audit
UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549
FORM
(Mark One)
OR
For the fiscal year ended
OR
For the transition period from ______________________ to ___________________________
OR
Date of event requiring this shell company report
Commission file number:
(Exact name of Registrant as specified in its charter)
(Jurisdiction of incorporation)
(Address of principal executive offices)
Chief Strategy, Sustainability and Legal Officer
GeoPark Limited
Phone: +
(Name, Telephone, E-mail and/or Facsimile number and Address of Company Contact Person)
Copies to:
Davis Polk & Wardwell LLP
Phone: (
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 |
Securities registered or to be registered pursuant to Section 12(g) of the Act:
None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:
None
Indicate the number of outstanding shares of each of the issuer’s classes of capital stock or common stock as of the close of business covered by the annual report.
Common shares:
Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.
Yes ☐
If this report is an annual or transition report, indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Securities Exchange Act of 1934.
Yes ☐
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.
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 ☐ | 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 ☐ |
| Other ☐ |
If “Other” has been checked in response to the previous question indicate by check mark which financial statement item the registrant has elected to follow.
☐ Item 17 ☐ Item 18
If this is an annual report, indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act).
Yes
GEOPARK LIMITED
TABLE OF CONTENTS
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ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS | 1 | ||
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ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK | 137 | ||
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES | 137 | ||
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ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS | 138 | ||
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Management’s Annual Report on Internal Control over Financial Reporting | 138 | ||
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ITEM 16D. Exemptions from the listing standards for audit committees | 141 | ||
ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers. | 141 | ||
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ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections | 143 | ||
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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.
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“exploratory well” means a well drilled to find and produce oil or gas in an unproved area, to find a new reservoir in a field previously found to be productive of oil or gas in another reservoir, or to extend a known reservoir. Generally, an exploratory well is any well that is not a development well, a service well, or a stratigraphic test well as those items are defined below.
“field” means an area consisting of a single reservoir or multiple reservoirs all grouped on or related to the same individual geological structural feature and/or stratigraphic condition. There may be two or more reservoirs in a field that are separated vertically by intervening impervious strata, or laterally by local geologic barriers, or by both. Reservoirs that are associated by being in overlapping or adjacent fields may be treated as a single or common operational field. The geological terms structural feature and stratigraphic condition are intended to identify localized geological features as opposed to the broader terms of basins, trends, provinces, plays, areas-of-interest, etc.
“formation” means a layer of rock which has distinct characteristics that differ from nearby rock.
“mbbl” means one thousand barrels of crude oil, condensate, or natural gas liquids.
“mboe” means one thousand barrels of oil equivalent.
“mcf” means one thousand cubic feet of natural gas.
“Measurements” include:
● | “m” or “meter” means one meter, which equals approximately 3.28084 feet; |
● | “km” means one kilometer, which equals approximately 0.621371 miles; |
● | “sq. km” means one square kilometer, which equals approximately 247.1 acres; |
● | “bbl” or “barrel of oil” means one stock tank barrel, which is equivalent to approximately 0.15898 cubic meters; |
● | “boe” means one barrel of oil equivalent, which equals approximately 160.2167 cubic meters, determined using the ratio of 6,000 cubic feet of natural gas to one barrel of oil; |
● | “cf” means one cubic foot; |
● | “m,” when used before bbl, boe or cf, means one thousand bbl, boe or cf, respectively; |
● | “mm,” when used before bbl, boe or cf, means one million bbl, boe or cf, respectively; |
● | “b,” when used before bbl, boe or cf, means one billion bbl, boe or cf, respectively; and |
● | “pd” means per day. |
“metric ton” or “MT” means one thousand kilograms. Assuming standard quality oil, one metric ton equals 7.9 bbl.
“mmbbl” means one million barrels of crude oil, condensate or natural gas liquids.
“mmboe” means one million barrels of oil equivalent.
“mmbtu” means one million British thermal units.
“productive well” means a well that is found to be capable of producing hydrocarbons in sufficient quantities such that proceeds from the sale of the production exceed production expenses and taxes.
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“prospect” means a potential trap which may contain hydrocarbons and is supported by the necessary amount and quality of geologic and geophysical data to indicate a probability of oil and/or natural gas accumulation ready to be drilled. The five required elements (generation, migration, reservoir, seal and trap) must be present for a prospect to work and if any of them fail neither oil nor natural gas will be present, at least not in commercial volumes.
“proved developed reserves” means those proved reserves that can be expected to be recovered through existing wells and facilities and by existing operating methods.
“proved reserves” means estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty to be economically recoverable in future years from known reservoirs under existing economic and operating conditions, as well as additional reserves expected to be obtained through confirmed improved recovery techniques, as defined in SEC Regulation S-X 4 10(a)(2).
“proved undeveloped reserves” means are those proved reserves that are expected to be recovered from future wells and facilities, including future improved recovery projects which are anticipated with a high degree of certainty in reservoirs which have previously shown favorable response to improved recovery projects.
“reasonable certainty” means a high degree of confidence.
“recompletion” means the process of re-entering an existing wellbore that is either producing or not producing and completing new reservoirs in an attempt to establish or increase existing production.
“reserves” means estimated remaining quantities of oil and gas and related substances anticipated to be economically producible, as of a given date, by application of development projects to known accumulations. In addition, there must exist, or there must be a reasonable expectation that there will exist, a revenue interest in the production, installed means of delivering oil, gas, or related substances to market, and all permits and financing required to implement the project.
“reservoir” means a porous and permeable underground formation containing a natural accumulation of producible oil and/or gas that is confined by impermeable rock or water barriers and is individual and separate from other reservoirs.
“royalty” means a fractional undivided interest in the production of oil and natural gas wells or the proceeds therefrom, to be received free and clear of all costs of development, operations or maintenance.
“service well” means a well drilled or completed for the purpose of supporting production in an existing field. Specific purposes of service wells include gas injection, water injection, steam injection, air injection, saltwater disposal, water supply for injection, observation, or injection for in-situ combustion.
“shale” means a fine-grained sedimentary rock formed by consolidation of clay- and silt-sized particles into thin, relatively impermeable layers. Shale can include relatively large amounts of organic material compared with other rock types and thus has the potential to become rich hydrocarbon source rock. Its fine grain size and lack of permeability can allow shale to form a good cap rock for hydrocarbon traps.
“spacing” means the distance between wells producing from the same reservoir. Spacing is often expressed in terms of acres (e.g., 40-acre spacing, and is often established by regulatory agencies).
“stratigraphic test well” means a drilling effort, geologically directed, to obtain information pertaining to a specific geologic condition. Such wells customarily are drilled without the intention of being completed for hydrocarbon production. This classification also includes tests identified as core tests and all types of expendable holes related to hydrocarbon exploration. Stratigraphic test wells are classified as (i) exploratory-type, if not drilled in a proved area, or (ii) development-type, if drilled in a proved area.
“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
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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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PRESENTATION OF FINANCIAL AND OTHER INFORMATION
Certain definitions
Unless otherwise indicated or the context otherwise requires, all references in this annual report to:
● | “GeoPark Limited,” or the “Company” are to GeoPark Limited, an exempted company incorporated under the laws of Bermuda; |
● | “GeoPark,” “we,” “us,” “our,” the “Group” and words of a similar effect, are to GeoPark Limited together with its consolidated subsidiaries; |
● | “Amerisur” are to Amerisur Resources Limited and its subsidiaries; |
● | “GeoPark Brazil” are to GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda.; |
● | “Ecopetrol” are to Ecopetrol S.A.; |
● | “YPF” are to YPF S.A.; |
● | “ONGC” are to ONGC Videsh Limited, international petroleum company of India; |
● | “Argentina (Vaca Muerta) acquisition” or “Acquisition in Argentina (Vaca Muerta)” refers to our acquisition of non-operated working interests in four adjacent unconventional blocks in the Vaca Muerta shale formation in the Neuquén Basin in Argentina. We entered into the farm-out agreement for this acquisition in May 2024, and closing of the transaction is pending customary regulatory approvals from the respective provincial governments; |
● | “PGR” or “Phoenix” are to Phoenix Global Resources; a subsidiary of Mercuria Energy Trading (“Mercuria”), together with its consolidated subsidiaries, such as Petrolera El Trebol S.A. (“PETSA”), Kilwer S.A. and Ketsal S.A.; |
● | “GyP” are to Gas y Petróleo de Neuquén S.A., the state owned entity of the Neuquén province in Argentina; |
● | “EDHIPSA” are to Empresa de Desarrollo Hidrocarburífero Provincial S.A., the state owned entity of the Río Negro province in Argentina; |
● | “Petroecuador” are to the Ecuador Hydrocarbons Public Company (Empresa Pública de Hidrocarburos del Ecuador); |
● | “MSCI” are to Morgan Stanley Capital International; |
● | “Notes due 2027” are to our 2020 issuance of US$350.0 million aggregate principal amount and our 2021 additional issuance of US$150.0 million aggregate principal amount of 5.50% senior notes due 2027; |
● | “Notes due 2030” are to our 2025 issuance of US$550.0 million aggregate principal amount of 8.75% senior notes due 2030; |
● | “US$” and “U.S. dollar” are to the official currency of the United States of America; |
● | “AR$” and “Argentine pesos” are to the official currency of Argentina; |
● | “real,” “reais” and “R$” are to the official currency of Brazil; |
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● | “ANH” are to the Colombian National Hydrocarbons Agency (Agencia Nacional de Hidrocarburos); |
● | “ANP” are to the Brazilian National Petroleum, Natural Gas and Biofuels Agency (Agência Nacional do Petróleo, Gás Natural e Biocombustíveis); |
● | “RODA” are to the Oil Pipeline Network of the Amazonian District (Red de Oleoductos del Distrito Amazónico); |
● | “SOTE” are to the Ecuadorian Oil Pipeline System (Sistema de Oleoducto Transecuatoriano); |
● | “IOGP” are to the International Association of Oil and Gas Producers; |
● | “IPIECA” are to the International Petroleum Industry Environmental Conservation Association; |
● | “IADC” are to the International Association of Drilling Contractors; |
● | “ARPEL” are to the Regional Association of Oil and Gas Companies; |
● | “UTA” are to Unidad Tributaria Anual; |
● | “economic interest” are to an indirect participation interest in the net revenues from a given block based on bilateral agreements with the concessionaires; |
● | “ESG” are to Environmental, Social and Governance; and |
● | “IFC” are to the International Finance Corporation. |
Financial statements
Our historical financial data presented does not include any results or other financial information of any acquisitions, prior to their incorporation into our financial statements.
Our consolidated financial statements
This annual report includes our audited consolidated financial statements as of December 31, 2024 and 2023 and for each of the years ended December 31, 2024, 2023 and 2022 (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, 2024, 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 2024,” 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 Company 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 2024, 2023 and 2022.
Oil and gas reserves and production information
DeGolyer and MacNaughton 2024 Year-end Reserves Report
The information included elsewhere in this annual report regarding estimated quantities of proved reserves in Colombia, Ecuador, Brazil and Argentina is derived from estimates of the proved reserves as of December 31, 2024. While the report includes estimated proved reserves in Argentina, such reserves are presented on a pro forma basis as closing of the Argentina (Vaca Muerta) acquisition is pending customary regulatory approvals from the respective provincial governments. The reserves estimates described herein are derived from the DeGolyer and MacNaughton Reserves Report (“D&M Reserves Report”), which was prepared for us by the independent reserves engineering team of DeGolyer and MacNaughton Corp. and is included as an exhibit to this annual report. The D&M Reserves Report presents oil and gas reserves estimates located in various blocks in the Llanos and Putumayo Basins in Colombia, the Perico Block in the Oriente Basin in Ecuador, the BCAM-40 (Manati) Block in the Camamu-Almada Basin in Brazil and the Mata Mora Norte Block and Confluencia Norte Block 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
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been independently verified. However, we believe such data is accurate and agree that we are responsible for the accurate extraction of such information from such sources and its correct reproduction in this annual report.
In addition, we have provided definitions for certain industry terms used in this annual report in the “Glossary of oil and natural gas terms”.
Rounding
We have made rounding adjustments to some of the figures included elsewhere in this annual report. Accordingly, numerical figures shown as totals in some tables may not be an arithmetic aggregation of the figures that precede them.
FORWARD-LOOKING STATEMENTS
This annual report contains statements that constitute forward-looking statements. Many of the forward-looking statements contained in this annual report can be identified by the use of forward-looking words such as “anticipate,” “believe,” “could,” “expect,” “should,” “plan,” “intend,” “will,” “estimate” and “potential,” among others.
Forward-looking statements appear in several places in this annual report and include, but are not limited to, statements regarding our intent, belief or current expectations. Forward-looking statements are based on our management’s beliefs and assumptions and on information currently available to our management. Such statements are subject to risks and uncertainties, and actual results may differ materially from those expressed or implied in the forward-looking statements due to various factors, including, but not limited to, those identified under the section “Item 3. Key Information—D. Risk factors” in this annual report. These risks and uncertainties include factors relating to:
● | the volatility of oil and natural gas prices; |
● | operating risks, including equipment failures and the amounts and timing of revenues and expenses; |
● | termination of, or intervention in, concessions, rights or authorizations granted by the Colombian, Ecuadorian, Brazilian and Argentinian governments to us; |
● | uncertainties inherent in making estimates of our oil and natural gas data; |
● | environmental constraints on operations and environmental liabilities arising out of past or present operations; |
● | discovery and development of oil and natural gas reserves; |
● | climate change related risks; |
● | project delays or cancellations; |
● | financial market conditions and the results of financing efforts; |
● | any future defaults in respect of our outstanding debt agreements; |
● | political, legal, regulatory, governmental, administrative and economic conditions and developments in the countries in which we operate; |
● | social and political unrest in many countries in which we operate; |
● | fluctuations in inflation and/or exchange rates in Colombia, Ecuador, Brazil and Argentina and in other countries in which we may operate in the future; |
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● | availability and cost of drilling rigs, production equipment, supplies, personnel and oil field services; |
● | contract counterparty risk; |
● | projected and targeted capital expenditures and other cost commitments and revenues; |
● | pandemics, or the future outbreak of any highly infectious or contagious disease; |
● | weather and other natural phenomena; |
● | armed conflicts, including the current armed conflicts in Ukraine and Israel; |
● | the impact of recent and future regulatory proceedings and changes, changes in environmental, health and safety and other laws and regulations to which our company or operations are subject, as well as changes in the application of existing laws and regulations; |
● | current and future litigation; |
● | our ability to successfully identify, integrate and complete pending or future acquisitions and dispositions; |
● | our ability to retain key members of our senior management and key technical employees; |
● | information technology failures; |
● | competition from other similar oil and natural gas companies; |
● | market or business conditions and fluctuations in global and local demand for energy; |
● | the direct or indirect impact on our business resulting from terrorist incidents or responses to such incidents, including the effect on the availability of and premiums on insurance; |
● | the adverse effect which a substantial or extended decline in oil and natural gas price may have on our business; |
● | potential impacts that tariffs may have on our cost structure, supply chain, and commodity markets; |
● | the difficulty in integrating significant acquisitions, including the Acquisition in Argentina (Vaca Muerta), or unexpected contingencies or changes in reserves estimates we discover following the completion of such acquisitions; and |
● | other factors discussed under “Item 3. Key Information—D. Risk factors” in this annual report. |
Forward-looking statements speak only as of the date they are made, and we do not undertake any obligation to update them in light of new information or future developments or to release publicly any revisions to these statements in order to reflect later events or circumstances or to reflect the occurrence of unanticipated events.
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SUMMARY
This summary highlights certain information appearing elsewhere in this Annual Report. As this is a summary, it does not contain all the information you should consider in making an investment decision. You should read this entire Annual Report carefully before investing in the Company, including the risk factors and uncertainties set forth in “Item 3. Key Information—D. Risk factors.”
About Us
We are a leading independent energy company with over 20 years of successful operations across Latin America and a long-term strategy to build a unique risk-balanced portfolio in the region’s main basins.
Our high-return core assets in Colombia’s Llanos Basin demonstrate our exploration and operational strength. In Argentina, we have entered a new growth phase with Vaca Muerta, Latin America’s fastest-growing play, pending customary regulatory approvals for the acquisition. Our position in Ecuador gives us access to acreage in an established petroleum system, and we also have a non-operated interest in the shallow-water offshore Manati gas field in Brazil, which is in process of divestment.
Leveraging both operated and non-operated organic and inorganic opportunities, we are focused on sustainable growth with an achievable aspiration of producing 100 mboepd by the end of the decade, a scale that will give us access to opportunities with greater economic and strategic value for our investors.
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$300 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 North Star Strategy
Our North Star strategy is grounded in profitability, reliability and sustainability, ensuring we deliver strong results today while remaining resilient in the competitive oil and gas industry. This strategy guides our long-term success and adaptability in an evolving energy landscape and is built on the following five key principles:
● | Highly profitable, dependable and sustainable: Strong focus on maintaining and improving efficiency and profitability, underpinned by operational excellence and a comprehensive sustainability strategy. As part of our commitment to reducing our environmental impact, we have set ambitious targets to decrease carbon intensity by 35-40% compared to 2020 levels. |
● | Focused on growth through big assets, big basins and big plays: Leveraging on our competitive strengths to maximize opportunities, the strategy is built on a foundation of (i) distinctive assets, such as Llanos 34, CPO-5, and Vaca Muerta (ii) operating across differentiated basins, including both conventional and unconventional resources, and (iii) a diversified footprint spanning Colombia, Argentina, and Brazil to capitalize on large-scale, high-impact opportunities across the region. |
● | Near term performance, long term vision and targets: Strong organic footprint leveraged by accretive inorganic opportunities. Our North Star targets include 70 mboepd net production by 2028, while maintaining 400 mmboe proved plus probable reserves, and 100 mboepd net production by 2030. |
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● | Financial flexibility and stewardship: We are committed to maintaining conservative leverage metrics, ensuring a balanced and sustainable financial structure while generating attractive cash flows. Our diversified financing sources enhance resilience and provide access to capital across various markets. Additionally, our proactive hedging strategy mitigates risks associated with market volatility, reinforcing financial stability. |
● | Competitive shareholder returns while driving sustainable growth: Generating consistent and attractive returns for investors through efficient operations and strategic investments, striking a balance between profitability and long-term responsibility. |
At the core of our strategy and business model lies a culture of agility, adaptability, and trust that empowers all employees with autonomy, ownership of their actions and results, and a crucial role in our success.
