redeem all or part of the Notes due 2027 at their principal amount plus accrued and unpaid interest thereon (including additional amounts), if any, beginning on January 17, 2026; however, we did not exercise this option.
Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2027, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2027 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2027 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption.
The Notes due 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company.
In the event the Notes due 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable.
The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to Adjusted EBITDA ratio should not exceed 3.25 and the Adjusted EBITDA to interest ratio should exceed 2.5. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions).
Events of default under the indentures governing the Notes due 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of
96
default would permit or require the principal of and accrued interest on the Notes due 2027 to become or to be declared due and payable.
Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31, 2025, or as of December 31, 2024.
C. Research and development, patents and licenses, etc.
See “Item 4. Information on the Company—B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to properties.”
D. Trend information
For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company—B. Business Overview— Our business strategy.”
E. Critical accounting policies and estimates
A.Directors and executive officers
Board of directors
Our board of directors is currently composed of nine members. Our directors are elected by shareholders annually at the Company’s annual general meeting and can hold office for such term as the shareholders may determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. The term for the current directors expires on the date of our next annual general meeting of shareholders to be held in 2026.
The current members of the board of directors were appointed at our annual general meeting held on August 6, 2025, except for Gabriel Gilinski, who was appointed to our board of directors on March 8, 2026 to fill an existing vacancy. The table below sets forth certain information concerning our current board of directors. All ages are current as of March 31, 2026.
At the Company
Name
Position
Age
since
Sylvia Escovar (1)
Chair and Director
2020
James F. Park
Deputy Chair, Director and Co-founder
2002
Robert A. Bedingfield (1)(2)
Director
2015
Constantin Papadimitriou (1)(2)
2018
Brian F. Maxted (1)
Carlos E. Macellari (1)(2)
Marcela Vaca (1)
2012
Gabriel Gilinski
2026
Felipe Bayon
Chief Executive Officer and Director
Biographical information of the current members of our board of directors is set forth below. Unless otherwise indicated, the current business address for our directors is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Sylvia Escovar has been a member of our board of directors since August 2020 and was appointed as Chair on June 6, 2021. She is one of the most respected and admired business leaders in Latin America. An economist by training she has had a long and prestigious career in both the public and private sectors, having worked for the World Bank, the Central Bank of Colombia and the Colombian National Department of Planning. Previously, she served as Deputy Secretary of Education and Deputy Secretary of Finance for Bogota’s government as well as Vice President of Finance of Fiduciaria Bancolombia. Ms. Escovar was CEO of Organización Terpel S.A., the leading fuel distribution company in Colombia that operates also in Panama, Peru and the Dominican Republic from 2012 until December 2020. In 2014, Sylvia was named the top businessperson of the year by Portafolio, Colombia’s leading financial daily. In 2018, she received the National Order of Merit for spearheading private sector support for peacebuilding and reconciliation in Colombia. In 2020, she was the only woman on the Corporate Reputation Business Monitor’s list of Colombian leaders with the best reputation to rank in the top 10. Sylvia’s other board memberships include Organización Terpel S.A., Grupo Bancolombia, Empresa de Telecomunicaciones de Bogotá S.A. E.S.P., Grupo Energía Bogotá S.A. E.S.P. and Organización Corona S.A.. Sylvia has a bachelor’s degree in economics from the Universidad de los Andes in Colombia.
James F. Park co-founded the Company in 2002, and served for 20 years as our Chief Executive Officer until his retirement effective 30 June 2022, and has been a member of our board of directors since May 2002. He founded, built the team, and led the strategy and growth of GeoPark from its small footprint at the southern tip of South America into becoming one of the leading oil and gas companies operating across Latin America today. He continues to serve as Vice Chairman of our board of directors, Chair of the Strategy and Risk Committee and a member of the Technical and
SPEED/Sustainability Committees.Mr. Park has more than 50 years of experience in all phases of the upstream oil and gas business, with a record of achievement in the acquisition, technical operation, and management of international projects and teams across the globe - including projects in North America, Central America, South America, Asia, Europe, Africa, and the Middle East - with focus on people, communities, and the environment. He earned a Bachelor of Science in Geophysics from the University of California at Berkeley and previously worked as a research scientist focused on earthquakes and tectonics at the Geophysics Laboratory of the University of Texas. Mr. Park has a degree in environmental management from the University of California at Santa Barbara and is a member of the board of directors of GoodRock LLC. He is a former board member of the humanitarian non-profit SEE (Surgical Eye Expeditions) International, and the service and advocacy non-profit Girls, Inc. He is a member of the AAPG and SPE, and has lived in Latin America since 2002.
Robert A. Bedingfield has been a member of our board of directors since March 2015. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies, including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. From 2013 to 2023, Mr. Bedingfield served as board member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). Robert holds a degree in Accounting from the University of Maryland and is a Certified Public Accountant.
Constantin Papadimitriou has been a member of our board of directors since May 2018. He is a respected and successful international investor and businessman, with more than 30 years of investment experience in global capital markets and in resource and industrial projects and was an early investor in GeoPark. Mr. Papadimitriou was for 18 years the Head of General Oriental Investments S.A., the Investment Manager of the Cavenham Funds, as part of the Cavamont Group founded by the Late Sir James Goldsmith. During his tenure at the Cavamont group, Mr. Papadimitriou was initially CFO, then Head of the Private Equity Portfolio representing the group on the boards of associated companies including investments in the oil and gas, mining, real estate, and gaming sectors (including Basic Petroleum, a Nasdaq-listed Guatemalan oil and gas company). He is now a founding partner of Diorasis International, a company mainly focusing on investments in Aquaculture, and also chairs the Greek Language School of Geneva and Lausanne. Mr. Papadimitriou is currently a non-executive board member of Cavamont Holdings Limited, Capland S.A. and Tellco AG. Constantin holds an Economics and Finance degree and a post-graduate Diploma in European Studies from Geneva University.
Brian F. Maxted has been a member of our board of directors since July 2022. He is a proven oil and gas explorer, private equity entrepreneur and public company leader in the upstream E&P business, with a global track record of significant basin and play discoveries over 30 years. He spent the first part of his professional life from the late 1970s working for BP in locations including Europe, Africa, North America and South America, where he was involved in the discovery of Colombia’s giant Cusiana and Cupiagua oil fields in the early 1990s. During the second half of his career from the mid-1990s through the 2010s Mr. Maxted held various exploration leadership roles for US-based independents, including Triton Energy and Hess Corporation. In 2003, Mr. Maxted became a founding partner and later the CEO/CXO and Board Director of Kosmos Energy. Mr. Maxted retired from Kosmos in 2019 and established Limatus Energy Advisory Limited to provide strategic counsel to upstream E&P companies. In addition, he led the formation of Lapis Energy – now Lapis Carbon Solutions Holdings LP, a company focused on carbon solutions in the US Lower 48, where he currently serves as Chair of the Board. Mr. Maxted is also a member of the board of directors of Triple 7 Energy Inc. Brian holds a bachelor’s degree in geology from the University of Sheffield and a master’s degree in organic geochemistry and petrology from the University of Newcastle-upon-Tyne.
Carlos E. Macellari has served as a member of our board of directors since July 2022. Dr. Macellari has more than 35 years of experience in oil and gas exploration, development and operations across South America, North America, Europe and Africa. He has held senior technical and executive positions at Tecpetrol, Repsol, Hocol, Benton Oil & Gas, Enron Oil & Gas International and Shell. As Director of Exploration and Development at Tecpetrol, he led the subsurface team responsible for the development of Fortín de Piedra, the largest gas-producing field in Argentina, and for the
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discovery and development of multiple oil fields in Colombia. At Repsol, he served as Worldwide Director of Geology, leading exploration activities resulting in significant discoveries in Libya, Algeria, Brazil (Pre-Salt), the Gulf of Mexico, Venezuela and Peru. Dr. Macellari has authored more than 50 technical publications and has lectured internationally. He is the founder of the Journal of South American Earth Sciences and currently serves as professor for postgraduate studies at Universidad Nacional de La Plata and as President of AAPG Latin America. He previously served on the boards of several companies within the Techint Group and currently serves as an independent director of Olympic Peru Inc. He is also the founder and managing director of Andes Energy Consulting. Carlos holds a bachelor’s degree in geology from the Universidad Nacional de La Plata in Argentina, and a master’s degree and a PhD in geology from Ohio State University.
Marcela Vaca has been a member of our board since July 2022, following ten years of distinguished service as the Company’s General Director and Chief Asset Officer (2012–2022). With over 20 years of experience in the oil and gas industry across Latin America, Ms. Vaca brings deep knowledge of the Company’s operations, strategy, and values. As General Director, she led GeoPark’s growth into one of Colombia’s leading independent E&P companies, with a strong focus on operational efficiency, ESG performance, and stakeholder engagement. She has played a central role in advancing the Company’s diversity and inclusion agenda and continues to promote female leadership as a driver of long-term value. Prior to joining GeoPark, Ms. Vaca was President of the Hupecol Group, where she led major field developments and executed key M&A transactions. She also served in senior legal and corporate affairs roles at GHK Company Colombia. She chaired the board of the Colombian Oil Association (ACP) and was a board member from 2010 to 2021. She is a Certified Corporate Director both in Colombia (Instituto Colombiano de Gobierno Corporativo) and in the United States (Harvard Business School), and currently serves on the boards of Corficolombiana, Fundación Juanfe, and Women in Connection. Marcela holds a Law degree with a specialization in Commercial Law, both from Pontificia Universidad Javeriana in Colombia, and an LL.M. Summa Cum Laude from Georgetown University as a Fulbright Scholar.
Gabriel Gilinski has been a member of our board since March 2026. He is a senior executive within the Gilinski Group and brings deep experience in financial services, banking and board-level governance, with a track record supporting the Group’s growth initiatives and portfolio expansion through hands-on involvement and strategic oversight across its businesses. He has been Director of JGB Financial Holdco Inc. since 2010 and has served on the boards of Banco GNB Paraguay (2013–2025), Banco GNB Perú (2013–2022), Banco GNB Sudameris S.A. in Colombia (2018–2022), and Corporación Financiera GNB Sudameris (2019–2022). He has also served as a board member of Grupo Nutresa S.A. since 2022 and was previously a board member of Grupo Sura S.A. (2022–2024). Earlier in his career, he served as Executive Vice President of JGB Bank (2008–2010) and worked as a financial consultant at The Boston Consulting Group in Santiago, Chile. Mr. Gilinski holds a bachelor’s degree from the University of Pennsylvania.
Felipe Bayon has served as our Chief Executive Officer and as a member of our board of directors since June 2025. Mr. Bayon is recognized as one of the most effective energy executives in Latin America with more than three decades of accomplishments in the international oil and gas industry. From 2017 to 2023, Mr. Bayon was CEO of Ecopetrol S.A. (NYSE:EC), one of the most important energy groups in Latin America, where he led 18,000 employees, oversaw production of approximately 700,000 boepd and revenues of over US$30 billion, and delivered record financial, operational, and safety results. He is a proven and disciplined dealmaker who brought Ecopetrol S.A. into the unconventional Permian Basin in the United States in partnership with Occidental Petroleum Corp., a project that grew from 0 to 150,000 bpd gross in 4 years, into the Brazilian ultra-deep water pre-salt play in partnership with Shell, as well as into a leading position in the Latin American power transmission sector and focused investments in renewable energies, water management, and nature-based climate solutions.
Mr. Bayon is a mechanical engineer who began his career in 1991 with Shell in field operations and projects, and then moved to BP where he worked for 21 years in increasingly important operational and management roles in Colombia, Argentina, Brazil, Bolivia, the United States and the United Kingdom, including his tenure as CEO of Pan American Energy, one of the leading private hydrocarbon producers in Argentina, from 2005 to 2010. Mr. Bayon has served on multiple boards of directors across the energy, utilities, education, and technology sectors.
Executive officers
Our executive officers are responsible for the management and representation of our company. The table below sets forth certain information concerning our current executive officers. All ages are current as of March 31, 2026.
Jaime Caballero Uribe
Chief Financial Officer
Rodrigo Dalle Fiore
Chief Exploration and Development Officer
Martín Terrado
Chief Operations Officer
Agustina Wisky
Chief People Officer
Biographical information of our executive officers is set forth below. Unless otherwise indicated, the current business address of our executive officers is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Jaime Caballero Uribe has served as our Chief Financial Officer since January 2024. He has more than 25 years of industry and finance experience, including senior positions in large corporations as well as in start-ups and entrepreneurial businesses. Until August 2023, Mr. Caballero was Group CFO at Ecopetrol, the largest corporation in Colombia and one of the 400 largest companies in the world where he helped the management team achieve various performance records, including the delivery of more than US$20 billion in growth financing and debt refinance. During his tenure, he was recognized by the Institutional Investor publication as one of the top three sector CFOs in Latin America. Previously, he held multiple positions at BP plc over 17 years, where his most recent appointment was CFO for the Brazil Region, which includes Colombia, Uruguay and Venezuela. Mr. Caballero holds a degree in Law from Universidad de Los Andes, an MBA in Energy Business from Fundação Getulio Vargas, and certificates in CFO Excellence from Wharton and Energy Innovation and Emerging Technologies from Stanford. Mr. Caballero currently serves as a board member of Agricola Cerro Prieto S.A.
Rodrigo Dalle Fiore has served as our Chief Exploration and Development Officer since February 2025. He has worked in the oil and gas industry in Latin America for over 20 years. Since joining the Company in 2023 as Inorganic Growth, Unconventional & Portfolio Director he has been key in identifying and materializing strategic opportunities for the Company, the most important of which was the Company’s entry into Vaca Muerta, the fastest growing play in Latin America today. Prior to joining GeoPark, in his capacity as New Energies Corporate Manager at Ecopetrol, Mr. Dalle Fiore was responsible for positioning the group as a regional leader in the energy transition, and he was also on the board of directors of Ecopetrol E&P’s international subsidiaries in the Permian basin, Gulf of Mexico and offshore Brazil. His earlier positions at Ecopetrol were Corporate VP of Development and Enhanced Recovery Development Manager. Mr. Dalle Fiore began his career at Pan American Energy as a well and facilities operator before eventually becoming Operations Manager at the Cerro Dragon field. A Chemical Engineer from the University of Cordoba in Argentina, he holds a Global Executive MBA from IESE Business School, a specialization in Oil and Gas Reservoirs from the Faculty of Natural Sciences at the Patagonia San Juan Bosco University in Argentina, and a specialization in Oil and Gas Technology from the Technological Institute of Buenos Aires (ITBA).
Martín Terrado has served as our Chief Operations Officer since July 2022. He previously served as our Director of Operations since he joined GeoPark in August 2018. Mr. Terrado has more than 29 years of experience in the oil industry and has held leadership roles in asset development, operations and planning. Prior to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San Jorge and Chevron in different international operations, including Argentina, the United States and Venezuela. He led Chevron technical and operations teams of heavy oil assets in eastern and western Venezuela with production of 160,000 and 100,000 bopd respectively. Prior responsibilities include waterflooding, CO2 flooding and setting up Chevron’s operated unconventional Wolfcamp program in Midland, TX. Mr. Terrado has a degree in Petroleum Engineering from the Instituto Tecnológico de Buenos Aires (ITBA) and an MBA from the IAE Business School at the Universidad Austral in Buenos Aires. He is an active member and mentor at the Society of Petroleum Engineers (SPE) and is President of the board of Arpel. Mr. Terrado has published several papers at SPE and has US Patent #8175751 on EOR/IOR screening and performance prediction systems.
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Agustina Wisky is GeoPark’s Chief People Officer, responsible for enriching and promoting an organizational culture based on trust, teamwork, continuous improvement, mutual respect, and diversity. Mrs. Wisky has been with the Company since it was founded in 2002, and she created and has led the People department for over 15 years, guided by the principles of attracting, motivating and developing the best professionals, and ensuring the comprehensive wellbeing of staff and their families. She previously held the position of Performance Director at GeoPark. Before joining GeoPark, Mrs. Wisky worked at PricewaterhouseCoopers and AES Gener in Argentina. Mrs. Wisky is a Public Accountant and has a master’s degree in Human Resources from the IAE Business School of the Universidad Austral in Buenos Aires, Argentina. Thanks to Mrs. Wisky’s leadership in the implementation of inclusion and diversity best practices, GeoPark won the Equipares Silver Award in 2020, which is given by the Government of Colombia with technical support from the United Nations Development Program. GeoPark was also included in the Bloomberg Gender-Equality Index (GEI) in 2022, which evaluates the performance of listed companies that are committed to transparency in gender reporting.
B. Compensation
Executive officers and director compensation
For the year ended December 31, 2025, we paid an aggregate of US$1.6 million to the non-employee members of our board of directors for their services in all capacities. This does not include payments made to executive directors Mr. Andrés Ocampo (who served as Chief Executive Officer until May 31, 2025) and Mr. Felipe Bayon (who served as Chief Executive Officer since June 1, 2025), as they only received compensation in their capacity as executive officers (as described below). Disclosure of compensation on an individual basis is included in Note 10 to our Consolidated Financial Statement.
During this same period, we paid an aggregate of US$10.9 million for salaries and other benefits (including with respect to one-off severance and hiring payments related executive management changes during the year, grants of awards under the LTIP Executives and contingent amounts or deferred compensation accrued for the year, even if payable at a later date) to the executive officers of the Company for their services in all capacities.
Annual Bonus Program
Our Corporate Governance Guidelines set forth that the Compensation Committee will evaluate annually the performance of the Chief Executive Officer and the other executive officers of the Company based on objective and relevant corporate goals and that the independent members of the board of directors, in consultation with and at the recommendation of the Compensation Committee will review executive officers’ annual performance evaluations. In addition, the charter of the Compensation Committee establishes that the Committee shall review and approve written annual and longer-term corporate goals and objectives relevant to the compensation of the Chief Executive Officer and other executive officers, making sure that they are appropriately linked to the Company’s strategy.
In this regard, the Compensation Committee reviews and approves the annual performance scorecard that contains the performance metrics and objective criteria against which the Chief Executive Officer and the other executive officers are evaluated. Depending on the performance evaluation, the amounts to be paid to the Chief Executive Officer and the other executive officers as annual bonuses are recommended by the Committee and submitted to be approved by the independent members of our board of directors. The total bonus amount approved on March 2, 2026, based on a 2025 Scorecard result of 110%, amounts to US$2.7 million.
CEO Appointment
On April 2025, the board of directors selected and approved Felipe Bayon as the new Chief Executive Officer and a member of the board of directors of the Company, effective on June 1, 2025. This appointment follows the decision of Andrés Ocampo to step down for personal reasons.
Former CEO Severance Agreement
In connection with his departure from GeoPark in May 2025, Andrés Ocampo received certain severance benefits, including (i) cash severance payments, (ii) accelerated vesting of his outstanding and unvested restricted stock units (“RSUs”), (iii) continued vesting of his outstanding and unvested performance stock units (“PSUs”), (iv) 12 months of expatriate benefits and reimbursement for reasonable relocation costs and (v) 12 months of health insurance.
Former CEO Consultant Agreement
Mr. James F. Park, our former Chief Executive Officer and current non-executive member of the board of directors and a consultant of the Company, advising on M&A and strategic matters has a consulting agreement with the Company, which was approved by the board of directors. Such agreement governs his consulting services and does not provide for payments upon a termination of service (other than previously earned or accrued amounts).
Senior Management Severance
Our board of directors determined that it is in the best interests of the Company and its shareholders to provide certain members of the Company’s senior management with payments and benefits in connection with certain qualified terminations and/or in connection with certain change in control scenarios. Therefore, the board of directors approved the adoption of an Executive Termination and Change in Control Benefits Plan (the “Severance Plan”). In addition, the board of directors approved an employment agreement with our current Chief Executive Officer, Felipe Bayon, which provides for severance benefits consistent with those provided under the Severance Plan.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control, the executive will be entitled to receive the following, subject to the execution of a release of claims: (i) cash severance in an amount equal to two times the sum of (a) the executive’s annual base salary, (b) the average of any cash bonuses paid in the two years preceding the termination date (for any year in which the executive did not receive an annual bonus in their current executive role, the executive’s target annual bonus for that year is used) and (c) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000; provided that the executive will be entitled to receive the foregoing severance benefits within 30 days following the consummation of a change in control if the change in control results from an unsolicited offer in response to which the board recommends rejection of the offer and continues to recommend rejection of the offer until the closing date of the change in control and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following the executive’s termination of employment. In addition, the Severance Plan provides that, in the event an executive has relocated at the Company’s request, the executive’s ex-pat benefits will be continued for a minimum of 12 months following the change in control.
Pursuant to the Severance Plan, in the event of a change in control, outstanding performance equity awards will convert into time-based equity awards based on actual performance through the date of the change in control and, except as set forth below, will vest in accordance with the awards’ original schedule, subject to the executive’s continued service through such date. In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control: (i) all outstanding time-vesting equity awards will fully accelerate and vest; and (ii) performance equity awards, as converted in accordance with clause (i) above, will fully accelerate and vest. In the event that the acquiror cashes out outstanding equity awards at closing of the change in control, then, at closing, (i) performance awards will accelerate, and vest based on actual performance through the date of the change in control and (ii) all outstanding time-vesting equity awards will fully accelerate and vest.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability, other than within the 24 months following a change in control, then, subject to the execution of a release of claims, the executive will be entitled to the following benefits: (i) cash severance in an amount equal to 1.5 times (or, in the case of the Chief Executive Officer, 2 times) the sum of (a) the executive’s annual base salary, (b) the average of any cash bonuses paid in the two years preceding the termination and (c) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000, such aggregate severance amount in clauses (a) through (c)
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shall be paid in 2 equal semi-annual installments, and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of employment. In addition, the executive’s unvested equity awards will accelerate pro-rata (in the case of performance equity awards, subject to achievement of the applicable performance metrics).
Termination Plan for Employees
The plan aims to retain and attract employees by ensuring fair, transparent, and competitive treatment in the event of a termination without cause, reaffirming our commitment to employee care and long-term growth.
This plan applies to all direct employees. It does not apply to executive officers.
Upon termination without cause, the employee will be entitled to receive the following, subject to the execution and non-revocation of a release of claims in favor of the Company:
GeoPark Limited 2018 Equity Incentive Plan
Given the expiration of our Stock Awards Plan on November 3, 2018, on November 5, 2018, we adopted the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those participating employees and executives to perform at the highest level and to further the best interests of the Company and our shareholders. The Plan is designed as an omnibus plan, pursuant to which we may grant awards in the form of options, share appreciation rights, restricted shares, restricted stock units (“RSUs”), performance awards, other share-based awards or other cash-based awards. Subject to adjustment as set forth in the Plan, the maximum number of shares available for issuance under the Plan was initially set at 5,000,000 shares. In February, 2026, our board of directors approved the registration of 2,001,554 recycled shares to be available for awards granted under the Plan. The applicable award documentation will set forth the terms and conditions of the awards granted under the Plan, including, but not limited to, the vesting conditions and the effect on a termination of service or a change in control on awards.
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The following table sets forth the common share awards granted to our employees and executive officers under the Plan which are outstanding as of the date of this annual report:
Number of underlying common shares outstanding
Grant date
Vesting date
50,962 (1)
01/01/2020
01/02/2023
99,739 (2)
03/31/2022
03/31/2025
221,557 (3)
01/02/2026
105,000 (4)
(5)
351,971 (6)
02/14/2024
02/14/2027
287,656 (7)
02/14/2025
02/14/2028
200,000 (8)
11/20/2025
11/21/2028
1,500,000 (9)
02/01/2026
02/01/2029
494,546 (10)
03/24/2026
02/14/2029
On November 6, 2019, our board of directors approved a share-based compensation program for approximately 800,000 shares to be granted in 2020. Considering the level of achievement of performance conditions, the Compensation Committee determined that only a total of 152,030 shares vested. As of December 31, 2025, 101,068 shares have been exercised, with a remaining amount of 50,962 shares to be exercised.
Retention and Hiring Bonus scheme initially covering 215,000 shares. The vesting date was March 31, 2025, or 3 years from grant date. As of December 31, 2025, 89,739 vested shares remain outstanding pending exercise, and 10,000 additional shares remain subject to vesting in May 2027.
LTIP Employees approved in December 2022 initially covered 1,000,000 shares. The vesting date of the RSUs was annually during a three-year period and the vesting date of the PSUs was on January 2, 2026. On January 30, 2026, considering the level of achievement of performance conditions, the Compensation Committee determined that only a total of 221,557 shares have vested.
(4)
One-time Bonuses.
The vesting date is 3 years from each grant date, which ranges between May 2026 and May 2028.
LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2027.
LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2028.
Retention and Hiring Bonus scheme approved in March 2025 covering 200,000 shares. The vesting date is November 21, 2028, or 3 years from the grant date.
LTIP Employees approved in February 2026 covering 1,500,000 shares. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs is on January 2, 2029.
(10) LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2029.
Currently, we have the following incentive equity programs in place under the Plan: the Retention and Hiring Bonus Scheme, the Long-Term Incentive Program for Executives (“LTIP Executives”) and the Long-Term Incentive Program for Employees (“LTIP Employees”).
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Long-Term Incentive Program to Employees (“LTIP Employees”)
In February 2026, the Compensation Committee approved a new Long-Term Incentive program for employees and new hirings. The main characteristics of the program are:
Retention and Hiring Bonus Scheme
On March 4, 2025, our board of directors approved a pool of 200,000 shares oriented for retention of key employees and new hires bonuses. Awards are granted at hiring, upon promotion or as a form of special recognition. The vesting date is 3 years from the grant date. Employees must remain with the Group until the vesting date and achieve a minimum individual performance evaluation score of 2 (target).
Long-Term Incentive Program to Executive Officers (“LTIP Executives”)
In March 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new Long-Term Incentive program for the executive officers. Main characteristics of the program are:
In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated 571,984 total shares, to vest during a three-year period. On February 17, 2023, February 26, 2024, March 4, 2025, and March 24, 2026, the Compensation Committee approved new grants of 197,197, 351,971, 287,656 and 494,546 shares, respectively, to vest during a three-year period.
On January 25, 2023, February 26, 2024, March 25, 2025 and January 30, 2026, the Compensation Committee determined that 246,110, 86,602, 93,326 and 47,608 shares, respectively, should be delivered to the participants according to the abovementioned grants.
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Non-Executive Director Equity Incentive Plan
In August 2014, our board of directors adopted the Non-Executive Director Equity Incentive Plan in order to grant shares to non-executive directors as part of their compensation program for serving as directors (the “Non-Executive Director Plan”). The Non-Executive Director Plan was amended and restated in October 2016, when an additional 1,000,000 shares were registered as the maximum number of shares available to be issued under this plan. Moreover, the Non-Executive Director Plan was amended and restated for the second time by our board of directors on August 12, 2024, when an extension of the Non-Executive Director Plan for an additional period of 10 years was approved, and an additional 1,000,000 shares were registered to be issued under this plan. In accordance with the resolutions adopted by our board of directors on May 20, 2014, our non-executive directors are paid their quarterly fees in the form of equity awards granted under the Non-Executive Director Plan. Under the Non-Executive Director Plan, the compensation committee may award common shares, restricted share units and other share-based awards that may be denominated or payable in common shares or factors that influence the value of common shares.
Potential dilution resulting from Equity Incentive Compensation Plans
In accordance with the equity awards granted by the Company under its Stock Awards Program and the Plan, as of March 19, 2026, there were 1,105,940 outstanding shares that had been awarded but which had not yet vested, representing approximately 2% of the total issued share capital as of that date.
Stock Ownership Guidelines
In December 2022, to further align the interests of our executive officers with those of the Company’s shareholders, our board of directors approved minimum stock ownership guidelines applicable to the Company’s executive officers, as determined by the board of directors. Each such executive officer is required to hold, within five years after the adoption of the guidelines or, if later, within five years after becoming subject to the policy, a number of shares with an aggregate value of at least three times his or her annual base salary. Shares beneficially owned by the applicable officer or held in a family trust established by the applicable executive officer and shares underlying vested equity awards (which, in the case of stock options, are at- or in-the-money) are taken into account for purposes of determining compliance with these guidelines. Until an officer has met his or her ownership requirement, he or she is required to retain at least 50% of shares received from the vesting, settlement or exercise of equity awards (and which remain outstanding after tax withholding and payment of any applicable exercise price).
C. Board practices
Directors are expected to provide stewardship to promote the long-term success of the Company. They are expected to fulfill their fiduciary duties and duty of care in the best interests of the Company, considering the various needs of its stakeholders (shareholders, employees, communities, suppliers and clients), providing advice to and oversight of management’s activities. Within its responsibilities, the board of directors oversees the Company’s strategic planning, including the review and approval of the major strategic corporate goals; reviews and approves the Company’s financial statements and oversees the Company’s financial health; oversees systems and controls to assess and mitigate risks; determines core values, integrity and ethical standards; determines management and board remuneration and succession planning, among others. On December 23, 2020, and as amended from time to time (with the most recent amendment dated March 4, 2025), the board of directors adopted our Corporate Governance Guidelines (available at the Company’s website) to further regulate and enhance the board’s corporate governance structures and processes.
Board composition
Our bye-laws provide that the board of directors consist of a minimum of three board members or such other number as determined from time to time by board resolutions. On May 10, 2022, the board resolved to increase and fix the maximum number of board members to nine, effective as of July 14, 2022. Although the maximum number is currently set at nine, there were eight directors in office following Somit Varma’s resignation from the board and its committees on
January 19, 2026. On March 8, 2026, the board appointed Gabriel Gilinski to fill the resulting vacancy, effective immediately, bringing the number of directors currently in office to nine. According to our bye-laws the board of directors may fill such vacancy by resolution.
Committees of our board of directors
Our board of directors has established an Audit Committee, a Compensation Committee, a Nomination and Corporate Governance Committee, a Strategy and Risk Committee, a Technical Committee and a SPEED/Sustainability Committee. The composition and responsibilities of each board committee are described below. The Nomination and Corporate Governance Committee annually considers and recommends to the board of directors the membership and the chair of each board committee. Our board of directors may establish other committees to assist with its responsibilities.
Audit Committee
The Audit Committee is currently composed of three independent directors. The current members of the Audit Committee are Mr. Robert A. Bedingfield (who serves as Chairman of the committee), Mr. Constantin Papadimitriou and Mr. Carlos E. Macellari. Mr. Robert A. Bedingfield is regarded as audit committee financial expert. The Nomination and Corporate Governance Committee determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou and Mr. Carlos E. Macellari are independent, as such term is defined under SEC rules applicable to foreign private issuers.
The main purposes of the Audit Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board of directors in its oversight of: (i) the integrity of the Company’s financial statements and the company’s accounting and financial reporting processes and financial statement audits; (ii) the independent auditor’s performance, qualifications and independence; (iii) the Company’s compliance with legal and regulatory requirements and the Company’s ethical standards; (iv) the performance of the Company’s internal audit function; and (v) promote that the strategy of the Company aligns with the Company’s ethical standards.
Compensation Committee
The Compensation Committee is currently composed of four independent directors. The current members of the compensation committee are Mr. Constantin Papadimitriou (who serves as Chairman of the committee), Mr. Robert A. Bedingfield, Mr. Brian F. Maxted and Ms. Marcela Vaca.
The main purposes of the Compensation Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) evaluate and recommend for approval by the independent members of the board the remuneration, benefits and incentive compensation arrangements for the executive officers of the Company; (ii) implement and administer compensation related policies approved by the board of directors; (iii) establish performance indicators against which the executive officers of the Company will be evaluated; (iv) evaluate and review the identification, recruitment and succession planning for the executive officers of the Company; and (v) review and recommend to the board of directors any changes to the remuneration of the non-executive directors of the Company.
Nomination and Corporate Governance Committee
The Nomination and Corporate Governance Committee is currently composed of three independent directors. The current members of the Nomination and Corporate Governance Committee are Ms. Marcela Vaca (who serves as Chair of the committee), Ms. Sylvia Escovar and Mr. Robert A. Bedingfield.
The main purposes of the Nomination and Corporate Governance Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) review board of directors succession planning, including identifying and selecting suitable board of directors candidates in accordance with the criteria set forth in its charter and approved by the board of directors; (ii) review and recommend to the board of directors the membership and Chair of each board of directors committee; (iii) develop, review and monitor the Company’s corporate governance guidelines, processes and structures; and (iv) conduct and oversee the board of directors’ annual evaluation process.
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Strategy and Risk Committee
The Strategy and Risk Committee is currently composed of five directors. The current members of the Strategy and Risk Committee are Mr. James F. Park (who serves as Chairman of the committee), Mr. Constantin Papadimitriou, Mr. Brian F. Maxted, Mr. Carlos E. Macellari and Mr. Felipe Bayon.
The main purposes of the Strategy and Risk Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board of directors in (i) its oversight function of understanding the various key risks to which the Company is exposed, and the interlink between the Company’s strategy and such risks; and (ii) its review of new strategic opportunities and transactions (including mergers, acquisitions, divestments and similar transactions).
Technical Committee
The Technical Committee is currently composed of four directors. The current members of the Technical Committee are Mr. Brian F. Maxted (who serves as Chairman of the committee), Mr. Carlos E. Macellari, Mr. James F. Park and Mr. Felipe Bayon.
The main purposes of the Technical Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board of directors in fulfilling its responsibilities by providing strategic oversight on specific technical matters which are beyond the scope or expertise of non-technical board of directors members to: (i) optimize and assure technical decision making in existing assets to ensure business performance targets, as defined by the annual corporate scorecard, and long-range plan goals are achieved, including with respect to the design, execution and delivery of the exploration and appraisal strategy and plan, as well as the field development programs and drilling/production operations; (ii) review and advise the board of directors on the technical analysis of prospective new ventures and/or in conjunction with the Strategy and Risk Committee, potential corporate merger and acquisition opportunities, as and when required; (iii) review and recommend for board of directors’ approval the exploration, appraisal, and development projects for inclusion in the Company’s annual work program and budget. The Technical Committee will provide regular, timely feedback, guidance and support to the management team and technical staff on all sub-surface matters to facilitate the board of directors processes related to work programs and budget planning, execution and reporting, as well as people and business performance review; and (iv) review and analyze the annual report in relation to the Company’s oil reserves and recommend to the board of directors to approve its disclosure and publication.
SPEED/Sustainability Committee
The SPEED/Sustainability Committee is currently composed of four directors. The current members of the SPEED/Sustainability committee are Ms. Marcela Vaca (who serves as Chair of the committee), Ms. Sylvia Escovar, Mr. James F. Park and Mr. Felipe Bayon.
The main purposes of the SPEED/Sustainability Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board in (i) its guidance and oversight function of the Company’s strategy concerning the SPEED/Sustainability matters, representing an integrated value system which stands for including the safety of its operations, the initiatives to give back value and prosperity to stakeholders, the wellbeing of employees, preservation of the environment, community development, and any other matters related to sustainability; and (ii) its review of the performance on the topics above.
Liability insurance
We maintain liability insurance coverage for all of our directors and officers, the level of which is reviewed annually.
D. Employees
As of December 31, 2025, we had 382 employees, representing a decrease of 19.7% from December 31, 2024.
The following table sets forth a breakdown of our employees by geographic segment for the periods indicated.
339
448
412
382
476
470
From time to time, we also utilize the services of independent contractors to perform various field and other services as needed. As of December 31, 2025, four of our employees were represented by labor unions or covered by collective bargaining agreements. We believe that relations with our employees are satisfactory.
E. Share ownership
As of March 19, 2026, members of our board of directors and our executive officers held as a group 9,686,904 of our common shares and 15.0% of our outstanding share capital.
The following table shows the share ownership of each member of our board of directors and executive officers as of March 19, 2026.
Percentage of
outstanding
Shareholder
Common shares
common shares
James F. Park (1)
8,817,251
13.6
Sylvia Escovar
44,868
*
Robert A. Bedingfield
228,709
Constantin Papadimitriou
101,110
Brian F. Maxted
39,647
Carlos E. Macellari
53,296
Marcela Vaca
38,558
8,350
9,362
159,011
186,742
9,686,904
* Indicates ownership of less than 1% of outstanding common shares.
Certain members of our board of directors have, since the time of our initial public offering in the U.S., entered into certain pledges of Company securities in order to access some liquidity with respect to those shares and/or to diversify their holdings. Since June 2021, the Company has prohibited insiders from pledging Company securities in any circumstance, including by purchasing Company securities on margin or holding Company securities in a margin account. Exceptions may be granted by the board of directors on a case-by-case basis, provided that the proposed securities pledge is insignificant in respect of the Company’s market value, trading volume, total common shares outstanding of the Company, or any other consideration relevant in the board’s analysis, and shall be disclosed as required by law. The board may impose any reasonable conditions to meet these objectives.
F. Disclosure of a registrant’s action to recover erroneously awarded compensation
A. Major shareholders
The following table presents the beneficial ownership of our common shares as of March 19, 2026, except for certain shareholders whose most recent publicly available information is as of another date, as noted below. The percentages reported herein are based on the shares outstanding as of March 19, 2026.
Jaime Gilinski (1)
16,663,243
25.8
James F. Park (2)
Parex Resources Inc. (3)
6,085,086
9.4
Other shareholders
33,113,192
51.2
64,678,772
Principal shareholders do not have any different or special voting rights in comparison to any other common shareholder.
According to our transfer agent, as of March 19, 2026, we had 13 registered shareholders, out of which 5 are registered as U.S. shareholders. Since some of the shares are held by nominees, the number of shareholders may not be representative of the number of beneficial owners.
B. Related party transactions
We have entered into the following transactions with related parties:
Executive Directors’ Service Agreements
We have entered into service contracts with certain of our executive directors. See “Item 6. Directors, Senior Management and Employees—B. Compensation—Executive officers and director compensation—.”
For further information relating to our related party transactions and balances outstanding as of December 31, 2025, 2024 and 2023, please see Note 33 to our Consolidated Financial Statements.
C. Interests of Experts and Counsel
A. Consolidated statements and other financial information
See “Item 18. Financial Statements,” which contains our audited financial statements prepared in accordance with IFRS.
Legal proceedings
From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, civil, environmental, safety and health matters. For example, from time to time, we receive notice of environmental, health and safety violations. It is not presently possible to determine whether any such matters will have a material adverse effect on our consolidated financial position and results of operations.
Dividends and dividend policy
Holders of common shares will be entitled to receive dividends, if any, paid on the common shares.
On March 5, May 7, August 5 and November 5, 2025 the Company’s board of directors declared cash dividends of US$0.147, US$0.147, US$0.147 and US$0.03 per share, respectively, which were paid on March 31, June 5, September 4 and December 4, 2025.
Because we are a holding company with no direct operations, we will only be able to pay dividends from our available cash on hand and any funds we receive from our subsidiaries. The terms of our indebtedness may restrict us from paying dividends.
Under the Companies Act 1981, as amended of Bermuda (the “Bermuda Companies Act”), we may not declare or pay a dividend if there are reasonable grounds for believing that we are, or would after the payment be, unable to pay our liabilities as they become due or that the realizable value of our assets would thereafter be less than our liabilities. Under our bye-laws, each common share is entitled to dividends if, as and when dividends are declared by our board of directors, subject to any preferred dividend right of the holders of any preference shares, if any.
Additionally, any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors and our shareholders, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. See “Item 3. Key Information—D. Risk factors—Risks related to our common shares—Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors” and “—We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us,” as well as “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
B. Significant changes
A discussion of the significant changes in our business can be found under “Item 4. Information on the Company—B. Business Overview.”
A. Offering and listing details
B. Plan of distribution
C. Markets
Our common shares have been listed on the NYSE under the symbol “GPRK” since February 7, 2014.
D. Selling shareholders
E. Dilution
F. Expenses of the issue
A. Share capital
B. Memorandum of association and bye-laws
The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws.
We are an exempted company limited by shares incorporated under the laws of Bermuda. We are registered with the Registrar of Companies in Bermuda under registration number 33273. The rights of our shareholders will be governed by Bermuda law and by our memorandum of association and bye-laws. Bermuda company law differs in some material respects from the laws generally applicable to Delaware corporations. Below is a summary of some of those material differences.
Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and to our shareholders.
Share capital and bye-laws
Our share capital consists of common shares only. Our authorized share capital consists of 5,171,949,000 common shares of par value US$0.001 per share. As of March 19, 2026, there are 64,678,772 common shares outstanding. All of our issued and outstanding common shares are fully paid and non-assessable. We also have an employee incentive program (LTIP Employees and LTIP Executives), pursuant to which we have granted share awards to our executive officers and employees. See “Item 6. Directors, Senior Management and Employees.”
According to our bye-laws, if our share capital is divided into different classes of shares, the rights attached to any class (unless otherwise provided by the terms of issue of the shares of that class) may, whether or not the Company is being wound-up, be varied with the consent in writing of the holders of at least two-thirds of the issued shares of that class
or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least, in person or by proxy, holding or representing one-third of the issued shares of the class. The rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further shares ranking pari passu therewith.
Our bye-laws give our board of directors the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary.
On June 3, 2025, our board of directors authorized a new series of preferred shares designated as “Series A Preferred Shares” of par value US$0.001, in connection with the Company’s shareholder Rights Plan. Under the Rights Plan, one preferred share purchase right was distributed for each common share outstanding on June 13, 2025. Each right entitles the holder to purchase one one-hundredth of a Series A Preferred Share at an initial exercise price of US$36.00, subject to adjustment. The rights become exercisable if a person or group acquires 12% or more of the Company’s common shares without board of directors’ approval and may be redeemed by the Company at US$0.01 per right. No Series A Preferred Shares have been issued, and the adoption of the Rights Plan did not alter the Company’s issued or authorized share capital.
Furthermore, we entered into an SPA with Colden, by virue of which we agreed to terminate the Rights Plan on or prior to the 2026 anual meeting and not to adopt a shareholder rights plan or take similar measures in the future with the purpose of preventing Colden from (i) acquiring up to 32% of our outstanding common shares or (ii) making a tender offer for all of GeoPark Limited’s outstanding share capital. The SPA grants Colden certain board nomination rights and governance rights and subjects Colden to certain voting obligations. For a more detailed description of the SPA entered into with Colden, see “Item 4. Information on the Company—B. Business Overview—Recent Developments—Strategic Equity Investment by Grupo Gilinski.”
Holders of our common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Under our bye-laws, each common share is entitled to dividends, if, as and when dividends are declared by our board of directors, subject to any preferred dividend right of the holders of any preference shares, if any. Holders of common shares have no pre-emptive, redemption, conversion or sinking fund rights. In the event of our liquidation, dissolution or winding up the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.
Our bye-laws provide that the minimum number of directors shall be three or such other number as shall be determined from time to time by resolution of our board of directors. In addition, our bye-laws provide that our board of directors shall determine the maximum size of the board. As per the meeting of the board of directors of GeoPark Limited, which took place on May 10, 2022, the modification of the members of the board of directors was approved and it was determined that the maximum number of members will be nine. Therefore, the current number of members of the board is nine.
Election and removal of directors
Our bye-laws provide that our directors shall hold office for such term as the shareholders shall determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. Directors whose term has expired may offer themselves for re-election at each election of the directors.
A director may be removed by the shareholders at any special general meeting by a resolution adopted by 65% or more of the votes cast at the meeting, provided that notice of the shareholders meeting convened to remove the director is given to the director. The notice must contain a statement of the intention to remove the director and must be served on
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the director not less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the motion for his removal.
In addition, our bye-laws provide that our board of directors may remove a director only for cause by the affirmative vote of at least three-quarters of the board of directors, provided that notice of any such meeting convened for the purpose of removing a director shall contain a statement of the intention to remove the director and must be served on the director not less than fourteen days before the meeting. The director is entitled to attend the meeting and be heard on the motion for his removal.
Any vacancy created by the removal of a director at a special general meeting may be filled at that meeting by the election of another director in his or her place or, in the absence of any such election, by the board of directors. Any other vacancy, including a newly created directorship due to an increase in the maximum number of directors on our board, may be filled by our board of directors.
Proceedings of board of directors
Our bye-laws provide that our business is to be managed and conducted by our board of directors. Our board of directors may act by the affirmative vote of a majority of the directors present at a meeting at which a quorum is present. The quorum necessary for the transaction of business at meetings of the board of directors shall be the presence of a majority of the board of directors from time to time. Our bye-laws also provide that resolutions unanimously signed by all directors are valid as if they had been passed at a meeting of the board duly called and constituted.
Duties of directors
The Companies Act authorizes the directors of a company, subject to its bye-laws, to exercise all powers of the company except those that are required by the Companies Act or the company’s bye-laws to be exercised by the shareholders of the company. Our bye-laws provide that our business is to be managed and conducted by our board of directors. Under Bermuda common law, members of a board of directors owe a fiduciary duty to the Company to act in good faith in their dealings with or on behalf of the company, and to exercise their powers and fulfill the duties of their office honestly. This duty has the following essential elements: (1) a duty to act in good faith in the best interests of the company; (2) a duty not to make a personal profit from opportunities that arise from the office of director; (3) a duty to avoid conflicts of interest; and (4) a duty to exercise powers for the purpose for which such powers were intended. The Bermuda Companies Act also imposes a duty on directors (and officers) of a Bermuda company, to act honestly and in good faith, with a view to the best interests of the company, and to exercise the care, diligence and skill that a reasonably prudent person would exercise in comparable circumstances. In addition, the Companies Act imposes various duties on directors (and officers) of a company with respect to certain matters of management and administration of the company. Under Bermuda law, directors (and officers) generally owe fiduciary duties to the company itself, not to the company’s individual shareholders, creditors or any class thereof.
The Companies Act provides that in any proceedings for negligence, default, breach of duty or breach of trust against any director, if it appears to a court that such officer is or may be liable in respect of the negligence, default, breach of duty or breach of trust, but that he has acted honestly and reasonably, and that, having regard to all the circumstances of the case, including those connected with his appointment, he ought fairly to be excused for the negligence, default, breach of duty or breach of trust, that court may relieve him, either wholly or partly, from any liability on such terms as the court may think fit.
By comparison, under Delaware law, the business and affairs of a corporation are managed by or under the direction of its board of directors. In exercising their powers, directors are charged with a duty of care and a duty of loyalty. The duty of care requires that directors act in an informed and deliberate manner and to inform themselves, prior to making a business decision, of all relevant material information reasonably available to them. The duty of care also requires that directors exercise care in overseeing the conduct of corporate employees. The duty of loyalty is the duty to act in good faith, not out of self-interest, and in a manner which the director reasonably believes to be in the best interests of the shareholders. A party challenging the propriety of a decision of a board of directors bears the burden of rebutting the presumptions afforded to directors by the “business judgment rule.” If the presumption is not rebutted, the business
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judgment rule attaches to protect the directors and their decisions. Where, however, the presumption is rebutted, the directors bear the burden of demonstrating the fairness of the relevant transaction. Notwithstanding the foregoing, Delaware courts subject directors’ conduct to enhanced scrutiny in respect of defensive actions taken in response to a threat to corporate control and approval of a transaction resulting in a sale of control of the corporation.
Conflicts of Interest
Pursuant to our bye-laws, a director who directly or indirectly has an interest in a contract or proposed contract, arrangement or transaction involving the Company, or has any other interest that results or could potentially result, in a conflict with the best interests of the Company (a “Conflict Case”) shall declare the nature of such interest as required by the Companies Act. A director so interested shall not, except in particular circumstances set out in our bye-laws, be entitled to vote or be counted in the quorum in relation to a resolution of the directors or of a committee concerning a contract, arrangement, transaction or proposal to which the Company is or is to be a party and in which such director has a Conflict Case, which is to such director’s knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of the Company). A director will be liable to us for any secret profit realized from the transaction. In contrast, under Delaware law, such a contract or arrangement is voidable unless it is approved by a majority of disinterested directors or by a vote of shareholders, in each case if the material facts as to the interested director’s relationship or interests are disclosed or are known to the disinterested directors or shareholders, or such contract or arrangement is fair to the corporation as of the time it is approved or ratified. Additionally, such interested director could be held liable for a transaction in which such director derived an improper personal benefit.
Indemnification of directors and officers
Section 98 of the Companies Act provides generally that a Bermuda company may indemnify its directors, officers and auditors against any liability which by virtue of any rule of law would otherwise be imposed on them in respect of any negligence, default, breach of duty or breach of trust, except in cases where such liability arises from fraud or dishonesty of which such director, officer or auditor may be guilty in relation to the company. Section 98 further provides that a Bermuda company may indemnify its directors, officers and auditors against any liability incurred by them in defending any proceedings, whether civil or criminal, in which judgment is awarded in their favour or in which they are acquitted or granted relief by the Supreme Court of Bermuda pursuant to section 281 of the Companies Act.
We have adopted provisions in our bye-laws that provide that we shall indemnify our officers and directors in respect of their actions and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such director is not legally entitled. Our bye-laws provide that the shareholders waive all claims or rights of action that they might have, individually or in right of the company, against any of the company’s directors for any act or failure to act in the performance of such director’s duties, except in respect of any fraud or dishonesty of such director. Section 98A of the Companies Act permits us to purchase and maintain insurance for the benefit of any officer or director in respect of any loss or liability attaching to him in respect of any negligence, default, breach of duty or breach of trust, whether or not we may otherwise indemnify such officer or director. We have purchased and maintain a directors’ and officers’ liability policy for such a purpose.
Meetings of shareholders
Under Bermuda law, the company is required to convene at least one general meeting of shareholders each calendar year (the “annual general meeting”). However, the members may by resolution waive this requirement, either for a specific year or period of time, or indefinitely. When the requirement has been so waived, any member may, on notice to the company, terminate the waiver, in which case an annual general meeting must be called.
Bermuda law provides that a special general meeting of shareholders may be called by the board of directors of a company and must be called upon the request of shareholders holding not less than 10% of the paid-up capital of the company carrying the right to vote at general meetings. Bermuda law also requires that shareholders be given at least five days’ advance notice of a general meeting, but the accidental omission to give notice to any person does not invalidate the proceedings at a meeting.
Our bye-laws provide that our board of directors may convene an annual general meeting or a special general meeting. Under our bye-laws, not less than fifteen nor more than sixty days’ notice of an annual general meeting or a special general meeting must be given to each shareholder entitled to vote at such meeting. This notice requirement is subject to the ability to hold such meetings on shorter notice if such notice is agreed: (i) in the case of an annual general meeting by all of the shareholders entitled to attend and vote at such meeting; or (ii) in the case of a special general meeting by a majority in number of the shareholders entitled to attend and vote at the meeting holding not less than 95% in nominal value of the shares entitled to vote at such meeting. The quorum required for a general meeting of shareholders is two or more persons present in person and representing in person or by proxy in excess of 50% of the total issued voting shares in the Company throughout the meeting, provided that if the Company shall at any time have only one shareholder, one shareholder present in person or by proxy shall form the quorum. Unless otherwise required by law or by our bye-laws, shareholder action requires a resolution adopted by the affirmative votes of a majority of votes cast by shareholders at a general meeting at which a quorum is present.
Shareholder proposals
Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group composed of at least 100 shareholders may require a proposal to be submitted to an annual general meeting of shareholders by giving a requisition in writing to the company. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide (among other things) advance notice, as set out in our bye-laws. Shareholders may only propose a person for election as a director at an annual general meeting.
Shareholder action by written consent
Our bye-laws provide that, except for the removal of auditors and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by the shareholders through the unanimous written consent of all the shareholders who would be entitled to vote on the matter at the general meeting.
Amendment of memorandum of association and bye-laws
Our memorandum of association and bye-laws may be amended with the approval of a majority of our board of directors and by a resolution by a majority of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws.
Under Bermuda law, the holders of an aggregate of not less than 20% in par value of the company’s issued share capital or any class thereof have the right to apply to the Supreme Court of Bermuda for an annulment of any amendment of the memorandum of association adopted by shareholders at any general meeting, other than an amendment which alters or reduces a company’s share capital as provided in the Companies Act. Where such an application is made, the amendment becomes effective only to the extent that it is confirmed by the Bermuda court. An application for an annulment of an amendment of the memorandum of association must be made within twenty-one days after the date on which the resolution altering the company’s memorandum of association is passed and may be made on behalf of persons entitled to make the application by one or more of their number as they may appoint in writing for the purpose. No application may be made by shareholders voting in favour of the amendment.
Business combinations
The amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Under the Companies Act, unless the company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass a resolution to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation or merger will require the approval of our board of directors and of our shareholders by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-
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laws. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholder’s shares may, within one month of the notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the value of those shares.
Our bye-laws provide that the directors shall manage the business of the Company and may exercise all such powers as are not, by the Companies Act or by the bye-laws, required to be exercised by the Company in general meeting and may pay all expenses incurred in promoting and incorporating the company and may exercise all the powers of the Company including, but not by way of limitation, the power to borrow money and to mortgage or charge all or any part of the undertaking property and assets (present and future) and uncalled capital of the Company and to issue debentures and other securities, whether outright or as security for any debt, liability or obligation of the Company or any third party.
Compulsory Acquisition of Shares Held by Minority Holders
An acquiring party is generally able to acquire compulsorily the common shares of minority holders in the following ways:
(1)By a procedure under the Companies Act 1981 known as a “scheme of arrangement”. A scheme of arrangement could be effected by obtaining the agreement of the company and of holders of common shares, representing in the aggregate a majority in number and at least 75% in value of the common shareholders present and voting at a court ordered meeting held to consider the scheme of arrangement. The scheme of arrangement must then be sanctioned by the Bermuda Supreme Court. If a scheme of arrangement receives all necessary agreements and sanctions, upon the filing of the court order with the Registrar of Companies in Bermuda, all holders of common shares could be compelled to sell their shares under the terms of the scheme of arrangement.
(2)If the acquiring party is a company it may compulsorily acquire all the shares of the target company, by acquiring pursuant to a tender offer 90% of the shares or class of shares not already owned by, or by a nominee for, the acquiring party (the offeror), or any of its subsidiaries. If an offeror has, within four months after the making of an offer for all the shares or class of shares not owned by, or by a nominee for, the offeror, or any of its subsidiaries, obtained the approval of the holders of 90% or more of all the shares to which the offer relates, the offeror may, at any time within two months beginning with the date on which the approval was obtained, require by notice any nontendering shareholder to transfer its shares on the same terms as the original offer. In those circumstances, nontendering shareholders will be compelled to sell their shares unless the Supreme Court of Bermuda (on application made within a one-month period from the date of the offeror’s notice of its intention to acquire such shares) orders otherwise.
(3) Where one or more parties holds not less than 95% of the shares or a class of shares of a company, such holder(s) may, pursuant to a notice given to the remaining shareholders or class of shareholders, acquire the shares of such remaining shareholders or class of shareholders. When this notice is given, the acquiring party is entitled and bound to acquire the shares of the remaining shareholders on the terms set out in the notice, unless a remaining shareholder, within one month of receiving such notice, applies to the Supreme Court of Bermuda for an appraisal of the value of their shares. This provision only applies where the acquiring party offers the same terms to all holders of shares whose shares are being acquired.