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 10 producing oil fields, Jacana and Tigana. Now starting its process of natural decline, the Llanos 34 Block produced 21,659 bopd at our working interest in 2024 and holds certified proved reserves of 49.1 mmboe as of December 31, 2024.
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 10 producing oil fields. Although the CPO-5 Block has also started its process of natural decline, net production in 2024 was 6,931 bopd and proved reserves were 3.5 mmboe as of December 31, 2024.
We also operate the Llanos 86, Llanos 87, Llanos 104, Llanos 123, and Llanos 124 Blocks in the Llanos Basin. Significant discoveries were made in the Llanos 123 Block, including the Toritos, Saltador, and Bisbita oil fields, with a net production of 1,332 bopd during 2024. Elsewhere in Colombia, we hold several blocks in the underexplored yet proven Putumayo Basin, including our developed Platanillo Block.
In 2024, we made a transformative acquisition in Argentina’s Vaca Muerta shale formation, and we entered into a farm-out agreement for non-operated positions in the unconventional Mata Mora Norte, Mata Mora Sur, Confluencia Norte and Confluencia Sur Blocks. Closing of the transaction is pending customary regulatory approvals from the respective provincial governments. The acquisition continues our history of generating value through inorganic opportunities, and has an immediate impact on production, reserves, and cash flow. We have 22 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.
The Perico and Espejo Blocks in Ecuador and the Manati gas field in Brazil (which is in process of divestment) are also part of our asset portfolio, which gives us positions in some of Latin America’s largest basins.
Our Sustainability Approach
Building on our SPEED foundation, in 2024, we developed a comprehensive sustainability framework that reinforces our commitment and enhances our capacity to navigate sustainability-related risks and opportunities, generate operational efficiencies and amplify positive impacts beyond our operations. This approach strengthens our resilience in the face of dynamic regulatory landscapes and societal expectations in issues related to decarbonization, climate change adaptation, energy security and human rights, among others. This major step forward enhances our operational practices and ensures that we are consistently aligned with our North Star strategy, remaining competitive in a rapidly evolving market.
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A key goal in 2025 is to make our suppliers, contractors and partners knowledgeable of our Safety, Prosperity, Employees, Environment and Community Development values and seek to have our suppliers, contractors and partners incorporate such values in their practices, applying our sustainability commitment to our entire value chain.
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PART I
ITEM 1. IDENTITY OF DIRECTORS, SENIOR MANAGEMENT AND ADVISERS
A. Directors and senior management
Not applicable.
B. Advisers
Not applicable.
C. Auditors
Not applicable.
ITEM 2. OFFER STATISTICS AND EXPECTED TIMETABLE
A. Offer statistics
Not applicable.
B. Method and expected timetable
Not applicable.
ITEM 3. KEY INFORMATION
A. Reserved
B. Capitalization and indebtedness
Not applicable.
C. Reasons for the offer and use of proceeds
Not applicable.
D. Risk factors
Our business, financial condition and results of operations could be materially and adversely affected if any of the risks described below occur. As a result, the market price of our common shares could decline, and you could lose all or part of your investment. This annual report also contains forward-looking statements that involve risks and uncertainties. See “Forward-Looking Statements.” The risks below are not the only ones facing our Company. Additional risks not currently known to us or that we currently deem immaterial may also adversely affect us. The following risk factors have been grouped as follows:
a) | Risks relating to our business; |
b) | Risks relating to the countries in which we operate; and |
c) | Risks relating to our common shares. |
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Summary of Key Risks
Our business is subject to numerous risks and uncertainties, discussed in more detail below. These risks include, among others, the following key risks:
● | A substantial or extended decline in oil and natural gas prices may materially adversely affect our business, financial condition, or results of operations. |
● | Low oil prices may impact our operations and corporate strategy. |
● | Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities. |
● | We derive a significant portion of our revenues from sales to a few key customers. |
● | Our results of operations could be materially adversely affected by fluctuations in foreign currency exchange rates. |
● | There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas. |
● | Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling. |
● | Our business requires significant capital investment and maintenance expenses, which we may be unable to finance on satisfactory terms or at all. |
● | Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business. |
● | The development schedule of oil and natural gas projects is subject to cost overruns and delays. |
● | Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel. |
● | Our estimated oil and gas reserves are based on assumptions that may prove inaccurate. |
● | Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production. |
● | We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located. |
● | Under the terms of some of our various E&P contracts, exploration permits, exploitation concessions, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas. |
● | Our contracts 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, production sharing agreements and concession agreements are subject to early termination in certain circumstances. |
● | We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets. |
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● | Acquisitions that we have completed, as well as the Argentina (Vaca Muerta) acquisition, 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. |
● | Failure to consummate or uncertainty related to the Argentina (Vaca Muerta) acquisition could adversely affect our business, strategy, and ability to deliver our targets. |
● | The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves. |
● | The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced. |
● | We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations. |
● | Our operations are subject to operating hazards, including 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. |
● | We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified personnel. |
● | We, and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs. |
● | Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and limit our access to financing and insurance. |
● | Legislation and regulatory initiatives relating to hydraulic fracturing and other drilling activities for unconventional oil and gas resources could increase the future costs of doing business, cause delays or impede our plans, and materially adversely affect our operations. |
● | Our indebtedness and other commercial obligations could adversely affect our financial health and our ability to raise additional capital and prevent us from fulfilling our obligations under our existing agreements and borrowing of additional funds. |
● | Our business could be negatively impacted by cybersecurity threats and related disruptions. |
● | The 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 related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business. |
● | We operate in an industry with climate related risks. |
● | We operate in areas of significant biodiversity value. |
● | We operate in areas that have historical and current ties to indigenous peoples. |
● | Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk due to challenges related to overlapping territories and indigenous land titling processes. |
● | New U.S. trade tariffs may adversely affect our cost structure, supply chain, and commodity markets. |
● | 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. |
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● | We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation. |
● | Oil and natural gas companies in Colombia, Ecuador, Brazil and Argentina operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries. |
● | Oil and gas operators are subject to extensive regulation in the countries in which we operate. |
● | Colombia has experienced and continues to experience internal security and community related issues that have had or could have negative effects on the Colombian economy. |
● | Our operations are subject to security and human rights risks. |
● | Exposure to corruption and compliance risks in the jurisdictions in which we operate could adversely affect our business, financial condition, and reputation. |
● | 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. |
● | The Colombian government, through the ANH, announced it will not grant any new oil and gas exploration licenses. |
● | Restrictions on foreign exchange and transfer of funds abroad in Argentina could adversely affect our liquidity and financial flexibility. |
● | An active, liquid, and orderly trading market for our common shares may not develop and the price of our stock may be volatile, which could limit your ability to sell our common shares. |
● | Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. |
● | We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us. |
● | Sales of substantial amounts of our common shares in the public market, or the perception that these sales may occur, could cause the market price of our common shares to decline. |
● | Provisions of the Notes due 2027 and Notes due 2030 could discourage an acquisition of us by a third party. |
● | Certain shareholders have substantial influence over us and could limit your ability to influence the outcome of key transactions, including a change of control. |
● | Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price. |
● | As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it. |
● | There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make. |
● | We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers. |
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● | The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia. |
● | Legislation enacted in Bermuda as to Economic Substance may affect our operations. |
Risks relating to our business
A substantial or extended decline in oil and natural gas prices may materially adversely affect our business, financial condition, or results of operations.
The prices that we receive for our oil and natural gas production heavily influence our revenues, profitability, access to capital and growth rate. Historically, the markets for oil and natural gas have been volatile and will likely continue to be volatile in the future. International oil and natural gas prices have fluctuated widely in recent years and may continue to do so in the future.
The prices that we will receive for our production and the levels of our production depend on numerous factors beyond our control. These factors include, but are not limited, to the following:
● | global economic conditions; |
● | changes in global supply and demand for oil and natural gas; |
● | the conflicts in Ukraine and Israel and other armed conflicts; |
● | the actions of the Organization of the Petroleum Exporting Countries (“OPEC”); |
● | political and economic conditions, including embargoes, in oil-producing countries or affecting other countries; |
● | the level of oil- and natural gas-producing activities, particularly in the Middle East, Africa, Russia, South America and the United States; |
● | the level of global oil and natural gas exploration and production activity; |
● | the level of global oil and natural gas inventories; |
● | availability of markets for natural gas; |
● | weather conditions and other natural disasters; |
● | technological advances affecting energy production or consumption; |
● | domestic and foreign governmental laws and regulations, including environmental, health and safety laws and regulations; |
● | proximity and capacity of oil and natural gas pipelines and other transportation facilities; |
● | the price and availability of competitors’ supplies of oil and natural gas in captive market areas; |
● | quality discounts for oil production based, among other things, on API, sulphur and mercury content; |
● | taxes and royalties under relevant laws and the terms of our contracts; |
● | our ability to enter into oil and natural gas sales contracts at fixed prices; |
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● | the price and availability of alternative fuels, and possible regulations establishing costs for carbon emissions along the value chain; and |
● | future changes to our hedging policies. |
These factors and the volatility of the energy markets make it extremely difficult to predict future oil and natural gas price movements. For example, during the last five 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 2024, Brent crude prices fluctuated within a range of US$69.2 to US$91.2 per barrel, driven by key factors such as the ongoing conflict in the Middle East and expectations surrounding the global economy in 2025, particularly the possibility of a slowdown and its potential impact on crude oil demand. Despite these uncertainties, price stability has been largely supported by measures adopted by OPEC and non-OPEC producers (sometimes referred to as OPEC+), with production cuts of approximately 2.2 million barrels per day. These actions have helped maintain a balanced market, with Brent crude prices averaging US$79.8 per barrel for the year.
For the year ended December 31, 2024, 99% of our revenues were derived from oil. Because we expect that our production mix will continue to be weighted towards oil, our financial results are more sensitive to movements in oil prices.
For 2025, the crude oil market is expected to experience a slightly more balanced supply-demand dynamic. The anticipated slowdown in the global economy, coupled with supply growth from non-OPEC producers such as Canada, Guyana, Argentina, and Brazil, may shift the balance, potentially resulting in supply growth outpacing demand. This scenario could lead to a softer price environment compared to 2024. However, the crude oil market remains highly dynamic, with geopolitical and environmental factors playing critical roles in shaping price movements. Any significant developments—such as escalations in the Russia/Ukraine and/or Middle East armed conflicts—could severely impact the region’s oil supply, potentially causing price volatility and disruptions to the global market.
Lower oil and natural gas prices may impact our revenues on a per unit basis and may also reduce the amount of oil and natural gas that can be produced economically. In addition, changes in oil and natural gas prices can impact the valuation of our reserves and, in periods of lower commodity prices, we may curtail production and capital spending or may defer or delay drilling wells because of lower cash generation. Lower oil and natural gas prices could also affect our growth, including future and pending acquisitions. A substantial or extended decline in oil or natural gas prices could adversely affect our business, financial condition, and results of operations.
Continuing our hedging strategy, we entered into derivative financial instruments with the intent to partially mitigate our exposure to oil price risk. These derivatives were placed with major financial institutions and commodity traders, under ISDA Master Agreements and Credit Support Annexes.
To the extent that we engage in oil price risk management activities to partially protect ourselves from declines in oil price, we may be prevented from realizing the benefits of oil price increases above the levels of the zero-premium collars used to manage oil price risk.
As market values of these derivatives fluctuate, we may post or receive variation cash collaterals with our counterparties. In the event of a significant decrease in the market value of the derivatives, we may have to post cash collateral, if they exceed our available credit lines. Even though cash collateral is returned to us upon reductions in the underlying Brent oil price, having to post cash collaterals could affect our near-term liquidity needs. As of the date of this annual report, we have no cash collateral posted related to our commodity risk management contracts. See Note 8 to our Consolidated Financial Statements for details regarding Commodity Risk Management Contracts.
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Low oil prices may impact our operations and corporate strategy.
We face limitations on our ability to increase prices or improve margins on the oil and natural gas that we sell. As a consequence of the oil price crisis which started in the first half of 2020 (WTI and Brent, the main international oil price markers, fell by more than 45% between December 2019 and March 2020), we immediately took decisive measures to ensure our ability to both maximize ongoing projects and to preserve our cash, such as reducing our work program and made adjustments to our operating and administrative costs, with continuous monitoring to adjust further if necessary. While oil prices have rebounded since then, they may continue to be volatile and thus, we have developed a capital expenditure program for 2025 which may be subject to change as a result of market conditions, developments regarding our business, results of operation and financial condition, and other factors. See “Item 4. Information on the Company—B. Business Overview—2025 Strategy and Outlook.”
Funding our anticipated capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program, which would cause us to further decrease our work program and would harm our business outlook, investor confidence and our share price.
In addition, actions taken by the company to maximize ongoing projects and to reduce expenses, including renegotiations and reduction of oil and gas service contracts and other initiatives such as cost cutting may expose us to claims and contingencies from interested parties that may have a negative impact on our business, financial condition, results of operations and cash flows. If oil prices are lower than expected, we may be unable to meet our contractual obligations with oil and service contracts and suppliers. Equally, those third parties may be unable to meet their contractual obligations to us as a result of the oil price crisis, impacting on our operations.
In budgeting for our future activities, we have relied on a number of assumptions, including, with regard to our discovery success rate, the number of wells we plan to drill, our working interests in our prospects, the costs involved in developing or participating in the development of a prospect, the timing of third-party projects and our ability to obtain needed financing with respect to any further acquisitions and the availability of both suitable equipment and qualified personnel. These assumptions are inherently subject to significant business, political, economic, regulatory, environmental, and competitive uncertainties, conditions in the financial markets, contingencies, and risks, all of which are difficult to predict and many of which are beyond our control. In addition, we opportunistically seek out new assets and acquisition targets to complement our existing operations and have financed such acquisitions in the past through the incurrence of additional indebtedness, including additional bank credit facilities, equity issuances or the sale of minority stakes in certain operations to our partners. We may need to raise additional funds more quickly if one or more of our assumptions prove to be incorrect or if we choose to expand our hydrocarbon asset acquisition, exploration, appraisal or development efforts more rapidly than we presently anticipate, and we may decide to raise additional funds even before we need them if the conditions for raising capital are favorable. The ultimate amount of capital that we will expend may fluctuate materially based on market conditions, our continued production, decisions by the operators in blocks we do not operate, the success of our drilling results and future acquisitions. Our future financial condition and liquidity will be impacted by, among other factors, our level of production of oil and natural gas and the prices we receive from the sale thereof, the success of our exploration and appraisal drilling program, the number of commercially viable oil and natural gas discoveries made and the quantities of oil and natural gas discovered, the speed with which we can bring such discoveries to production and the actual cost of exploration, appraisal and development of our oil and natural gas assets.
Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.
Production from oil and gas properties declines as reserves are depleted, with the rate of decline depending on reservoir characteristics and field maturity. Accordingly, our current proved reserves will decline as these reserves are produced. As of December 31, 2024, our reserves-to-production (or reserve life) ratio for net proved reserves in Colombia, Ecuador and
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Brazil was 5.0 years. According to D&M estimates, if on January 1, 2025, we ceased all drilling and development activities, including recompletions, refracts and workovers, our proved developed producing reserves base would decline by 14%, 44%, 12% and 43% during the first year in Colombia, Ecuador, Brazil and the Argentina (Vaca Muerta) acquisition, respectively.
A significant portion of our production comes from relatively mature fields, such as our core Llanos 34 Block, which require continuous investment in drilling, secondary and tertiary recovery methods, and infrastructure optimization to sustain output. Unexpected reservoir performance issues, such as lower-than-anticipated recovery rates or technical challenges in implementing enhanced recovery techniques, could negatively impact our ability to meet production targets and replenish reserves.
Our future oil and natural gas reserves and production, and therefore our cash flows and income, are highly dependent on our success in efficiently developing our current reserves and using cost-effective methods to find or acquire additional recoverable reserves. While we have had success in identifying and developing commercially exploitable fields and drilling locations in the past, we may be unable to replicate that success in the future. We may not identify any more commercially exploitable fields or successfully drill, complete or produce more oil or gas reserves, and the wells which we have drilled, and currently plan to drill within our blocks or concession areas, may not discover or produce any further oil or gas or may not discover or produce additional commercially viable quantities of oil or gas to enable us to continue to operate profitably. If we are unable to replace our current and future production, the value of our reserves will decrease, and our business, financial condition and results of operations will be materially adversely affected.
We derive a significant portion of our revenues from sales to a few key customers.
Due to the nature of the oil and gas industry, a significant portion of our revenue is derived from a few key clients. For example, in 2024, three clients represented 95% of revenue for our Colombian subsidiaries, accounting for 89% 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, Brazil and Argentina 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.
Because our Consolidated Financial Statements are presented in US$, we must translate revenues, expenses and income, as well as assets and liabilities, into US$ at exchange rates in effect during or at the end of each reporting period.
From time to time, we enter into derivative financial instruments in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. In January 2023, we entered into derivative financial instruments (zero-premium collars) with local banks in Colombia, for an amount equivalent to US$38.0 million, in order to anticipate any currency fluctuation with respect to a portion of the estimated income taxes to be paid in April and June 2023. Additionally, in November 2024, we entered into a derivative financial instrument (zero-premium collar) 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. 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.
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There are inherent risks and uncertainties relating to the exploration and production of oil and natural gas.