Shareholder Rights Plan
On June 3, 2025, our board of directors adopted a limited-duration shareholder rights plan (the “Rights Plan”), effective immediately and set to expire 364 days after adoption. The board implemented the Rights Plan to protect value for the Company and all shareholders in light of the unusually rapid and significant accumulation of our common shares by a single shareholder. The Rights Plan is intended to reduce the likelihood that any shareholder obtains undue influence or control through open-market accumulation without paying all shareholders an appropriate control premium or without allowing the board sufficient time to evaluate alternatives in the best interests of all shareholders.
Under the Rights Plan, the rights become exercisable if any person, entity or group acquires beneficial ownership of 12% or more of our outstanding common shares (including through derivatives) in a transaction not approved by the board.
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If the triggering threshold is crossed, each right (other than those held by the triggering person, entity or group, which become void) entitles the holder, at the then-current exercise price, to purchase additional common shares having a then-current market value equal to twice the exercise price of the right.
Dividends and repurchase of shares
Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than its liabilities. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due.
Shareholder suits
Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. Furthermore, consideration would be given by a Bermuda court to acts that are alleged to constitute a fraud against the minority shareholders or, for instance, where an act requires the approval of a greater percentage of the company’s shareholders than that which actually approved it.
When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company.
Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they may have, both individually and on our behalf, against any director in relation to any action or failure to take action by such director, including the breach of any fiduciary duty by a director, except in respect of any fraud or dishonesty of such director or to recover any gain, personal profit or advantage to which such director is not legally entitled.
Comparison of Bermuda law to Delaware corporate law
Bermuda law differs from the laws in effect in the United States and might afford less protection to shareholders.
Our shareholders could have more difficulty protecting their interests than would shareholders of a corporation incorporated in a jurisdiction of the United States. As a Bermuda company, we are governed by our memorandum of association and bye-laws and Bermuda company law. The provisions of the Companies Act, which applies to us, differs in some material respects from laws generally applicable to U.S. corporations and shareholders, including the provisions relating to interested directors, mergers and acquisitions, takeovers, shareholder lawsuits and indemnification of directors. Set forth below is a summary of these provisions, as well as modifications adopted pursuant to our bye-laws, which differ in certain respects from provisions of Delaware corporate law. Our shareholders approved the adoption of our bye-laws with effect on February 19, 2014, and amended with effect on July 15, 2021. Because the following statements are summaries, they do not discuss all aspects of Bermuda law that may be relevant to us and our shareholders.
Interested Directors. Under our bye-laws and the Companies Act, a director shall declare the nature of his interest in any contract or arrangement with the company. Our bye-laws further provide that a director so interested shall not, except in particular circumstances, be entitled to vote or be counted in the quorum at a meeting in relation to any resolution in which he has an interest, which is to his knowledge, a material interest (otherwise than by virtue of his interest in shares or debentures or other securities of the company). A director will be liable to us for any secret profit realized from the transaction. See “Item 10—B. Memorandum of association and bye-laws—Interested directors.”
Amalgamations, Mergers and Similar Arrangements. Pursuant to the Companies Act, the amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliates) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Under our bye-laws, an amalgamation or merger will require the approval of our board of directors and our shareholders by Special Resolution, which is a resolution adopted by 65% of more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. The quorum for any such general meeting must be two or more persons, in person or by proxy, representing more than one-third of the issued shares of the company. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value has been offered for such shareholders shares may, within one month of notice of the shareholders meeting, apply to the Supreme Court of Bermuda to appraise the fair value of those shares.
Under Delaware law, with certain exceptions, a merger, consolidation or sale of all or substantially all the assets of a corporation must be approved by the board of directors and a majority of the issued and outstanding shares entitled to vote thereon. Under Delaware law, a shareholder of a corporation participating in certain major corporate transactions may, under certain circumstances, be entitled to appraisal rights pursuant to which such shareholder may receive cash in the amount of the fair value of the shares held by such shareholder (as determined by a court) in lieu of the consideration such shareholder would otherwise receive in the transaction.
Shareholders’ Suit. Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company to remedy a wrong to the company where the act complained of is alleged to be beyond the corporate power of the company or illegal, or would result in the violation of the company’s memorandum of association or bye-laws. When the affairs of a company are being conducted in a manner which is oppressive or prejudicial to the interests of some part of the shareholders, one or more shareholders may apply to the Supreme Court of Bermuda, which may make such order as it sees fit, including an order regulating the conduct of the company’s affairs in the future or ordering the purchase of the shares of any shareholders by other shareholders or by the company. See “Item 10—B. Memorandum of association and bye-laws—Shareholder suits.”
Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they might have, individually or in the right of the company, against any director for any act or failure to act in performance of such director’s duties, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or to recover any gain, personal profit or advantage to which such director is not legally entitled. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.
Indemnification of Directors. We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. See “Item 10—B. Memorandum of association and bye-laws—Enforcement of Judgments.” Our bye-laws provide that we shall indemnify our officers and directors in respect of their acts and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such Director is not legally entitled, and (by incorporation of the provisions of the Companies Act) that we may advance money to our officers and directors for the costs, charges and expenses incurred by our officers and directors in defending any civil or criminal proceedings against them on condition that the directors and officers repay the money if any allegations of fraud or dishonesty is proved against them provided, however, that, if the Companies Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking, by or on behalf of such indemnitee, to repay all amounts if it shall ultimately be determined by final judicial decision that such indemnitee is not entitled to be indemnified for such expenses under our bye-laws or otherwise. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to
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believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors.
As a result of these differences, investors could have more difficulty protecting their interests than would shareholders of a corporation incorporated in the United States.
Tax matters. Under current Bermuda law, we are not subject to tax on income or capital gains in Bermuda. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035, except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda. On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of the last four fiscal years beginning on or after January 1, 2025. We are incorporated in Bermuda as an exempted company and pay annual Bermuda government fees. In addition, all entities employing individuals in Bermuda are required to pay a payroll tax and there are other sundry taxes payable, directly or indirectly, to the Bermuda government. Neither we nor our Bermuda subsidiaries employ individuals in Bermuda as at the date of this annual report.
Access to books and records and dissemination of information
Members of the general public have a right to inspect the public documents of a company available at the office of the Registrar of Companies in Bermuda. These documents include the company’s memorandum of association, including its objects and powers, and certain alterations to the memorandum of association. The shareholders have the additional right to inspect the bye-laws of the company, minutes of general meetings and the company’s audited financial statements, which must be presented to the annual general meeting. The register of members of a company is also open to inspection by shareholders and by members of the general public without charge. The register of members is required to be open for inspection for not less than two hours in any business day (subject to the ability of a company to close the register of members for not more than thirty days in a year). A company is required to maintain its share register in Bermuda but may, subject to the provisions of the Companies Act, establish a branch register outside of Bermuda. A company is required to keep at its registered office a register of directors and officers that is open for inspection for not less than two hours in any business day by members of the public without charge. A company is also required to file with the Registrar of Companies in Bermuda a list of its directors to be maintained on a register, which register will be available for public inspection subject to such conditions as the Registrar may impose and on payment of such fee as may be prescribed. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.
Registrar or transfer agent
A register of holders of the common shares is maintained by Conyers Corporate Services (Bermuda) Limited in Bermuda, and a branch register is maintained in the United States by Computershare Trust Company, N.A., who serves as branch registrar and transfer agent.
Enforcement of Judgments
We are incorporated as an exempted company limited by shares under the laws of Bermuda, and substantially all of our assets are located in Colombia, Ecuador, Brazil and Argentina. In addition, most of our directors and executive officers reside outside the United States, and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws.
There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. However, the courts of Bermuda would recognize any final
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and conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct procedures under the laws of Bermuda.
An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, may not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, may not be available under Bermuda law or enforceable in a Bermuda court, as they may be contrary to Bermuda public policy. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violations of U.S. federal securities laws because these laws have no extraterritorial jurisdiction under Bermuda law and do not have force of law in Bermuda. A Bermuda court may, however, impose civil liability on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. However, section 281 of the Companies Act allows a Bermuda court, in certain circumstances, to relieve officers and directors of Bermuda companies of liability for acts of negligence, breach of duty or trust or other defaults.
C. Material contracts
See “Item 4. Information on the Company—B. Business Overview—Significant Agreements.”
D. Exchange controls
E. Taxation
The following summary contains a description of certain Bermudian, U.S. federal income, and Colombian tax consequences of the acquisition, ownership and disposition of our common shares. The summary is based upon the tax laws of Bermuda, the United States, and Colombia, and regulations thereunder as of the date hereof, which are subject to change.
Bermuda tax consideration
At the date of this annual report, there is no Bermuda income or profits tax, withholding tax, capital gains tax, capital transfer tax, estate duty or inheritance tax payable by us or by our shareholders in respect of our common shares. On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of the last four fiscal years beginning on or after January 1, 2025. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits or income, or computed on any capital asset, gain or appreciation or any tax in the nature of estate duty or inheritance tax, such tax shall not, until March 31, 2035, be applicable to us or to any of our operations or to our common shares, debentures or other obligations except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda.
Material U.S. federal income tax considerations
The following is a description of the material U.S. federal income tax consequences to U.S. Holders (as defined below) of owning and disposing of our common shares. This discussion is not a comprehensive description of all tax considerations that may be relevant to a particular person’s decision to hold our common shares. This discussion applies only to a U.S. Holder that holds our common shares as capital assets for tax purposes. In addition, it does not describe all
of the tax consequences that may be relevant in light of the U.S. Holder’s particular circumstances, including alternative minimum tax and Medicare contribution tax consequences and differing tax consequences applicable to a U.S. Holder subject to special rules, such as:
If an entity that is classified as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the partnership. Partnerships holding common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares.
This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date hereof, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances.
A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal income tax purposes that is:
·
a citizen or individual resident of the United States;
a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or
an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source.
This discussion assumes that we are not, and will not become, a passive foreign investment company, as described below.
Taxation of distributions
Distributions paid on our common shares, other than certain pro rata distributions of common shares, will generally be treated as dividends to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions will generally be reported to U.S. Holders as dividends. Subject to
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the passive foreign investment company rules described below, dividends paid by qualified foreign corporations to certain non-corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the NYSE where our common shares are traded. Non-corporate U.S. Holders should consult their tax advisers to determine whether the favorable rate will apply to dividends they receive and whether they are subject to any special rules that limit their ability to be taxed at this favorable rate.
A dividend generally will be included in a U.S. Holder’s income when received, will be treated as foreign-source income to U.S. Holders and will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code with respect to dividends paid by domestic corporations.
Sale or other taxable disposition of common shares
Gain or loss realized on the sale or other taxable disposition of our common shares will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder held our common shares for more than one year. Long-term capital gain of a non-corporate U.S. Holder is generally taxed at preferential rates. The deductibility of capital losses is subject to limitations. The amount of the gain or loss will equal the difference between the U.S. Holder’s tax basis in the common shares disposed of and the amount realized on the disposition. If a non-U.S. tax is withheld on the sale or disposition of common shares, a U.S. Holder’s amount realized will include the gross amount of the proceeds of the sale or disposition before deduction of the non-U.S. tax. Gain or loss will generally be U.S.-source gain or loss for foreign tax credit purposes. U.S. Holders should consult their tax advisers as to whether the non-U.S. tax on gains may be creditable against the U.S. Holder’s U.S. federal income tax on foreign-source income from other sources.
The rules governing foreign tax credits are complex. For example, under applicable Treasury regulations, in the absence of an election to apply the benefits of an applicable income tax treaty, in order for a non-U.S. income tax to be creditable, the foreign jurisdiction’s income tax rules must be consistent with certain U.S. federal income tax principles, and we have not determined whether the Colombian income tax system meets all these requirements. The Internal Revenue Service (the “IRS”) has released notices that provide relief from certain of the provisions of the Treasury regulations described above for taxable years ending before the date that a notice or other guidance withdrawing or modifying the temporary relief is issued (or any later date specified in such notice or other guidance). With regards to the possible application of the Colombian and Argentine taxes on transfers of shares, described under "—Colombian tax on transfers of shares" and "—Argentine tax on transfers of shares" below, respectively, you generally will not be entitled to claim a foreign tax credit for any Colombian nor Argentine taxes imposed on gains from taxable dispositions of our common shares (although it is possible that such taxes may reduce the amount realized on the disposition).
Passive foreign investment company rules
We believe that we were not a “passive foreign investment company,” or PFIC, for U.S. federal income tax purposes for 2025, and we do not expect to be a PFIC in the foreseeable future. However, because the composition of our income and assets will vary over time, there can be no assurance that we will not be a PFIC for any taxable year. The determination of whether we are a PFIC is made annually and is based upon the composition of our income and assets (including the income and assets of, among others, entities in which we hold at least a 25% interest), and the nature of our activities.
If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would generally be allocated ratably over the U.S. Holder’s holding period for the common shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations for that year, as appropriate, and an interest charge would be imposed on the tax on such amount. Further, to the extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, that distribution would be subject to taxation in the same manner as gain, as described immediately above. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of our common shares.
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U.S. Holders should consult their tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances.
Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were treated as a PFIC for the taxable year in which we paid a dividend or the prior taxable year, the preferential dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply.
Information reporting and backup withholding
Payments of dividends and sales proceeds that are made within the United States or through certain U.S.-related financial intermediaries generally are subject to information reporting, and may be subject to backup withholding, unless (1) the U.S. Holder is a corporation or other exempt recipient or (2) in the case of backup withholding, the U.S. Holder provides a correct taxpayer identification number and certifies that it is not subject to backup withholding. The amount of any backup withholding from a payment to a U.S. Holder will be allowed as a credit against the U.S. Holder’s U.S. federal income tax liability and may entitle it to a refund, provided that the required information is timely furnished to the IRS.
Colombian tax on transfers of shares
In August 2020, the Colombian government enacted Decree 1103 that regulates the indirect transfer tax set in article 90-3 of the Colombian Tax Code. Through this regulation, the transfer of shares and assets of entities located abroad are taxed in Colombia when such transaction represents a transfer of underlying assets located in Colombia. The latter applies unless (i) shares transferred are listed on a stock exchange recognized by the Colombian Government and no more than 20% of such shares are owned by a single beneficiary; or (ii) the value of assets indirectly transferred represents less than 20% of book and/or fair market value of all assets owned by the non-resident entity transferor.
For income tax purposes, indirect transfer shall be assessed at fair market value of the Colombian underlying assets and the relevant tax basis is the one held in the underlying Colombian asset, which should be calculated based on the Colombian Tax Code rules. When the underlying assets are held by a Colombian branch, any taxable base determined shall be allocated first to amortization/depreciation recapture taxed as ordinary income.
When a subsequent indirect transfer is made, the tax basis of the underlying Colombian assets corresponds to the purchase price paid and allocated to the underlying Colombian assets. However, Decree 1103 clarifies that the tax basis of the entity owning the underlying asset in Colombia is not stepped up.
See “Item 3. Key Information—D. Risk Factors—Risks related to our common shares—The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia.”
Argentine tax on transfers of shares
Argentina’s income tax law may impose tax on a non-resident seller upon the sale, transfer or other disposition of an interest in a foreign entity if, at the time of the transaction or at any time during the preceding 12 months, (i) 30% or more of the foreign entity’s market value is attributable, directly or indirectly, to assets located in Argentina, and (ii) the interest transferred represents 10% or more of the foreign entity’s equity (including, for purposes of this threshold, certain aggregation rules for transfers made by related parties). Where applicable, the tax is generally 15% on the actual net gain (if basis and costs are substantiated) or, alternatively, 15% on a deemed net gain equal to 90% of the sale price (an effective 13.5% tax on the sale price). The rules also provide an exception for transfers carried out within the same economic group, subject to applicable requirements. These rules generally apply to participations in foreign entities acquired on or after January 1, 2018. Although assets located in Argentina currently represent less than 30% of the Group’s total assets based on our consolidated financial statements, the applicability of these rules depends on the facts and circumstances at the time of a transaction; therefore, we monitor this exposure.
F. Dividends and paying agents
G. Statement by experts
H. Documents on display
We are subject to the informational requirements of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC maintains an Internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov.
I. Subsidiary information
We are exposed to a variety of market risks, including commodity price risk, interest rate risk, currency risk and credit (counterparty and customer) risk. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates.
For further information on our market risks, please see Note 3 to our Consolidated Financial Statements.
A. Debt securities
B. Warrants and rights
C. Other securities
D. American Depositary Shares
A. Defaults
No matters to report.
B. Arrears and delinquencies
A. Disclosure Controls and Procedures
As of December 31, 2025, under the supervision and with the participation of our management, including our Chief Executive Officer and Chief Financial Officer, we performed an evaluation of the effectiveness of the design and operation of our disclosure controls and procedures (as defined in Rule 13a-15(e) under the Exchange Act), which are designed to provide reasonable assurance that the information we are required to disclose in the reports we file or submit under the Exchange Act is (1) recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms, and (2) accumulated and communicated to our management to allow timely decisions regarding required disclosures. There are inherent limitations to the effectiveness of any disclosure controls and procedures system, including the possibility of human error and circumventing or overriding them. Even if effective, disclosure controls and procedures can provide only reasonable assurance of achieving their control objectives.
Based on such evaluation, our Chief Executive Officer and Chief Financial Officer, with assistance from other members of management, have concluded that the disclosure controls and procedures were effective as of such date.
B. Management’s Annual Report on Internal Control over Financial Reporting
Our management is responsible for establishing and maintaining an adequate internal control over financial reporting as defined in Rule 13a-15(f) under the Exchange Act.
Our internal control over financial reporting is a process designed by, or under the supervision of, our principal executive and principal financial officers, management and other personnel, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of our financial statements for external reporting purposes, in accordance with generally accepted accounting principles. These include those policies and procedures that:
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, effective control over financial reporting cannot, and does not, provide absolute assurance of achieving our control objectives. Also, projections of, and any evaluation of effectiveness of the internal controls in future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
Under the supervision and with the participation of our management, including our Chief Executive Officer and our Chief Financial Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2025, based on the criteria established in Internal Control - Integrated Framework of the Committee of Sponsoring Organizations of the Treadway Commission (2013).
Based on this assessment, management believes that, as of December 31, 2025, its internal control over financial reporting was effective based on those criteria.
Moreover, on October 16, 2025, we acquired operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Vaca Muerta shale formation in Argentina (the “Acquired Business”). For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina’s Vaca Muerta Formation.” As permitted by SEC staff interpretive guidance for newly acquired businesses, management excluded the Acquired Business from the evaluation of ICFR as of December 31, 2025. The Acquired Business represented approximately 13% of our total consolidated assets and 1% of our total consolidated revenues as of and for the year ended December 31, 2025.
Management’s conclusion regarding the effectiveness of our ICFR as of December 31, 2025 does not extend to the ICFR of the Acquired Business. The Acquired Business will be included in the scope of our ICFR assessment within the permitted timeframe, and its processes and controls will be evaluated as part of our assessment for the year ending December 31, 2026.
C. Attestation Report of the Registered Public Accounting Firm
The effectiveness of the Group’s internal control over financial reporting as of December 31, 2025, has been audited by independent registered public accounting firm, Ernst & Young Audit S.A.S. See pages F-5 to F-6 of this annual report.
D. Changes in Internal Control over Financial Reporting
There have been no changes in the Group’s internal control over financial reporting that occurred during the year ended December 31, 2025, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
We have determined that Mr. Robert A. Bedingfield, Mr. Constantin Papadimitriou and Mr. Carlos E. Macellari are independent, as such term is defined under SEC rules applicable to foreign private issuers. In addition, Mr. Robert A. Bedingfield is regarded as audit committee financial expert.
We adopted a Code of Ethics on September 24, 2012 and last amended on March 4, 2025. It is applicable to the board of directors and all employees. Since its adoption date, we have not waived compliance with the Code of Ethics. The Code of Ethics is available at the Company’s website.
The independent registered public accounting firm for the fiscal year ended December 31, 2025 and 2024 was Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited).
The following table provides detail in respect of audit, tax and other fees billed by the independent registered public accounting firm and other member firms of Ernst & Young Global Limited for professional services:
(in millions of US$)
Audit fees
1.12
1.02
Audit related fees
0.05
0.04
1.17
1.06
Fees are shown net of VAT and other associated tax charges.
Audit Fees
Audit fees are fees billed for professional services rendered by the principal accountant for the audit of the registrant’s annual financial statements or services that are normally provided by the accountant in connection with statutory and regulatory filings or engagements for those fiscal years. It includes the audit of our Consolidated Financial Statements and other services that generally only the independent accountant reasonably can provide, such as statutory audits, comfort letters, consents and assistance with and review of documents, accounting consultations and audits in connection with acquisitions, attestation of services that are not required by statute or regulation and consultation concerning financial accounting and reporting standards.
Audit-Related Fees
Audit-related fees are fees billed for assurance and related services that are reasonably related to the performance of the audit or review of our Consolidated Financial Statements and are not reported under the previous category. It includes attestation services related to climate-related disclosures included in the sustainability report of one of our subsidiaries.
Pre-Approval Policies and Procedures
Following the listing of our common shares on the NYSE, the Audit Committee proposes the appointment of the independent auditor to the board of directors to be put to shareholders for approval at the Annual General meeting. The Audit Committee oversees the auditor selection process for new auditors and ensures key partners in the appointed firm are rotated in accordance with best practices. Also, following our NYSE listing, the Audit Committee is required to pre-approve the audit and non-audit fees and services performed by the Company’s auditors in order to be sure that the provision of such services does not impair the audit firm’s independence.
All of the audit and tax fees described in this item 16C have been approved by the Audit Committee.
None.
We have had recurring programs to repurchase our own shares. The latest renewal took place on November 8, 2023, and established a program to repurchase up to 10% of our shares outstanding, or approximately 5,611,797 shares, until December 31, 2024. During 2024 and 2025, no common shares were repurchased under this program. As of the date of this annual report, there is no any program to repurchase our own shares in place.
On March 20, 2024, we announced a tender offer to purchase up to US$50.0 million of our common shares. Consequently, on April 22, 2024, we acquired 4,369,181 of our common shares at a purchase price of US$10 per share, for a total cost of US$43.7 million, excluding fees and other expenses related to the tender offer.
The following table presents purchases of our common shares by the company and “affiliated purchasers” (as that term is defined in Rule 10b-18(a)(3) under the Securities Exchange Act of 1934, as amended) during 2025:
Total Number of
Maximum Number (or
Shares Purchased as
Approximate Dollar Value) of
Number of
Part of Publicly
Shares that May Yet be
Shares
Price Paid
Announced Plans or
Purchased Under the Plans or
Purchased
per Share
Programs
Our common shares are listed on the NYSE. We are therefore required to comply with certain of the NYSE’s corporate governance listing standards (the “NYSE Standards”). As a foreign private issuer, we may follow our home country’s corporate governance practices in lieu of most of the NYSE Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary of those differences is provided as follows.
Director independence
The NYSE Standards require a majority of the membership of domestic NYSE-listed company boards to be composed of independent directors. Neither Bermuda law, the law of our country of incorporation, nor our memorandum of association or bye-laws require a majority of our board to consist of independent directors. However, pursuant to our corporate governance guidelines and in line with the NYSE Standards for U.S. companies, our board of directors is required to be comprised of at least a majority of independent directors.
At the date of this annual report, 67% of our board of directors is independent.
Non-management directors’ executive sessions
The NYSE Standards require non-management directors of NYSE-listed companies to meet at regularly scheduled executive sessions without management. Our memorandum of association and bye-laws do not require our non-management directors to hold such meetings.
Committee member composition
The NYSE Standards require domestic NYSE-listed companies to have a nominating/corporate governance committee and a compensation committee that are composed entirely of independent directors. Bermuda law, the law of our country of incorporation, does not impose similar requirements. However, pursuant to our corporate governance
guidelines and committee charters and in line with the NYSE Standards for U.S. companies, both our nomination/corporate governance committee and our compensation committee are composed entirely of independent directors.
Independence of the compensation committee and its advisers
On January 11, 2013, the SEC approved NYSE listing standards that require that the board of directors of a domestic listed company consider two factors (in addition to the existing general independence tests) in the evaluation of the independence of compensation committee members: (i) the source of compensation of the director, including any consulting, advisory or other compensatory fees paid by the listed company, and (ii) whether the director has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. In addition, before selecting or receiving advice from a compensation consultant or other adviser, the compensation committee of a listed company will be required to take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence.
Foreign private issuers, such as us, will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we will not be required to implement the NYSE listing standards relating to compensation committees of domestic listed companies. Nonetheless, the Company has adopted its own definition of independence pursuant to its Corporate Governance Guidelines. This definition is applied in assessing the independence of directors. All current members of our compensation committee are independent, as defined in our Corporate Governance Guidelines. The charter of our compensation committee does not require the compensation committee to consider the independence of any advisers that assist them in fulfilling their duties.
Additional audit committee functions
The NYSE Standards require that audit committees of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements, engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these procedures. Finally, audit committees are responsible for designing and implementing an internal audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis.
Foreign private issuers such as us are exempt from these additional requirements if home country practice is followed. Bermuda law does not impose similar requirements, and consequently, our audit committee does not perform these additional functions. Our Audit Committee is composed exclusively of independent members.
Miscellaneous
In addition to the above differences, we are not required to: make our audit and compensation committees prepare a written charter that addresses either purposes and responsibilities or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity compensation plans in certain cases; or adopt and make publicly available corporate governance guidelines.
We are incorporated under, and are governed by, the laws of Bermuda. For a summary of some of the differences between provisions of Bermuda law applicable to us and the laws applicable to companies incorporated in Delaware and their shareholders, See “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
We have adopted insider trading policies and procedures governing the purchase, sale, and other dispositions of our securities by directors, senior management, and employees that are reasonably designed to promote compliance with applicable insider trading laws, rules and regulations, and any listing standards applicable to us. A copy of our insider trading policy is attached as Exhibit 11.1 to this annual report.
GeoPark prioritizes cybersecurity risk management as an integral part of its overall enterprise risk management framework. Our cybersecurity risk management practices provide a structure for identifying, preventing, and responding to cyber threats and incidents while ensuring coordination across all departments.
Since 2022, we have successfully implemented the NIST Cybersecurity Framework and established a 24/7 Security Operations Center (SOC), reinforcing our commitment to cybersecurity and operational resilience. This framework includes:
Under the NIST framework, we also address potential cybersecurity threats associated with third-party service providers by assessing operational dependencies and embedding cybersecurity requirements within contractual documentation. Third-party providers are required to periodically report on compliance with these requirements.
In 2025, we reinforced our defenses against cyber threats by enhancing our capabilities, adding new roles to the cybersecurity team, implementing continuous measurement and improvement processes, and conducting an independent external assessment of our cybersecurity strategy and framework. We implemented a corporate cybersecurity awareness program for all employees and third parties to strengthen GeoPark’s security culture.
In addition, we optimized our platforms and controls through advanced endpoint detection and response (EDR) and privileged access management (PAM) technologies, based on solutions from Palo Alto Networks and CyberArk, in line with international industry standards for endpoint protection, identity management, and critical access control. We also strengthened our technology infrastructure by adopting network segmentation policies, multifactor authentication, and patch automation, together with a site-recovery plan for critical applications that includes redundant systems in different geographic locations and multi-cloud backups across several service providers.
As part of this evolution, GeoPark adopted the Cybersecurity Capability Maturity Model (C2M2) as a complementary framework to NIST, allowing for a deeper and sector-specific assessment of cybersecurity capabilities within the energy industry and enhancing organizational maturity and resilience against digital threats.