Our performance depends on the success of our exploration and production activities and on the existence of the infrastructure that will allow us to take advantage of our oil and gas reserves. Oil and natural gas exploration and production activities are subject to numerous risks beyond our control, including the risk that exploration activities will not identify commercially viable quantities of oil or natural gas. Our decisions to purchase, explore, develop, or otherwise exploit prospects or properties will depend in part on the evaluation of seismic and other data obtained through geophysical, geochemical and geological analysis, production data and engineering studies, the results of which are often inconclusive or subject to varying interpretations.
Furthermore, the marketability of any oil and natural gas production from our projects may be affected by numerous factors beyond our control. These factors include, but are not limited to, proximity and capacity of pipelines and other means of transportation, the availability of upgrading and processing facilities, equipment availability and government laws and regulations (including, without limitation, laws and regulations relating to prices, sale restrictions, taxes, governmental stake, allowable production, importing and exporting of oil and natural gas, environmental protection and health and safety). The effect of these factors, individually or jointly, cannot be accurately predicted, but may have a material adverse effect on our business, financial condition, and results of operations.
There can be no assurance that our drilling programs will produce oil and natural gas in the quantities or at the costs anticipated, or that our currently producing projects will not cease production, in part or entirely. Drilling programs may become uneconomic due to an increase in our operating costs or as a result of a decrease in market prices for oil and natural gas. Our actual operating costs or the actual prices we may receive for our oil and natural gas production may differ materially from current estimates. In addition, even if we are able to continue to produce oil and gas, there can be no assurance that we will have the ability to market our oil and gas production. See “—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production” below.
Our identified potential drilling location inventories are scheduled over many years, making them susceptible to uncertainties that could materially alter the occurrence or timing of their drilling.
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—2025 Strategy and Outlook.” We incurred capital expenditures of US$191.3 million and US$199.0 million during the years ended December 31, 2024 and 2023, respectively. See “Item 5. Operating and Financial Review and Prospects—A. Operating Results—Factors Affecting our Results of Operations—Discovery and exploitation of reserves.”
The actual amount and timing of our future capital expenditures may differ materially from our estimates as a result of, among other things, commodity prices, actual drilling results, the availability of drilling rigs and other equipment and services, and regulatory, technological and competitive developments. In response to changes in commodity prices, we
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may increase or decrease our actual capital expenditures. For example, as a result of the oil price decline in 2020 we adjusted the capital expenditures program for that year to US$65-75 million, approximately a 60% reduction from prior preliminary estimates (approximately US$180-200 million).
We intend to finance our future capital expenditures through cash generated by our operations and potential future financing arrangements. However, our financing needs may require us to alter or increase our capitalization substantially through the issuance of debt or equity securities or the sale of assets.
If our capital requirements vary materially from our current plans, we may require further financing. In addition, we may incur significant financial indebtedness in the future, which may involve restrictions on other financing and operating activities. We may also be unable to obtain financing or financing on terms favorable to us, including as a result of financial institutions having lower capital availability or potentially higher interest rates. These changes could cause our cost of doing business to increase, limit our ability to pursue acquisition opportunities, reduce cash flow used for drilling and place us at a competitive disadvantage. A significant reduction in cash flows from operations or the availability of credit could materially adversely affect our ability to achieve our planned growth and operating results.
Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business.
Oil and gas exploration and production is uncertain and involves a high degree of risk and hazards. Our operations may be disrupted by risks and hazards that are beyond our control and that are common among oil and gas companies, including environmental hazards, blowouts, industrial accidents, occupational safety and health hazards, technical failures, labor disputes, nationwide or regional social protests or blockades, unusual or unexpected geological formations, flooding, earthquakes and extended interruptions due to weather conditions, explosions and other accidents.
While we believe that we maintain customary insurance coverage for companies engaged in similar operations, there are risks that are not subject to insurance coverage, therefore, we are not fully insured against all risks in our business. In addition, insurance that we do, and plan to, carry may contain significant exclusions from and limitations on coverage. We may elect not to obtain certain non-mandatory types of insurance if we believe that the cost of available insurance is excessive relative to the risks presented. The occurrence of a significant event or a series of events against which we are not fully insured, and any losses or liabilities arising from uninsured or underinsured events could have a material adverse effect on our business, financial condition or results of operations.
The development schedule of oil and natural gas projects is subject to cost overruns and delays.
Oil and natural gas projects may experience capital cost increases and overruns due to, among other factors, the unavailability or high cost of drilling rigs and other essential equipment, supplies, personnel, and oil field services. The cost to execute projects may not be properly established and remains dependent upon a number of factors, including the 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; |
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● | obtaining easements and rights of way; |
● | blockades or embargoes; |
● | litigation; |
● | compliance with governmental laws and regulations, including environmental, health and safety laws and regulations; |
● | adverse weather conditions; |
● | unanticipated increases in costs; |
● | natural disasters; |
● | epidemics or pandemics; |
● | accidents; |
● | transportation; |
● | unforeseen engineering and drilling complications; |
● | delays during prior consultation processes; |
● | delays attributable to the operator of the project; |
● | environmental or geological uncertainties; and |
● | other unforeseen circumstances. |
Any of these events or other unanticipated events could give rise to delays in development and completion of our projects and cost overruns.
For example, during 2024, 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. On the other hand, the drilling costs for the Azogue 3 and Azogue 6 wells in the Llanos 32 Block and the Jacana 94 well in the Llanos 34 Block in Colombia, included costs overruns caused by operational issues of US$2.4 million, US$2.2 million and US$ 0.8 million, respectively.
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, the Mata Mora and Confluencia Blocks in Argentina, the Perico Block in Ecuador and the Manati gas field in Brazil, which could adversely affect our financial condition and results of operations.
Delays in the construction and commissioning of projects or other technical difficulties may result in future projected target dates for production being delayed or further capital expenditures being required. These projects may often require the use of new and advanced technologies, which can be expensive to develop, purchase and implement and may not function as expected. Such uncertainties and operating risks associated with development projects could have a material adverse effect on our business, results of operations or financial condition.
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Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel.
We compete with the major oil and gas companies engaged in the exploration and production sector, including state-owned exploration and production companies that possess greater financial and technical resources than we do for researching and developing exploration and production technologies and access to markets, equipment, labor and capital required to acquire, develop and operate our properties. We also compete for the acquisition of licenses and properties in the countries where we operate.
Our competitors may be able to pay more for productive oil and natural gas properties and exploratory prospects and to evaluate, bid for and purchase a greater number of properties and prospects than our financial or personnel resources allow. Our competitors may also be able to offer better compensation packages to attract and retain qualified personnel than we are able to offer. In addition, there is substantial competition for capital available for investment in the oil and natural gas industry. As a result of each of the aforementioned, we may not be able to successfully compete in acquiring prospective reserves, developing reserves, marketing hydrocarbons, attracting and retaining quality personnel or raising additional capital, which could have a material adverse effect on our business, financial condition or results of operations. See “Item 4. Information on the Company—B. Business Overview—Our competition.”
Our estimated oil and gas reserves are based on assumptions that may prove inaccurate.
Our oil and gas reserves estimate as of December 31, 2024, is based on the D&M Reserves Report. Although classified as “proved reserves,” the reserves estimate set forth in the D&M Reserves Reports is based on certain assumptions that may prove inaccurate. DeGolyer and MacNaughton’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us.
Oil and gas reserves engineering is a subjective process of estimating accumulations of oil and gas that cannot be measured in an exact way, and estimates of other engineers may differ materially from those set out herein. Numerous assumptions and uncertainties are inherent in estimating quantities of proved oil and gas reserves, including projecting future rates of production, timing and amounts of development expenditures and prices of oil and gas, many of which are beyond our control. Post estimate drilling, testing and production results may require revisions. For example, if we are unable to sell our oil and gas to customers, this may impact the estimate of our oil and gas reserves. Accordingly, reserves 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
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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 2024, 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 that connects us to the Ecuador pipeline system.
Trucking remains a component of our crude delivery strategy, and while in 2024 we successfully used alternative delivery points and trucking to avoid production setbacks, we cannot assure we would be able to do so in the future.
In Argentina’s Neuquén Basin, where most crude is transported through a pipeline system operating near maximum capacity, the situation is further strained by limited port facilities. While capacity expansions are in progress and we have secured participation in these projects through our partner, partial capacity deliveries implemented throughout 2024 have eased pressure on existing infrastructure. As of the date of this annual report, we have entered into contracts aimed at securing capacity to transport both our current production and the projected development plan for the coming years. Additionally, we have entered into contracts aimed at securing storage and dispatch capacity at port facilities, reinforcing our ability to support sustained production growth and operational stability. We continue to evaluate additional expansion projects aimed at securing future transportation capacity in line with production growth. However, these contracts may not entirely avoid capacity issues in their entirety and any operational disruptions or shutdowns in the pipeline system could impact our ability to transport crude, which may adversely affect our production volumes and financial results.
In Ecuador, our oil production is transported through the existing pipeline infrastructure. While the Ecuadorian pipeline system is well-developed and has operated reliably in the past, we cannot guarantee this will be the case in the future. Also, as production in Ecuador increases, available capacity may be limited. An inability to access transport capacity could adversely affect our production levels or the transport costs associated with getting our production to the market.
In Brazil, despite a mature network of pipelines and storage facilities, we may face occasional access restrictions, particularly during peak seasons in natural gas pipelines. Our gas production from the Manati field is dependent on Petrobras-operated pipelines and any unavailability of these pipelines could reduce production levels from this field.
We may suffer delays or incremental costs due to difficulties in negotiations with landowners and local communities, including indigenous communities, where our reserves are located.
Access to the sites where we operate requires agreements (including easements, rights-of-way and access authorizations), primarily with the owners of the lands on which we intend to develop our operational projects. If we are unable to negotiate easements with landowners, we may have to go to court to obtain access to the sites of our operations, which may delay the progress of our operations at such sites.
In Colombia, although we have agreements with many landowners and ongoing negotiations with others, the economic expectations of landowners have generally increased concomitant with direct negotiations, which may result in delayed access to existing or future sites. Additionally, local communities and other stakeholders in the territory, such as workers’ associations, trade unions and unions for activities related to the industry, are leading demands to the operators, beyond what is legally established, sometimes exerting pressures under de facto means or blockades to operational activities. Although oil and gas companies are managing these situations and stakeholder expectations in the territory, it ultimately becomes necessary to establish agreements for the viability of the operations, which on occasions translates into higher execution costs. Additionally, there are demands for improvements of transport infrastructure and the addressing
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of unsatisfied basic needs that have been historically ignored by the authorities and the fulfillment of such demands may be redirected towards the oil and gas companies.
In Putumayo (Colombia), where we have operating sites, there is presence of illegal groups which may pressure farmers to oppose the control and eradication of illicit crops, and instrumentalize the oil and gas industry with blockades, seeking to draw the attention of the national government and prevent the eradication of these crops.
As part of its international commitments, the Colombian government may seek to enhance the participatory phases of hydrocarbon projects, which could broaden the parameters of community participation and access to information and ultimately affect project timelines. Furthermore, local communities’ expectations may increase because of several reforms the government has announced. If the government reforms do not meet the communities’ expectations, the pressure to reform may shift to the oil and gas industry.
The expectations and demands of local communities on oil and gas companies operating in Colombia may also increase. As a result, local communities have demanded that oil and gas companies invest in fixing and improving public access roads, compensate them for any damages related to use of such roads and, more generally, invest in infrastructure which is commonly paid for with public funds. Due to these circumstances, oil and gas companies in Colombia, including us, are now dealing with increasing difficulties resulting from instances of social unrest, temporary road blockades and conflicts with landowners.
In addition, community and indigenous protests and blockades may arise near our operations, which could adversely affect our business, financial condition or results of operations.
Other legal proceedings such as land restitution, a judicial process implemented because of the peace agreement in Colombia, focus on returning illegally held land to its rightful owners, may delay access to future sites.
There can be no assurance that disputes with landowners and local communities or legal proceedings will not delay our operations or that any agreements we reach with such landowners and local communities or legal proceedings in the future will not require us to incur additional costs, thereby materially adversely affecting our business, financial condition and results of operations. Local communities may also protest or take actions that restrict or cause their elected government to restrict our access to the sites of our operations, which may have a material adverse effect on our operations at such sites.
Under the terms of some of our various E&P contracts, exploration permits, exploitation concessions, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.
To protect our exploration and production rights in our license areas, we must meet various drilling and declaration requirements. In general, unless we make and declare discoveries within periods specified in our various special operation contracts (E&P contracts, exploration permits, exploitation concessions, production sharing agreements and concession agreements), our interests in the undeveloped parts of our license areas may lapse. Should the prospects we have identified under these contracts and agreements yield discoveries, we may face delays in drilling these prospects or be required to relinquish them. The costs to maintain or operate the E&P contracts, exploration permits, exploitation concessions, production sharing agreements and concession agreements over such areas may fluctuate and may increase significantly, and we may not be able to meet our commitments under such contracts and agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. For example, 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 amount of our reserves or production have been derived from our operations in certain blocks, including various blocks in the Llanos and Putumayo Basins in Colombia, the Espejo and Perico Blocks in the Oriente Basin in Ecuador and the BCAM-40 Concession in the Camamu-Almada Basin in Brazil.
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For the year ended December 31, 2024, the different blocks in the Llanos Basin contained 95.6% of our net proved reserves and generated 90.1% of our production, the Platanillo Block in the Putumayo Basin contained 1.1% of our net proved reserves and generated 4.1% of our production, the Espejo and Perico Blocks in the Oriente Basin contained 1.5% of our net proved reserves and generated 4.9% of our production and the BCAM-40 Concession in the Camamu-Almada Basin contained 1.8% of our net proved reserves and generated 0.7% of our production. While our continuing expansion with new exploratory blocks incorporated in our portfolio and the recent acquisition of four unconventional blocks in Argentina, 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, production sharing agreements and concession agreements are subject to early termination in certain circumstances.
Under certain E&P contracts, exploration permits, exploitation concessions, production sharing contracts and concession agreements to which we are or may in the future become parties, we are or may become subject to guarantees to perform our commitments and/or to make payment for other obligations, and we may not be able to obtain financing for all such obligations as they arise. If such obligations are not complied with when due, in addition to any other remedies that may be available to other parties, this could result in cancelation of our E&P contracts, exploration permits, exploitation concessions, production sharing contracts and concession agreements or dilution or forfeiture of interests held by us. As of December 31, 2024, the aggregate outstanding amount of this potential liability for guarantees was US$84.3 million, mainly related to capital commitments in the Llanos 34, CPO-5, Platanillo, PUT-8 and Llanos 86 Blocks in Colombia, the Espejo and Perico Blocks in Ecuador, the Manati field in Brazil and the Campanario Block in Chile. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements” and Note 33.2 to our Consolidated Financial Statements.
Additionally, certain E&P contracts, exploration permits, exploitation concessions, production sharing contracts and concession agreements to which we are or may in the future become a party are subject to set expiration dates. Although we may want to extend some of these contracts beyond their original expiration dates, there is no assurance that we can do so on terms that are acceptable to us or at all, although some of these agreements contain provisions enabling exploration extensions.
In Colombia, our E&P contracts are subject to early termination for a breach by the parties, a default declaration, application of any of the contracts’ unilateral termination clauses or pursuant to termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH and/or a restriction on our ability to engage in contracts with the Colombian government during a certain period of time. See “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Colombia—E&P contracts.” To avoid the breach of an E&P contract due to unfulfillment of our exploration commitments, regulation gives us options such as the ability to transfer or credit those commitments to other E&P contracts, subject to meeting certain regulatory conditions.
In Ecuador, our production sharing contracts may be subject to early termination in case of breach of the obligations under the contract, non-performance of the exploratory commitments or unjustified suspension of the operations, lack of remediation of environmental damages or unauthorized assignment of a working interest under the production sharing contracts, among others, as specified under the laws of the contract. The declaration of an early termination is subject to prior due process, which would allow us to remedy any hypothetical breach claimed against us, or to present our defense allegations. A declaration of early termination will cause forfeiture of equipment and facilities and enforcement of monetary guarantees.
In Brazil, concession agreements in the production phase generally may be renewed at the ANP’s discretion for an additional period, provided that a renewal request is made at least 12 months prior to the termination of the concession agreement and there has not been a breach of the terms of the concession agreement. We expect that all our concession
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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.
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; (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 shall surrender to the government the acreage together with all the improvements, facilities, wells and other equipment that may have been used in the performance of the activities.
Early termination or nonrenewal of any E&P contract, exploration permits, exploitation concessions, production sharing agreements or concession agreement could have a material adverse effect on our business, financial situation, or results of operations.
We are not, and may not be in the future, the sole owner or operator of all our licensed areas and do not, and may not in the future, hold all the working interests in some of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.
We are not the operator or sole owner of all the blocks included in our portfolio. See “Item 4. Information on the Company—B. Business Overview—Operations in Colombia”, “—Operations in Ecuador”, “—Operations in Brazil” and “—Operations in Argentina”. Therefore, certain decisions are not under our sole discretion and need to be agreed to with our partners. Accordingly, our decision-making capabilities may be limited to the extent our partner operators or owners have any limitations with respect to any proposed action or plan.
In addition, the terms of the joint operations agreements or association agreements governing our other partners’ interests in almost all of the blocks that are not wholly owned or operated by us require that certain actions be approved by supermajority vote. The terms of our other current or future license or venture agreements may require at least the majority of working interests to approve certain actions. As a result, we may have limited ability to exercise influence over operations or prospects in the blocks operated by our partners, or in blocks that are not wholly owned or operated by us. A breach of contractual obligations by our partners who are the operators of such blocks could eventually affect our rights in exploration and production contracts in some of our blocks in Colombia, Ecuador, Brazil and Argentina. Our dependence on our partners could prevent us from achieving our target returns for those discoveries or prospects.
Moreover, as we are not the sole owner or operator of all our properties, we may not be able to control the timing of exploration or development activities or the amount of capital expenditures and may therefore not be able to carry out our key business strategies of minimizing the cycle time between discovery and initial production at such properties. The success and timing of exploration and development activities operated by our partners will depend on a number of factors that will be largely outside of our control, including:
● | the timing and amount of capital expenditures; |
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● | the operator’s expertise and financial resources; |
● | approval of other block partners in drilling wells; |
● | the scheduling, pre-design, planning, design and approvals of activities and processes; |
● | selection of technology; and |
● | the rate of production of reserves, if any. |
This limited ability to exercise control over the operations on some of our license areas may cause a material adverse effect on our financial condition and results of operations.
For instance, we are not the operator of the Manati gas field in Brazil, and do not control the execution of the operation. Any delays in the execution schedule of the Manati gas field could have a material adverse effect in our financial condition and results of operation. For example, the production in the Manati gas field, which is currently in the process of divestment (please see “—Recent Developments—Divestment of non-operated working interest in the Manati gas field in Brazil”), has been suspended since mid-March 2024 due to unscheduled maintenance performed by the operator.
Acquisitions that we have completed, as well as the Argentina (Vaca Muerta) acquisition, 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 Argentina (Vaca Muerta) acquisition, requires an assessment of several factors, including recoverable reserves, future oil and natural gas prices, development and operating costs, and potential environmental and other liabilities.
The accuracy of these assessments is inherently uncertain. In connection with these assessments, we perform a review of the subject properties that we believe to be generally consistent with industry practices. Our review and the review of advisors and independent reserves engineers will not reveal all existing or potential problems, nor will it permit us or them to become sufficiently familiar with the properties to fully assess their deficiencies and potential recoverable reserves. Inspections may not always be performed on every well, and environmental conditions are not necessarily observable even when an inspection is undertaken. We, advisors or independent reserves engineers may apply different assumptions when assessing the same field. Even when problems are identified, the seller may be unwilling or unable to provide effective contractual protection against all or part of the problems. We often are not entitled to contractual indemnification for environmental or other liabilities and acquire properties on an “as is” basis. Even in those circumstances in which we have contractual indemnification rights for pre-closing liabilities, it remains possible that the seller might not be able to fulfill its contractual obligations. There can be no assurance that unforeseen problems related to the assets or management of the companies and operations we have acquired, or operations we may acquire or add to our portfolio in the future, will not arise in the future, and these problems could have a material adverse effect on our business, financial condition, and results of operations.
Significant acquisitions and other strategic transactions may involve other risks, including:
● | diversion of our management’s attention to evaluating, negotiating and integrating significant acquisitions and strategic transactions; |
● | challenge and cost of integrating acquired operations, information management and other technology systems and business cultures with ours while carrying on our ongoing business; |
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● | contingencies and liabilities that could not be or were not identified during the due diligence process, including with respect to possible deficiencies in the internal controls of the acquired operations; |
● | challenge and cost of obtaining sufficient financing required to complete the acquisitions and strategic transactions; |
● | tax implications and potential liabilities related to the acquisitions and strategic transactions; |
● | complexities, liabilities or additional costs associated with transaction payments due to capital controls; |
● | regulatory and legal challenges in the host countries, including worsening fiscal conditions, difficulty in obtaining regulatory approvals or environmental licenses, among others, which can materially affect the benefits expected from the acquisitions and strategic transactions; |
● | additional capital needs and cost overruns which may detract from available capital to deploy in other projects in our portfolio; and |
● | challenge of attracting and retaining personnel associated with acquired operations. |
It is also possible that we may not identify suitable acquisition targets or strategic investment, partnership, or alliance candidates. Our inability to identify suitable acquisition targets, strategic investments, partners or alliances, or our inability to complete such transactions, may negatively affect our competitiveness and growth opportunities. Additionally, we may incur one-off transaction-related costs, such as financing and due diligence expenses, even if a proposed acquisition is not completed, as was the case with the proposed acquisition of certain Repsol exploration and production assets in Colombia in 2024. Moreover, if we fail to properly evaluate acquisitions, including the Argentina (Vaca Muerta) acquisition, 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 Argentina (Vaca Muerta) acquisition 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 Argentina (Vaca Muerta) acquisition. Some of these risks include, but are not limited to, risks related to (i) the ability to replace our oil and natural gas reserves and continued identification of productive fields, (ii) our revenues being derived from sales to a few key customers, (iii) fluctuations in foreign currency exchange rates and restrictions or additional costs associated to the access to foreign currency, (iv) exploration and production of oil and natural gas, (v) insurance of oil and gas operations, (vi) potential cost overruns and delays in oil projects, (vii) difficulties to attract capital, acquire properties, marketing oil and securing trained personnel, (viii) estimated reserves being based on assumptions that may prove inaccurate, (ix) availability and access to needed equipment, infrastructure and evacuation capacity in a timely manner, (x) difficulties in negotiations with landowners and local communities, including additional investment and demands imposed by local communities and potential blockades derived thereof, (xi) our contracts being subject to contractual expiration dates and operating conditions, and in certain circumstances, subject to early termination or additional costs or commitments associated to the term extension, (xii) not being the sole owner or operator 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, currently in effect in Argentina as of the date of this annual report, which limit and prohibit the ability to make payments and transfers.
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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.
Failure to consummate or uncertainty related to the Argentina (Vaca Muerta) acquisition could adversely affect our business, strategy, and ability to deliver our targets.
Our pending Argentina (Vaca Muerta) acquisition may not close for various reasons, including our ability to obtain regulatory approvals or to satisfy closing conditions. The realization of any anticipated benefits of our pending Argentina (Vaca Muerta) acquisition is subject to the consummation of the transaction. In the event that we are unable to consummate such acquisition, the market price of our common shares may decline to the extent that the current market price reflects a market assumption that our pending acquisition will be completed.
In addition, uncertainty related to our pending Argentina (Vaca Muerta) acquisition could disrupt our business operations and impact our relationships with our stakeholders. Delays in the closing of the transaction could also affect the expected contribution of these assets to our operating results, potentially preventing us from achieving our business targets within the anticipated timeframe. These factors could negatively affect our ability to execute our strategy and achieve our business objectives.
The present value of future net revenues from our proved reserves will not necessarily be the same as the current market value of our estimated oil and natural gas reserves.
You should not assume that the present value of future net revenues from our proved reserves is the current market value of our estimated oil and natural gas reserves. For the year ended December 31, 2024, we have based the estimated discounted future net revenues from our proved reserves on the 12-month unweighted arithmetic average of the first day-of-the-month price for the preceding 12 months. Actual future net revenues from our oil and natural gas properties will be affected by factors such as actual prices we receive for oil and natural gas, actual cost of development and production expenditures, the amount and timing of actual production, and changes in governmental regulations and taxation.
The timing of both our production and our incurrence of expenses in connection with the development and production of oil and natural gas properties will affect the timing and amount of actual future net revenues from proved reserves, and thus their actual value. In addition, the 10% discount factor we use when calculating discounted future net revenues may not be the most appropriate discount factor based on interest rates in effect from time to time and risks associated with us or the oil and natural gas industry in general.
The development of our proved undeveloped reserves may take longer and may require higher levels of capital expenditures than we currently anticipate. Therefore, our proved undeveloped reserves ultimately may not be developed or produced.
As of December 31, 2024, 88% 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.
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We are exposed to the credit risks of our customers and any material nonpayment or nonperformance by our key customers could adversely affect our cash flow and results of operations.
Our customers may experience financial problems that could have a significant negative effect on their creditworthiness. Severe financial problems encountered by our customers could limit our ability to collect amounts owed to us, or to enforce the performance of obligations owed to us under contractual arrangements.
The combination of declining cash flows, as a result of declines in commodity prices, a reduction in borrowing basis under reserves-based credit facilities and the lack of availability of debt or equity financing may result in a significant reduction of our customers’ liquidity and limit their ability to make payments or perform on their obligations to us.
Some of our customers may be highly leveraged, and, in any event, are subject to their own operating expenses. Therefore, the risk we face in doing business with these customers may increase. Other customers may also be subject to regulatory changes, which could increase the risk of defaulting on their obligations to us. Financial problems experienced by our customers could result in the impairment of our assets, a decrease in our operating cash flows and may also reduce or curtail our customers’ future use of our products and services, which may have an adverse effect on our revenues and may lead to a reduction in reserves.
Our operations are subject to operating hazards, including 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, such as explosions, fires, car and truck accidents, floods, labor disputes, social unrest, community protests or blockades, guerilla attacks, security breaches, pipeline ruptures and spills and mechanical failure of equipment at our or third-party facilities. Any of these events could have a material adverse effect on our exploration and production operations or disrupt transportation or other process-related services provided by our third-party contractors. For example, during 2023 and 2024, we incurred in higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. Additionally, during the 2024 rainy season, the Jacamar, Guaco and Jacana Sur well pads were temporary suspended due to floodings in the Llanos 34 Block in Colombia.
We are highly dependent on certain members of our management and technical team, including our geologists and geophysicists, and on our ability to hire and retain new qualified personnel.
The ability, expertise, judgment and discretion of our management and our technical and engineering teams are key in discovering and developing oil and natural gas resources. Our performance and success are dependent to a large extent upon key members of our management and exploration team, and their loss or departure would be detrimental to our future success. In addition, our ability to manage our anticipated growth depends on our ability to recruit and retain qualified personnel. Our ability to retain our employees is influenced by the economic environment and the remote locations of our exploration blocks, which may enhance competition for human resources where we conduct our activities, thereby increasing our turnover rate. There is strong competition in our industry to hire employees in operational, technical, and other areas, and the supply of qualified employees is limited in the regions where we operate and throughout Latin America generally. The loss of any of our key management or other key employees of our technical team or our inability to hire and retain new qualified personnel could have a material adverse effect on us.
We, and our operations are subject to numerous environmental, social, health and safety laws, regulations and rulings, which may result in material liabilities and costs.
We and our operations are subject to various international, foreign, federal (where applicable), state, and local environmental, health and safety laws and regulations governing, among other things, the emission and discharge of pollutants into the ground, air or water; the generation, storage, handling, use, transportation and disposal of regulated materials; and human health and safety. Our operations are also subject to certain environmental risks that are inherent in the oil and gas industry, and which may arise unexpectedly and result in material adverse effects on our business, financial condition, and results of operations. Breach of environmental laws could result in environmental administrative
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investigations and/or lead to the termination of our concessions and contracts. Other potential consequences include fines and/or criminal or civil environmental actions. For instance, non-governmental organizations may bring actions against us or other oil and gas companies to, among others, halt our activities in any of the countries in which we operate or require us to pay fines. Additionally, in Colombia, environmental licenses are administrative acts subject to class actions that could eventually result in their cancellation, with potential adverse impacts on our E&P contracts.
The Regional Agreement on Access to Information, Public Participation and Justice in Environmental Matters in Latin America and the Caribbean, also known as the Escazú Agreement, is an international human rights treaty that was signed by all the countries in which we operate and has been ratified by all, except for Brazil, where pressure has been growing for the government to ratify. We expect the countries where the Escazú Agreement has been ratified will proceed to regulate the agreement and such regulations may include additional processes on participation and information, which could directly affect our operations as it could require additional processes that take time. Nonetheless, current Colombian processes require minor adjustments to comply with Escazú Agreement with regards to private involvement and we have extensive experience on such processes. The agreement also increases the protection of human rights and environmental activists, protection which we believe is much required in the countries where we operate and is aligned with our commitment to human rights.
We are subject to national and regional environmental regulations and specific environmental requirements as part of the licenses and permits that we must obtain for our operations. We have mechanisms to assure the fulfillment of all those legal obligations such as a permanent external audit, a dedicated environmental team, and our environmental management system. The evidence of the fulfillment of such obligations is consolidated in the yearly environmental reports that are issued to the environmental authorities and correspond to public information. In addition, we are subject to yearly follow-up visits by the national environmental authority. Although we fulfill the requirements, sometimes we have not been and may not always be in complete compliance with some of them due to causes not attributable to us. This is the case of the offset obligations we must implement to compensate for the residual impacts that cannot be avoided, minimized or restored, in which we must consider a concertation process with different stakeholders that could take more time than what the regulation provides. Nevertheless, we report the progress and we define action plans to demonstrate our diligence to reduce the possibility of sanctions, penalties or fines related to a delay in our fulfillment of the obligations, which could have a material adverse effect on our business, financial condition or results of operations.
We have contracted with and intend to continue to hire third parties to perform services related to our operations. We could be held liable for some or all environmental, health and safety costs and liabilities arising out of our actions and omissions as well as those of our block partners, third-party contractors, predecessors, or other operators. To the extent we do not address these costs and liabilities or if we do not otherwise satisfy our obligations, our operations could be suspended, terminated, or otherwise adversely affected. Although we screen our contractors regarding their compliance on several issues, there is a risk that we may contract with third parties with unsatisfactory environmental, health and safety records or that our contractors may be unwilling or unable to cover any losses associated with their acts and omissions. In 2023, we approved and adopted a Supplier Code of Conduct under which we define the minimum obligations and behaviors expected from our contractors and suppliers, aiming to address the risk.
Releases of regulated substances may occur and can be significant. Under certain environmental laws and regulations applicable to us in the countries in which we operate, we could be held responsible for all the costs relating to any contamination at our past and current facilities and at any third-party waste disposal sites used by us or on our behalf. Pollution resulting from waste disposal, emissions and other operational practices might require us to remediate contamination, or retrofit facilities, at substantial cost. We also could be held liable for any and all consequences arising out of human exposure to such substances or for other damage resulting from the release of hazardous substances to the environment, property or to natural resources, or affecting endangered species or sensitive environmental areas. We are currently required to, and in the future may need to, plug and abandon sites in certain blocks in each of the countries in which we operate, which could result in substantial costs.
In addition, we expect continued and increasing attention to climate change issues. Various countries and regions have agreed to regulate emissions of greenhouse gases including methane (a primary component of natural gas) and carbon dioxide (a byproduct of oil and natural gas combustion). The regulation of greenhouse gases and the physical impacts of
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climate change in the areas in which we, our customers and the end-users of our products operate could adversely impact our operations and the demand for our products.
We have set a target to reduce operational Scope 1 and 2 GHG emissions intensity by 35-40 percent by year-end 2025 and by 40-60 percent by year-end 2030 against a 2020 baseline. We also have a long-term ambition to achieve net zero for Scopes 1 and 2 GHG emissions by 2050. Our ability to meet these targets is subject to numerous risks and uncertainties and actions taken in implementing such targets and ambition may also expose us to certain additional and/or heightened financial and operational risks such as increased costs and higher dependency on certain sources of energy, which is also dependent on how we grow. Furthermore, the long-term ambition of reaching net zero emissions by 2050 is inherently less certain due to the longer timeframe and certain factors outside of our control, including the commercial application of future technologies that may be necessary to achieve this long-term ambition. A reduction in GHG emissions relies on, among other things, the ability to develop, access and implement commercially viable and scalable emission reduction strategies and related technologies and actions, as well as our ability to participate in projects that capture carbon and reduce our footprint. The inability to implement these strategies and technologies cost-effectively could jeopardize compliance with the reduction targets.
In addition, achieving the 2030 GHG reduction targets and the 2050 net zero ambition may be affected by changes in the regulatory framework and will require capital expenditures and resources, with the potential that actual costs may differ from the original estimates and the differences may be material.
Environmental, health and safety laws and regulations are complex and change frequently, and our costs of complying with such laws and regulations may adversely affect our results of operations and financial condition. See “Item 4. Information on the Company—B. Business Overview—Health, safety and environmental matters” and “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework.”
Changing investor sentiment towards fossil fuels may affect our operations, impact the price of our common shares and limit our access to financing and insurance.
Factors including the concerns of the effects of the use of fossil fuels on climate change, the impact of oil and gas operations on the environment, environmental damage relating to spills of petroleum products during transportation and potential impacts on human rights, have affected certain investors’ sentiments towards investing in the oil and gas industry.
As a result of these concerns, some institutional, retail, and public investors have announced that they no longer are willing to fund or invest in oil and gas properties or companies or are reducing the amount thereof over time. In addition, certain institutional investors are requesting that issuers develop and implement more robust social, environmental and governance policies and practices. Although we have in place strong and robust social, environmental and governance practices, developing and implementing even broader policies and practices can involve significant costs and require a significant time commitment from our Board, management and employees. Failing to implement the policies and practices as requested by institutional investors may result in such investors reducing their investment in our Company or not investing in our Company at all.
Any reduction in the investor base interested or willing to invest in the oil and gas industry and more specifically, our Company, may result in limiting our access to capital and insurance, increasing the cost of capital and insurance, and decreasing the price and liquidity of our common shares even if our operating results, underlying asset values or prospects have not changed. Additionally, these factors, as well as other related factors, may cause a decrease in the value of our assets which may result in an impairment charge. 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”.
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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 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 fifth time this initiative has been filed in Congress and approval is uncertain.
We currently are not aware of any proposals in Ecuador, Brazil or Argentina 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 March 31, 2025, the principal amount of our outstanding consolidated indebtedness was US$654.7 million, of which 84% corresponds to our Notes due 2030.
Our indebtedness could:
● | limit our capacity to satisfy our obligations with respect to our indebtedness, and any failure to comply with the obligations of our debt instruments, including restrictive covenants and borrowing conditions, could result in an event of default under the agreements governing our indebtedness; |
● | require us to dedicate a substantial portion of our cash flow from operations to the payments on our indebtedness, including due to higher interest rates applicable to our current outstanding indebtedness, thereby reducing the availability of our cash flow to fund acquisitions, working capital, capital expenditures and other general corporate purposes; |
● | place us at a competitive disadvantage compared to certain of our competitors that have less debt; |
● | limit our ability to borrow additional funds; |
● | in the case of our secured indebtedness, if any, lose assets securing such indebtedness upon the exercise of security interests in connection with a default; |
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● | make us more vulnerable to downturns in our business or the economy; and |
● | limit our flexibility in planning for, or reacting to, changes in our operations or business and the industry in which we operate. |
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;
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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 proceedings related to contractual or regulatory privacy, cybersecurity, data protection, or other confidentiality obligations; diminution in the value of our investment in research, development and engineering; and increased costs associated with the implementation of cybersecurity measures to detect, deter, protect against, and recover from such incidents. Furthermore, the need for rapid detection of attempts to gain unauthorized access to our digital infrastructure, often through the use of sophisticated and coordinated means, presents a challenge we must face and any delay or failure to detect cyber incidents could compound potential harms. This could result in significant and compounding losses due to the cost of remediation and reputational consequences.