Our board of directors has overall oversight responsibility for risk management and delegates cybersecurity risk oversight to the Audit Committee. In this capacity, the Audit Committee reviews and reports to the board on cybersecurity risks and plans to ensure that management has effective processes to identify, assess, and mitigate cyber risks. Management is responsible for ongoing risk assessment and program maintenance, a process led by our IT Director with the support of our Cybersecurity and Compliance Manager. The IT Director and Cybersecurity and Compliance Manager regularly update the Audit Committee on the Company’s cybersecurity programs, risks, and mitigation strategies.
Our IT Director is a systems engineer with a master’s degree in systems and computing engineering focused on analytics and artificial intelligence, and a master’s degree in business administration. She has more than 16 years of experience in IT roles leading high-impact teams in the adoption of technologies that strengthen organizational strategy and results. Prior to joining GeoPark, she served as Regional Director for Microsoft in Colombia and as Chief Information Officer for Andes University in Colombia.
Our Cybersecurity and Compliance Manager brings over 20 years of experience in cybersecurity, digital transformation, and technology risk management in the oil and gas sector and multinational corporations. He is a systems engineer with a specialization in telecommunications and a master’s degree in project management. He has successfully designed and executed enterprise-wide cybersecurity strategies that protect critical infrastructure and ensure regulatory compliance. He has implemented global cybersecurity frameworks, including NIST and C2M2, strengthening the organization’s security posture and aligning risk management with business objectives. His contributions extend to the World Economic Forum (WEF), where he actively participates in developing global cybersecurity strategies. With deep expertise in governance, risk management, and compliance (GRC), he leads proactive risk mitigation initiatives, fortifying the organization’s defense against emerging threats and fostering a resilient cybersecurity culture across all operational levels.
If a cyberattack occurs, our incident-management process is activated and an interdisciplinary committee (including the IT Director, Cybersecurity and Compliance Manager, and cybersecurity team) is convened to contain the attack as quickly as possible with minimal impact on operations. This process includes an escalation matrix where, depending on the infrastructure and information affected, incident management is assigned to specific roles within the Company. Any material incidents must be reported by the IT Director and Cybersecurity and Compliance Manager to the Audit Committee and the board of directors.
As part of our risk-management process, we perform annual reviews to inventory, evaluate, and assess cybersecurity risks, including those related to third-party service providers, at both the information and operational infrastructure levels. To ensure independent assessment, we engage a third-party cybersecurity expert with experience in risk-evaluation methodologies and mitigation plan design to conduct ethical-hacking exercises testing (i) external attack paths that could be used to compromise our infrastructure and data, and (ii) internal SOC capabilities to detect and contain such simulated attacks.
Following these annual reviews, mitigation plans are prepared by the Cybersecurity and Compliance Manager and approved by the IT Director to eliminate identified risks or reduce them to acceptable levels. Once approved, the plans are presented to the Audit Committee. We also engage a third-party cybersecurity expert to perform an annual audit assessing the effectiveness of existing cybersecurity controls. The results of these audits are shared with the Audit Committee.
As cyber threats continue to evolve, we may need to invest additional resources to further enhance protective measures and remediate potential information-security vulnerabilities. We maintain a cybersecurity insurance policy and recognize that the continuously evolving threat landscape may require significant additional resources. In 2025, we did not identify any cybersecurity threats that have materially affected or are reasonably likely to materially affect our business strategy, results of operations, or financial condition. However, despite our efforts, we cannot eliminate all risks from cybersecurity threats or guarantee that we have not experienced an undetected incident. For more information about these risks, please see “Risk Factors – Our business could be negatively impacted by cybersecurity threats and related disruptions.” in this annual report on Form 20-F.
As part of our overall cybersecurity risk management program, our recently initiated operations in Argentina have been fully integrated into our corporate cybersecurity framework. In October 2025, we initiated operations in Argentina following the full integration of our corporate and operational systems. All systems and applications implemented in the country were subjected to our cybersecurity and risk-assessment protocols prior to deployment, including vulnerability testing, network segmentation, and access-control validation. As of the date of this annual report, the Argentine operation remains stable, with no technology or security alerts reported, and cybersecurity performance fully aligned with our corporate standards.
The main cybersecurity risks identified in connection with the new operation include: (i) potential exposure to local third-party networks and service providers; (ii) integration risks associated with new data environments and inter-country connectivity; (iii) regulatory and data-protection compliance under local frameworks; and (iv) a broader attack surface resulting from distributed infrastructure. Each of these risks is actively mitigated through our corporate controls, including continuous monitoring via the 24/7 SOC, privileged access management (PAM) through CyberArk, endpoint detection and response (EDR) using Palo Alto Networks, and alignment with the NIST and C2M2 frameworks to ensure consistent oversight and operational resilience across all jurisdictions.
134
We have responded to Item 18 in lieu of this item.
Financial Statements are filed as part of this annual report, see pages F-1 to F-79 to this annual report.
Exhibit no.
Description
Certificate of Incorporation (incorporated herein by reference to Exhibit 3.1 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
Memorandum of Association (incorporated herein by reference to Exhibit 3.2 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
Current bye-laws (incorporated herein by reference to Exhibit 1.3 to the Company’s Annual Report on Form 20-F filed with the SEC on April 2, 2025).
1.4
Certificate of Incorporation on Name Change (incorporated herein by reference to Exhibit 1.4 to the Company’s Annual Report on Form 20-F filed with the SEC on March 31, 2021).
Indenture dated January 17, 2020, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on April 1, 2020).
2.2
First Supplemental Indenture dated August 25, 2021, among GeoPark Limited and GeoPark Colombia S.A.S. and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.6 to the Company’s Annual Report on Form 20-F filed with the SEC on March 31, 2022).
2.3
Second Supplemental Indenture dated June 27, 2022, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.3 to the Company’s Annual Report on Form 20-F filed with the SEC on March 30, 2023).
2.4
Indenture dated January 31, 2025, among GeoPark Limited and the Bank of New York Mellon (incorporated herein by reference to Exhibit 2.4 to the Company’s Annual Report on Form 20-F filed with the SEC on April 2, 2025).
2.5 (a)
Description of Securities – Common Shares. *
2.5 (b)
Description of Securities – Series A Preferred Shares Purchase Rights *
2.6 (a)
Rights Agreement, dated as of June 3, 2025, between GeoPark Limited and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Form 6-K furnished to the SEC on June 3, 2025).
2.6 (b)
Amendment no. 1 to Rights Agreement, dated as of March 5, 2026, between GeoPark Limited and Computershare Trust Company, N.A. (incorporated herein by reference to the Company’s Form 6-K furnished to the SEC on March 6, 2026).
Exploration and Production Contract regarding exploration for and exploitation of hydrocarbons in the Llanos 34 Block, dated March 13, 2009, between the Colombian Agencia Nacional de Hidrocarburos and Unión Temporal Llanos 34 (incorporated herein by reference to Exhibit 10.3 to the Company’s Registration Statement on Form F-1 (File No. 333-191068) filed with the SEC on September 9, 2013).
Sale and purchase agreement related, among others, to the hydrocarbons blocks “Loma Jarillosa Este” and “Puesto Silva Oeste” in the Neuquén Province, dated September 25, 2025, between Pluspetrol S.A. and GeoPark Argentina S.A. (portions of this exhibit have been omitted pursuant to Item 601(b)(10) of Regulation S-K).*†
4.3
Share purchase agreement by and between GeoPark Limited and Colden Investments S.A. dated as of March 5, 2026 (incorporated herein by reference to the Company’s Form 6-K furnished to the SEC on March 6, 2026).
8.1
Subsidiaries of GeoPark Limited.*
Insider Trading Policy.*
12.1
Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.*
12.2
13.1
Certification pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002.*
13.2
15.1
Consent of Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited). *
Consents of DeGolyer and MacNaughton to use its report.*
97.1
Compensation Recoupment Policy. (incorporated herein by reference to Exhibit 97.1 to the Company’s Annual Report on Form 20-F filed with the SEC on March 27, 2024).
99.1
Reserves Report of DeGolyer and MacNaughton dated March 3, 2026, for reserves in Argentina and Colombia as of December 31, 2025.*
101.INS
Inline XBRL Instance Document*
101.SCH
XBRL Taxonomy Extension Schema Document*
101.CAL
XBRL Taxonomy Extension Calculation Linkbase Document*
101.DEF
XBRL Taxonomy Extension Definition Linkbase Document*
101.LAB
XBRL Taxonomy Extension Label Linkbase Document*
101.PRE
XBRL Taxonomy Extension Presentation Linkbase Document*
104 Cover Page Interactive Data File (formatted in Inline XBRL and included in Exhibit 101)
Filed with this Annual Report on Form 20-F.
†
Pursuant to Instruction 4 to Item 19 of Form 20-F and Rule 601(b)(10) of Regulation S-K, the registrant has omitted from the filed version of this exhibit certain non-material schedules and attachments containing detailed employee compensation and other confidential information. The omitted information is not material and is the type that the registrant customarily and actually treats as private or confidential. A complete unredacted copy of the exhibit has been retained by the registrant and will be furnished to the U.S. Securities and Exchange Commission staff upon request.
136
SIGNATURES
The registrant hereby certifies that it meets all of the requirements for filing on Form 20-F and that it has duly caused and authorized the undersigned to sign this annual report on its behalf.
By:
/s/ Felipe Bayon
Name: Felipe Bayon
Title: Chief Executive Officer and Director
Date: March 31, 2026
137
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
Consolidated Financial Statements—GeoPark Limited
Reports of Independent Registered Public Accounting Firm: Ernst & Young Audit S.A.S. - PCAOB ID No. 1522.
F-2
Consolidated Statement of Income for the years ended December 31, 2025, 2024 and 2023.
F-7
Consolidated Statement of Comprehensive Income for the years ended December 31, 2025, 2024 and 2023.
F-8
Consolidated Statement of Financial Position as of December 31, 2025 and 2024.
F-9
Consolidated Statement of Changes in Equity for the years ended December 31, 2025, 2024 and 2023.
F-10
Consolidated Statement of Cash Flows for the years ended December 31, 2025, 2024 and 2023.
F-11
Notes to the Consolidated Financial Statements.
F-12
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of GeoPark Limited
Opinion on the Financial Statements
We have audited the accompanying consolidated statements of financial position of GeoPark Limited (the Company) as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the three years in the period ended December 31, 2025, and the related notes (collectively referred to as the “consolidated financial statements”). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company at December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025, in conformity with IFRS Accounting Standards as issued by the International Accounting Standards Board (IASB).
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) and our report dated March 31, 2026 expressed an unqualified opinion thereon.
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audits provide a reasonable basis for our opinion.
Critical Audit Matters
The critical audit matters communicated below are matters arising from the current period audit of the financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.
Depreciation, depletion and amortization (DD&A) of oil and gas properties and production facilities and machinery
Description of the Matter
As described in Note 2.11 to the consolidated financial statements, capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated using the unit-of-production method based on commercially proved and probable oil reserves that are estimated by independent reserves engineers. As further described in Note 18, the carrying amount of the Company’s oil and gas properties and production facilities and machinery as of December 31, 2025 was $644 million, and the related DD&A expense recognized during the year was $112 million. The estimation of proved and probable oil reserves requires an evaluation of inputs, such as historical oil production and the future prices of oil, among others.
Auditing the Company’s calculation of the DD&A expense of oil and gas properties and production facilities and machinery was complex because of the use of the work of the Company’s independent reserves engineers and the evaluation of management’s inputs described above, which were used by the Company’s independent reserves engineers in estimating proved and probable oil reserves.
How We Addressed the Matter in Our Audit
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to determine DD&A expense of oil and gas properties and production facilities and machinery, including management’s controls over the completeness and the accuracy of the data related to historical oil production and future prices of oil provided to the independent reserves engineers for use in the estimation of proved and probable oil reserves.
Our audit procedures included, among others, obtaining the reserves report from the independent reserves engineers, evaluating the competence, capabilities and objectivity of the independent reserves engineers and evaluating the methodology used in the preparation of the reserves estimates. Additionally, we evaluated the professional qualifications and experience of management’s officer responsible for overseeing the preparation of the oil reserves estimates. Furthermore, we evaluated the completeness and accuracy of the data related to historical production and future prices of oil used by the independent reserves engineers in estimating proved and probable oil reserves by agreeing to source documentation. We tested the mathematical accuracy of the DD&A computations for oil and gas properties and production facilities and machinery, including testing the underlying data by comparing the proved and probable oil reserves amounts used in the calculations to the reserves report prepared by the independent reserves engineers.
F-3
Fair value measurement of oil and gas properties and related mineral interest acquired in the Vaca Muerta formation
As described in Note 2.7 to the consolidated financial statements, business combinations are accounted for using the acquisition method, under which the consideration transferred is allocated to the identifiable assets acquired and liabilities assumed based on their estimated fair values at the acquisition date. As further described in Note 34.1, on October 16, 2025, the Company completed the acquisition of Loma Jarillosa Este and Puesto Silva Oeste, two blocks in Argentina’s Vaca Muerta formation, for total consideration of US$ 115 million.
The Company estimated the fair value of acquired oil and gas properties and related mineral interests using an income approach based on the present value of expected future cash flows, which were determined based on oil reserves estimated by independent reserves engineers. The estimation of oil reserves requires an evaluation of inputs, such as historical oil production and the future prices of oil, among others. The estimation of the fair value of acquired oil and gas properties and related mineral interest also involved determination of the discount rate used to present value the expected future cash flows.
Auditing the Company’s fair value of the acquired oil and gas properties and related mineral interest was complex because of the use of the work of the Company’s independent reserves engineers and the evaluation of management’s assumptions described above, which were used by the Company’s independent reserves engineers in estimating oil reserves, and the determination of the discount rate.
We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s controls over its process to determine the fair value of the acquired oil and gas properties and related mineral interests, including management’s controls over the completeness and accuracy of the data related to historical oil production and future prices of oil provided to the independent reserves engineers for use in the estimation of oil reserves and management’s controls over the determination of the discount rate.
Our audit procedures included, among others, obtaining the reserves report from the independent reserves engineers, evaluating the competence, capabilities and objectivity of the independent reserves engineers and evaluating the methodology used in the preparation of the reserves estimates. Additionally, we evaluated the professional qualifications and experience of management’s officer responsible for overseeing the preparation of the oil reserves estimates. Furthermore, we evaluated the completeness and accuracy of the data related to historical production and future prices of oil used by the independent reserves engineers in estimating oil reserves by agreeing to source documentation. We also involved our valuation specialists to assist with the evaluation of certain assumptions, including the discount rate, among others.
/s/ Ernst & Young Audit S.A.S.
We have served as the Company’s auditor since 2023.
March 31, 2026
F-4
Opinion on Internal Control over Financial Reporting
We have audited GeoPark Limited’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control-Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) (the COSO criteria). In our opinion, GeoPark Limited (the Company) maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on the COSO criteria.
As indicated in the accompanying Management’s Annual Report on Internal Control over Financial Reporting, management’s assessment of and conclusion on the effectiveness of internal control over financial reporting did not include the internal controls of the acquired operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste blocks in the Vaca Muerta formation in Argentina, which are included in the 2025 consolidated financial statements of the Company and constituted 13% of total assets as of December 31, 2025 and 1% of revenues for the year then ended. Our audit of internal control over financial reporting of the Company also did not include an evaluation of the internal control over financial reporting of Loma Jarillosa Este and Puesto Silva Oeste blocks.
We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated statements of financial position of the Company as of December 31, 2025 and 2024, the related consolidated statements of income, comprehensive income, changes in equity and cash flow for each of the three years in the period ended December 31, 2025, and the related notes and our report date March 31, 2026 expressed an unqualified opinion thereon.
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
F-5
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
F-6
CONSOLIDATED STATEMENT OF INCOME
Amounts in US$´000
Note
REVENUE
756,625
(232,325)
(11,192)
(43,969)
(13,084)
(120,934)
(29,563)
Impairment loss for non-financial assets
18‑35
(13,332)
Other (expenses) income, net
(21,319)
OPERATING PROFIT
270,907
(45,815)
6,237
Foreign exchange (loss) gain
(16,820)
PROFIT BEFORE INCOME TAX
214,509
Income tax benefit (expense)
(103,441)
PROFIT FOR THE YEAR
111,068
Earnings per share (in US$). Basic
0.96
1.84
1.95
Earnings per share (in US$). Diluted
0.95
1.81
1.94
The accompanying notes are an integral part of these Consolidated Financial Statements.
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Other comprehensive income:
Items that may be subsequently reclassified to profit or loss
Currency translation differences
(1,628)
1,624
Profit (Loss) on cash flow hedges (a)
19,433
(960)
2,738
Income tax (expense) benefit relating to cash flow hedges
(6,842)
932
(1,369)
Other comprehensive profit (loss) for the year
12,575
(1,656)
2,993
Total comprehensive profit for the year
62,242
94,723
114,061
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
ASSETS
NON-CURRENT ASSETS
775,686
740,491
Right-of-use assets
20,496
24,451
Prepayments and other receivables
3,990
2,650
Other financial assets
1,020
Deferred income tax asset
20,579
1,332
TOTAL NON-CURRENT ASSETS
820,763
769,944
CURRENT ASSETS
Inventories
12,379
10,567
Trade receivables
39,095
40,211
42,394
79,731
Derivative financial instrument assets
25,498
2,764
20,088
Cash and cash equivalents
100,318
276,750
TOTAL CURRENT ASSETS
219,684
430,111
TOTAL ASSETS
1,040,447
1,200,055
EQUITY
Equity attributable to owners of the Company
Share premium
79,716
73,750
Translation reserve
(11,606)
(11,590)
Other reserves
27,644
15,053
Retained earnings
149,991
126,027
TOTAL EQUITY
245,797
203,291
LIABILITIES
NON-CURRENT LIABILITIES
Borrowings
535,080
492,007
Lease liabilities
18,889
17,318
Provisions and other long-term liabilities
24,630
31,952
Deferred income tax liability
78,821
86,814
TOTAL NON-CURRENT LIABILITIES
657,420
628,091
CURRENT LIABILITIES
18,467
22,326
7,106
8,605
Derivative financial instrument liabilities
620
464
Current income tax liabilities
57,329
Trade and other payables
111,037
279,949
TOTAL CURRENT LIABILITIES
137,230
368,673
TOTAL LIABILITIES
794,650
996,764
TOTAL EQUITY AND LIABILITIES
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Attributable to owners of the Company
Retained
Earnings
Share
Translation
(Accumulated
Amount in US$‘000
Capital
Premium
Reserve
Reserves
Losses)
Equity as of January 1, 2023
134,798
(11,586)
73,462
(81,147)
115,585
Comprehensive income:
Other comprehensive profit for the year
1,369
Total Comprehensive profit for the year 2023
Transactions with owners:
Share-based payment (Note 30)
7,718
(391)
7,328
Repurchase of shares (Note 24.1.3)
(31,235)
(31,239)
Cash distribution (Note 24.2)
(29,715)
Total 2023
(23,517)
(53,626)
Balances as of December 31, 2023
111,281
(9,962)
45,116
29,530
176,020
Other comprehensive loss for the year
(28)
Total Comprehensive (loss) profit for the year 2024
6,156
6,274
(43,687)
(43,691)
(30,035)
Total 2024
(37,531)
(67,452)
Balances as of December 31, 2024
Other comprehensive (loss) profit for the year
12,591
Total Comprehensive (loss) profit for the year 2025
5,966
(1,500)
4,467
(24,203)
Total 2025
(25,703)
(19,736)
Balances as of December 31, 2025
CONSOLIDATED STATEMENT OF CASH FLOWS
Amounts in US$‘000
Adjustments to reconcile profit to net cash flows for:
Income tax (benefit) expense
(1,016)
145,792
103,441
117,190
130,659
120,934
Loss on disposal of property, plant and equipment
426
30,989
13,332
13,422
14,779
29,563
Interest and amortization of debt issue costs
49,298
31,088
30,839
Borrowings cancellation gain, net
(3,917)
Amortization of other long-term liabilities
(107)
(127)
Unwinding of long-term liabilities
4,780
5,153
6,456
Share-based payment expenses
Foreign exchange loss (gain)
10,065
(12,160)
19,729
Income tax paid (a)
(96,870)
(66,805)
(115,626)
Changes in working capital
(163,309)
119,941
(26,425)
Cash flows from operating activities – net
Purchase of property, plant and equipment
(98,358)
(191,310)
(199,040)
Acquisitions of business
34.1
(115,518)
Unconsummated transaction in Argentina
34.5
38,000
(38,000)
Proceeds from divestment of long-term assets
34.2-34.3-34.4
20,381
2,455
450
Cash flows used in investing activities – net
Proceeds from borrowings
553,000
10,728
Debt issuance costs paid
(5,034)
Principal paid
(512,629)
(731)
Interest paid
(41,523)
(27,736)
(27,500)
Lease payments
(5,733)
(10,267)
Repurchase of shares
Cash distribution
24.2
Cash flows used in financing activities – net
Cash and cash equivalents at January 1
133,036
128,843
480
(1,222)
566
Cash and cash equivalents at the end of the year
Cash and cash equivalents are comprised by:
Cash in bank and bank deposits
100,317
276,739
133,023
Cash in hand
NOTES TO CONSOLIDATED FINANCIAL STATEMENTS
Note 1 General Information
GeoPark Limited (the “Company”) is a company incorporated under the law of Bermuda. The Registered Office address is Clarendon House, 2 Church Street, Hamilton HM11, Bermuda.
The principal activities of the Company and its subsidiaries (the “Group” or “GeoPark”) are exploration, development and production for oil and gas reserves in Latin America.
These Consolidated Financial Statements were authorized for issue by the Board of Directors and approved to be included in our 2025 annual report (Form 20-F) on March 31, 2026.
Note 2 Summary of significant accounting policies
The principal accounting policies applied in the preparation of these Consolidated Financial Statements are set out below. These policies have been consistently applied to the years presented, unless otherwise stated.
2.1 Basis of preparation
The Consolidated Financial Statements of GeoPark Limited have been prepared in accordance with IFRS Accounting Standards (“IFRS”) as issued by the International Accounting Standards Board (“IASB”), under the historical cost basis, except for the following: certain financial assets and liabilities (including derivative instruments) measured at fair value, and assets held for sale – measured at fair value less costs to sell.
The Consolidated Financial Statements are presented in thousands of United States Dollars (US$’000) and all values are rounded to the nearest thousand (US$’000), except in the footnotes and where otherwise indicated.
The preparation of financial statements in conformity with IFRS requires the use of certain critical accounting estimates. It also requires management to exercise its judgement in the process of applying the Group’s accounting policies. The areas involving a higher degree of judgement or complexity, or areas where assumptions and estimates are significant to the Consolidated Financial Statements are disclosed in this note under the title “Accounting estimates and assumptions”.
All the information included in these Consolidated Financial Statements corresponds to the Group, except where otherwise indicated.
2.1.1 Changes in accounting policy and disclosure
2.1.1.1 New and amended standards and interpretations
The Group applied for the first-time certain standards and amendments, which are effective for annual periods beginning on or after January 1, 2025, as follows:
Lack of Exchangeability - Amendments to IAS 21
For annual reporting periods beginning on or after January 1, 2025, Lack of Exchangeability – Amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates specifies how an entity should assess whether a currency is exchangeable and how it should determine a spot exchange rate when exchangeability is lacking. The amendments also require disclosure of information that enables users of its financial statements to understand how the currency not being exchangeable into the other currency affects, or is expected to affect, the entity’s financial performance, financial position and cash flows.
These amendments had no impact on the Consolidated Financial Statements of the Group.
2.1.1.2 Standards issued but not yet effective
The new and amended standards and interpretations that have been issued, but are not yet effective, as of the date of issuance of these Consolidated Financial Statements are disclosed below. The Group has not early adopted these new and amended standards and interpretations, and intends to adopt them, if applicable, when they become effective.
IFRS 18 Presentation and Disclosure in Financial Statements
In April 2024, the IASB issued IFRS 18, which replaces IAS 1 Presentation of Financial Statements. IFRS 18 introduces new requirements for presentation within the statement of profit or loss, including specified totals and subtotals. Furthermore, entities are required to classify all income and expenses within the statement of profit or loss into one of five categories: operating, investing, financing, income taxes and discontinued operations, whereof the first three are new.
The standard requires disclosure of newly defined management-defined performance measures, subtotals of income and expenses, and it also includes new requirements for aggregation and disaggregation of financial information based on the identified ‘roles’ of the primary financial statements and the notes.
In addition, narrow-scope amendments have been made to IAS 7 Statement of Cash Flows, which include changing the starting point for determining cash flows from operations under the indirect method, from ‘profit or loss’ to ‘operating profit or loss’ and removing the optionality around classification of cash flows from dividends and interest. In addition, there are consequential amendments to several other standards.
IFRS 18, and the amendments to the other standards, are effective for reporting periods beginning on or after January 1, 2027, but earlier application is permitted and must be disclosed. IFRS 18 will apply retrospectively.
The Group is currently working to identify all impacts the amendments will have on the primary financial statements and notes to the financial statements. The initial expected material impacts on Group’s financial statements are, as follows:
IFRS 19 Subsidiaries without Public Accountability: Disclosures
In May 2024, the IASB issued IFRS 19, which allows eligible entities to elect to apply its reduced disclosure requirements while still applying the recognition, measurement and presentation requirements in other IFRS accounting standards. To be eligible, at the end of the reporting period, an entity must be a subsidiary as defined in IFRS 10, cannot have public accountability and must have a parent (ultimate or intermediate) that prepares consolidated financial statements, available for public use, which comply with IFRS accounting standards.
IFRS 19 will become effective for reporting periods beginning on or after January 1, 2027, with early application permitted.
As the Group’s equity instruments are publicly traded, it is not eligible to elect to apply IFRS 19.
Amendments to the Classification and Measurement of Financial Instruments - Amendments to IFRS 9 and IFRS 7
In May 2024, the IASB issued Amendments to IFRS 9 and IFRS 7, Amendments to the Classification and Measurement of Financial Instruments (the Amendments). The Amendments include:
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The Amendments are effective for annual periods starting on or after January 1, 2026, with early adoption permitted for classification of financial assets and related disclosures only. The Group does not anticipate that the amendments will have a material effect on the Group’s financial statements.
Annual Improvements to IFRS Accounting Standards - Volume 11
In July 2024, the IASB issued nine narrow scope amendments as part of its periodic maintenance of IFRS accounting standards. The amendments include clarifications, simplifications, corrections or changes to improve consistency in IFRS 1 First-time Adoption of International Financial Reporting Standards, IFRS 7 Financial instruments: Disclosure and its accompanying Guidance on implementing IFRS 7, IFRS 9 Financial Instruments, IFRS 10 Consolidated Financial Statements and IAS 7 Statements of Cash Flows.
The amendments will be effective for reporting periods beginning on or after January 1, 2026. Earlier application is permitted and must be disclosed.
The amendments are not expected to have a material impact on the Group’s financial statements.
Contracts Referencing Nature-dependent Electricity - Amendments to IFRS 9 and IFRS 7
In December 2024, the IASB issued Amendments to IFRS 9 and IFRS 7 - Contracts Referencing Nature-dependent Electricity. The amendments apply only to contracts that reference nature-dependent electricity; the amendments:
The amendments will take effect for annual reporting periods starting on or after January 1, 2026. Early adoption is allowed, but it must be disclosed. The amendments concerning the own-use exception are to be applied retrospectively, while the hedge accounting amendments should be applied prospectively to new hedging relationships designated from the initial application date. Additionally, the IFRS 7 disclosure amendments must be implemented alongside the IFRS 9 amendments. If an entity does not restate comparative information, it cannot present comparative disclosures.
The Group does not expect that the amendments will have a material impact on its financial statements.
2.2 Going concern
The Directors regularly monitor the Group’s cash position and liquidity risks throughout the year to ensure that it has sufficient funds to meet forecasted operational and investment funding requirements. Sensitivities are run to reflect latest expectations of expenditures, oil and gas prices and other factors to enable the Group to manage the risk of any funding short falls and/or potential debt covenant breaches.
Considering the performance of the operations, the Group’s cash position of US$ 100,318,000, the oil hedges to mitigate the price risk exposure within the next twelve to eighteen months, and the fact that, as of December 31, 2025, 83% of its total indebtedness matures in January 2030, the Directors have formed a judgement, at the time of approving the Consolidated Financial Statements, that there is a reasonable expectation that the Group has adequate resources to meet
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all its obligations for the foreseeable future. For this reason, the Directors have continued to adopt the going concern basis in preparing the Consolidated Financial Statements.
2.3 Consolidation
Subsidiaries are all entities over which the Group has control. The Group controls an entity when the Group is exposed to, or has rights to, variable returns from its involvement with the entity and has the ability to affect those returns through its power over the entity. Subsidiaries are fully consolidated from the date on which control is transferred to the Group. They are deconsolidated from the date that control ceases.
Intercompany transactions, balances and unrealized gains on transactions between the Group and its subsidiaries are eliminated. Unrealized losses are also eliminated unless the transaction provides evidence of an impairment of the asset transferred. Amounts reported in the financial statements of subsidiaries have been adjusted where necessary to ensure consistency with the accounting policies adopted by the Group.
2.4 Segment reporting
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the Chief Executive Officer, Chief Financial Officer, Chief Exploration and Development Officer, Chief Operating Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports.
2.5 Foreign currency translation
2.5.1 Functional and presentation currency
The Consolidated Financial Statements are presented in U.S. Dollars, which is the Group’s presentation currency.
Items included in the Consolidated Financial Statements of each of the Group’s entities are measured using the currency of the primary economic environment in which the entity operates (the “functional currency”). The functional currency of Group companies incorporated in Colombia, Argentina and Ecuador is the U.S. Dollar, meanwhile for the Group’s Brazilian company the functional currency is the local currency, which is the Brazilian Real.
2.5.2 Transactions and balances
Foreign currency transactions are translated into the functional currency using the exchange rates prevailing at the dates of the transactions. Foreign exchange gains and losses resulting from the settlement of such transactions and from the translation at period-end exchange rates of monetary assets and liabilities denominated in foreign currencies are recognized in the Consolidated Statement of Income.
The results and financial position of foreign operations that have a functional currency different from the presentation currency are translated into the presentation currency as follows: assets and liabilities are translated at the closing rate, and income and expenses are translated at average exchange rates. All resulting exchange differences are recognized in Other comprehensive income.
2.6 Joint arrangements
Under IFRS 11, investments in joint arrangements are classified as either joint operations or joint ventures depending on the contractual rights and obligations of each investor. The Group has assessed the nature of its joint arrangements and determined them to be joint operations. The Group accounts for the assets, liabilities, revenues and expenses relating to its interest in joint operations in accordance with the IFRSs applicable to such assets, liabilities, revenues and expenses.
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2.7 Business combinations
Business combinations are accounted for using the acquisition method. The cost of an acquisition is measured as the aggregate of the consideration transferred, which is measured at the acquisition date fair value, and the amount of any non-controlling interests in the acquiree. For each business combination, the Group elects whether to measure the non-controlling interests in the acquiree at fair value or at the proportionate share of the acquiree’s identifiable net assets. Acquisition-related costs are expensed as incurred and included in administrative expenses.
The Group determines that it has acquired a business when the acquired set of activities and assets include an input and a substantive process that together significantly contribute to the ability to create outputs. The acquired process is considered substantive if it is critical to the ability to continue producing outputs, and the inputs acquired include an organized workforce with the necessary skills, knowledge, or experience to perform that process or it significantly contributes to the ability to continue producing outputs and is considered unique or scarce or cannot be replaced without significant cost, effort, or delay in the ability to continue producing outputs.
When the Group acquires a business, it assesses the financial assets and liabilities assumed for appropriate classification and designation in accordance with the contractual terms, economic circumstances and pertinent conditions as at the acquisition date. This includes the separation of embedded derivatives in host contracts by the acquiree.
Any contingent consideration to be transferred by the acquirer will be recognized at fair value at the acquisition date. Contingent consideration classified as equity is not remeasured and its subsequent settlement is accounted for within equity. Contingent consideration classified as an asset or liability that is a financial instrument and within the scope of IFRS 9 Financial Instruments, is measured at fair value with the changes in fair value recognized in the statement of profit or loss in accordance with IFRS 9. Other contingent consideration that is not within the scope of IFRS 9 is measured at fair value at each reporting date with changes in fair value recognized in profit or loss.
Goodwill is initially measured at cost (being the excess of the aggregate of the consideration transferred and the amount recognized for non-controlling interests and any previous interest held over the net identifiable assets acquired and liabilities assumed). If the fair value of the net assets acquired is in excess of the aggregate consideration transferred, the Group re-assesses whether it has correctly identified all of the assets acquired and all of the liabilities assumed and reviews the procedures used to measure the amounts to be recognized at the acquisition date. If the reassessment still results in an excess of the fair value of net assets acquired over the aggregate consideration transferred, then the gain is recognized in profit or loss.
2.8 Revenue recognition
Revenue from the sale of crude oil and gas is recognized at the point in time when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipe or other delivery mechanism and the customer accepts the product. Consequently, the Group’s performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place.
The Group’s sales of crude oil are priced based on market prices. The sales price is linked to U.S. Dollar denominated crude oil international benchmarks, such as Brent, adjusted for certain marketing and quality discounts based on, among other things, American Petroleum Institute (“API”) gravity, viscosity, sulphur content, delivery point and transport costs. The Group’s sales of natural gas, maily from the Manati gas field in Brazil, were priced based on long-term Gas Supply contracts with customers.
Revenue is shown net of VAT, discounts related to the sale and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. See Note 32.1.2.
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2.9 Production and operating costs
Production and operating costs are recognized in the Consolidated Statement of Income on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, and royalties and economic rights in cash are also included within this account.
2.10 Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. The Group has capitalized the borrowing cost directly attributable to wells and facilities identified as qualifying assets, if applicable. Qualifying assets are assets that necessarily take a substantial period of time to get ready for their intended use or sale. The capitalization rate used to determine the amount of borrowing costs to be capitalized, if any, is the weighted average interest rate applicable to the Group’s general borrowings.
2.11 Property, plant and equipment
Property, plant and equipment are stated at historical cost less depreciation and impairment charges, if applicable. Historical cost includes expenditure that is directly attributable to the acquisition of the items; including provisions for asset retirement obligation.
Oil and gas exploration and production activities are accounted for in accordance with the successful efforts method on a field by field basis. The Group accounts for exploration and evaluation activities in accordance with IFRS 6, Exploration for and Evaluation of Mineral Resources, capitalizing exploration and evaluation costs until such time as the economic viability of producing the underlying resources is determined. Costs incurred prior to obtaining legal rights to explore are expensed immediately to the Consolidated Statement of Income.
Exploration and evaluation costs may include: license acquisition, geological and geophysical studies (i.e., seismic), direct labor costs and drilling costs of exploratory wells. No depreciation and/or amortization are charged during the exploration and evaluation phase. Upon completion of the evaluation phase, the prospects are either transferred to oil and gas properties or charged to expense (exploration costs) in the period in which the determination is made, depending on whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable.
A charge of US$ 13,422,000 has been recognized in the Consolidated Statement of Income within the ‘Write-off of unsuccessful exploration efforts’ line item (US$ 14,779,000 in 2024 and US$ 29,563,000 in 2023). See Note 18.
All field development costs are considered construction in progress until they are finished and capitalized within oil and gas properties, and are subject to depreciation once completed. Such costs may include the acquisition and installation of production facilities, development drilling costs (including dry holes, service wells and seismic surveys for development purposes), project-related engineering and the acquisition costs of rights and concessions related to proved properties.
Workovers of wells made to develop reserves and/or increase production are capitalized as development costs. Maintenance costs are charged to the Consolidated Statement of Income when incurred.
Capitalized costs of proved oil and gas properties and production facilities and machinery are depreciated on a licensed area by the licensed area basis, using the unit of production method, based on commercial proved and probable oil and gas reserves. The calculation of the “unit of production” depreciation considers estimated future finding and development costs and is based on current year-end price levels. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.
Depreciation of the remaining property, plant and equipment assets (i.e., furniture and vehicles) not directly associated with oil and gas activities has been calculated by means of the straight-line method by applying such annual rates as required to write-off their value at the end of their estimated useful lives. The useful lives range between 3 years and 10 years.
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Depreciation is allocated in the Consolidated Statement of Income as a separate line to better follow the performance of the business.
An asset’s carrying amount is written down immediately to its recoverable amount if the asset’s carrying amount is greater than its estimated recoverable amount (see Impairment of non-financial assets in Note 2.13).
2.12 Provisions and other long-term liabilities
Provisions for asset retirement obligations and other environmental liabilities, deferred income, restructuring obligations and legal claims are recognized when the Group has a present legal or constructive obligation as a result of past events, it is probable that an outflow of resources will be required to settle the obligation, and the amount has been reliably estimated. Restructuring provisions, if any, comprise lease termination penalties and employee services termination payments.
Provisions are measured at the present value of the expenditures expected to be required to settle the obligation using a pre-tax rate that reflects current market assessments of the time value of money and the risks specific to the obligation. The increase in the provision due to the passage of time is recognized as financial expense.
2.12.1 Asset Retirement Obligation
The Group records the fair value of the liability for asset retirement obligations in the period in which the wells are drilled. When the liability is initially recorded, the Group capitalizes the cost by increasing the carrying amount of the related long-lived asset. Over time, the liability is accreted to its present value at each reporting period, and the capitalized cost is depreciated over the estimated useful life of the related asset. According to interpretations and the application of current legislation, and on the basis of the changes in technology and the variations in the costs of restoration necessary to protect the environment, the Group has considered it appropriate to periodically re-evaluate future costs of well-capping.
The effects of this recalculation are included in the Consolidated Financial Statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset.
2.12.2 Deferred Income
Government grants and other contributions relating to the purchase of property, plant and equipment are included in non-current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions.
2.13 Impairment of non-financial assets
An impairment loss is recognized for the excess of the asset’s carrying amount over its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.
No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable.
Impairment losses were recognized for US$ 30,989,000 in 2025 (no impairment losses were recognized in 2024 and US$ 13,332,000 were recognized in 2023). See Note 34. The write-offs are detailed in Note 18.
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2.14 Lease contracts
The Group assesses at contract inception whether a contract is, or contains, a lease. That is, if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration.
Group as a lessee
The Group applies a single recognition and measurement approach for all leases, except for short-term leases and leases of low-value assets. The Group recognizes lease liabilities to make lease payments and right-of-use assets representing the right to use the underlying assets.
2.14.1 Right-of-use assets
The Group recognizes right-of-use assets at the commencement date of the lease. Right of use assets are measured at cost, less any accumulated depreciation and impairment losses, an adjusted for any measurement of lease liabilities.
The cost of right-of-use assets comprise the following:
The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of 1 to 15 years but may have extension options. Lease terms are negotiated on an individual basis and contain a wide range of different terms and conditions. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. The right-of-use assets are also subject to impairment.
2.14.2 Lease liabilities
At the commencement date of the lease, the Group recognizes lease liabilities measured at the present value of lease payments to be made over the lease term. Lease liabilities include the net present value of the following lease payments:
In calculating the present value, the lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the Group’s incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.
2.14.3 Short-term leases and leases of low-value assets
The Group applies the short-term lease recognition exemption to its short-term leases of machinery and equipment (i.e., those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of IT equipment and small items of
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office furniture that are considered to be low value. Lease payments on short-term leases and leases of low-value assets are recognized as expense on a straight-line basis over the lease term.
2.15 Inventories
Inventories comprise crude oil and materials. Crude oil is measured at the lower of cost and net realizable value. Materials are measured at the lower of cost and recoverable amount. The cost of materials and consumables is calculated at acquisition price with the addition of transportation and similar costs. Cost is determined using the first-in, first-out (FIFO) method.
2.16 Current and deferred income tax
The tax expense for the year comprises current and deferred income tax. Income tax is recognized in the Consolidated Statement of Income.
The current income tax charge is calculated on the basis of the tax laws enacted or substantially enacted at the financial statements date in the countries where the Company’s subsidiaries operate and generate taxable income. The computation of the income tax expense involves the interpretation of applicable tax laws and regulations in many jurisdictions. The resolution of tax positions taken by the Group, through negotiations with relevant tax authorities or through litigation, can take several years to complete and, in some cases, it is difficult to predict the ultimate outcome. Therefore, current income tax assets and liabilities are measured at the amount expected to be recovered from or paid to the taxation authorities.
Current income tax relating to items recognized directly in equity is recognized in equity and not in the statement of profit or loss. Management periodically evaluates positions taken in the tax returns with respect to situations in which applicable tax regulations are subject to interpretation and establishes provisions where appropriate.
Deferred income tax is recognized, using the liability method, on temporary differences arising between the tax bases of assets and liabilities and their carrying amounts in the Consolidated Financial Statements. Deferred income tax is determined using tax rates (and laws) that have been enacted or substantially enacted as of the financial statements date and are expected to apply when the related deferred income tax asset is realized, or the deferred income tax liability is settled. In addition, the Group has tax-loss carry-forwards in certain tax jurisdictions that are available to be offset against future taxable profit. However, deferred income tax assets are recognized only to the extent that it is probable that taxable profit will be available against which the unused tax losses can be utilized. Management judgment is exercised in assessing whether this is the case. To the extent that actual outcomes differ from management’s estimates, taxation charges or credits may arise in future periods.
Deferred income tax liabilities are provided on taxable temporary differences arising from investments in subsidiaries and joint arrangements, except for deferred income tax liability where the timing of the reversal of the temporary difference is controlled by the Group and it is probable that the temporary difference will not reverse in the foreseeable future. The Group is able to control the timing of dividends from its subsidiaries and hence does not expect taxable profit. Hence deferred income tax is recognized in respect of the retained earnings of overseas subsidiaries only if at the date of the Consolidated Financial Statements, dividends have been accrued as receivable or a binding agreement to distribute past earnings in future has been entered into by the subsidiary. As mentioned above the Group does not expect that the temporary differences will revert in the foreseeable future.
Deferred income tax balances are provided in full, with no discounting.
2.17 Non-current assets or disposal groups held for sale
Non-current assets or disposal groups are classified as held for sale if their carrying amount will be recovered principally through a sale transaction rather than through continuing use and a sale is considered highly probable. They are measured at the lower of their carrying amount and fair value less costs to sell, except for assets such as deferred tax assets, assets arising from employee benefits, financial assets and investment property that are carried at fair value and contractual rights under insurance contracts, which are specifically exempt from this requirement.
F-20
An impairment loss is recognized for any initial or subsequent write-down of the asset or disposal group to fair value less costs to sell. A gain is recognized for any subsequent increases in fair value less costs to sell of an asset or disposal group, but not in excess of any cumulative impairment loss previously recognized. A gain or loss not previously recognized by the date of the sale of the non-current asset or disposal group is recognized at the date of derecognition.
Non-current assets (including those that are part of a disposal group) are not depreciated or amortized while they are classified as held for sale. Interest and other expenses attributable to the liabilities of a disposal group classified as held for sale continue to be recognized.
Non-current assets classified as held for sale and the assets of a disposal group classified as held for sale are presented separately from the other assets in the Consolidated Statement of Financial Position. The liabilities of a disposal group classified as held for sale are presented separately from other liabilities in the Consolidated Statement of Financial Position.
2.18 Financial assets
Financial assets are divided into the following categories: amortized cost; financial assets at fair value through profit or loss and fair value through other comprehensive income. The classification depends on the Group’s business model for managing the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when its business model for managing those assets changes.
All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs. Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss.
Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date.
Interest and other cash flows resulting from holding financial assets are recognized in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured.
Amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. These financial assets comprise trade and other receivables and cash and cash equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, less provision for impairment, if applicable.
Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of Income. All of the Group’s financial assets are classified as amortized cost.
2.19 Other financial assets
Non-current other financial assets include contributions made for environmental obligations according to a Colombian government request and are restricted for those purposes.
Current other financial assets include short-term investments with original maturities up to twelve months and over three months.
2.20 Impairment of financial assets
The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied depends on whether there has been a significant increase in credit risk. For trade receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial recognition of the receivables.
F-21
2.21 Cash and cash equivalents
Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts, if any.
2.22 Trade and other payables
Trade payables are obligations to pay for goods or services that have been acquired in the ordinary course of the business from suppliers. Accounts payable are classified as current liabilities if payment is due within one year or less (or in the normal operating cycle of the business if longer). If not, they are presented as non-current liabilities.
Trade payables are recognized initially at fair value and subsequently measured at amortized cost using the effective interest method.
2.23 Derivatives and hedging activities
Derivative financial instruments are recognized in the Consolidated Statement of Financial Position as assets or liabilities and initially and subsequently measured at fair value. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period.
The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy.
2.23.1 Cash flow hedges that qualify for hedge accounting
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion is recognized immediately in the Consolidated Statement of Income.
When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the forward contracts are recognized in Other Reserves within Equity.
Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost of the asset.
When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately reclassified to the Consolidated Statement of Income.
For more information about derivatives designated as cash flow hedges please refer to Notes 7.1 and 8.1.
2.23.2 Other Derivatives
Certain derivative instruments do not qualify for hedge accounting. Changes in the fair value of any derivative instrument that does not qualify for hedge accounting are recognized immediately in the Consolidated Statement of Income.
For more information about derivatives related to commodity risk management please refer to Note 14.1 and for more information about derivatives related to currency risk management please refer to Note 3 Currency risk.
F-22
2.24 Borrowings
Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument.
Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the Consolidated Statement of Income over the period of the borrowings using the effective interest method.
Direct issue costs are charged to the Consolidated Statement of Income on an accrual basis using the effective interest method.
2.25 Share capital
Equity comprises the following:
2.26 Share-based payment
The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to employees and other third-party contractors. Share-based payment transactions are measured in accordance with IFRS 2.
The fair value of the share awards payments is determined at the grant date by reference to the market value of the shares, calculated using the Geometric Brownian Motion method or the Monte Carlo simulation, and recognized as an expense over the vesting period.
Service and non-market performance conditions are not taken into account when determining the grant date fair value of awards, but the likelihood of the conditions being met is assessed as part of the Group’s best estimate of the number of equity instruments that will ultimately vest. Market performance conditions are reflected within the grant date fair value. Any other conditions attached to an award, but without an associated service requirement, are considered to be non-vesting conditions. Non-vesting conditions are reflected in the fair value of an award and lead to an immediate expensing of an award unless there are also service and/or performance conditions.
No expense is recognized for awards that do not ultimately vest because non-market performance and/or service conditions have not been met. Where awards include a market or non-vesting condition, the transactions are treated as vested irrespective of whether the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied.
At each reporting date, the entity revises its estimates of the number of options that are expected to vest. It recognizes the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment to equity.
When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium.
F-23
Note 3 Financial Instruments-risk management
The Group is exposed through its operations to the following financial risks:
The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is described in more detail below.
Currency risk
In Colombia and Argentina the functional currency is the U.S. Dollar. The fluctuation of the local currencies of these countries against the U.S. Dollar does not impact the loans, costs and revenue held in U.S. Dollars; but it does impact receivables, payables and costs originated in local currency mainly corresponding to VAT, income tax, labor costs and local services.
The Group minimises the local currency positions in Colombia and Argentina by seeking to balance local and foreign currency assets and liabilities. However, tax receivables (VAT) seldom match with local currency liabilities. Therefore, the Group maintains a net exposure to them, except for what it is described below.
From time to time, the Group uses derivative financial instruments to mitigate the exposure to local currency fluctuations, primarily those related to tax payments and operating costs denominated in Colombian peso. These instruments are entered into in line with the Group’s currency risk management policy. See Note 14.1.
Most of the Group’s assets held in those countries are associated with oil and gas productive assets. Those assets, even in the local markets, are generally settled in U.S. Dollar equivalents.
During 2025, the Colombian Peso revalued by 15% (devalued by 15% in 2024 and revalued by 21% in 2023) and the Argentine Peso devalued by 41% (28% and 356% in 2024 and 2023, respectively), all against the U.S. Dollar.
If the Colombian Peso and the Argentine Peso had each devalued an additional 10% against the U.S. Dollar at year-end, with all other variables held constant, post-tax profit for the year would have been higher by US$ 6,227,000 (US$ 11,404,000 in 2024 and US$ 13,971,000 in 2023).
In Brazil, the functional currency is the Brazilian Real. Accordingly, fluctuations in the U.S. Dollar against the Brazilian Real do not affect loans, costs, and revenues denominated in Brazilian Real; however, they do affect balances denominated in U.S. Dollars. This was the case for the asset retirement obligation provision and the lease liabilities related to the Manati gas field. During 2025, the Brazilian Real revalued by 11% against the U.S. Dollar (devalued by 28% in 2024 and revalued by 7% in 2023). As of December 31, 2025, following the divestment of Manati gas field (see Note 34.2), there were no material U.S. Dollar–denominated balances; therefore, the Group’s year-end results were not exposed to fluctuations in the Brazilian Real.
As currency rate changes between the U.S. Dollar and the local currencies, the Group recognizes gains and losses in the Consolidated Statement of Income.
F-24
Price risk
The realized oil price for the Group is linked to U.S. Dollar denominated crude oil international benchmarks. The market price of this commodity is subject to significant volatility and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil, the geopolitical landscape, armed conflicts, the economic conditions and a variety of additional factors. The main factors affecting realized prices for gas sales vary across countries with some closely linked to international references while others are more domestically driven.
In Colombia, the realized oil price is based on Brent, adjusted by a differential linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador. The Oriente reference is specifically used for crude oil from the Putumayo Basin that is transported through Ecuador. In both basins, the reference price is further adjusted for marketing and quality discounts, considering factors such as API gravity, viscosity, sulphur content, delivery point and transport costs.
In Argentina, the realized oil price is based on Brent, adjusted by the Medanito differential, the Neuquén Basin benchmark. Realized prices also reflect quality and logistics adjustments, including API gravity, treatment costs and transportation expenses.
GeoPark seeks to partially mitigate its exposure to crude oil price volatility using derivatives by hedging a portion of its production for a limited period going forward. The Group uses a combination of options to manage its exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. GeoPark has also obtained credit lines from different counterparties to minimize the potential cash exposure of the derivative contracts. See Note 7.1.
If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$ 8,244,000 (US$ 24,844,000 in 2024 and US$ 32,335,000 in 2023).
Credit risk– concentration
The Group’s credit risk relates mainly to accounts receivable where the credit risks correspond to the recognized values of commodities sold or hedged. GeoPark considers that there is no significant risk associated to the Group’s major customers and hedging counterparties.
In Colombia, GeoPark allocates its sales on a competitive basis to industry leading participants including traders and other producers. During 2025, the oil and gas production was sold to three clients which concentrate 97% of the Colombian subsidiaries’ revenue, accounting for 94% of the consolidated revenue (95% and 96% of the Colombian subsidiaries’ revenue, accounting for 89% and 97% of the consolidated revenue in 2024 and 2023). GeoPark works with different leading commodity traders throughout the year. The main contracts for Colombian production include offtake agreements with Vitol C.I. Colombia S.A.S. (“Vitol”) and BP Products North America Inc. ("BP"), all recognized as industry-leading global traders with strong credit profiles (see Note 29).
Delivery points include wellhead and other locations on the Colombian pipeline system for the Llanos Basin production. The Putumayo Basin production is delivered to clients FOB in Esmeraldas, Ecuador, and to the Colombian pipeline system in case of contingencies in Ecuador that affect the transport through the Ecuadorian pipeline system. GeoPark manages its counterparty credit risk associated to sales contracts by periodic evaluation of the counterparties’ credit profile and, in certain contracts, including early payment conditions to minimize the exposure.
In Argentina, sales from the recently acquired operated assets are concentrated in Pluspetrol under a transitional marketing arrangement, during which Pluspetrol acts as the sole commercial counterparty. Once this transitional period concludes, GeoPark expects to reassess this strategy, including direct commercialization of its production. Sales of crude oil in Argentina accounted for 1% of the consolidated revenue in 2025.
F-25
GeoPark Limited has entered into a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside the Group’s Putumayo Basin production. Sales of crude oil purchased from third parties accounted for 1% of the consolidated revenue in 2025, 2024 and 2023.
The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk.
GeoPark executes oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions and trading companies; therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes 7.1 and 23.
The credit risk of cash in bank and bank deposits is limited since the counterparties are banks with high credit ratings. As of December 31, 2025, 99% of cash and cash equivalents were maintained in banks ranked within investment grade category.
Funding and Liquidity risk
In the past, the Group has been able to raise capital through different sources of funding including equity, strategic partnerships and financial debt.
At the end of 2025, the Group maintained a cash position of US$ 100,318,000, had access to up to US$ 45,000,000 of committed prepayment facilities with BP (see Note 29), a US$ 100,000,000 senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. and US$ 200,305,000 in uncommitted credit lines (including US$ 95,000,000 in Argentina), and 83% of its total indebtedness maturing in January 2030. In addition, the Group has a large portfolio of attractive and largely discretional projects - both oil and gas - in multiple countries with net average production of 28,233 boepd for the year ended December 31, 2025. This scale and positioning permit the Group to protect its financial condition and selectively allocate capital to the optimal projects subject to prevailing macroeconomic conditions.
The Indentures governing the Company Notes 2027 and 2030 include incurrence test covenants related to compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indentures’ provisions and covenants.
In 2024, GeoPark Argentina S.A., obtained an “AA+(arg)” credit rating from Fitch Ratings’ local Argentine affiliate, FIX, and received approval from the Argentine securities regulator (Comisión Nacional de Valores, or “CNV” by its Spanish acronym) for the creation of a program to issue up to US$ 500,000,000 in debt securities over the following five years, providing strategic financial flexibility to support the future development of the Argentine assets in the Vaca Muerta shale formation.
In January 2025, the Company issued US$ 550,000,000 aggregate principal amount of 8.75% senior notes due 2030 (the “Notes due 2030”). From June to October 2025, the Company executed a deleveraging process by repurchasing through open market transactions and cancelling with the trustee a nominal amount of US$ 108,321,000 of Notes due 2030. See Note 25.
After the balance sheet date, GeoPark renewed and expanded its offtake and prepayment agreement with Vitol, providing access to a new prepayment facility of up to US$ 500,000,000 (US$ 330,000,000 committed with an option to increase by up to US$ 170,000,000) at SOFR risk-free rate plus a margin of 3.50% per annum, available until June 30, 2027. “SOFR” (Secured Overnight Financing Rate) is a broad measure of the cost of borrowing cash overnight collateralized by treasury securities. See Note 29.1.
F-26
Interest rate risk
The Group’s interest rate risk could arise from long-term debt issued at variable rates, which would expose the Group to interest rate risk.