Our efforts to comply with, and changes to, laws, regulations, and contractual and other actual and asserted obligations concerning privacy, cybersecurity, and data protection, including developing restrictions on cross-border data transfer and data localization, could result in significant expense, and any actual or alleged failure to comply could result in inquiries, investigations, and other proceedings against us by regulatory authorities or other third parties. Customers and third-party providers increasingly demand rigorous contractual provisions regarding privacy, cybersecurity, data protection, confidentiality, and intellectual property, which may increase our overall compliance burden. With respect to certain potential incidents, such as a cyber-attack or data breach, we are covered under a cybersecurity insurance. However, no assurances can be made as to whether the insurance policy is sufficient in coverage or amount to cover all our potential liability.
The 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 related to the pandemic or estimate the ultimate adverse impact that the pandemic may have on our business.
The COVID-19 pandemic and the actions taken by third parties, including, but not limited to, governmental authorities, businesses, and consumers, in response to the pandemic adversely impacted the global economy and created significant volatility in the global financial markets. The COVID-19 pandemic resulted in significant volatility in the financial and commodities markets worldwide, including the dramatic drop in the price of crude oil during 2020. In the event of a potential resurgence of the COVID-19 pandemic, responsive measures may be implemented and further disruptions to the global economy, demand, supply chain and others may occur.
As of the date of this annual report, we believe we have implemented adequate operational measures (such as remote working procedures) to avoid or minimize major disruptions to our business. However, our operations rely on our workforce being able to access our wells, structures and facilities located upon or used in connection with our oil and gas blocks. The uncertainty of the impact that an endemic or pandemic disease may have makes it impossible for us to identify all potential risks related to an endemic or pandemic disease and we cannot assure if, and to what extent, our business, financial condition, cash flows or results of operations may be adversely impacted by any potential resurgence or outbreak of the COVID-19 pandemic, or any other regional or global outbreaks related to any other endemic or pandemic disease.
The COVID-19 pandemic and its unprecedented consequences amplified, and may continue to amplify, the other risks identified in this annual report.
We operate in an industry with climate related risks.
The oil and gas industry, where we operate, is particularly exposed to risks arising from climate change and the energy transition, such as volatility of products prices, possible new regulations that may restrict our operations, or increase our costs to operate, and an increase in extreme weather events that affect our ability to operate. In 2022, we made a climate risk assessment for the entire company, which includes a site-specific working plan on physical and transitional risks to efficiently increase the climate resiliency of our operations.
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Moreover, our main assets are in countries like Colombia and Ecuador, where the risks related to the occurrence of natural hazards such as floods, landslides and droughts are high and expected to increase in the following years. For example, during 2023 and 2024, we incurred in higher energy costs in the Llanos 34 Block due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. During the 2024 rainy season, the Jacamar, Guaco and Jacana Sur well pads were temporarily suspended due to floodings in the Llanos 34 Block in Colombia. Additionally, we received requests to review zoning conditions of our operational clusters, mainly driven by floods in the area.
We operate in areas of significant biodiversity value.
Some of our operations are in or adjacent to areas with significant biodiversity value, some of which are being considered for designation as conservation or protected areas. This could require modifications to our plans in order to adapt our projects to the environmental conditions and the allowed use of the land, which may increase viability costs and delay our timelines. We carry out detailed due diligence processes and specific environmental studies to mitigate the potential impacts derived from this risk, but there are factors outside of our control, such as local politics and political decisions.
We operate in areas that have historical and current ties to indigenous peoples.
We operate in highly culturally diverse areas, which brings us and our operations in close contact with different indigenous groups. This means we may need to carry out prior consultation processes aligned with domestic law and regulations. Such processes may cause delays in planned activities, thereby affecting our operations and may lead to claims from indigenous peoples, including those who have not been certified by the competent authorities, claims of alleged violations of human rights and may encourage requests for expansion of territories and precautionary measures to protect the rights of indigenous peoples, among others.
During 2022 and 2023, as part of our exploration projects and based on certifications of the origin of prior consultation issued by the directorate of the national authority for prior consultation of the Ministry of the Interior, we have made advancements in the development of consultation processes in the department of Meta with the Resguardo, Turpial and La Victoria communities for the Golondrina development area project in the Llanos 86 and Llanos 104 Blocks. The agreements that resulted from the prior consultation process were documented and protocolized in August 2023.
In 2023, the closing of five prior consultation processes that were underway for the 2D and 3D Seismic Project in the Coatí Block (Putumayo) was completed, taking into account that the seismic project was not carried out due to a corporate decision.
In 2024, the National Prior Consultation Authority of the Ministry of the Interior received certification of five Prior Consultations for the Nasua Development Area Project in the Coatí Block (Putumayo). These processes are currently in the pre-consultation and opening stage and are expected to be completed by 2026.
Exploration blocks in the Putumayo area carry significant costs related to biodiversity management and reputational risk due to challenges related to overlapping territories and indigenous land titling processes.
Costs related to mitigation and offset measures to protect the habitat could be greater than currently anticipated due to the sensitivity of the biodiversity and the legal requirements imposed by the environmental authority. Nevertheless, we design our exploration and production projects, considering the mitigation hierarchy and the specific conditions of the environment avoiding or minimizing any intervention or disruption to sensitive ecosystems, natural forest coverage and ecosystems connectivity.
Several oil and gas development and exploration blocks in the Putumayo region of Colombia intersect with indigenous territories, some of which are formally titled, while others are under consideration for titling under Colombia’s land restitution law. Given the presence of ethnic communities in this region, there is a possibility that our operations may overlap with these recognized territories. In compliance with national regulations and as part of our commitment to maintaining responsible and sustainable operations, we engage with the National Prior Consultation Authority before
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initiating activities. This process allows us to identify the presence of recognized communities in the areas of influence and to establish agreements on appropriate measures to prevent and mitigate any potential impacts on these communities and their territories.
Additionally, considering the particularities of the territory and within our commitment to respecting and promoting human rights, we carried out a human rights identification and analysis exercise as part of our operations, including activities in Putumayo. This exercise allowed us to identify key issues related to our operations and those of our suppliers and contractors, thereby creating a work plan reflected in roadmaps to manage potential and actual human rights impacts, aiming to prevent and/or mitigate them.
New U.S. trade tariffs may adversely affect our cost structure, supply chain, and commodity markets.
The current U.S. administration has put in place 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 in Colombia, Ecuador, Brazil, and Argentina 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.
Risks relating to the countries in which we operate
Our operations may be adversely affected by political and economic circumstances in the countries in which we operate and in which we may operate in the future.
All of our current operations are located in South America. If local, regional or worldwide economic trends adversely affect the economy of any of the countries in which we have investments or operations, our financial condition and results from operations could be adversely affected.
The Economic Commission for Latin America and the Caribbean (ECLAC) has forecasted a regional growth of 2.4% in 2025, after a 2.2% growth in 2024, indicating that the region would stay on a path of low growth, which means job creation would decelerate and informality and gender gaps would persist, among other effects. These projections reflect, in part, low dynamism in economic growth and global trade, which translates into a limited impetus from the global economy. Although inflation has declined, the interest rates of the main developed economies have not, which means that financing costs have remained at high levels throughout the year, and they are expected to stay that way in coming years. Furthermore, this low growth is also attributable to the limited domestic space for fiscal and monetary policy faced by the region’s countries. In this regard, it is emphasized that while public debt levels have declined, they remain high, and this, coupled with the increase in financing costs, restricts fiscal space. In the monetary arena, inflation continues to decline in the region, but monetary policy still has a restrictive bias, due to the effects that rate cuts could have on capital flows and the exchange rate, given that high interest rates are still in effect in developed countries.
Oil and natural gas exploration, development and production activities are subject to political and economic uncertainties (including but not limited to changes in energy policies or the personnel administering them), changes in laws and policies governing operations of foreign-based companies, expropriation of property, cancellation or modification of contract rights, revocation of consents or approvals, the obtaining of various approvals from regulators, foreign exchange restrictions, price controls, currency fluctuations, royalty increases and other risks arising out of foreign governmental sovereignty, as well as to risks of loss due to civil strife, acts of war and community-based actions, such as protests or blockades, guerilla activities, terrorism, acts of sabotage, territorial disputes and insurrection. In addition, we are subject both to uncertainties in the application of the tax laws in the countries in which we operate and to possible changes in such tax laws (or the application thereof), each of which could result in an increase in our tax liabilities. These risks are higher in developing countries, such as those in which we conduct our activities.
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The main economic risks we face and may face in the future because of our operations in the countries in which we operate include the following:
● | difficulties incorporating movements in international prices of crude oil and exchange rates into domestic prices; |
● | the possibility that a deterioration in Colombia’s, Ecuador’s, Brazil’s and Argentina’s relations with multilateral credit institutions, such as the International Monetary Fund, will impact negatively on capital controls, and result in a deterioration of the business climate; |
● | inflation, exchange rate movements (including devaluations), exchange control policies (including restrictions on remittance of dividends), price instability and fluctuations in interest rates; |
● | liquidity of domestic capital and lending markets; |
● | tax policies; and |
● | the possibility that we may become subject to restrictions on repatriation of earnings from the countries in which we operate in the future. |
In addition, our operations in these areas increase our exposure to risks of guerilla and other illegal armed group activities, social unrest, local economic conditions, political disruption, civil disturbance, community protests or blockades, expropriation, tribal conflicts and governmental policies that may: disrupt our operations; require us to incur greater costs for security; restrict the movement of funds or limit repatriation of profits; lead to U.S. government or international sanctions; limit access to markets for periods of time; or influence the market’s perception of the risk associated with investments in these countries.
Some countries where we operate have experienced, and may continue to experience, political instability, and losses caused by these disruptions may not be covered by insurance. In 2022, Colombia and Ecuador experienced relevant social and political turmoil, including riots, nationwide protests, strikes and street demonstrations against their governments which led to acts of violence and social and political tensions. In Ecuador in May 2023, President Guillermo Lasso dissolved the National Assembly under the figure of “cross death,” resulting in early elections in which Daniel Noboa was elected as President. However, political uncertainty persists as Ecuador prepares for the second round of its 2025 presidential election, scheduled for April 2025, amid growing violence linked to organized crime. Security concerns are heightened, with proposals to militarize the country’s fight against crime. In Colombia, political debates and social movements continue to shape the national discourse. Such instability could materially affect both the Colombian and Ecuadorian economies, with potential adverse consequences for our business activities. As a result, our exploration, development, and production activities may be significantly impacted, which could have a material adverse effect on our results of operations and financial condition. We cannot guarantee that current policies governing the oil and gas industry will remain in effect.
Our operations may also be adversely affected by laws and policies of the jurisdictions in which we do business, that affect foreign trade and taxation, and by uncertainties in the application of, possible changes to (or to the application of) tax laws in these jurisdictions. For example, the Colombian government (i) enacted a tax reform in 2022 that materially affected the oil producing companies and (ii) issued a decree in February 2025, which establishes new tax measures intended to address the expenses arising from the internal commotion declared in certain regions of the country. These latest tax measures include a special tax on 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, all of which could increase our financial liabilities in Colombia. For further information, please see “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia—Regulatory framework—New tax regulations.”
Changes in any of these laws or policies or the implementation thereof, and uncertainty over potential changes in policy or regulations affecting any of the factors mentioned above or other factors in the future may increase the volatility of domestic securities markets and securities issued abroad by companies operating in these countries, which could
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materially and adversely affect our financial position, results of operations and cash flows. Furthermore, we may be subject to the exclusive jurisdiction of courts outside the United States or may not be successful in subjecting non-U.S. persons to the jurisdiction of courts in the United States, which could adversely affect the outcome of such dispute. Changes in tax laws may result in increases in our tax payments, which could materially adversely affect our profitability, restrict our ability to do business in our existing and target markets and cause our results of operations to suffer. There can be no assurance that we will be able to maintain our projected cash flow and profitability following any increase in taxes applicable to us and to our operations.
We depend on maintaining good relations with the respective host governments and national oil companies in each of our countries of operation.
The success of our business and the effective operation of the fields in each of our countries of operation depend upon continued good relations and cooperation with applicable governmental authorities and agencies, including national oil companies such as Ecopetrol, YPF, Petroecuador and Petrobras. For instance, our Brazilian operations in the BCAM-40 Concession provide us with a long-term off-take contract with Petrobras, the Brazilian state-owned company that covers 100% of net proved gas reserves in the Manati gas field. If we, the respective host governments and the national oil companies are not able to cooperate with one another, it could have an adverse impact on our business, operations and prospects.
Oil and natural gas companies in Colombia, Ecuador, Brazil and Argentina operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries.
Under Colombian, Ecuadorian, Brazilian and Argentinian law, all onshore and offshore hydrocarbon resources in these countries are owned by the respective sovereign. Although we have working and/or economic interests in the blocks and generally have the power to make decisions as how to market the hydrocarbons we produce, the Colombian, Ecuadorian, Brazilian and Argentinian governments have full authority to determine the rights, royalties or compensation to be paid by or to private investors for the exploration or production of any hydrocarbon reserves located in their respective countries.
If these governments were to restrict or prevent concessionaires, including us, from exploiting oil and natural gas reserves, or otherwise interfered with our exploration through regulations with respect to restrictions on future exploration and production, price controls, export controls, foreign exchange controls, income taxes, expropriation of property, environmental legislation or health and safety, this could have a material adverse effect on our business, financial condition and results of operations.
Additionally, we are dependent on receipt of government approvals or permits to develop the concessions we hold in some countries. There can be no assurance that future political conditions in the countries in which we operate will not result in changes to policies with respect to foreign development and ownership of oil and gas, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities. Any delays in receiving government approvals in such countries may delay our operations or may affect the status of our contractual arrangements or our ability to meet contractual obligations.
Oil and gas operators are subject to extensive regulation in the countries in which we operate.
The Colombian, Ecuadorian, Brazilian and Argentinian hydrocarbons industries are subject to extensive regulation and supervision by their respective governments in matters such as the environment, social responsibility, tort liability, health and safety, labor, the award of exploration and production contracts, the imposition of specific drilling and exploration obligations, taxation, foreign currency controls, price controls, export and import restrictions, capital expenditures and required divestments. In some countries in which we operate, such as Colombia, we are required to pay a percentage of our expected production to the government as royalties. See “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia” and see Note 33.1 to our Consolidated Financial Statements.
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For example, in Brazil there is potential liability for personal injury, property damage and other types of damages. Failure to comply with these laws and regulations also may result in the suspension or termination of operations or our being subjected to administrative, civil, and criminal penalties, which could have a material adverse effect on our financial condition and expected results of operations. We expect to also operate in a consortium in some of our concessions, which, under the Brazilian Petroleum Law, establishes joint and strict liability among consortium members, and failure to maintain the appropriate licenses may result in fines from the ANP, ranging from R$5 thousand to R$500 million. In addition, there is a contractual requirement in Brazilian concession agreements regarding local content, which has become a significant issue for oil and natural gas companies operating in Brazil given the penalties related with breaches thereof. The local content requirement will also apply to the production sharing contract regime. See “Item 4. Information on the Company—B. Business Overview— Significant Agreements.”
Significant expenditures may be required to ensure our compliance with governmental regulations related to, among other things, licenses for drilling operations, environmental matters, drilling bonds, reports concerning operations, the spacing of wells, unitization of oil and natural gas accumulations, local content policy and taxation.
Colombia has experienced and continues to experience internal security and community related issues that have had or could have negative effects on the Colombian economy.
The presence of criminal groups, including Revolutionary Armed Forces of Colombia (“FARC”) dissidents, the National Liberation Army (“ELN”), and the Clan del Golfo, has contributed to widespread instability in various parts of the country. These groups are primarily involved in drug trafficking, extortion, and kidnapping. The strengthening of these criminal organizations and the perceived ineffectiveness of the government’s Total Peace policy could lead to an escalation of violent incidents, infrastructure damage, and social unrest, with potentially negative repercussions for the Colombian economy.
The ELN has attacked oil pipelines in Colombia, including the Caño Limón-Coveñas pipeline, and other related infrastructure, disrupting the operations of certain oil and gas companies, causing unscheduled shutdowns of transportation systems, and harming ecosystems and the environment. FARC dissidents have also targeted oil and gas infrastructure, installing illegal valves to extract hydrocarbons, which are then used as raw material for processing cocaine base. These activities, their potential escalation, and associated impacts have had and may continue to have a negative impact on the Colombian economy or our business, potentially affecting our employees or assets.
Our operations are subject to security, communities and human rights risks.
Our operations are conducted in areas where security incidents can disrupt or delay production and exploration. The nature and likelihood of risks vary depending on the specific operating area. For example, our operations in Casanare and Meta have been affected by civil unrest, including blockades. In Putumayo, the primary risk is the presence and constant confrontation of illegal armed groups controlling drug production and trafficking, which can lead to displacement of populations, social protests related to eradication efforts, and other factors connected to drug trafficking; additionally, the planting of improvised explosive devices or anti-personnel mines affects the general population.
Organized criminal networks in Ecuador are engaged in drug trafficking, kidnapping, and extortion. In the Sucumbíos province, significant criminal activities include the theft of copper and the illegal tapping of pipelines to steal hydrocarbons.