The Group does not currently face interest rate risk on its Notes due 2027 and Notes due 2030 (see Note 25), which carry fixed rates coupon of 5.50% and 8.75% per annum, respectively. Consequently, the accruals and interest payments are not substantially affected by changes in prevailing interest rates.
As of December 31, 2025, the outstanding debt affected by a variable rates comprises the Vitol prepayment of US$ 2,182,000 (see Note 29.1) and the loan agreement with Bancolombia Panamá, S.A. of US$ 3,000,000 (see Note 25).
If the variable interest rate had increased by 10% compared to the actual rate during the period in which the debt was outstanding, with all other variables held constant, post-tax profit for the year would have been lower by US$ 69,000 (US$ 44,000 in 2024).
As of December 31, 2025, there were no other outstanding debt affected by a variable rate.
Capital risk
The Group’s objectives when managing capital are to safeguard the Group’s ability to continue as a going concern in order to provide returns for shareholders and benefits for other stakeholders and to maintain an optimal capital structure to reduce the cost of capital. The Group manages its capital structure and makes adjustments in light of changes in economic conditions, operating risks and working capital requirements. To maintain or adjust its capital structure, the Group may issue or buy back shares, change its dividend policy, raise or refinance debt and/or adjust its capital expenditures to manage its operating and growth objectives. Additionally, the Group utilizes a planning, budgeting and forecasting process to help determine and monitor the funds needed to maintain appropriate liquidity for operational, capital and financial needs.
As of December 31, 2025 and 2024, GeoPark is in compliance with the debt covenant ratios associated with the Company’s Notes due 2027 and 2030. See Note 25.
The following table summarizes the Group’s capital structure balances:
Total Equity
Net Debt (a)
455,411
389,583
Working capital (b)
82,454
61,438
F-27
Note 4 Accounting estimates and assumptions
Estimates and assumptions are used in preparing financial statements. Although these estimates are based on management’s best knowledge of current events and actions, actual results may differ. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.
The key estimates and assumptions used in these Consolidated Financial Statements are noted below:
It incorporates many factors and assumptions including:
Management believes these factors and assumptions are reasonable based on the information available to them at the time of preparing the estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment may require revision -where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities- and, (d) the recognition and carrying value of deferred income tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets.
F-28
The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available.
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved and probable reserves, or future capital expenditure estimates change. Changes to proved and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues.
The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.
The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required.
F-29
Note 5 Consolidated Statement of Cash Flows
The Consolidated Statement of Cash Flows shows the Group’s cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents during the year.
Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital and corporate tax. Income tax paid is presented as a separate item under operating activities.
Cash flows from investing activities include payments in connection with the purchase and sale of property, plant and equipment and cash flows relating to the purchase and sale of enterprises to third parties, if any.
Cash flows from financing activities include changes in equity and proceeds from borrowings and repayment of loans.
The following chart describes non-cash transactions related to the Consolidated Statement of Cash Flows:
Increase in asset retirement obligation
1,326
2,162
7,374
Increase in provisions for other long-term liabilities
2,700
157
2,370
Purchase of property, plant and equipment on deferred terms
(7,864)
Additions / changes in estimates of right-of-use assets
239
2,603
Changes in working capital shown in the Consolidated Statement of Cash Flows are disclosed as follows:
(Increase) Decrease in Inventories
(1,886)
1,664
(1,330)
Decrease in Trade receivables
1,071
23,876
6,820
Decrease (Increase) in Prepayments and other receivables and Other assets (a)
22,592
(48,865)
(33,328)
Customer advance payments (b)
(149,818)
152,000
(Decrease) Increase in Trade and other payables
(35,268)
(8,734)
1,413
In addition to the variations explained in the footnotes above, changes in working capital during 2025 include lower trade and other payables at year-end due to cost efficiency measures and lower operational activity during the year, including the settlement of supplier balances in Ecuador operations divested in 2025, as well as higher crude oil volumes in transit to export terminals in the CPO-5 and Llanos 123 Blocks in Colombia, which were sold in early 2026.
F-30
The following chart shows the movements in the borrowings and lease liabilities for each of the periods presented:
Lease
Liabilities
As of January 1, 2023
497,642
32,051
529,693
Addition to lease liabilities
Accrual of borrowing's interests
Exchange difference
7,061
Divestments (Note 34.7)
Foreign currency translation
174
Unwinding of discount
3,168
As of December 31, 2023
500,981
32,298
533,279
(3,283)
(502)
(346)
2,928
As of December 31, 2024
25,923
540,256
3,057
3,076
Divestments (Notes 34.2)
(250)
2,759
Bond emission expenditures
25,995
579,542
Note 6 Segment information
Operating segments are reported in a manner consistent with the internal reporting provided to the chief operating decision-maker. The chief operating decision-maker, who is responsible for allocating resources and assessing performance of the operating segments, has been identified as the Executive Committee. This committee is integrated by the Chief Executive Officer, Chief Financial Officer, Chief Exploration and Development Officer, Chief Operating Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective. No operating segments have been aggregated to form the reportable segments.
F-31
The Executive Committee assesses the performance of the operating segments based on a measure of Adjusted EBITDA. Adjusted EBITDA is defined as profit (loss) for the period (determined in accordance with the indenture governing the 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. Other information provided to the Executive Committee is measured in a manner consistent with that in the Consolidated Financial Statements.
Segment areas (geographical segments)
Amounts in US$ ‘000
Argentina (a)
Brazil (b)
Ecuador (c)
447,624
5,767
200
6,235
Share-based payment
(368)
(32)
(400)
Operating costs
(115,436)
(3,398)
(4,491)
(7,743)
(131,385)
280,080
(4,460)
(440)
7,284
(5,323)
277,141
Recognition of impairment losses
Total assets
867,288
158,596
7,789
2,450
4,324
96,659
1,432
161
98,358
Chile (d)
617,989
1,858
2,820
(642)
(647)
(132,555)
(3,916)
(9,544)
(425)
(152,714)
419,320
(4,511)
(3,732)
14,746
(8,814)
(120)
416,889
885,438
215,755
14,040
48,333
36,489
167,002
24,057
191,310
F-32
702,401
14,019
19,097
5,464
15,644
702,308
490
5,052
726,947
903
13,529
10,592
25,024
(810)
(204,245)
(4,946)
(10,242)
(4,666)
(8,226)
(11,201)
(1,096)
(548)
(12,845)
(72,032)
(671)
(72)
(750)
(120,341)
(3,850)
(10,235)
(7,606)
(146,698)
446,835
(2,620)
6,374
5,159
(8,838)
4,952
451,862
(101,666)
(22)
(2,332)
(7,096)
(9,815)
895,900
357
27,891
40,336
15,873
36,192
1,016,549
178,113
20,889
199,040
A reconciliation of Adjusted EBITDA to Profit for the year is provided as follows:
(4,467)
(7,328)
Lease accounting - IFRS 16
5,733
7,775
10,267
Others (a)
(6,263)
594
(20,065)
Profit before tax
F-33
Note 7 Revenue
Commodity risk management contracts designated as cash flow hedges (a)
7.1 Commodity risk management contracts
The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars and zero-premium 3 ways (put spread plus call) were placed with major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protect the Group from potential non-performance risk by its counterparties.
The Group’s derivatives that hedge cash flows from the sales of crude oil are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in ‘Other Reserves’ within ‘Equity’. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in ‘Other Reserves’ is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the ‘Revenue’ line item in the Consolidated Statement of Income.
The following table presents the Group’s production hedged during the year ended December 31, 2025, and for the following periods as a consequence of the derivative contracts in force as of December 31, 2025:
Period
Reference
Type
Volume (bbl/d)
Weighted average price (US$/bbl)
January 1, 2025 - March 31, 2025
ICE BRENT
Zero Premium Collars
19,500
69.79 Put 82.48 Call
April 1, 2025 - June 30, 2025
19,000
69.26 Put 79.02 Call
July 1, 2025 - September 30, 2025
17,500
68.69 Put 78.59 Call
October 1, 2025 - December 31, 2025
16,000
68.25 Put 77.50 Call
January 1, 2026 - March 31, 2026
1,000
68.00 Put 77.40 Call
January 1, 2026 - December 31, 2026
Zero Premium 3 Ways
5,000
50.00-65.00 Put 70.93 Call
7,000
50.00-65.00 Put 73.86 Call
April 1, 2026 - June 30, 2026
50.00-65.00 Put 76.32 Call
July 1, 2026 - December 31, 2026
2,000
50.00-65.00 Put 69.35 Call
July 1, 2026 - September 30, 2026
6,000
50.00-65.00 Put 73.30 Call
October 1, 2026 - December 31, 2026
50.00-65.00 Put 73.90 Call
The following table presents the Group’s derivative contracts agreed after the balance sheet date:
52.00-64.00 Put 70.21 Call
67.00 Put 74.06 Call
52.14-64.57 Put 70.41 Call
12,000
51.67-63.92 Put 70.18 Call
January 1, 2027 - March 31, 2027
18,000
51.50-65.00 Put 71.25 Call
April 1, 2027 - June 30, 2027
15,000
50.80-65.00 Put 72.41 Call
July 1, 2027 - September 30, 2027
50.00-65.80 Put 77.24 Call
October 1, 2027 - December 31, 2027
50.00-65.80 Put 76.96 Call
F-34
Note 8 Production and operating costs
Amounts in US$ '000
Staff costs (Note 10)
15,604
15,697
13,889
Share-based payment (Note 10)
400
647
750
Royalties in cash (a)
6,195
4,189
12,845
Economic rights in cash (a)
3,079
72,032
25,675
25,631
26,089
8,239
8,936
8,143
Consumables (b)
31,398
36,868
37,556
7,511
5,716
4,314
4,095
5,409
5,850
4,822
6,401
6,546
4,213
4,937
5,487
2,393
3,586
3,363
3,120
3,893
2,291
1,857
1,753
1,865
19,697
22,305
20,421
(747)
976
2,004
317
4,666
3,191
4,332
4,214
141,059
164,034
232,325
8.1 Energy cost risk management contracts
In July 2025, GeoPark entered into a derivative financial instrument to manage its exposure to energy cost volatility in Colombia, particularly in the Llanos 34 Block, where electricity expenses represent a significant portion of its production and operating costs. This derivative is a Contract for Differences (“CfD”) on the generation component of the electricity tariff and is structured as a fixed-for-floating swap that settles financially against the wholesale spot market price. It is effective from August to December 2025, covering 12.5 MW (approximately 9 GWh/month) at a strike price of COP 312/kWh from August 2025 to September 2025 and COP 350/kWh from October 2025 to December 2025, indexed to the monthly Producer Price Index.
The Group’s CfD is designated and qualifies as a cash flow hedge. The effective portion of changes in the fair value of this derivative is recognized in Other Reserve within Equity. The gain or loss relating to the ineffective portion, if any, is recognized immediately as a gain or loss in the results of the periods in which it occurs. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss, as part of the Production and operating costs line item in the Consolidated Statement of Income.
F-35
Note 9 Depreciation
Depreciation of property, plant and equipment (Note 18)
Oil and gas properties
97,128
109,093
95,369
Production facilities and machinery
14,821
13,116
12,896
Furniture, equipment and vehicles
1,548
1,550
1,304
Buildings and improvements
247
191
503
113,744
123,950
110,072
Depreciation associated with crude oil stock variation
Capitalized costs for oil stock variation
159
281
2,212
Depreciation of right-of-use assets (Note 26)
2,670
5,156
7,858
617
1,272
792
3,287
6,428
8,650
Depreciation total
Related to:
Productive assets
114,778
127,646
118,335
Administrative assets
2,412
3,013
2,599
Note 10 Staff costs and Directors’ Remuneration
Wages and salaries
41,098
46,542
41,917
Share-based payments (Note 30)
Social security charges
7,507
6,967
5,992
Director’s fees and allowance
449
700
896
53,521
60,483
56,133
Recognized as follows:
16,004
16,344
14,639
7,313
9,445
8,407
29,719
34,183
32,604
485
511
483
Board of Directors’ and key managers’ remuneration
Salaries and fees (a)
9,071
7,355
6,081
Share-based payments
3,416
4,072
4,886
12,487
11,427
10,967
F-36
Directors’ Remuneration
Non-Executive
Director Fees
Cash Equivalent
Directors’ Fees
Paid in Shares
Total Remuneration
(in US$)
(No. of Shares)
James F. Park (a)
Robert A. Bedingfield (b)
29,738
225,000
Constantin Papadimitriou (c)
120,000
13,280
220,000
Somit Varma (d)
30,545
230,000
Sylvia Escovar (e)
34,269
259,103
Brian F. Maxted (f)
Carlos E. Macellari (g)
103,397
203,397
Marcela Vaca (h)
105,870
205,870
Felipe Bayon (i)
Andrés Ocampo (j)
Note 11 Geological and geophysical expenses
7,158
8,971
7,879
155
474
528
Communication and IT costs
2,615
2,624
2,139
1,092
1,385
1,373
Allocation to capitalized project
(1,061)
(1,371)
(1,254)
Other services
579
512
527
10,538
12,595
11,192
F-37
Note 12 Administrative expenses
25,366
28,344
5,139
6,033
8,565
11,443
10,645
2,561
3,224
3,890
Travel expenses
1,168
1,730
Non-operated blocks expenses
4,038
1,568
Director’s fees and allowance (Note 10)
3,305
3,777
3,760
Allocation to joint operations
(9,276)
(12,054)
(13,986)
Other administrative expenses
3,070
3,058
3,758
40,544
49,534
43,969
Administrative expenses decreased in 2025 primarily due to cost efficiency measures, including workforce optimization. These measures were implemented to align the organizational structure with the Group's strategic objectives and operational requirements.
Note 13 Selling expenses
477
497
466
Shared-based payment (Note 10)
Transportation (a)
14,332
10,387
9,022
Selling taxes and other (b)
6,092
4,016
3,579
20,909
14,914
13,084
F-38
Note 14 Financial results
Bank charges and other financial costs (a)
(16,006)
(15,310)
(8,520)
Borrowings cancellation costs (b)
(6,240)
(49,298)
(31,088)
(30,839)
(4,780)
(5,153)
(6,456)
Interest received
11,561
Borrowings cancellation gain (c)
10,157
Foreign exchange gains and losses
(10,508)
12,603
(19,729)
Realized result on currency risk management contracts (d)
2,779
2,909
Unrealized result on currency risk management contracts (d)
443
(443)
Total Financial results
(61,892)
(31,375)
(56,398)
14.1 Currency risk management contracts
From time to time, the Group enters into derivative financial instruments in order to anticipate currency fluctuations in Colombia. In November 2024, GeoPark entered into a derivative financial instrument (zero-premium collars) with a local bank in Colombia, for an amount equivalent to US$ 50,000,000, 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, GeoPark entered into derivative financial instruments (zero-premium collars) with local banks in Colombia, for a total amount equivalent to US$ 30,000,000 (allocated at US$ 5,000,000 per month during the second half of 2025), to mitigate potential currency fluctuations and protect the Group’s exposure to the Colombian peso arising from its regular business operations.
Note 15 Income tax
Current income tax charge
(32,893)
(108,040)
(107,740)
Deferred income tax benefit (charge) (Note 16)
33,909
(37,752)
4,299
F-39
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows:
Profit before tax (a)
Income tax calculated at domestic tax rates applicable to Profit in the respective countries (mainly Colombia)
(26,540)
(127,804)
(123,202)
Tax losses where no deferred income tax benefit is recognized
(10,224)
(3,912)
(6,918)
Effect of currency translation on tax base
23,714
(21,252)
36,691
Changes in the income tax rate (b)
402
10,324
(8,853)
Write-down of deferred income tax benefits previously recognized (c)
(878)
(2,371)
(3,895)
Previously unrecognized tax losses (d)
9,444
632
Income tax on dividends (e)
(2,595)
Non-taxable results (f)
3,133
558
4,699
Income tax
Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Additionally, Bermuda Pillar Two is applicable starting in 2025.
The statutory income tax rate in Colombia is 35%, though a tax surcharge is also applicable, impacting companies engaged in the extraction of crude oil like GeoPark. The tax surcharge varies from zero to 15%, depending on different Brent oil prices. The applicable surtax for 2025 was 0%, and therefore, the full applicable statutory income tax rate in Colombia for 2025 was 35%.
Income tax rates in other countries where the Group operates (Ecuador, Brazil, Argentina and Spain) ranges from 25% to 35%. In Spain, dividend income became fully exempt in 2025 following the relocation of GeoPark Colombia S.L.U. from Madrid to Bizkaia (previously 95% exempt under the Madrid regime).
There are no income tax consequences attached to the payment of dividends by the Group to its shareholders.
On May 23, 2023, the International Accounting Standards Board (IASB) issued International Tax Reform – Pillar Two Model Rules – Amendments to IAS 12 which clarify that IAS 12 applies to income taxes arising from tax law enacted or substantively enacted to implement the Pillar Two model rules published by the OECD, including tax law that implements Qualified Domestic Minimum Top-up Taxes. The Group has adopted these amendments. However, they are not yet applicable for the current reporting year as the Group’s consolidated revenue is currently below the threshold of EUR 750,000,000 (equivalent to US$ 810,000,000).
The Group has tax losses available which can be utilized against future taxable profit in the following countries:
F-40
5,646
Brazil (a)
26,972
23,587
26,808
Chile (a) (c)
313,409
Argentina (b)
36,638
12,689
9,981
Spain (a)
6,936
Total tax losses as of December 31
63,610
41,922
357,134
As of December 31, 2025, deferred income tax assets have not been recognized for tax losses in Brazil and for the portion of tax losses in Argentina expiring in 2026, as there is insufficient evidence of future taxable profits against which such losses could be utilized.
Note 16 Deferred income tax
The gross movement on the deferred income tax account is as follows:
Deferred income tax as of January 1
(85,482)
(48,143)
173
(519)
Income tax relating to cash flow hedges recognized in OCI
Income statement benefit (charge)
Deferred income tax as of December 31
(58,242)
The breakdown and movement of deferred income tax assets and liabilities as of December 31, 2025, and 2024, are as follows:
At the
Currency
beginning
Charged to
translation
At the end
of year
net profit
differences
Deferred income tax assets
Difference in depreciation rates and other
(1,728)
9,861
8,205
Tax losses
3,060
9,213
12,374
19,074
15,920
(14,069)
At the beginning
relating to
cash flow hedges
Deferred income tax liabilities
(86,814)
14,835
(78,821)
(64,063)
(23,683)
F-41
Note 17 Earnings per share
Amounts in US$ ‘000 except for shares
Numerator: Profit for the year
Denominator: Weighted average number of shares used in basic EPS
51,527,107
52,487,688
56,836,682
Earnings per share (US$) – basic
Weighted average number of shares used in basic EPS
Effect of dilutive potential common shares
Stock awards at US$ 0.001
543,270
651,320
359,587
Weighted average number of common shares for the purposes of diluted earnings per shares
52,070,377
53,139,008
57,196,269
Earnings per share (US$) – diluted
Note 18 Property, plant and equipment
Furniture,
Buildings
Exploration
Oil & gas
equipment
facilities and
and
Construction in
and evaluation
Amounts in US$’000
properties
and vehicles
machinery
improvements
progress
assets(a)
Cost as of January 1, 2023
1,079,257
19,093
222,727
11,027
16,480
113,041
1,461,625
Additions / ARO change
9,744
(b)
1,683
116,304
73,160
200,920
Write-off / Impairment
(c)
(d)
(42,895)
Transfers
171,538
21,262
(116,905)
(76,081)
3,477
277
3,851
Disposals
(1,223)
(2,150)
(119)
(3,492)
Assets held for sale (Note 34.7)
(330,024)
(6,559)
(74,491)
(4,948)
(416,022)
Cost as of December 31, 2023
920,660
13,133
169,787
4,047
80,579
1,203,987
2,319
1,252
126,746
63,312
193,629
(e)
122,437
23,616
352
(118,410)
(28,085)
(10,570)
(140)
(901)
(11,708)
(104)
(11)
(115)
Cost as of December 31, 2024
1,034,846
14,231
192,502
4,363
24,117
100,955
1,371,014
4,026
842
68,498
29,005
102,384
Acquisitions of business (Note 34.1)
115,689
115,811
(18,111)
(26,300)
(f)
48,059
19,410
(59,818)
(7,668)
3,024
253
3,361
(538)
(632)
Divestment of long-term assets (Note 34)
(97,529)
(193)
(8,148)
(329)
(106,199)
Cost as of December 31, 2025
1,090,004
14,508
204,017
4,301
32,489
96,009
1,441,328
Depreciation and write-down as of January 1, 2023
(642,280)
(16,799)
(129,073)
(6,594)
(794,746)
(95,369)
(1,304)
(12,896)
(503)
(110,072)
(3,179)
(41)
(277)
(3,505)
1,189
1,877
3,066
310,683
6,488
68,765
2,158
388,094
Depreciation and write-down as of December 31, 2023
(430,145)
(10,467)
(73,481)
(3,070)
(517,163)
(109,093)
(1,550)
(13,116)
(191)
(123,950)
9,520
838
10,513
Depreciation and write-down as of December 31, 2024
(529,718)
(11,809)
(85,759)
(3,237)
(630,523)
(97,128)
(1,548)
(14,821)
(113,744)
(2,663)
(39)
(236)
(2,946)
509
603
73,283
187
7,498
80,968
Depreciation and write-down as of December 31, 2025
(556,226)
(12,700)
(93,318)
(665,642)
Carrying amount as of December 31, 2023
490,515
2,666
96,306
977
686,824
Carrying amount as of December 31, 2024
505,128
2,422
106,743
1,126
Carrying amount as of December 31, 2025
533,778
1,808
110,699
F-42
Exploration wells as of December 31, 2023
7,998
Additions
31,134
Write-offs
(11,721)
(21,724)
Exploration wells as of December 31, 2024
5,687
19,868
(5,886)
Divestment (Note 34.3)
(3,393)
(3,619)
Exploration wells as of December 31, 2025
12,657
As of December 31, 2025, the carrying amount included three exploratory wells that have been capitalized for a period less than three years amounting to US$ 12,657,000 (two exploratory wells of US$ 5,687,000 in 2024 and two exploratory wells of US$ 7,998,000 in 2023). After the balance sheet date, one of these wells, the Vencejo well in the Llanos 104 Block, was determined to be dry in January 2026 and will be written off in the first quarter of 2026.
F-43
Note 19 Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of December 31, 2025:
During the year ended December 31, 2025, the following change to the Group structure has taken place:
F-44
Details of all the subsidiaries of the Group as of December 31, 2025, are set out below:
Name and registered office
Ownership interest
Subsidiaries
GeoPark Argentina S.A. (Argentina)
100% (a)
GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda. (Brazil)
GeoPark Colombia S.A.S. (Colombia)
GeoPark Colombia, S.L.U. (Spain)
GeoPark Perú S.A.C. (Peru)
GeoPark Mexico S.A.P.I. de C.V. (Mexico)
100% (a) (b)
GeoPark E&P S.A.P.I. de C.V. (Mexico)
GeoPark Ecuador S.A. (Ecuador)
GeoPark (UK) Limited (United Kingdom)
Amerisur Resources Limited (United Kingdom)
100% (a) (c)
Amerisur Exploración Colombia Limited (British Virgin Islands)
Amerisur Exploración Colombia Limited Sucursal Colombia (Colombia)
Yarumal S.A.S. (Colombia)
Fenix Oil & Gas Limited (British Virgin Islands)
100% (a) (b) (c)
Fenix Oil & Gas Limited Sucursal Colombia (Colombia)
Amerisur S.A. (Paraguay)
Market Access LLP (United States)
9% (c)
GeoPark Colombia S.A.S. Sucursal Panama (Panama)
GPK Panama, S.A. (Panama)
GeoPark Americas S.A.S. (Colombia)
Details of the joint operations of the Group as of December 31, 2025, are set out below:
Joint operations
Llanos 34 Block (Colombia)
45% (a)
Llanos 86 Block (Colombia)
50% (a)
Llanos 87 Block (Colombia)
Llanos 104 Block (Colombia)
Llanos 123 Block (Colombia)
Llanos 124 Block (Colombia)
CPO-5 Block (Colombia)
Mecaya Block (Colombia)
PUT-8 Block (Colombia)
PUT-9 Block (Colombia)
50% (a) (b)
Tacacho Block (Colombia)
Terecay Block (Colombia)
PUT-36 Block (Colombia)
CPO-4-1 Block (Colombia)
Puesto Silva Oeste (Argentina)
95% (a)
F-45
Note 20 Prepayments and other receivables
V.A.T.
2,264
3,734
Income tax payments in advance
13,153
1,112
Other prepaid taxes
965
227
To be recovered from co-venturers (Note 33)
14,610
9,740
15,392
13,484
Advanced payment for unconsummated transaction in Argentina (a)
54,084
46,384
82,381
Classified as follows:
Current
Non-current
Movements on the Group provision for impairment of prepayments and other receivables are as follows:
At January 1
Note 21 Inventories
Crude oil
6,090
6,509
Materials and spares
6,289
4,058
The carrying amount of inventories is not pledged as security for liabilities.
Note 22 Trade receivables
As of December 31, 2025, and 2024, there are no balances that were aged by more than 3 months. Trade receivables that are aged by less than three months are not considered impaired.
The credit period for trade receivables is 30 days or less. The maximum exposure to credit risk at the reporting date is the carrying value of each class of receivable. The Group does not hold any collateral as security related to trade receivables.
The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature.
F-46
Note 23 Financial instruments by category
Assets as per statement
of financial position
Financial assets at fair value through profit or loss
Other financial assets at amortized cost
Trade receivables (Note 22)
Other financial assets (a)
21,108
Cash and cash equivalents (b)
154,035
347,809
Total financial assets
179,533
350,573
Liabilities as per statement
Liabilities at fair value through profit and loss
Other financial liabilities at amortized cost
Trade payables (Note 28)
80,649
93,435
Customer advance payments (Note 28)
2,182
To be paid to co-venturers (Note 33)
708
1,829
Lease liabilities (Note 26)
Borrowings (Note 25)
663,081
787,520
Total financial liabilities
663,701
787,984
F-47
23.1 Credit quality of financial assets
The credit quality of financial assets that are neither past due nor impaired can be assessed by reference to external credit ratings (if available) or to historical information about counterparty default rates:
Counterparties with an external credit rating (Moody’s, S&P, Fitch)
A1
4,201
Baa3
178
Ba1
1,927
260
Ba2
Ba3
B1
1,215
Counterparties without an external credit rating
Group 1 (a)
31,721
39,773
Total trade receivables
All trade receivables are denominated in U.S. Dollar, except in Brazil where they are denominated in Brazilian Real.
Cash at bank and other financial assets (a)
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services)
Aaa
2,016
Aa1
46,188
Aa2
7,145
Aa3
3,315
153,330
1,035
94,495
A3
9,765
Baa1
25,068
20,114
Baa2
3,312
9,017
8,304
4,091
389
234
930
B3
2,346
Caa1
1,117
5,830
100,329
297,847
F-48
23.2 Financial liabilities- contractual undiscounted cash flows
The table below analyses the Group’s financial liabilities into relevant maturity groupings based on the remaining period at the balance sheet to the contractual maturity date. The amounts disclosed in the table are the contractual undiscounted cash flows.
Less than 1
Between 1
Between 2
Over 5
year
and 2 years
and 5 years
years
44,019
136,082
541,503
7,371
3,784
11,351
20,681
Customer advance payments (Note 29.1)
134,929
139,866
552,854
37,500
27,500
513,750
8,933
3,752
10,032
18,558
Trade payables
293,697
31,252
523,782
A portion of the Group’s trade payables in Colombia is included under supplier finance arrangements. As a result, these payables are managed with specific counterparties rather than individual suppliers. This requires the Group to settle certain amounts with a limited number of counterparties instead of smaller amounts with multiple suppliers. However, the payment terms for trade payables under these arrangements are identical to those for other trade payables.
Management considers that these arrangements do not create excessive concentrations of liquidity risk. The primary purpose of the arrangements is to streamline administrative processes associated with managing a high volume of invoices from numerous suppliers and to provide local suppliers with access to favorable financial terms. These arrangements are not intended to secure financing for the Group.
23.3 Fair value measurement of financial instruments
Accounting policies for financial instruments have been applied to classify as either: amortized cost, financial assets at fair value through profit or loss and fair value through other comprehensive income. For financial instruments that are measured in the statement of financial position at fair value, IFRS 13 requires a disclosure of fair value measurements by level according to the following fair value measurement hierarchy:
Level 1 - Quoted prices (unadjusted) in active markets for identical assets or liabilities.
Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the asset or liability, either directly (that is, as prices) or indirectly (that is, derived from prices).
Level 3 - Inputs for the asset or liability that are not based on observable market data (that is, unobservable inputs).
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23.3.1 Fair value hierarchy
The following table presents the Group’s financial assets and financial liabilities measured and recognized at fair value as of December 31, 2025 and 2024, on a recurring basis:
Level 1
Level 2
Assets
Commodity risk management contracts
25,474
Energy cost risk management contracts
Total Assets
Total Liabilities
Currency risk management contracts
444
There were no transfers between Level 2 and 3 during the period.
The Group did not measure any financial assets or financial liabilities at fair value on a non-recurring basis as of December 31, 2025.
23.3.2 Valuation techniques used to determine fair values
Specific valuation techniques used to value financial instruments include:
23.3.3 Fair values of other financial instruments (unrecognized)
The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest receivable/payable is either close to current market rates or the instruments are short-term in nature.
Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short-term portion where interest has already been fixed. They are classified under other financial liabilities and measured at their amortized cost.
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The fair value of these financial instruments as of December 31, 2025, amounts to US$ 506,809,000 (US$ 490,980,000 in 2024). The fair values are based on market price for the Notes and cash flows discounted for other borrowings using a rate based on the borrowing rate and are within level 1 and level 2 of the fair value hierarchy, respectively.
Note 24 Equity
24.1 Share capital and Share premium
Issued share capital
Common stock (amounts in US$ ‘000)
The share capital is distributed as follows:
Common shares, of nominal US$ 0.001
51,707,198
51,247,287
Total common shares in issue
Authorized share capital
US$ per share
0.001
Number of common shares (US$ 0.001 each)
5,171,949,000
Amount in US$
5,171,949
Details regarding the share capital of the Company are set out below.
24.1.1 Common shares
As of December 31, 2025, the outstanding common shares confer the following rights on the holder:
movement
closing
US$(`000)
GeoPark common shares history
Month
(millions)
Closing
Shares outstanding at the end of 2023
55.3
Stock awards
Jan to Mar 2024
0.2
55.5
Apr 2024
(4.5)
51.0
Apr to Dec 2024
Shares outstanding at the end of 2024
Jan to Dec 2025
51.7
Shares outstanding at the end of 2025
As of December 31, 2025, the Company held 11,348,762 (11,808,673 in 2024) common shares in treasury, which had been repurchased under the share buyback programs. Treasury shares are recorded as a deduction from equity and are not entitled to vote or receive dividends. Accordingly, the number of shares outstanding used for earnings-per-share calculations excludes treasury shares. No gain or loss is recognized in profit or loss on the purchase, sale, issue or cancellation of treasury shares.
24.1.2 Stock Award Program and Other Share Based Payments
Non-Executive Directors Fees
During 2025, the Company issued 147,672 shares (121,694 in 2024 and 99,590 in 2023) to Non-Executive Directors in accordance with contracts as compensation, generating a share premium of US$ 1,114,000 (US$ 1,114,000 in 2024 and US$ 1,133,000 in 2023). The number of shares issued is determined considering the contractual compensation and the fair value of the shares for each relevant period.
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Stock Award Program and Other Share Based Payments
In March 2025, 168,684 common shares (86,602 in 2024 and 246,110 in 2023) were issued as a result of the vesting of a tranche of the Long-Term Incentive program (“LTIP”) oriented to executive officers, generating a share premium of US$ 2,896,000 (US$ 2,039,000 in 2024 and US$ 1,505,000 in 2023).
During 2025, 143,555 common shares (80,652 in 2024 and 82,472 in 2023) were issued as part of other equity incentive plans vested during the year, generating a share premium of US$ 1,956,000 (US$ 3,003,000 in 2024 and US$ 281,000 in 2023).
24.1.3 Buyback Program
The Company have had recurring buyback programs to repurchase its own shares. The latest renewal took place on November 8, 2023, and established a program to repurchase up to 10% of the shares outstanding, or approximately 5,611,797 shares, until December 31, 2024. During 2025 and 2024, no common shares were repurchased under this program (3,073,588 for a total amount of US$ 31,239,000 in 2023). These transactions had no impact on the Group’s results. As of the date of these Consolidated Financial Statements, there is no buyback program in place.
On April 22, 2024, GeoPark acquired 4,369,181 of its common shares at a purchase price of US$ 10 per share, for a total cost of US$ 43,691,810, excluding fees and other expenses related to the tender offer.
24.2 Cash distributions
On November 6, 2019, the Company’s Board of Directors declared the initiation of quarterly cash distributions.
The following table summarizes the cash distributions for each of the years presented:
Total amount
Date of declaration
Date of distribution
in US$ ‘000
March 8, 2023
March 31, 2023
0.1300
7,505
May 3, 2023
May 31, 2023
7,378
August 9, 2023
September 7, 2023
0.1320
7,383
November 8, 2023
December 11, 2023
0.1340
7,449
Cash distributions for the year ended December 31, 2023
29,715
March 6, 2024
March 28, 2024
0.1360
7,520
May 15, 2024
June 14, 2024
0.1470
7,496
August 14, 2024
September 12, 2024
7,506
November 6, 2024
December 6, 2024
7,513
Cash distributions for the year ended December 31, 2024
30,035
March 5, 2025
March 31, 2025
7,525
May 7, 2025
June 5, 2025
7,559
August 5, 2025
September 4, 2025
7,572
November 5, 2025
December 4, 2025
0.0300
1,547
Cash distributions for the year ended December 31, 2025
24,203
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In October 2025, GeoPark announced that its Board of Directors approved a revised dividend program totaling approximately US$ 6,000,000 over the next four quarters, followed by a dividend suspension starting with the third quarter 2026 results.
During the year ended December 31, 2025, these distributions were deducted from Retained Earnings.
24.3 Other reserves
GeoPark applies hedge accounting for the derivative financial instruments entered to manage its exposure to oil price risk. Consequently, the Group’s derivatives are designated and qualify as cash flow hedges and, therefore, the effective portion of changes in the fair values of these derivative contracts along with the income tax relating to those results are recognized in Other Reserve within Equity. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss. During 2025, a realized gain of US$ 13,794,000 on commodity risk management contracts and a realized loss of US$ 1,225,000 on energy cost risk management contracts were reclassified to the Consolidated Statement of Income.
Note 25 Borrowings
Nominal amount
441,679
Unamortized debt issuance costs
(3,469)
Accrued interests
16,095
94,667
500,000
(797)
(7,993)
2,372
12,528
Local debt in Argentina (a)
Total borrowings
On January 31, 2025, the Company successfully placed an aggregate principal amount of US$ 550,000,000 senior notes (the “Notes due 2030”) which were offered in a private placement to qualified institutional buyers in accordance with Rule 144A under the Securities Act of 1933, as amended (the “Securities Act”), and outside the United States to non U.S. persons in accordance with Regulation S under the Securities Act. The Notes due 2030 are fully and unconditionally guaranteed jointly and severally by GeoPark Colombia S.L.U., GeoPark Colombia S.A.S., and GeoPark Argentina S.A. The Notes due 2030 were priced at 100% and carry a coupon of 8.75% per annum (yield 8.75% per annum). The debt issuance cost for this transaction amounted to US$ 5,034,000 (debt issuance effective rate: 8.98%). Final maturity of the Notes due 2030 will be January 31, 2030.
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The indenture governing the Notes due 2030 includes incurrence test covenants that provide among other things, that, the Net Debt to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Company’s capacity to incur additional indebtedness, as specified in the indenture governing the Notes due 2030. Incurrence covenants as opposed to maintenance covenants must be tested by the Company before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others.
The net proceeds from the Notes due 2030 were used by the Group to repurchase part of its Notes due 2027 for a nominal amount of US$ 405,333,000, to repay part of the outstanding prepayment under the agreement with Vitol (see Notes 28 and 29.1) and, the remainder for general corporate purposes, including capital expenditures.
From June to October 2025, the Company repurchased through open market transactions and cancelled with the Trustee, a total nominal amount of US$ 108,321,000 of its Notes due 2030 at an average price of US$ 0.90. The difference of US$ 10,157,000 between the carrying amount of the debt repurchased (net of the associated unamortized issuance costs) and the consideration paid was recognized as financial income in the Consolidated Statement of Income. See Note 14.
On December 24, 2025, GeoPark Colombia S.A.S. executed a loan agreement with Bancolombia Panamá, S.A. for US$ 3,000,000 to finance sustainable capital requirements associated to the Orinoquia Regenera project in Colombia. The loan carries a variable interest rate of SOFR risk-free rate plus a margin of 1.8% per annum and matures on December 20, 2029. Principal is repayable semi-annually in equal installments following a grace period of two years, and interest is payable semi-annually on the outstanding balance.
After the balance sheet date, GeoPark Colombia S.A.S. obtained two short-term loans from Bancolombia Panamá, S.A. totaling US$ 25,000,000 (US$ 17,000,000 and US$ 8,000,000), to fund the advance payment related to the proposed acquisition of Frontera Energy's E&P assets (see Note 36.1). The loans were disbursed on January 23, 2026. In February 2026, the terms of these loans were amended, and the loans were restructured to bear interest at a fixed annual rate of 5.06320% and to mature on February 3, 2027.
Additionally, on February 2026, GeoPark Colombia S.A.S. obtained a short-term bank loan from Citibank Colombia S.A. in an aggregate principal amount of Colombian Pesos 145,280,000,000 (equivalent to US$ 40,000,000), to support liquidity and working capital requirements in Colombia following the advance payment related to the proposed acquisition of Frontera Energy's E&P assets (see Note 36.1). The loan was disbursed on February 6, 2026, bears interest at a floating rate of IBR (the Colombian interbank reference rate) plus 1.53% per annum, and matures on February 3, 2027. In connection with this borrowing, we entered into a cross-currency swap arrangement with Citibank N.A., New York to hedge the foreign exchange exposure associated with the loan and to secure the Colombian peso cash flows required to service principal and interest payments.
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Note 26 Leases
The Consolidated Statement of Financial Position shows the following amounts relating to leases:
Right of use assets
Production, facilities and machinery
17,666
20,935
2,830
3,516
The Consolidated Statement of Income shows the following amounts relating to leases:
Depreciation charge of Right of use assets
(2,670)
(5,156)
(7,858)
(617)
(1,272)
(792)
(3,287)
(6,428)
(8,650)
Unwinding of long-term liabilities (included in Financial results)
(2,759)
(2,928)
(3,168)
Expenses related to short-term leases (included in Production and operating cost and Administrative expenses)
(730)
(838)
Expenses related to low-value leases (included in Administrative expenses)
(992)
(907)
(775)
The table below summarizes the amounts of Right-of-use assets recognized and the movements during the reporting years:
Right-of-use assets as of January 1
28,451
Additions / changes in estimates
Divestments (Note 34.2)
(874)
Right-of-use assets as of December 31
The table below summarizes the amounts of Lease liabilities recognized and the movements during the reporting years:
Lease liabilities as of January 1
Lease liabilities as of December 31
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Note 27 Provisions and other long-term liabilities
Assets retirement
Deferred
obligation (a)
Income (b)
Other (c)
As of January 1, 2024
23,536
810
9,737
34,083
Addition to provision / changes in estimates
3,314
5,476
333
(611)
(378)
(2,554)
(2,534)
Amortization
1,751
2,225
Amounts used during the year
(4,341)
(2,472)
(6,813)
20,887
10,462
3,524
4,850
238
1,371
1,135
1,957
2,021
(900)
(2,684)
(3,584)
Acquisitions (Note 34.1)
2,244
Divestments (Note 34)
(14,287)
(982)
(15,269)
13,397
611
10,622
Note 28 Trade and other payables
V.A.T
3,683
8,842
Customer advance payments (a)
Outstanding commitments in Chile (b)
3,320
Staff costs to be paid
14,177
11,563
Royalties to be paid
1,307
723
Taxes and other debts to be paid
8,331
8,237
The average credit period (expressed as creditor days) during the year ended December 31, 2025, was 114 days (2024: 92 days).
The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value.
F-56
The Group has established a supplier finance arrangement in Colombia where payables are managed with specific counterparties rather than individual suppliers. Participation in these arrangements is entirely at the suppliers’ discretion. Suppliers opting to participate may receive early payment for their invoices through the Group’s external finance provider, which charges a fee to the suppliers for this service. The Group is not a party to this fee arrangement. For the finance provider to process early payments, the goods or services must have been delivered and the invoices approved by the Group. The Group subsequently settles the original invoice amount with the finance provider on the original invoice maturity date. Payment terms with suppliers have not been renegotiated in connection with these arrangements and the Group does not provide any collateral or guarantees to the finance provider.
As of December 31, 2025, trade payables subject to supplier finance arrangements amounting to US$ 1,135,000 (US$ 2,664,000 in 2024) are included within “Trade and other payables” line item in the Consolidated Statement of Financial Position.
Note 29 Offtake and prepayment agreements
29.1 Vitol
In May 2024, GeoPark executed an offtake and prepayment agreement with Vitol, one of the world’s leading energy and commodity companies. The offtake agreement provides for GeoPark to sell and deliver production from the Llanos 34 Block in Colombia to Vitol, for a minimum of 20 months and up to 36 months, starting on July 1, 2024.
As part of this transaction, GeoPark obtained access to committed funding from Vitol, with an initial limit of up to US$ 300,000,000, which decreases by US$ 10,000,000 per month, in prepaid future oil sales over the period of the offtake agreement. Funds committed by Vitol were available until December 31, 2024. Amounts drawn on this prepayment facility can be repaid through future oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.75% per annum. In November 2024, GeoPark drew US$ 152,000,000 under this prepayment agreement. During 2025, GeoPark repaid US$ 142,244,000 in cash and US$ 7,574,000 in kind. As of December 31, 2025, US$ 2,182,000 remained outstanding.
After the balance sheet date, in January 2026, GeoPark renewed its offtake and prepayment agreement with Vitol, extending its term through December 31, 2028. The new terms take effect in January 2026, with deliveries beginning in January 2026 for Llanos 34 and in May 2026 for CPO-5 and Llanos 123, and remaining in force through December 31, 2028. As part of this transaction, GeoPark obtained access to committed funding from Vitol with an initial limit of up to US$ 500,000,000 (US$ 330,000,000 committed with an option to increase by up to US$ 170,000,000) at a SOFR risk-free rate plus a margin of 3.50% per annum. The committed funds are available for drawn until June 30, 2027, subject to certain conditions. Amounts drawn under this prepayment facility may be repaid through future oil deliveries or prepaid at any time without penalty. As of the date of these Consolidated Financial Statements, no amounts have been drawn under this renewed agreement.
29.2 BP
In August 2025, GeoPark executed an offtake and prepayment agreement with BP. Under this arrangement, GeoPark agreed to sell and deliver, on an FOB Coveñas basis, crude oil production from the CPO-5, Llanos 87 and Llanos 123 blocks for a 12-month term starting on August 1, 2025 with the option for unilateral early termination after nine months. As part of this transaction, BP made available a committed prepayment facility of up to US$ 50,000,000 initially, which decreases over the life of the agreement through monthly step-downs until April 2026. Amounts drawn under the prepayment facility may be amortized through future crude oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.50% per annum. After the balance sheet date, GeoPark drew US$ 15,000,000 from the prepayment facility.
29.3 Trafigura
In August 2024, GeoPark executed an offtake and prepayment agreement with Trafigura for the sale of light crude oil from the CPO-5 Block. The agreement expired in July 2025 upon completion of its 12 month term. All contractual obligations
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were fulfilled as agreed, no amounts were drawn under the prepayment facility, and there were no outstanding balances as of December 31, 2025.
Note 30 Share-based payment
The Group has established different stock awards programs and other share-based payment plans to incentivize the directors, executive officers and employees, enabling them to benefit from the increased market capitalization of the Company.
During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a 10-year term, and embraces all equity incentive programs that the Company decides to implement throughout such term. The maximum number of shares available for issuance under the Plan is 5,000,000 Shares.
Employee Share-Based Compensation Programs
In 2020, a share-based compensation program for employees was approved for approximately 800,000 shares, to vest in 2023. On February 17, 2023, the Compensation Committee reviewed the Group’s results and the performance conditions established in the program and approved 152,030 shares to be delivered to participants, due to the fact that, throughout the vesting period, the performance conditions included in the program were only partially achieved and, to a lesser extent, the Group had lower hirings than estimated and not all the beneficiaries continued being employees at the vesting date.
On March 8, 2022, and March 4, 2025, the Company’s Board of Directors approved pools of approximately 215,000 and 200,000 shares, respectively, oriented for retention of key employees and new hires bonuses, under the Stock Awards Program. The vesting of the plans are in a three-years period from the grant date.
In December 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program for employees and new hirings. The main characteristics of the program are:
On January 30, 2026, the Compensation Committee reviewed the Group’s results and the performance conditions established in the program and approved 221,557 shares to be delivered to participants.
In February 2026, the Company’s Compensation Committee approved a new Long-Term Incentive program for employees and new hirings. The main characteristics of the program are:
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Executive Long-Term Incentive Program (LTIP)
During 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program (“LTIP”) for executive officers. Main characteristics of the program are:
In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated 571,984 total shares, to vest during a three-year period. On February 17, 2023, February 26, 2024, March 4, 2025, and March 24, 2026 the Compensation Committee approved new grants of 197,197, 351,971, 287,656 and 494,546 shares, respectively, to vest during a three-year period.
Summary
Details of these costs and the characteristics of the different stock awards programs and other share-based payments are described in the following table:
Awards at the
Awards granted
Awards
Awards at
Charged to net profit/loss
in the year
forfeited
exercised
year end
No. of Shares
Oriented to Employees
LTIP for Employees
660,648
21,137
(488,435)
(37,612)
155,738
769
1,452
Retention Program
168,039
193,000
(68,300)
292,739
282
990
Compensation Program 2020
60,271
(9,309)
50,962
Oriented to Directors and Executive Officers
LTIP for Executives
636,276
510,056
(410,532)
(168,684)
567,116
1,963
3,612
Shares granted to Non-Executive Directors
147,672
(147,672)
1,114
1,133
Shares granted to Executive Officers
63,334
70,000
(28,334)
105,000
141
1,588,568
941,865
(898,967)
(459,911)
1,171,555
The awards that are forfeited correspond to employees that had left the Group before vesting date.
F-59
Note 31 Interests in Joint operations
The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Latin America.
GeoPark is the operator in the Llanos 34, Llanos 86, Llanos 87, Llanos 104, Llanos 123, Llanos 124, Mecaya, PUT-8, PUT-9, PUT-36, Tacacho and Terecay Blocks in Colombia, and in the Puesto Silva Oeste Block in Argentina.
The following amounts represent the Group’s share in the assets, liabilities and results of the joint operations which have been recognized in the Consolidated Statement of Financial Position and Statement of Income:
Subsidiary /
Net Assets/
Operating
Joint operation
Interest
PP&E
(Liabilities)
profit (loss)
GeoPark Colombia S.A.S.
Llanos 34 Block
361,660
7,683
369,343
(6,220)
363,123
296,932
146,458
Llanos 32 Block (a)
12.5
3,725
2,424
Llanos 86 Block
10,216
166
10,382
Llanos 87 Block
13,256
454
13,710
(664)
13,046
2,938
(2,833)
Llanos 104 Block
18,055
861
18,916
(86)
18,830
(308)
Llanos 123 Block
58,606
3,519
62,125
(1,236)
60,889
41,321
Llanos 124 Block
139
(43)
(61)
CPO-5 Block
124,154
124,320
(2,367)
121,953
98,581
17,782
CPO-4-1 Block
655
709
Amerisur Exploración Colombia Limitada Sucursal Colombia
Mecaya Block
4,109
4,147
(63)
PUT-8 Block
14,072
744
14,816
(57)
14,759
(6,167)
PUT-9 Block
(4,618)
PUT-36 Block
(3,044)
Tacacho Block
Terecay Block
GeoPark Ecuador S.A.
Espejo Block (b)
3,103
(12,322)
Perico Block (b)
15,360
(16,064)
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda.
Manati Field (c)
1,203
GeoPark Argentina S.A.
Puesto Silva Oeste (d)
2,996
2,902
138
F-60
382,116
5,530
387,646
(4,588)
383,058
393,759
242,732
Llanos 32 Block
13,738
13,774
(319)
13,455
9,742
5,925
9,553
164
9,717
(170)
15,498
194
15,692
(390)
15,302
4,661
(88)
Llanos 94 Block (e)
(469)
(81)
8,845
145
8,990
(149)
34,915
1,930
36,845
(895)
35,950
31,237
12,303
(97)
(62)
156,932
(1,698)
155,234
122,634
53,560
303
359
4,101
4,142
4,133
(51)
11,916
809
12,725
12,692
4,286
4,421
3,113
3,158
Espejo Block
12,403
356
12,759
(758)
12,001
1,187
Perico Block
29,228
(1,455)
27,773
29,380
6,699
Manati Field
4,812
1,144
5,956
(13,044)
(7,088)
(4,044)
Los Parlamentos Block
(76)
Puelen Block
(38)
F-61
354,361
5,079
359,440
(7,641)
351,799
464,146
295,556
2,493
(655)
1,838
7,811
5,661
5,532
5,759
16,621
650
17,271
(1,211)
16,060
1,527
(17,722)
Llanos 94 Block
(336)
(1,044)
5,536
320
5,856
16,292
17,327
(520)
16,807
8,648
4,006
170
(166)
(7,496)
182,484
(1,540)
180,944
148,594
50,032
(96)
3,948
3,999
3,959
9,118
306
9,424
4,454
4,522
2,950
10,072
213
10,285
(467)
9,818
1,450
(1,897)
22,231
(889)
21,342
17,647
258
5,233
17,546
22,779
(12,788)
9,991
4,955
POT-T‑785 Block
160
GeoPark TdF S.p.A.
Flamenco Block
(1,336)
Campanario Block
(5,438)
(5,113)
Isla Norte Block
(1,018)
(1,000)
(7,086)
Capital commitments are disclosed in Note 32.2.
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Note 32 Commitments
32.1 Royalty and economic rights commitments
32.1.1 Royalty
In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using the level of production sliding scale detailed below:
Average daily production in barrels
Production Royalty rate
Up to 5,000
8%
5,000 to 125,000
8% + (production - 5,000) * 0.1
125,000 to 400,000
20%
400,000 to 600,000
20% + (production - 400,000) * 0.025
Greater than 600,000
25%
The production royalty rate depends on the crude quality. When the API is lower than 15°, the payment is reduced to the 75% of the total calculation. Royalties over gas production have a 20% discount.
In Argentina, crude oil and gas production accrues royalties payable to the Province of Neuquen equivalent to 12% on estimated value at well head of those products. This value is equivalent to the final sales price less transport, storage and certain treatment costs.
32.1.2 Overriding royalty
GeoPark is obligated to pay an overriding royalty of 4% and 2.5%, plus a 20% grossing up over that overriding royalty, to the previous owners of the Llanos 34 Block and the CPO-5 Block, respectively, based on the production and sale of hydrocarbons discovered in the blocks. During 2025, the Group has accrued US$ 18,262,000 (US$ 26,101,000 in 2024 and US$ 27,453,000 in 2023) in relation with these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they are exploratory blocks with no production during 2024, these agreements had no impact on the Group’s results.
32.1.3 Economic rights
According to each E&P Contract, the Colombian National Hydrocarbons Agency (“ANH”) has an economic right, offered by the operator at the moment of the ANH bid. This economic right, which is based on the production of the block after royalty discount, is equal to 1% in the Llanos 34 and Llanos 123 Blocks, 3% in the Llanos 87 Block, 23% in the CPO-5 Block and 0% in the Platanillo Block. Furthermore, there are economic rights applicable to other blocks with currently no production and, therefore, they have no impact on the Group’s results.
When the accumulated production of each field or block (depending on each E&P Contract), including the royalties’ volume, exceeds 5,000,000 barrels and the WTI price exceeds a defined threshold price (“Po”), the Group is required to deliver to the ANH an additional share of production net of royalties in accordance with a price-linked formula defined in each E&P Contract. This mechanism is progressive and applies only to the portion of the price exceeding Po, with marginal rates that increase as prices rise, typically ranging from 30% to 50% depending on the price level relative to Po. The effective high-price participation over total revenue (“HPP”) can be expressed as: HPP = A × (P − Po) / P, where P is the realized price and A is the applicable rate (expressed as a percentage) based on the price level and crude quality. For reference, for crude oil with characteristics similar to the Group’s production, the applicable Po is estimated to be approximately US$ 50 per barrel for 2026. As a result, the ANH’s participation increases proportionally in higher price scenarios, while having no impact when prices are at or below the defined threshold.
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32.2 Capital commitments
During 2025, the Group incurred investments of US$ 11,175,000 to fulfil its commitments, at GeoPark’s working interest.
32.2.1 Colombia
The future investment commitments assumed by GeoPark, at its working interest, are up to:
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32.2.2 Argentina
32.2.3 Brazil
The future investment commitments assumed by GeoPark are up to:
Note 33 Related parties
Controlling interest
The main shareholders of GeoPark Limited as of December 31, 2025, based on Schedules 13D, 13G and 13F filed with the SEC, are:
Common
Percentage of outstanding
shares
17.05
Parex Resources Inc. (b)
11.77
Fourth Sail Capital LP (c)
3,232,585
6.25
Socoservin Overseas SPF S.à.r.l. (d)
2,889,315
5.59
Renaissance Technologies LLC (e)
2,730,853
5.28
27,952,108
54.06
100.00
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Balances outstanding and transactions with related parties
Balances
at year
Account (Amounts in US$´000)
end
Related Party
Relationship
To be recovered from co-venturers
Joint Operations
To be paid to co-venturers
(708)
(1,829)
8,630
(522)
Balances with joint operation partners arise in the normal course of business under Joint Operating Agreements and are settled in accordance with standard cash call procedures. These balances are primarily related to capital expenditures and operating costs incurred by GeoPark as operator or non-operator, and are recoverable from or payable to co-venturers based on their respective working interests. As of December 31, 2025, balances with joint operation partners include amounts from Verano Energy Ltd., a subsidiary of Parex Resources Inc. (see ‘Controlling Interest’ above).
There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 10.
Note 34 Business transactions
34.1 Acquisition in Argentina’s Vaca Muerta Formation
On September 25, 2025, GeoPark announced that it had entered into an agreement to acquire a 100% operated working interest (“WI”) in the Loma Jarillosa Este and Puesto Silva Oeste Blocks located in the Neuquen Province, Argentina, targeting black oil in the Vaca Muerta formation. The transaction is consistent with GeoPark’s strategic intent to establish a position in Vaca Muerta, one of the world’s most prolific unconventional oil and gas plays.