Consequently, we conduct annual risk assessments, clearly defining the security context based on incident records, social and political dynamics, and threat analysis. Furthermore, since June 2022, we have strengthened our human rights and security risk management processes with our security contractors and stakeholders. All our security contractors and stakeholders have received training in human rights and the Voluntary Principles (as determined by the UN Voluntary Principles on Security and Human Rights initiative).
Our security strategy is aimed at mitigating risks, fostering a strong safety culture and self-protection, maintaining positive relationships and communication with authorities and stakeholders, and implementing protocols that allow us to
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continue operating in challenging environments. To date, we have not experienced any incidents that have impacted the continuity of our operations.
Additionally, our operations may be affected by our compliance with national laws and all international human rights treaties ratified by the countries where we operate. As part of our commitment to respecting human rights and engaging in an open, respectful, and transparent manner with all our stakeholders, we always strive to resolve all issues with government authorities, especially following their lead regarding the guarantee of human rights, through dialogue and communication, which may result in delays in the advancement of our projects.
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 high levels of perceived 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.
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 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, 2024, 98% 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.
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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. 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 to trade on the New York Stock Exchange (the “NYSE”) on February 7, 2014, and as a result have a limited trading history. We cannot predict the extent to which investor interest in our company will maintain an active trading market on the NYSE, or how liquid that market will be in the future.
The market price of our common shares may be volatile and may be influenced by many factors, some of which are beyond our control, including:
● | our operating and financial performance and identified potential drilling locations, including reserve estimates; |
● | quarterly variations in the rate of growth of our financial indicators, such as net income per common share, net income and revenues; |
● | changes in revenue or earnings estimates or publication of reports by equity research analysts; |
● | fluctuations in the price of oil or gas; |
● | speculation in the press or investment community; |
● | sales of our common shares by us or our shareholders, or the perception that such sales may occur; |
● | involvement in litigation; |
● | changes in personnel; |
● | announcements by the company; |
● | domestic and international economic, legal and regulatory factors unrelated to our performance; |
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● | variations in our quarterly operating results; |
● | volatility in our industry, the industries of our customers and the global securities markets; |
● | changes in our dividend policy; |
● | risks relating to our business and industry, including those discussed above; |
● | strategic actions by us or our competitors; |
● | actual or expected changes in our growth rates or our competitors’ growth rates; |
● | investor perception of us, the industry in which we operate, the investment opportunity associated with our common shares and our future performance; |
● | adverse media reports about us or our directors and officers; |
● | changes in the composition of our board of directors, including any transitions in leadership resulting from succession planning; |
● | addition or departure of our executive officers; |
● | change in coverage of our company by securities analysts; |
● | trading volume of our common shares; |
● | future issuances of our common shares or other securities; |
● | volatility from stock deposit certificates in Argentina (CEDEARs), as price differences may arise between the NYSE and the local market where the CEDEARs are traded; |
● | terrorist acts; or |
● | the release or expiration of transfer restrictions on our outstanding common shares. |
Any decision to pay dividends in the future, and the amount of any distributions, is at the discretion of our board of directors, and will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors.
We are committed to return value to our shareholders. From 2018 to 2024, we distributed a total of US$298.7 million to our shareholders, consisting of US$200.1 million through share repurchases and US$98.6 million in cash dividends. However, our availability to continue making distributions to shareholders in the future will depend on many factors, such as our results of operations, financial condition, cash requirements, prospects and other factors. For example, from April to November 2020, we temporarily suspended our quarterly cash dividends and share buybacks due to the sharp decline in oil prices as a result of the COVID-19 pandemic.
Furthermore, we are subject to Bermuda legal constraints that may affect our ability to pay dividends on our common shares and make other payments. Under the Companies Act, 1981 (as amended) of Bermuda (the “Companies Act”), we may not declare or pay a dividend or make a distribution out of contributed surplus, if there are reasonable grounds for believing that (i) we are, or would after the payment be, unable to pay our liabilities as they become due; or (ii) that the realizable value of our assets would thereby be less than our liabilities. We are also subject to contractual restrictions under certain of our indebtedness. “Contributed surplus” is defined for purposes of section 54 of the Companies Act to include
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the proceeds arising from donated shares, credits resulting from the redemption or conversion of shares at less than the amount set up as nominal capital and donations of cash and other assets to the company.
We are a holding company and our only material assets are our equity interests in our operating subsidiaries and our other investments; as a result, our principal source of revenue and cash flow is distributions from our subsidiaries; our subsidiaries may be limited by law and by contract in making distributions to us.
As a holding company, our only material assets are our cash on hand, the equity interests in our subsidiaries and other investments. Our principal source of revenue and cash flow is distributions from our subsidiaries. Thus, our ability to service our debt, finance acquisitions and pay dividends to our stockholders in the future is dependent on the ability of our subsidiaries to generate sufficient net income and cash flows to make upstream cash distributions to us. Our subsidiaries are and will be separate legal entities, and although they may be wholly-owned or controlled by us, they have no obligation to make any funds available to us, whether in the form of loans, dividends, distributions or otherwise. The ability of our subsidiaries to distribute cash to us will also be subject to, among other things, restrictions that are contained in our subsidiaries’ financing and joint operations agreements, availability of sufficient funds in such subsidiaries and applicable state laws and regulatory restrictions. Claims of creditors of our subsidiaries generally will have priority as to the assets of such subsidiaries over our claims and claims of our creditors and stockholders. To the extent the ability of our subsidiaries to distribute dividends or other payments to us could be limited in any way, our ability to grow, pursue business opportunities or make acquisitions that could be beneficial to our businesses, or otherwise fund and conduct our business could be materially limited.
We may not be able to fully control the operations and the assets of our joint operations and we may not be able to make major decisions or take timely actions with respect to our joint operations unless our joint operation partners agree. We may, in the future, enter into joint operations agreements imposing additional restrictions on our ability to pay dividends.
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 51,247,287 common shares were outstanding as of December 31, 2024. We cannot predict the size of future issuances of our common shares or the effect, if any, that future sales and issuances of shares would have on the market price of our common shares.
Provisions of the Notes due 2027 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 19.2% of our outstanding common shares as of March 6, 2025, 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
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that differ from yours and may vote in a way with which you disagree, and which may be adverse to your interests. The concentration of ownership may have the effect of delaying, preventing, or deterring a change of control of our company, could deprive our stockholders of an opportunity to receive a premium for their common shares as part of a sale of our company and might ultimately affect the market price of our common shares. See “Item 7. Major Shareholders and Related Party Transactions—A. Major shareholders” for a more detailed description of our share ownership.
Shareholder activism could cause us to incur significant expenses, hinder execution of our business strategy and impact our stock price.
Shareholder activism has been increasing generally and in the energy industry specifically. Investors may attempt to effect changes to our business or governance, such as with respect to climate change or otherwise, by means such as shareholder proposals, public campaigns, proxy solicitations or other means. Such actions could adversely impact us by distracting the Board and employees from core business operations, increasing advisory fees and related costs, interfering with our ability to successfully execute on strategic transactions and plans and provoking perceived uncertainty about the future direction of the business.
As a foreign private issuer, we are subject to different U.S. securities laws and NYSE governance standards than domestic U.S. issuers. This may afford less protection to holders of our common shares, and you may not receive corporate and company information and disclosure that you are accustomed to receiving or in a manner in which you are accustomed to receiving it.
As a foreign private issuer, the rules governing the information that we disclose differ from those governing U.S. corporations pursuant to the Securities Exchange Act of 1934, as amended (the “Exchange Act”). Although we intend to report quarterly financial results and report certain material events, we are not required to file quarterly reports on Form 10-Q or provide current reports on Form 8-K disclosing significant events within four days of their occurrence and our quarterly or current reports may contain less information than required under U.S. filings. In addition, we are exempt from the Section 14 proxy rules, and proxy statements that we distribute will not be subject to review by the SEC. Our exemption from Section 16 rules regarding sales of common shares by insiders means that you will have less data in this regard than shareholders of U.S. companies that are subject to the Exchange Act. As a result, you may not have all the data that you are accustomed to having when making investment decisions. For example, our officers, directors and principal shareholders are exempt from the reporting and “short-swing” profit recovery provisions of Section 16 of the Exchange Act and the rules thereunder with respect to their purchases and sales of our common shares. The periodic disclosure required of foreign private issuers is more limited than that required of domestic U.S. issuers and there may therefore be less publicly available information about us than is regularly published by or about U.S. public companies. See “Item 10. Additional Information—H. Documents on display.”
As a foreign private issuer, we are exempt from complying with certain corporate governance requirements of the NYSE applicable to a U.S. issuer, including the requirement that a majority of our board of directors consist of independent directors as well as the requirement that shareholders approve any equity issuance by us which represents 20% or more of our outstanding common shares. As the corporate governance standards applicable to us are different than those applicable to domestic U.S. issuers, you may not have the same protections afforded under U.S. law and the NYSE rules as shareholders of companies that do not have such exemptions.
There are regulatory limitations on the ownership and transfer of our common shares which could result in the delay or denial of any transfers you might seek to make.
The permission of the Bermuda Monetary Authority is required, under the provisions of the Exchange Control Act 1972 and related regulations, for all issuances and transfers of shares (which includes our common shares) of Bermuda companies to or from a non-resident of Bermuda for exchange control purposes, other than in cases where the Bermuda Monetary Authority has granted a general permission. The Bermuda Monetary Authority, in its notice to the public dated June 1, 2005, has granted a general permission for the issue and subsequent transfer of any securities of a Bermuda company from and/or to a non-resident of Bermuda for exchange control purposes for so long as any “Equity Securities” of the company (which would include our common shares) are listed on an “Appointed Stock Exchange” (which would include the New York Stock Exchange). In granting the general permission the Bermuda Monetary Authority accepts no
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responsibility for our financial soundness or the correctness of any of the statements made or opinions expressed in this annual report. Any changes in the permission granted by the Bermuda Monetary Authority and related regulations could result in a delay or denial of any transfer of shares an investor might seek.
We are a Bermuda company, and it may be difficult for you to enforce judgments against us or against our directors and executive officers.
We are incorporated as an exempted company under the laws of Bermuda and our assets are substantially located in Colombia, Ecuador, Brazil 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 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
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ES Act must comply with economic substance requirements. The ES Act may require in-scope Bermuda entities which are engaged in such “relevant activities” to be directed and managed in Bermuda, have an adequate of qualified employees in Bermuda, incur an adequate level of annual expenditure in Bermuda, maintain physical offices and premises in Bermuda or perform core income-generating activities in Bermuda. The list of “relevant activities” includes carrying on any one or more of: banking, insurance, fund management, financing, leasing, headquarters, shipping, distribution and service center, intellectual property and holding entities.
The ES Act could affect how we operate our business, which could adversely affect our business, financial condition and results of operations. Although it is presently anticipated that the ES Act will have little material impact on us or our operations, as the legislation is new and remains subject to further clarification and interpretation, it is not currently possible to ascertain the precise impact of the ES Act on us.
ITEM 4. INFORMATION ON THE COMPANY
A. History and development of the company
General
We were incorporated as an exempted company pursuant to the laws of Bermuda in February 2006. We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our principal executive office is located at Street 94 N° 11-30, 8th floor, Bogotá, Colombia, telephone number +57 601 743 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 to build a unique risk-balanced portfolio in the region’s main basins. We currently operate or hold working interests in Colombia, Ecuador, Brazil and Argentina. We are focused on Latin America because we believe it is one of the richest and most underexplored hydrocarbon regions globally, with less presence of independent E&P companies compared to the United States and Canada. In this region, much of the acreage has historically been controlled or owned by state-owned companies. We believe that these factors create an opportunity for smaller, more agile companies like us to build a long-term business.
Our North Star strategy is centered on being highly profitable, reliable, and sustainable, ensuring we deliver strong results today and remain resilient in the competitive oil and gas industry. Our North Star targets include 70 mboepd net production by 2028, while maintaining 400 mmboe proved plus probable reserves, and 100 mboepd net production by 2030. We are currently generating approximately US$100 million in profit for the year, more than US$400 million in annual Adjusted EBITDA, with a Return on Average Capital Employed (“ROACE”), defined as last twelve-month operating profit divided by average total assets minus current liabilities, over 30%. 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 2024, 2023 and 2022. This success is grounded in our operational excellence while maintaining best-in-class health, safety, and environmental (“HSE”) practices and a comprehensive sustainability strategy, which includes reducing our carbon intensity by 35-40% compared to 2020.
We are focused on growth through significant assets, basins, and plays, with distinctive assets in the Llanos 34 and CPO-5 Blocks in Colombia, and our recently acquired assets in the Vaca Muerta shale formation in Argentina. Our operations span both conventional and unconventional basins and a diversified footprint across Colombia, Ecuador, Brazil and Argentina.
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During the year ended December 31, 2024, we produced a net average of 33.9 mboepd, of which 94.2%, 4.9%, 0.7% and 0.2% were, respectively, in Colombia, Ecuador, Brazil and Chile, and of which 98.8% was oil.
Our near-term performance targets focus on achieving sustainable growth by mid-term (2028) and long-term (2030). We 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 are committed to delivering competitive shareholder returns while driving sustainable growth. Since 2018, we have returned almost US$300 million to shareholders through buybacks and dividends. Dividend payments remain subject to Board approval and will depend on factors such as business performance, financial condition, and growth plans.
A clear set of priorities and key values have driven our Company through a two-decade track record of growth, sustainability performance and strong value delivery. Furthermore, our internal value system SPEED, which has been part of the Company’s culture since its inception, differentiates us from our peers, guides our decision-making process and is the basis for our value-generation approach to all our stakeholders.
Meeting the energy needs of a growing population while contributing to the energy transition requires us to conduct best-in-class oil and gas exploration and operation, to manage our assets in the most ethical and sustainable way, and to continue creating long-term value for our shareholders and all our stakeholders.
Our business model
Our updated business model can be summarized in four simple words and one unifying idea: “We Make Assets Better.” This principle is underscored by our track record of adapting to change, expanding our capabilities, and continuously enhancing our asset portfolio. The model comprises three interlocking elements:
● | We deliver more energy by focusing on finding and producing energy as well as effectively taking it to the market. As we focus strongly on results, our business model requires the right people, the right assets, and the right execution. |
● | We invest with the goal of returning value to all our stakeholders. Accordingly, we follow a disciplined capital allocation that targets the highest value projects while responsibly assuming and managing risk. |
● | We create and share prosperity with everyone from our employees to governments and local communities. “Creating Value and Giving Back” is a central tenet of our Company and bringing prosperity to people while protecting the environment will always be one of our top priorities, in parallel to maintaining the highest standards of ethics and governance. |
Central to our company and business model is our culture of agility, adaptability, and trust. We maintain a horizontal structure where all employees have autonomy, ownership, and play key roles. Our culture is our binding force, which we protect and nurture to excel in delivering our business model.
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History
We were founded in 2002. We are a leading independent energy company with operations in Latin America. During 2024, we had operations or held working interests in Colombia, Ecuador, Brazil, Argentina and Chile, and we divested our Chilean operations in January 2024.
Our history can be summarized by our growth in each country and our performance in the capital markets:
Colombia
In the first quarter of 2012, we entered into Colombia by acquiring three privately held E&P companies, that were later merged into GeoPark Colombia S.A.S. These acquisitions provided us with an attractive platform of reserves and resources in Colombia, including a 45% operated working interest in the Llanos 34 Block. 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 235 wells. As of December 31, 2024, the block has produced more than 185 million barrels of oil, with a gross daily production of over 40,000 bopd, and the block’s Jacana and Tigana fields ranking among Colombia’s top 10 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 1,505 boepd to our net average production for the year ended December 31, 2024 (3,010 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, has enabled the identification of new drilling opportunities for 2025.
In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development, and exploration blocks in Colombia, distributed as follows: twelve operated blocks in the Putumayo basin (including the producing Platanillo Block) and one non-operated block in the Llanos basin (the producing CPO-5 Block), 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 23,104 bopd during the year ended December 31, 2024 (net production of 6,931 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 10 producing oil fields.
During the year ended December 31, 2024, we were the second largest oil operator in Colombia, according to the ANH.
Ecuador
On May 22, 2019, we signed participation contracts for the Espejo (GeoPark operated, 50% working interest) and Perico (GeoPark non-operated, 50% working interest) Blocks in Ecuador. Since then, we have successfully advanced exploration and development activities, transitioning these blocks from exploratory to production. In 2022, we recorded our first oil sales in Ecuador due to the successful exploration campaign in the Perico Block, and since the start of operations, we have drilled a total of nine exploration and appraisal wells in the Perico Block and four exploration wells in the Espejo Block, and we also acquired 60 sq km of 3D seismic in the Espejo Block. During the year ended December 31, 2024, the net production from the Perico and Espejo Blocks was 1,668 boepd.
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. While we currently have certain exploratory blocks, in March 2025, we entered into an agreement to divest our 10% non-operated working interest in the BCAM-40 Concession and such divestment, is pending customary regulatory
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approvals. For further information, please see “—Recent Developments—Divestment of non-operated working interest in the Manati gas field in Brazil.”
Argentina
In May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in four adjacent unconventional blocks in the world-class Vaca Muerta shale formation in the Neuquén Basin in Argentina. Closing of the transaction is pending customary regulatory approvals from the respective provincial governments. This acquisition complements our existing asset portfolio and provides immediate access to rapidly growing production and existing reserves.
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.
Funding
In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares.
Between 2005 and 2023, we raised approximately US$200 million in equity offerings at the holding company level and nearly US$1.5 billion through debt arrangements with multilateral agencies such as the IFC, gas prepayment facilities, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.
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 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, for a minimum of 20 months and up to 36 months, starting on July 1, 2024. As part of this transaction, we obtained access to committed funding from Vitol, with an initial limit of up to US$300.0 million, which decreases by US$10.0 million per month. 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, we drew US$152.0 million under this prepayment agreement. Between February and March 2025, we repaid US$126.4 million in cash and US$6.4 million in kind from that amount and, as of the date of this annual report, US$19.2 million remain outstanding.
In August 2024, we executed an offtake and prepayment agreement with C.I. Trafigura Petroleum Colombia S.A.S. (“Trafigura”), one of the world’s leading commodity traders. The offtake agreement provides for GeoPark to sell and deliver the light crude oil production from the CPO-5 Block in Colombia to Trafigura, for 12 months, starting on August 1, 2024. As part of this transaction, GeoPark obtained access to committed funding from Trafigura for up to an initial US$100.0 million in prepaid future oil sales over the period of the offtake and prepayment agreement, which decreases over the life of the contract. Funds committed by Trafigura are available until June 30, 2025, subject to certain conditions. 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 3.50% per annum. As of the date of this annual report, we have not drawn any amount under this offtake and prepayment agreement.
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In August 2024, our Brazilian subsidiary executed a loan agreement with Banco Santander for an amount in local currency equivalent to US$0.7 million to finance working capital requirements in Brazil as a consequence of the suspended production at the Manati gas field. The interest rate applicable to this loan was 8.70% per annum. The loan principal and interests were fully repaid in September 2024.
During the three-month period ended September 30, 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 Argentinian 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 Argentinian 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 is 3% per annum and final maturity will be July 3, 2025. The funds collected from this transaction were mainly used for making an additional advance payment for the acquisition of midstream capacity in Argentina.
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 through a concurrent tender offer, to repay part of the abovementioned prepayment drawn from the Vitol offtake and prepayment agreement and, the remainder was used for general corporate purposes, including capital expenditures.
B. Business Overview
We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. We continually evaluate the potential acquisition of strategic assets that will allow us to continue growing our business in line with our recent operating and financial successes. Since our inception, we have supported our growth through our prospect development efforts, drilling program, long-term strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and engineers, including professionals with specialized expertise in the geology of Colombia, Ecuador, Brazil and Argentina.
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The following map shows the countries in which we have blocks with working and/or economic interests as of December 31, 2024. For information on our working interests in each of these blocks, see “—Our assets” below.
(1) | In May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in the blocks. Closing of the transaction is pending customary regulatory approvals from the respective provincial governments and upon closing will have an effective date of July 1, 2024. |
(2) | In process of relinquishment. See “—Our operations—Operations in Colombia” and “—Our operations—Operations in Argentina.” |
(3) | In process of transferring our working interest in the block to the partner. See “—Our operations—Operations in Argentina.” |
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Our assets
We have a portfolio of assets that includes working and/or economic interests in 29 hydrocarbon blocks, 28 of which are onshore blocks, including 10 in production as of December 31, 2024, and provides the ability to quickly optimize capital allocation as market conditions change. Our assets give us access to approximately four million gross exploratory and productive acres. Our recent acquisition in Argentina (Vaca Muerta) will add four additional onshore blocks, including two in production as of December 31, 2024.
According to the D&M Reserves Report, as of December 31, 2024, the blocks in Colombia, Ecuador and Brazil in which we have a working interest had 58.4 mmboe of net proved reserves, with 96.7%, 1.5%, 1.8% of such net proved reserves located in Colombia, Ecuador and Brazil, 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, 2024.
For the year ended December 31, 2024 |
| ||||||||||||
|
|
| Oil |
|
| Revenues |
| ||||||
| Oil | Gas | equivalent | (in thousands | % of total | ||||||||
Country | (mmbbl) | (bcf) | (mmboe) | % Oil | of US$) | revenues | |||||||
Colombia | 56.4 | 0.9 | 56.5 | 99.7 | % | 619,762 | 93.8 | % | |||||
Ecuador | 0.9 | — | 0.9 | 100.0 | % | 30,567 | 4.6 | % | |||||
Brazil | 0.0 | 6.1 | 1.0 | 1.5 | % | 2,934 | 0.4 | % | |||||
Chile(1) | — | — | — | — | 398 | 0.1 | % | ||||||
Other | — | — | — | — | 7,177 | 1.1 | % | ||||||
Total | 57.3 | 7.0 | 58.4 | 98.0 | % | 660,838 | 100.0 | % | |||||
Argentina (2) | 36.1 | 11.5 | 38.0 | 95.0 | % | ||||||||
Total - Pro forma | 93.4 | 18.5 | 96.4 | 96.8 | % |
(1) | Divested in January 2024. |
(2) | Reflects reserves estimates from the D&M Reserves Report for the Argentina (Vaca Muerta) acquisition. Closing of the acquisition is pending customary regulatory approvals from the respective provincial governments. For further information, please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina (Vaca Muerta).” |
We produced a net average of 33.9 mboepd during the year ended December 31, 2024, of which 94.2%, 4.9%, 0.7% and 0.2%, were in Colombia, Ecuador, Brazil and Chile, respectively, and of which 98.8% 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, | |||||||||
|
| 2024 |
| 2023 |
| 2022 |
| 2021 |
| 2020 |
Average net production (mboepd) | 33.9 | 36.6 | 38.6 | 37.6 | 40.2 | |||||
% oil | 99% | 93% | 91% | 86% | 87% |
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The following table sets forth our production of oil and natural gas in the blocks in which we have a working and/or economic interest as of December 31, 2024.
| Average daily production | |||||||||
| For the year ended December 31, 2024 | |||||||||
|
| Colombia |
| Ecuador |
| Brazil |
| Chile(1) |
| Total |
Oil production | ||||||||||
Total crude oil production (bopd) | 31,867 | 1,668 | 3 | 5 | 33,544 | |||||
Natural gas production | ||||||||||
Total natural gas production (mcf/day) | 685 | — | 1,313 | 363 | 2,362 | |||||
Oil and natural gas production | ||||||||||
Total oil and natural gas production (mboepd) | 31,982 | 1,668 | 222 | 66 | 33,937 |
(1) | Divested in January 2024. |
Acquisition in Argentina (Vaca Muerta)
In May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in four adjacent unconventional blocks in the world-class Vaca Muerta shale formation in the Neuquén Basin in Argentina as follows: a 45% working interest in each of the Mata Mora Norte producing block and Mata Mora Sur exploration block, located in the Neuquén province, and a 50% working interest in each of the Confluencia Norte and Confluencia Sur exploration blocks, located in the Río Negro province. Closing of the transaction is pending customary regulatory approvals from the respective provincial governments and upon closing will have an effective date of July 1, 2024.
We believe the Vaca Muerta shale formation is the best onshore hydrocarbons play in Latin America today. According to the US Energy Information Administration, it holds an estimated 16 billion oil barrels and over 300 trillion cubic feet of unconventional gas resources with approximately 10% developed to date.
The four blocks are operated by PGR, an independent E&P company focused on unconventional operations in Argentina. PGR is a subsidiary of Mercuria, one of the world’s leading independent energy and commodity groups. The partnership between GeoPark and PGR represents an opportunity to jointly leverage the substantial operational, technical, financial and commercial expertise of both companies – underpinned by unique complementary entrepreneurial culture – to unlock the full potential of the acquired blocks.
The agreement includes an upfront consideration of US$190.0 million, funding 100% of exploratory commitments up to US$113.0 million gross (US$56.5 million net) over the first two years, an acquisition of midstream capacity according to our working interest for an initial amount of US$11.1 million, and a US$10 million bonus which is contingent on the results of the Confluencia exploration campaign.
In May 2024, we made an advance payment of US$49.1 million (of which US$38.0 million corresponded to the upfront consideration and US$11.1 million to the acquisition of midstream capacity) and, in December 2024, we made an additional advance payment of US$5.0 million for the acquisition of midstream capacity. These advance payments are recognized in the “Prepayments and other receivables” line item within “Current assets” in the Consolidated Statement of Financial Position as of December 31, 2024.
Upon closing, we will pay the remaining US$152.0 million of the upfront consideration, plus an interim period adjustment of approximately US$67.0 million, as of December 31, 2024. This adjustment relates to reimbursement of capital expenditures (including a portion of exploratory commitments), net of results from operations attributable to our acquired working interest since July 1, 2024 (the effective date of the acquisition). In the event that the transaction is not consummated, we will not be required to make any of the outstanding payments due at closing, and all advance payments made to date will be reimbursed to us.
The acquisition complements our existing asset portfolio and provides access to rapidly growing production and reserves profiles. During the three-month period ended December 31, 2024, the Mata Mora Norte Block (GeoPark non-
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operated, 45% working interest) and the Confluencia Norte Block (GeoPark non-operated, 50% working interest) achieved a gross average production of 15.1 mboepd (or 6,929 boepd net, with the following breakdown: 5,375 boepd in the Mata Mora Norte Block and 1,554 boepd in the Confluencia Norte Block). According to the D&M Reserves Report, as of December 31, 2024, the Mata Mora Norte and Confluencia Norte Blocks had a combined 38.0 mmboe of net proved reserves and have achieved 1P reserve PV 10 of US$317.1 million, at our working interest.
Recent Exploration Success in the Confluencia Norte Block (Vaca Muerta)
During the third quarter of 2024, the Confluencia Norte Block completed its first pad of three unconventional wells, which began production in mid-October. This development confirmed the presence of the Vaca Muerta formation at the westernmost edge of the block. The pad included a vertical pilot well, drilled specifically for data acquisition, along with three horizontal wells reaching a total measured depth of 6,300 meters, with 3,000 meters of lateral extension.
A high intensity fracturing program was executed across 135 stages, resulting in a gross production rate of 4,000 bopd during the ongoing flowback and well testing phase, with production currently being transported to and marketed through the Mata Mora Norte Block facility. The wells are expected to reach their peak production within 90 days of the production start, highlighting the block’s rich petrophysical properties, which are comparable to those found in the Mata Mora Norte Block.
As part of its exploration commitment in the Confluencia Norte and Sur blocks, PGR has completed the acquisition of 228 km² of 3D seismic data, which is currently undergoing interpretation and will be key to define the upcoming drilling program, which includes a further four wells that PGR will drill as part of its commitment.
Proposed Acquisition of Certain Repsol Exploration and Production Assets in Colombia
On November 29, 2024, we announced that we 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, we announced that Ecopetrol, the operator of the CPO-9 block, 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. On January 14, 2025, we announced that Repsol’s partner in SierraCol Energy Arauca LLC 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, we and Repsol have mutually agreed not to proceed with the transaction previously announced on November 29, 2024.
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, we are currently in the process of divesting non-core assets in Colombia (the Llanos 32 Block) and Brazil (the Manati gas field), while also evaluating strategic options for our assets in Ecuador. 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 North Star strategy to build a highly profitable, dependable, and sustainable oil and gas portfolio in Latin America.
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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 (Vaca Muerta) 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 (Vaca Muerta) includes one block with proven production and reserves to provide us with a cash flow base and three exploration blocks with significant exploration 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 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
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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, 2024, cash flows from operating activities were US$471.0 million. Our cash flows from operating activities plays a significant role in funding our capital expenditures and shareholders return. For example, during 2024, our organic cash flow from operating activities allowed us to fund our capital expenditures program of US$191.3 million, the advance payments of US$54.1 million for the Argentina (Vaca Muerta) acquisition, the security deposit of US$20.0 million for the proposed acquisition of certain Repsol exploration and production assets in Colombia, the repurchase of own shares and cash dividends of US$73.7 million, and debt services of US$27.7 million, among others.
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 by maintaining a disciplined capital structure and a conservative financial philosophy, including limiting our debt incurrence to specified projects with repayment sources and our use of financial hedges, we are positioned to maintain sufficient liquidity and remain flexible in volatile commodity price environments. For example, we are currently in the process of implementing cost efficiency initiatives including workforce and other structural cost reductions. These initiatives further simplify our cost structure and are aligned with our North Star strategy. Our financial flexibility also gives us the ability to pursue new opportunities through future potential acquisitions.
As of December 31, 2024, we had US$514.3 million of total outstanding financial indebtedness, 98% of which was scheduled to mature in January 2027, and maintained a net debt to Adjusted EBITDA ratio below 1x. In January 2025, we issued US$550.0 million in aggregate principal amount of Notes due 2030 and used the net proceeds to repurchase US$405.3 million in principal amount of our Notes due 2027, partially repay a prepayment drawn from Vitol, and fund general corporate purposes. While this transaction resulted in higher annual debt service payments due to prevailing market interest rates, it strengthened our financial position by extending our debt maturities.
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 enhanced regional portfolio, including investment-grade countries and strong partnerships, position us as a regional consolidator. We intend to continue to grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix of oil and gas-producing assets (though we expect to remain weighted towards oil) and focusing on both assets and corporate targets.
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Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become the second largest operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30 million and have achieved 1P reserve PV-10 of US$739.1 million as of December 31, 2024.
In January 2020, we acquired the entire share capital of Amerisur, which owned thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and the non-operated CPO-5 Block in the Llanos Basin) and a cross-border oil pipeline from Colombia to Ecuador named Oleoducto Binacional Amerisur (“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 23,104 bopd during the year ended December 31, 2024 (net production of 6,931 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 10 producing oil fields.
In May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in four adjacent unconventional blocks in the world-class Vaca Muerta shale formation in the Neuquén Basin in Argentina, including one block with proven production and reserves to provide us with a cash flow base and three exploration blocks with significant exploration upside. For further information, please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina (Vaca Muerta).”.
In November 2024, we entered into an agreement to acquire certain Repsol’s upstream oil and gas assets in Colombia. However, we were unable to proceed with the transaction due to the exercise of preemptive rights by Repsol’s joint operation partners. Nevertheless, our entering into this agreement demonstrates our commitment and strategic intent to continue driving growth in Latin America.
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 10 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 believe we have developed a strong relationship with Ecopetrol, the Colombian state-owned oil and gas company, particularly with its subsidiary Hocol, which is our partner in several blocks within the Llanos Basin. Additionally, we also established a strong relationship with Parex and its subsidiary Verano Energy, who have also been key partners in various blocks within the Llanos Basin, including our flagship, the Llanos 34 Block. We have also developed productive relationships with our customers, which led to offtake and prepayment agreements with Vitol and Trafigura in 2024, serving as significant sources of financing.
In the recent acquisition in Argentina (Vaca Muerta), we believe the partnership between GeoPark and Phoenix represents an opportunity to jointly leverage the substantial operational, technical, financial and commercial expertise of both companies – underpinned by unique complementary entrepreneurial culture – to unlock the full potential of the acquired blocks.
Maintain our commitment to environmental, safety, human rights and social responsibility
An important component of our business strategy is our corporate approach and commitment to our safety, environmental and social responsibilities, which is embodied in decisions that are framed by our safety, environmental and social responsibility internal policies and aligned with international standards. We see this as a fundamental element
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in securing business initiatives for long-term growth. Our commitment to sustainable development has allowed us to generate positive impacts in the territories in which we operate, with important contributions to the protection of biodiversity and the environment, as well as to the wellbeing and reduction of multidimensional poverty in neighboring communities. We maintain a social license to operate, based on the construction and maintenance of mutually beneficial relationships with local communities, the return of value as allies for their social and economic development, the respect for their human rights and the care and preservation of the environment. Detailed information can be found in our latest SPEED Report which is available at the Company’s website.
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.”
During 2024, we structured our sustainability declaration and framework, which materializes our SPEED system and articulates three key pillars (focus, action, enablers) into our operations and decision-making processes, ensuring long-term viability of the business and a shared positive impact.
The sustainability framework's three key pillars can be described as:
1. Focus: Stakeholder prioritization & double materiality assessments. The latest double materiality assessment identified eight priority topics to drive our mid-term strategy.
2. Action: Prioritizing projects and initiatives on three different angles: i) Operational Efficiency: opportunities stemming from water use, energy and waste management, ii) Risks & Opportunities: addressing potential exposure to climate and nature risks and new related business opportunities and iii) Impact Multiplier: going beyond our operations (suppliers, partners and neighbors).
3. Enablers: Supporting our SPEED system by securing financial resources and unlocking new sources of capital, driving innovation, anticipating regulation, stakeholder engagement, and strengthening capabilities.
Our Environmental Management System (“EMS”) has been certified under the ISO 14001:2015 standard since 2017. The scope of this certification includes all our activities, processes and products related to the exploration and exploitation of hydrocarbons in Colombia, covering 99% of our operations.
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In 2023, we obtained the latest re-certification of the ISO 14001:2015, which is valid until August 2026.
Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-1 standard of the Colombian Institute of Technical Standards and Certification (ICONTEC). GeoPark was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions of greenhouse gases and help the countries where we operate meet their commitments under the Paris Agreement. During 2024, 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’s environmental sustainability management won an award granted by the Colombian Oil and Gas Association (“ACP”), the Colombian Petroleum Association, GeoPark won first place among 60 projects in the Climate Change and Decarbonization Management and the Implementation of Circularity Models categories, and was a finalist in the Partnerships for Sustainable Development category.
GeoPark also received two awards for being one of the top 10 companies contributing the most data to Colombia’s biodiversity information system, for the greatest impact in the use of biodiversity data and for its contribution to capacity building for open biodiversity data reporting.
In 2022, the Colombian national government, through its department for social prosperity, once again recognized our “Sustainable Housing” program among the 24 most important public, private and international cooperation programs in terms of overcoming poverty in Colombia. The homes of more than 2,000 families neighboring our areas of operation in the country have been benefitted by this program, which we have carried out since 2013 in partnership with the ‘Minuto de Dios’ corporation.
Additionally, in 2024, MSCI Ratings Assessment recognized us as an ESG ‘leader’ by upgrading our rating to “AA”. In 2024 we participated for the third time in the Dow Jones Sustainability Index (DJSI), and in the S&P Global Corporate 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 on Business and Human Rights (the “UN Guiding Principles”), the ten UN Global Compact Principles and the Voluntary Principles on Security and Human Rights. Our commitment to these standards is reflected in our SPEED program, as well as in all our policies and procedures. Human rights aspects are integrated into internal management processes, tools, communications, contracts, and trainings.