Additionally, a new unconventional exploitation concession for the Puesto Silva Oeste Block was issued for a 35-year term, requiring GeoPark to transfer a 5% economic interest to the provincial state-owned company, Gas y Petróleo del Neuquén S.A. (“GyP”), resulting in a 95% economic interest in the Puesto Silva Oeste Block. GeoPark will carry GyP’s portion of the capital expenditures in the Puesto Silva Oeste Block on a fully recoverable basis from up to 100% of GyP’s share of production.
The agreement established a cash consideration of US$ 115,000,000, subject to an interim period adjustment related to the net cash flows from operations since January 1, 2025 (the effective date of the acquisition). On September 25, 2025, GeoPark granted a security deposit of US$ 22,700,000. Subsequently, the transaction closed on October 16, 2025, upon which GeoPark acquired control of the assets and paid the remaining consideration of US$ 92,300,000.
In accordance with the acquisition method of accounting, the acquisition cost was allocated to the underlying assets acquired and liabilities assumed based upon their estimated fair values at the date of acquisition. An income approach (being the net present value of expected future cash flows) was adopted to determine the fair values of the mineral interest. Estimates of expected future cash flows reflect estimates of projected future revenues, production costs and capital expenditures based on the Group’s business model. The valuation incorporates significant unobservable inputs, including estimated production profiles based on certified reserves, commodity price assumptions derived from market data and internal estimates, and discount rates reflecting the risk profile of the assets and relevant market conditions. The acquisition did not result in any goodwill, as the fair value of the identifiable net assets acquired amounted to the total consideration transferred.
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The following table summarises the combined consideration paid for the acquired blocks, and the final allocation of fair value of the assets acquired and liabilities assumed for these transactions:
Amounts in US$ ´000
Cash (a)
115,518
Total consideration
Property, plant and equipment (including mineral interest)
1,951
Provision for other long-term liabilities
(2,244)
Total identifiable net assets
The acquisition did not involve any contingent consideration arrangements or contingent liabilities. Transaction costs of US$ 192,000 related to the acquisition were recognized as an expense in the Consolidated Statement of Income for the year ended December 31, 2025.
Since the acquisition date, the acquired business contributed revenue of US$ 5,783,000 and net profit of US$ 10,000 within the Consolidated Statement of Income for the year ended December 31, 2025. Had the acquisition occurred on January 1, 2025, management estimates, based on available information, that consolidated revenue would have been US$ 528,166,000 and net profit would have been US$ 52,165,000.
34.2 Divestment of non-operated working interest in the Manati gas field in Brazil
On March 27, 2025, GeoPark entered into an agreement to sell its 10% non-operated working interest in the Manati gas field in Brazil for a total consideration of US$ 1,000,000, subject to working capital adjustment, plus a contingent payment of an additional US$ 1,000,000, subject to the field’s future cash flow or its potential conversion into a natural gas storage facility. The transfer was completed on December 12, 2025 and, accordingly, GeoPark no longer holds any working interest in the Manati gas field. As of December 31, 2025, GeoPark has received US$ 500,000 from the total consideration. The remaining balance of US$ 500,000, subject to working capital adjustment, will be received upon completion of customary post-closing formalities.
34.3 Divestment of working interests in Ecuador
During the second quarter of 2025, GeoPark and its partner accepted an offer to divest their respective 50% working interests in the Perico and Espejo Blocks, in Ecuador.
Subsequently, on July 31, 2025, the parties executed definitive asset purchase agreements for a total consideration of US$ 6,910,000, corresponding to GeoPark’s working interest. This amount included a firm purchase price of US$ 7,775,000, net of a working capital adjustment of US$ 865,000, and subject to customary interim period adjustments. In addition, the agreement included a contingent consideration of US$ 750,000, payable upon the Perico Block achieving cumulative gross production of two million barrels as from January 1, 2025. As of June 30, 2025, the amount of property, plant and equipment and right-of-use assets corresponding to the Perico and Espejo Blocks and the liabilities associated to them have been classified as held for sale. Immediately before this reclassification, the recoverable amount of the associated net assets was estimated, and an impairment loss of US$ 30,989,000 was recognized in the Consolidated Statement of Income (see Note 35).
The divestment transaction closed on December 9, 2025, and consequently GeoPark received net cash of US$ 4,155,000 at closing, after interim period adjustments. The outstanding amount of US$ 1,555,000 will be received upon completion of certain administrative procedures related to the transaction.
34.4 Divestment of non-operated working interest in the Llanos 32 Block in Colombia
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On March 14, 2025, GeoPark agreed to transfer, subject to regulatory approval, its non-operated working interest in the Llanos 32 Block in Colombia to its joint operation partner for a total consideration of US$ 19,000,000, minus working capital adjustment of US$ 3,660,000. The transfer was approved by the ANH in October 2025, and formalized in November 2025. GeoPark has received the net proceeds from the transaction and no longer holds any working interest in the Llanos 32 Block.
34.5 Unconsummated Transaction in Argentina (“Vaca Muerta”)
On May 13, 2024, GeoPark announced the execution of a farm-out agreement with PGR, a subsidiary of Mercuria Energy Trading (“Mercuria”), for the acquisition of non-operated working interests in four adjacent unconventional blocks in the Neuquén Basin, Argentina. However, on May 14, 2025, GeoPark announced that PGR exercised its contractual right to withdraw from the transaction. As a result, the transaction was not completed.
Accordingly, GeoPark was not required to pay the remaining balance of the upfront consideration, and all advance payments previously made were fully reimbursed. The advance payments included US$ 49,096,000 paid in May 2024, comprising US$ 38,000,000 related to the upfront consideration and US$ 11,096,000 related to the acquisition of midstream capacity, and US$ 4,988,000 paid in December 2024 for additional midstream capacity. These amounts had been recognized under the “Prepayments and other receivables” line item within “Current assets” in the Consolidated Statement of Financial Position as of December 31, 2024, and were fully collected in May 2025.
34.6 Proposed Acquisition of Certain Repsol Exploration and Production Assets in Colombia
On November 29, 2024, GeoPark announced that it had signed Sale and Purchase Agreements with Repsol Exploración S.A. and Repsol E&P S.A.R.L (collectively, “Repsol”) to acquire certain Repsol upstream oil and gas assets in Colombia, which included (i) 100% of Repsol Colombia O&G Limited, which owns a 45% non-operated working interest in the CPO-9 Block in Meta Department (operated by Ecopetrol with a 55% WI), and (ii) Repsol’s 25% interest in SierraCol Energy Arauca LLC in Arauca Department, Colombia.
On December 30, 2024, GeoPark announced that Ecopetrol, the operator of the CPO-9 Block, had exercised its preemptive rights under the terms of the Joint Operating Agreement to acquire 100% of Repsol Colombia O&G Limited, which owns a 45% non-operated working interest in the CPO-9 Block. In addition, on January 14, 2025, GeoPark announced that Repsol’s partner in SierraCol Energy Arauca LLC had exercised its preemptive rights under the terms of the LLC Agreement to acquire Repsol’s 25% interest in SierraCol Energy Arauca LLC in Arauca Department, Colombia. As a result of the exercise of these preemptive rights, GeoPark and Repsol mutually agreed not to proceed with the transaction.
As of December 31, 2024, GeoPark recorded a security deposit of US$ 20,000,000 granted to the seller within “Other financial assets” in the Consolidated Statement of Financial Position. In January 2025, Repsol returned that security deposit to GeoPark, together with the carried interest of US$ 89,175.
34.7 Divestment of Business in Chile
On December 20, 2023, GeoPark signed a Stock Purchase Agreement to sell its wholly owned subsidiary GeoPark Chile S.p.A. and its subsidiaries, GeoPark Fell S.p.A., GeoPark TdF S.p.A. and GeoPark Magallanes Limitada, which comprise the entire business of GeoPark in Chile, for a total consideration of US$ 4,000,000, subject to working capital adjustments. At that date, GeoPark collected an advanced payment of US$ 450,000.
As part of the agreement, GeoPark remained responsible for the outstanding investment commitments in the Campanario and Isla Norte Blocks. Consequently, as of December 31, 2023, GeoPark recognized a liability for the full amount of those commitments which were fully settled in 2025.
Additionally, GeoPark keeps the private right over unconventional activities that would be carried out in the Fell Block and 95% of the revenue derived from such activities over the current operating contract.
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The divestment transaction closed on January 18, 2024, and consequently GeoPark received an additional payment of US$ 2,792,000, plus a preliminary working capital adjustment of US$ 486,000. The remaining outstanding amount of US$ 758,000 was received in 23 monthly equal installments until December 2025.
As of December 31, 2023, the amount of Property, plant and equipment and Right-of-use assets corresponding to the abovementioned subsidiaries and the liabilities associated with them were classified as held for sale for US$ 28,419,000 and US$ 26,948,000, respectively. Immediately before the classification as held for sale, the recoverable amount of the net assets was estimated and an impairment loss of US$ 13,332,000 was recognized in the Consolidated Statement of Income. In addition, the deferred income tax asset was written down for US$ 2,533,000 as it was assessed as non-recoverable due to the transaction. The restructuring and other costs incurred because of the divestment process for US$ 3,873,000 were recognized within the ‘Other (expenses) income’ line item in the Consolidated Statement of Income.
34.8 Transfer of Working Interest in the Los Parlamentos Block in Argentina
On October 27, 2023, GeoPark agreed to transfer its 50% working interest in the Los Parlamentos Block in Argentina to its joint operation partner. The transaction was formally approved by local authorities and the closing took place on October 21, 2025. Accordingly, GeoPark is no longer liable for remaining capital commitments or other legal obligations resulting from its participation in the block. As a result of this transaction, in 2023, GeoPark incurred a net loss of US$ 2,939,000 in the Consolidated Statement of Income, which was composed by a loss of US$ 7,023,000 within the ‘Other (expenses) income’ line item due to the payment to the joint operation partner, net of a gain of US$ 4,084,000 within the ‘Foreign exchange (loss) gain’ line item due to transactions with U.S. Dollar-denominated Argentine securities contributed to the local subsidiary when transferred and disposed in Argentina.
Note 35 Impairment test on Property, plant and equipment
The Group’s management defines each block or group of blocks in which the Group has operational or economic interests as a cash-generating unit (“CGU”). The classification in CGUs reflects the operational interdependence of the assets, with shared facilities and services contributing collectively to the generation of cash inflows. The grouping of assets to determine the CGUs is consistent as compared to the prior periods.
As of June 30, 2025, the divestment transaction in Ecuador described in Note 35.3 was considered to be an impairment indicator for the Perico and Espejo Blocks, as the carrying amount of the net assets related to these blocks exceeded their fair value less cost of disposal. Consequently, the net assets were impaired to their known selling price, resulting in the recognition of an impairment loss of US$ 30,989,000, comprising US$ 18,111,000 related to oil and gas properties and US$ 12,878,000 related to exploration and evaluation assets.
As of December 31, 2025, the certified reserves estimation at year-end showed declines in certain blocks compared to the prior year’s estimates. Management considered this, along with other facts related to oil price assumptions, production decline and the cash generation potential of the blocks, as indicators of impairment in the Llanos 87 and Platanillo Blocks in Colombia. As a result, the Group performed an impairment review for each of those CGUs. No impairment indicators were identified for the remaining CGUs.
The impairment tests were performed by comparing the carrying amount of each CGU to its recoverable amount, which was determined as the fair value less cost of disposal, in accordance with IAS 36 Impairment of Assets. The fair value less cost of disposal was estimated using a discounted cash flow model, as this is a commonly used approach to estimate market value in the oil and gas industry where observable market prices are not readily available. The fair value measurement used in the impairment tests is classified as Level 3 of the fair value hierarchy defined in IFRS 13 Fair Value Measurement, as it relies on inputs that are not directly observable in the market, including internal assumptions.
The key variables and assumptions applied in the valuation model included:
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The assets subject to the impairment test include oil and gas properties, production facilities and machinery, and construction in progress. The carrying amount tested also includes mineral interests, if any.
As a consequence of the evaluation, no impairment losses were recognized.
The following amounts of impairment loss were recognized in the last three years:
Ecuador (a)
Chile (a)
With regard to the assessment of fair value less cost of disposal for the identified CGUs subject to impairment indicators, Management believes that there are no reasonably possible changes in any of the above key assumptions that would cause the carrying value of the CGUs to materially exceed its recoverable amount. A 1% change to discount rates or a 5% change in forward price estimates over the life of the reserves would have an immaterial impact on the impairment.
Note 36 Subsequent events
36.1 Proposed acquisition of Frontera Energy’s Colombian E&P assets (not consummated)
On January 29, 2026, GeoPark entered into an agreement with Frontera Energy Corporation (“Frontera”) to acquire 100% of Frontera Petroleum International Holdings B.V. (“Frontera International”), which consisted exclusively of oil and gas exploration and production assets in Colombia. On February 2, 2026, GeoPark paid an initial deposit of US$ 75,000,000, with the remaining balance payable at closing, subject to regulatory approvals and customary closing conditions.
Following such notification and after evaluating its match right, on March 9, 2026, GeoPark announced its decision not to raise its offer for Frontera’s Colombian E&P assets. As a result, GeoPark became entitled to receive the return of the deposit previously placed in escrow, plus any accrued interest, and a US$ 25,000,000 break-up fee, in each case pursuant to the terms of the arrangement agreement.
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36.2 Strategic Equity Investment by Grupo Gilinski
On March 5, 2026, GeoPark Limited entered into a Share Purchase Agreement (the “SPA”) with Colden Investments S.A. (“Colden”), an affiliate of Jaime Gilinski, who leads Grupo Gilinski. Under the agreement, Colden invested US$ 107,000,000 to acquire 12,876,053 newly issued common shares of the Company at a price of US$ 8.31 per share. Immediately following the closing of the investment, Colden held approximately 20% of the Company’s outstanding common shares and has become the Company’s largest shareholder.
Pursuant to the SPA, Colden is entitled to nominate two directors to the Company’s nine-member Board of Directors at its current ownership level, subject to applicable corporate governance procedures and NYSE requirements. The agreement includes, among other provisions, an eighteen-month lock-up commitment, certain approval rights while maintaining a minimum 15% ownership stake, and ownership limitations requiring Board approval for increases above 32% during the first twelve months. Gabriel Gilinski was appointed to fill a vacancy on the Board.
On March 9, 2026, Spaldy Investments Limited, a business company that operates under the laws of the British Virgin Islands, deemed to be beneficially owned by Jaime Gilinski, acquired 200,000 of the Company’s common shares in the open market, at a weighted average price of US$ 8.83 per share, for an aggregate purchase price of US$ 1,772,339.
Between March 11, 2026 and March 19, 2026, Colden acquired a total of 3,587,190 common shares of the Company in the open market, at prices ranging from US$ 8.58 to US$ 10.20 per share, for an aggregate purchase price of US$ 32,880,179.
36.3 Recent oil price volatility
In March 2026, oil prices experienced increased volatility, including a sharp rise in Brent crude oil prices, driven primarily by heightened geopolitical tensions in the Middle East and concerns regarding potential disruptions to global oil supply and transportation routes. These developments may impact the Group’s future revenues, operating costs and cash flows. However, such effects will depend on future market conditions and are partially mitigated by existing hedging arrangements and price-linked contractual and fiscal mechanisms.
36.4 Other events after the reporting period
Other events occurring after the reporting period are disclosed in Notes 7.1, 18, 25, 29 and 30.
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Note 37 Supplemental information on oil and gas activities (unaudited)
The following information is presented in accordance with ASC No. 932 “Extractive Activities- Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on December 31, 2008. This information includes the Group’s oil and gas production activities carried out in each country.
Table 1 - Costs incurred in exploration, property acquisitions and development
The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2025, 2024 and 2023. The acquisition of properties includes the cost of acquisition of proved or unproved oil and gas properties. Exploration costs include geological and geophysical costs, costs necessary for retaining undeveloped properties, drilling costs and exploratory wells equipment. Development costs include drilling costs and equipment for developmental wells, the construction of facilities for extraction, treatment and storage of hydrocarbons and all necessary costs to maintain facilities for the existing developed reserves.
Year ended December 31, 2025
Acquisition of properties
Proved
Unproved
Total property acquisition
35,443
2,345
147
310
38,245
Development (a)
70,931
150
72,524
Total costs incurred
106,374
297
321
110,769
Year ended December 31, 2024
46,330
2,839
24,223
73,478
127,403
933
729
129,065
173,733
1,019
24,952
202,543
Year ended December 31, 2023
66,953
1,481
13,331
81,928
125,997
255
372
(564)
126,060
192,950
362
13,703
(508)
207,988
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Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as of December 31, 2025, 2024, and 2023, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.
Ecuador (b)
Chile (c)
Proved properties (a)
Equipment, camps and other facilities
Mineral interest and wells
974,315
Other uncompleted projects
31,057
Unproved properties
95,786
223
Gross capitalized costs
1,305,175
117,121
1,422,519
Accumulated depreciation
(647,458)
(649,544)
Total net capitalized costs
657,717
115,035
772,975
189,282
3,220
950,388
38,561
45,897
23,856
261
88,105
12,749
1,251,631
42,143
58,646
1,352,420
(561,537)
(37,257)
(16,683)
(615,477)
690,094
41,963
736,943
165,666
4,121
74,491
244,278
841,063
48,448
31,149
330,024
1,250,684
15,770
69,823
330
10,426
1,092,322
52,910
41,575
404,515
1,591,322
(447,716)
(47,388)
(8,522)
(379,448)
(883,074)
644,606
5,522
33,053
25,067
708,248
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Table 3 - Results of operations for oil and gas producing activities
The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2025, 2024 and 2023. Income tax for the years presented was calculated utilizing the statutory tax rates.
492,099
Production costs, excluding depreciation
(115,804)
(131,468)
(8,210)
(9,274)
Total production costs
(140,742)
Exploration expenses
(20,126)
(2,345)
(22,661)
Accretion expense (a)
(1,319)
(576)
(1,957)
Depreciation, depletion and amortization
(105,783)
(4,079)
(111,949)
Results of operations before income tax
210,176
(2,745)
961
(24,591)
183,801
Income tax (expense) benefit
(73,562)
(327)
(1,600)
(74,528)
Results of oil and gas operations
136,614
(1,784)
634
(26,191)
109,273
653,661
(133,197)
(147,087)
(10,437)
(10,673)
(157,760)
(13,984)
(2,839)
(242)
(7,880)
(24,945)
(987)
(636)
(128)
(1,751)
(113,820)
(227)
(8,162)
(122,209)
347,337
(2,311)
4,848
346,996
(156,302)
786
(1,212)
(156,728)
191,035
(1,525)
3,636
190,268
751,161
(121,012)
(142,782)
(83,233)
(84,877)
(227,659)
(36,395)
(1,481)
(309)
(56)
(38,331)
(669)
(560)
(1,478)
(2,794)
(92,735)
(1,047)
(6,205)
(8,278)
(108,265)
368,357
7,376
2,254
(15,726)
360,780
(165,761)
(2,508)
(168,833)
202,596
4,868
1,690
191,947
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Table 4 - Reserve quantity information
Estimated oil and gas reserves
Proved reserves represent estimated quantities of oil (including crude oil and condensate) and natural gas, which available geological and engineering data demonstrates with reasonable certainty to be recoverable in the future from known reservoirs under existing economic and operating conditions. Proved developed reserves are proved reserves that can reasonably be expected to be recovered through existing wells with existing equipment and operating methods. The choice of method or combination of methods employed in the analysis of each reservoir was determined by the stage of development, quality and reliability of basic data, and production history.
The Group believes that its estimates of remaining proved recoverable oil and gas reserve volumes are reasonable and such estimates have been prepared in accordance with the SEC Modernization of Oil and Gas Reporting rules, which were issued by the SEC at the end of 2008.
The Group estimates its reserves at least once a year. The Group’s reserves estimation as of December 31, 2025, 2024, 2023 and 2022 was based on the DeGolyer and MacNaughton Reserves Report (the “D&M Reserves Report”). DeGolyer and MacNaughton Corp. prepared its proved oil and natural gas reserve estimates in accordance with Rule 4-10 of Regulation S–X, promulgated by the SEC, and in accordance with the oil and gas reserves disclosure provisions of ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities - Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities).
Reserves engineering is a subjective process of estimation of hydrocarbon accumulation, which cannot be exactly measured, and the reserve estimation depends on the quality of available information and the interpretation and judgement of the engineers and geologists. Therefore, the reserves estimations, as well as future production profiles, are often different than the quantities of hydrocarbons which are finally recovered. The accuracy of such estimations depends, in general, on the assumptions on which they are based.
The estimated GeoPark net proved reserves for the properties evaluated as of December 31, 2025, 2024, 2023, and 2022 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
As of December 31, 2022
Oil and
condensate
(Mbbl)
(MMcf)
Colombia (a)
43,409
49,959
884
43,120
1,075
46,623
1,065
1,807
430
Brazil (c)
6,116
8,888
9,443
Ecuador (d)
515
1,017
322
Chile (e)
619
9,956
1,115
14,103
Total consolidated
45,216
50,489
44,784
19,919
48,068
24,611
Colombia (f)
4,082
6,396
16,225
17,765
8,885
2,114
367
1,278
479
855
12,967
6,763
17,982
18,241
Total proved reserves
58,183
2,544
57,252
62,766
20,774
66,309
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Table 5 - Net proved reserves of oil, condensate and natural gas
Net proved reserves (developed and undeveloped) of oil and condensate:
Thousands of barrels
Reserves as of December 31, 2022
64,388
1,591
Increase (decrease) attributable to:
Revisions (a)
3,617
324
(412)
3,555
Extensions and discoveries (b)
2,549
1,937
4,486
(11,209)
(288)
(11,584)
Reserves as of December 31, 2023
59,345
2,295
1,098
Revisions (c)
7,495
(803)
6,680
Extensions and discoveries (d)
Disposal of Minerals in place (e)
(10,970)
(610)
(11,583)
Reserves as of December 31, 2024
56,355
882
Revisions (f)
2,354
Extensions and discoveries (g)
Purchase or (Disposal) of Minerals in place (h)
(1,644)
10,788
(488)
8,644
(9,597)
(394)
(10,090)
Reserves as of December 31, 2025
47,491
10,692
- An increase of 1.7 mmbbl in Colombia due to a change in a previously adopted development plan.
- An increase of 1.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells.
- An increase of 0.4 mmbbl in Colombia due to a change in the royalties’ payment in certain fields from kind to cash.
- An increase of 0.3 mmbbl in Ecuador due to higher average oil prices.
- Such increase was partially offset by lower-than-expected performance from the existing wells in Chile by 0.4 mmbbl.
- An increase of 5.5 mmbbl in Colombia due to higher-than-expected performance from the existing wells.
- An increase of 3.2 mmbbl in Colombia due to a change in a previously adopted development plan.
- Such increase was partially offset by lower average oil prices by 1.2 mmbbl in Colombia.
- A decrease of 0.6 mmbbl in Ecuador due to unsuccessful activities.
- A decrease of 0.2 mmbbl in Ecuador due to lower-than-expected performance from the existing wells
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- An increase of 2.7 mmbbl in Colombia due to higher-than-expected performance from the existing wells.
- An increase of 1.0 mmbbl in Colombia due to a change in a previously adopted development plan.
- Such increase was partially offset by lower average oil prices by 1.3 mmbbl in Colombia.
Net proved reserves (developed and undeveloped) of natural gas:
Millions of cubic feet
219
1,659
1,869
(209)
(2,214)
(5,706)
10,811
Revisions (b)
(2,291)
(2,232)
Disposal of Minerals in place (c)
(10,678)
(481)
(133)
(864)
Purchase or (Disposal) of Minerals in place (d)
(828)
2,597
(4,992)
(3,223)
(1,124)
(1,233)
Revisions refer to changes in interpretation of discovered accumulations and some technical and logistical needs in the area obliged to modify the timing and development plan of certain fields under appraisal and development phases.
Table 6 - Standardized measure of discounted future net cash flows related to proved oil and gas reserves
The following table discloses estimated future net cash flows from future production of proved developed and undeveloped reserves of crude oil, condensate and natural gas. As prescribed by SEC Modernization of Oil and Gas Reporting rules and ASC 932 of the FASB Accounting Standards Codification (ASC) relating to Extractive Activities – Oil and Gas (formerly SFAS no. 69 Disclosures about Oil and Gas Producing Activities), such future net cash flows were estimated using the average first day-of-the-month price during the 12-month period for 2025, 2024 and 2023 and using a 10% annual discount factor. Future development and abandonment costs include estimated drilling costs, development and exploitation installations and abandonment costs. These future development costs were estimated based on evaluations made by the
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Group. The future income tax was calculated by applying the statutory tax rates in effect in the respective countries in which we have interests, as of the date this supplementary information was filed.
This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons.
Future cash inflows
2,644,803
638,021
3,282,824
Future production costs
(1,371,337)
(249,495)
(1,620,832)
Future development costs
(173,253)
(147,674)
(320,927)
Future income taxes
(318,394)
(48,333)
(366,727)
Undiscounted future net cash flows
781,819
192,519
974,338
10% annual discount
(204,268)
(107,211)
(311,479)
Standardized measure of discounted future net cash flows
577,551
85,308
662,859
3,636,275
50,881
60,366
3,747,522
(1,658,050)
(32,028)
(30,319)
(1,720,397)
(145,645)
(15,228)
(8,775)
(169,648)
(525,755)
(1,437)
(527,192)
1,306,825
2,188
21,272
1,330,285
(414,437)
3,462
(2,575)
(413,550)
892,388
5,650
18,697
916,735
4,027,686
75,757
140,607
111,384
4,355,434
(1,633,889)
(22,815)
(45,052)
(50,343)
(1,752,099)
(147,045)
(1,204)
(13,768)
(41,359)
(203,376)
(764,309)
(4,036)
(27,648)
(795,993)
1,482,443
47,702
54,139
19,682
1,603,966
(430,250)
(6,476)
(11,436)
5,205
(442,957)
1,052,193
41,226
42,703
24,887
1,161,009
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Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves
Present value as of December 31, 2022
1,381,801
22,911
15,658
64,285
1,484,655
Sales of hydrocarbon, net of production costs
(491,525)
(8,143)
(6,673)
(6,362)
(512,703)
Net changes in sales price and production costs
(596,668)
21,490
(2,893)
(33,595)
(611,666)
Changes in estimated future development costs
9,461
(4,440)
(17,908)
5,142
(7,745)
Extensions and discoveries less related costs
72,757
63,619
136,376
Development costs incurred
115,996
500
116,503
Revisions of previous quantity estimates
104,256
9,159
10,642
(11,019)
113,038
Net changes in income taxes
198,769
(2,218)
(21,808)
174,743
Accretion of discount
257,346
2,467
1,566
6,429
267,808
Present value as of December 31, 2023
(469,989)
2,103
(18,561)
(486,408)
(210,958)
(65,632)
(15,290)
(291,880)
(167,126)
41,782
(5,267)
(130,611)
11,586
132,094
401
10,293
142,788
179,475
(18,533)
(24,024)
136,918
Disposal of Minerals in place
(24,926)
183,463
(223)
21,808
205,048
181,650
4,526
7,035
193,211
Present value as of December 31, 2024
(319,063)
(806)
(319,869)
(342,480)
24,700
456
44,596
46,028
46,621
Purchase or (Disposal) of Minerals in place
(35,296)
84,682
(5,650)
(18,697)
25,039
123,815
141,814
Present value as of December 31, 2025
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