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:
• | Documented and structured the human rights due diligence process |
• | Update of our human rights policy, which was approved by our board of directors on March 4, 2025. The policy is available on our website in English and Spanish. |
• | Strengthened and mainstreamed communications within our grievance mechanisms to facilitate collaboration, follow up and monitoring. |
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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.
We have a grievance mechanism in place for all our blocks and operations in Colombia, which is aligned with the UN Guiding Principles (UNGP) on Business and Human Rights, meaning it is accessible, legitimate, aligned with judicial and non-judicial grievance mechanisms, based on dialogue and participation, and predictable, to name a few of the eleven principles established in the UNGP. Having open, accessible, transparent, and respectful communication with all our stakeholders is crucial to respecting their human rights to information and participation. Our grievance mechanism, “Cuéntame” (“Tell me” in English), is one of our most important tools to engage with communities, contractors and service providers, and our employees on the ground, and is easily accessible to all through all our social engagement employees, email, several mobile and Whatsapp numbers, and an office in the biggest city close to our respective operations. Stakeholder who engage with “Cuéntame” will be informed about the mechanism and can immediately present a grievance, complaint or question. To further align and strengthen our grievance mechanism with the highest standards on human rights, in 2022, we worked with a reputable NGO in Colombia called “Fundación Ideas para la Paz” to assess “Cuéntame” against the UNGP, the OECD Guidance, the International Financial Corporation and the World Bank standards. We were ranked as having best practices (meaning a complete level of implementation) in one of the UNGP, as having high level of progress and implementation in eight of the UNGP, and as having progress with an opportunity to improve in two of the UNGP. As part of the results, we have implemented a plan to close some of the gaps identified, for example by increasing the number of forums and meetings to communicate and raise awareness of the existence of the grievance mechanism, as well as providing stakeholders the opportunity to give feedback on the mechanism’s operation, effectiveness, responses, among others. To be even closer to our neighbors in Colombia, we opened a “Cuentame” office in Puerto Asis (Putumayo) in 2021, 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 Company.
Our Ethics and Compliance Program aims to support and promote an ethics culture, as well as create and establish commitments and procedures that ensure internal and external regulatory compliance and anti-corruption matters. The program’s execution and implementation is the responsibility of our Compliance Department, which is directed by the Corporate Governance and Compliance Manager, who, together with the Compliance Leader, presents quarterly reports directly to the Audit Committee. Additionally, the Board’s Audit Committee monitors the effectiveness of the Ethics and Compliance Program, its associated controls, and risk mitigation measures, and oversees plans to strengthen ethical culture. The program is based on three pillars:
● | Prevention: ethics-based culture, including tone from the top, training and awareness and ethics line management. |
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● | Detection: risk assessment and advisory, including policies and procedures assurance, laws and regulations compliance and risk management. |
● | Monitoring: monitor and oversight, including on-going monitoring, due diligence third parties and regulations oversight. |
During 2024, GeoPark continued its adherence to the Business Ethics Leadership Alliance (BELA) as part of its efforts to continue strengthening its ethical culture. BELA is a platform of more than 375 companies in 60 industries recognized worldwide for their ethics and compliance leadership.
Highly committed founding shareholder and technical and management teams with proven industry expertise and technically-driven culture
Management and operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture, which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience on finding and developing oil and gas fields.
In addition, we strive to provide a safe and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals. 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, such as maintaining the technical teams inherited through our Colombian 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 Chevron, Ecopetrol, Petrobras, Pluspetrol, San Jorge, Total and YPF, among others. Throughout our history, our management and operating team has had success in unlocking unexploited value from previously underdeveloped assets.
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 6, 2025, Mr. Park held 17.2% of our outstanding common shares.
In addition, as of March 6, 2025, our executive directors and executive officers owned 1.0% of our outstanding common shares, aligning their interests with those of our shareholders and helping retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management and Employees—B. Compensation.”
Innovation
We have fostered a company-wide innovation culture that integrates creativity and strategic thinking into daily operations. In 2024, we redefined our behavioral model, highlighting innovation as a key pillar and incorporating it into our performance and leadership evaluations.
To strengthen these capabilities, we implemented training in agile methodologies and conducted company-wide sessions on artificial intelligence and change management, some of these in partnership with the Colombian center for higher education in business (Centro de Estudios Superiores de Administración) commonly known as “CESA”. We also held our second innovation workshop in collaboration with Connect, a leading company in innovation topics, where 50 employees tackled strategic challenges in production, geosciences, energy transition, and innovation management. The workshop included 19 sessions, generating 150 ideas that were transformed into 70 challenges, leading to five prototypes currently under evaluation.
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In parallel, we advanced key innovation projects, such as process integration to improve production data reliability, nanotechnology applications to enhance oil extraction, and the implementation of a centrifuge to reduce wastewater. We also developed data-driven tools, including fluid prediction with gas chromatography, energy consumption monitoring, and a proof of concept to evaluate an injector well tracking software. Additionally, we identify an opportunity to promote industrial symbiosis to repurpose materials and strengthen our innovation management system through an internal platform for developing and tracking initiatives.
By balancing the expansion of new innovations with the consolidation of ongoing projects, we continue to foster our innovation culture, leveraging cutting-edge technology, and maintaining our leadership in industry transformation.
Recent Developments
U.S.-Colombia Relations
On January 26, 2025, U.S. President Trump posted on the Truth Social platform that he had directed his administration to take certain measures in retaliation for Colombia’s rejection of two U.S. repatriation flights carrying migrants to Colombia. These measures would include emergency 25% tariffs on all goods coming into the United States from Colombia, which President Trump indicated will be raised to 50% in one week; sanctions implementing visa bans and revocations on Colombian government officials and certain allies and supporters; and enhanced border inspections of Colombian nationals and cargo. President Trump also indicated that there could be additional sanctions and other measures imposed in the future. In addition, news sources reported that the visa section at the U.S. Embassy in Bogota, Colombia, had been closed. Colombian President Gustavo Petro initially responded on X ordering similar tariffs on U.S. goods imported into Colombia. The Trump Administration subsequently released a statement indicating that the government of Colombia agreed to resume the acceptance of deported migrants from the United States, and that the announced tariffs and sanctions will be held in reserve, while the sanctions implementing visa bans and revocations and enhanced inspections will remain in effect pending the acceptance by Colombia of the first plane of deported migrants. Colombia’s Ministry of Foreign Affairs also released a statement indicating that they had overcome the impasse with the U.S. government, and that the Colombian government would continue to welcome Colombians who return as deportees.
In the event any further measures are implemented, their impact and effects on our business are difficult to predict. Adverse developments in the diplomatic and commercial relations between the United States and Colombia, including, but not limited to, the imposition of tariffs, travel bans or sanctions by the United States, as well as any retaliatory measures taken by the Colombian government, could have an adverse effect on our business, results of operations and financial condition, including due to their potential impact on Colombian macroeconomic conditions, including the value of the Colombian peso, and the oil and gas industry more generally.
Issuance of Notes due 2030
On January 31, 2025, we issued US$550.0 million aggregate principal amount of senior notes (the “Notes due 2030”), and 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.
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.
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Appointment of Chief Exploration and Development Officer
In February 2025, Rodrigo Dalle Fiore was appointed as Chief Exploration and Development Officer after serving as Inorganic Growth, Unconventional & Portfolio Director since 2023. For further information, please see “Item 6. Directors, Senior Management and Employees—A. Directors and executive officers—Executive officers.”
New Colombian tax regulations.
On February 14, 2025, the Ministry of Finance and Public Credit of Colombia issued Decree No. 175, which establishes tax measures to finance the General Budget of the Nation (PGN). The two tax measures (a Special Tax for Catatumbo and an increase of the Stamp Tax Rate) are intended to address the expenses arising from internal commotion declared in the Catatumbo region. For further information, please see “Item 4. Information on the Company—B. Business Overview—Industry and regulatory framework—Colombia—Regulatory framework—New tax regulations.”
Approval of a New Retention and Hiring Bonus Scheme
On March 4, 2025, the board of directors of the Company 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. For further information, please see “Item 6. Directors, Senior Management and Employees—B. Compensation—Employees—Retention and Hiring Bonus Scheme.”
Divestment of non-operated working interest in the Llanos 32 Block in Colombia
On March 14, 2025, we agreed to transfer, subject to regulatory approval, our non-operated working interest in the Llanos 32 Block in Colombia to our joint operation partner for a total consideration of US$19.0 million, minus working capital adjustment of US$3.7 million. As of the date of this annual report, we have received the net proceeds from the transaction, which are subject to final settlement.
Divestment of non-operated working interest in the Manati gas field in Brazil
On March 27, 2025, we entered into an agreement to sell our 10% non-operated working interest in the Manati gas field in Brazil for a total consideration of US$1.0 million, subject to working capital adjustment, plus a contingent payment of an additional US$1.0 million, subject to the field’s future cash flow or its potential conversion into a natural gas storage facility. As of the date of this annual report, we have collected an advance payment of US$0.5 million. Closing of the transaction is pending customary regulatory approvals.
Cost efficiency measures
In March 2025, we implemented cost efficiency measures which include the immediate reduction of our workforce. These measures were undertaken to enhance cost efficiency and better align the organizational structure with our strategic objectives and operational challenges. In connection with these measures, we incurred termination costs of approximately US$1.6 million.
2025 Strategy and Outlook
As part of our updated work program for 2025 (the “2025 Work Program”), we aim to optimize our portfolio by focusing on maximizing value and leveraging a differentiated asset base for sustainable long-term growth, aligned with our “North Star” strategy. For further information on our capital allocation methodology, please see “—Our strengths— Capital allocation methodology.”
We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects. We expect to incur capital expenditures ranging from US$275.0 million to US$310.0 million during 2025 (including amounts we expect to spend at Vaca Muerta after the closing of the acquisition), of which approximately 70% will be allocated to Argentina and approximately 30% to Colombia, with a target to drill 23 to 31 gross wells plus infrastructure and facilities.
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The plan considers approximately 65% to be allocated to development and approximately 35% to be allocated to exploration and appraisal activities. This expected allocation of capital expenditures is subject to change as a result of market conditions, developments regarding our business, results of operation and financial condition, and other factors.
Our operations
Operations in Colombia
Our Colombian assets currently give us access to 3,266,000 gross exploratory and productive acres across 19 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, 2024, accounts for 63.9% of our production and 84.0% of our proved reserves in Colombia.
Highlights of the year ended December 31, 2024, related to our operations in Colombia included:
● | Successful drilling and putting into production three exploration wells in the Toritos oil field in the Llanos 123 Block; |
● | Successful drilling and putting into production three development wells in the Azogue gas field in the Llanos 32 Block; |
● | Successful drilling and putting into production the Indico 3 and Curucucu 4 development wells in the CPO-5 and Llanos 34 Blocks, respectively; |
● | Drilling campaign with 9 gross development wells drilled and putting into production in the Tigana and Jacana oil fields in the Llanos 34 Block, including successful drilling and putting into production 4 horizontal wells in the Tigana and Jacana oil fields; |
● | Waterflooding campaign, including 6 wells put into injection in the Jacana oil field, enhanced production in the Llanos 34 Block; |
● | Average net oil production of 31,867 boepd in 2024 (32,795 boepd in 2023), influenced by the natural production decline in the Llanos 34 Block and operational disruptions caused by blockades in the Llanos 34 and the CPO-5 Blocks; |
● | Proved oil and gas reserves of 56.5 mmboe at year-end 2024 (59.5 mmboe at year-end 2023), after producing 11.0 mmboe; |
● | Capital expenditures of US$167.0 million in 2024 (US$178.1 million in 2023), representing an 87% of our total capital expenditures; and |
● | Operating costs levels per barrel of US$14.1 in 2024 (US$11.5 in 2023), mainly due to inflationary pressures and the revaluation of the local currency in Colombia, affecting costs denominated in such local currency. |
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.
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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, 2024.
| 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 | Parex | — | Llanos | Exploration: 2028 | |||||||
CPO-5 | 490.8 | 30% | ONGC Videsh | ONGC Videsh | 6,931 | Llanos | Exploration: 2025 | |||||||
Exploitation: 2042-2045(3) | ||||||||||||||
Llanos 32 (4) | 8.5 | 12.5% | Verano Energy | Verano Energy | 490 | Llanos | Exploration: 2022 | |||||||
Exploitation: 2040-2045(3) | ||||||||||||||
Llanos 34 | 59.1 | 45% | Verano Energy | GeoPark | 21,659 | Llanos | Exploitation: 2039-2045(3) | |||||||
Llanos 86 | 255.5 | 50% | Hocol | GeoPark | — | Llanos | Exploration: 2026 | |||||||
Llanos 87 | 107.6 | 50% | Hocol | GeoPark | 172 | Llanos | Exploration: 2023 | |||||||
Llanos 104 | 274.8 | 50% | Hocol | GeoPark | — | Llanos | Exploration: 2026 | |||||||
Llanos 123 | 88.3 | 50% | Hocol | GeoPark | 1,332 | Llanos | Exploration: 2024 | |||||||
Llanos 124 | 27.6 | 50% | Hocol | GeoPark | — | Llanos | Exploration: 2024 | |||||||
Mecaya | 74.1 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Exploration: Currently suspended | |||||||
Platanillo | 27.5 | 100% | — | GeoPark | 1,381 | Putumayo | Exploitation: 2033(3) | |||||||
PUT-8 | 102.8 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Exploration: 2024 | |||||||
PUT-9 | 121.5 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Exploration: Currently suspended | |||||||
PUT-14 | 114.6 | 100% | — | GeoPark | — | Putumayo | In process of termination | |||||||
PUT-36 | 148.0 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Exploration: Currently suspended | |||||||
Tacacho | 589.0 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Termination requested | |||||||
Terecay | 586.6 | 50% | Sierracol Energy | GeoPark | — | Putumayo | Termination requested |
(1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
(2) | Partners with working interests. |
(3) | The concession expiration year is set on a field-by-field basis. |
(4) | In process of divestment, pending customary regulatory approval. For further information, please see “—Recent Developments—Divestment of non-operated working interest in the Llanos 32 Block in Colombia.” |
As of December 31, 2024, we had net proved reserves of 55.8 mmboe in various blocks in the Llanos Basin, with the Llanos 34 Block representing 87.9% of those reserves, and 0.7 mmboe in the Platanillo Block in the Putumayo Basin.
The table below summarizes information about the blocks in Colombia in which we have economic interests as of and for the year ended December 31, 2024.
| Gross acres |
|
|
|
| |||||
(thousand | Economic | Production | ||||||||
Block | acres) | interest(1) | Operator | (boepd) | Basin | |||||
Abanico | 25.7 | 10% | Frontera | 15 | Magdalena |
(1) | Economic interest corresponds to indirect participation interests in the net revenues from the block, granted to us pursuant to a joint operating agreement. In October 2024, the term of the Abanico Association Contract from which the economic interest arises expired and the termination process with the operator is currently ongoing. |
For further information of each E&P Contract in Colombia, please see “—Significant Agreements.”
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Operations in Ecuador
Our Ecuadorian assets currently give us access to 33,300 of gross exploratory and productive acres across 2 blocks in an attractive oil and gas geography.
Highlights of the year ended December 31, 2024, related to our operations in Ecuador include:
● | Successful drilling and putting into production three appraisal wells the Perico Block; |
● | Successful drilling and putting into production the Espejo Sur B3 exploration well in the Espejo Block; |
● | Average net oil production of 1,668 boepd in 2024 (926 boepd in 2023), reaching an exit production in the fourth quarter of 2024 of 1,749 boepd; |
● | Proved oil reserves of 0.9 mmboe (100% in the Perico Block) at year-end 2024 (2.3 mmboe at year-end 2023), after producing 0.6 mmboe; |
● | Capital expenditures of US$24.1 million in 2024 (US$20.9 million in 2023), representing 14% of our total capital expenditures. |
The table below summarizes information about the blocks in Ecuador in which we have working interests as of December 31, 2024.
| Gross |
|
|
|
|
| ||||||
acres | ||||||||||||
(thousand | Working | Production | Expiration | |||||||||
Block | acres) | interest (1) | Operator | (boepd) | Basin | concession year | ||||||
Espejo | 15.6 | 50% | GeoPark | 159 | Oriente | Exploration: 2025 | ||||||
Exploitation: 2045 | ||||||||||||
Perico | 17.7 | 50% | Frontera | 1,509 | Oriente | Exploration: 2025 | ||||||
Exploitation: 2045 |
(1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
For further information, please see “—Significant Agreements.”
Operations in Brazil
Our Brazilian assets currently give us access to 61,400 of gross exploratory and productive acres across 6 blocks (5 exploratory blocks and the BCAM-40 Concession, which is in production phase) in an attractive oil and gas geography.
Highlights of the year ended December 31, 2024, related to our operations in Brazil included:
● | Production in the Manati gas field was temporarily suspended since mid-March 2024 due to unscheduled maintenance activities performed by the operator; |
● | Average net oil and gas production of 222 boepd (98.5% gas) in 2024 (1,027 boepd in 2023), due to the abovementioned temporary suspension that affected production during the year; and |
● | Proved oil and gas reserves in the Manati field of 1.0 mmboe at year-end 2024 (from 1.5 mmboe at year-end 2023), after producing 0.1 mmboe. |
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The following table sets forth information as of December 31, 2024, on our concessions in Brazil in which we have a current or future working interest:
| Gross acres |
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|
|
|
|
| |||||||
(thousand | Working | Production | Concession | |||||||||||
Concession | acres) | interest(1) | Partners | Operator | (boepd) | Basin | expiration year | |||||||
POT-T-785 | 7.9 | 70% | Petroil | GeoPark | — | Potiguar | Exploration: 2025 | |||||||
Exploitation: 2050 | ||||||||||||||
REC-T 58 | 7.8 | 100% | — | GeoPark | — | Recôncavo | Exploration: 2026 | |||||||
Exploitation: 2052 | ||||||||||||||
REC-T 67 | 7.7 | 100% | — | GeoPark | — | Recôncavo | Exploration: 2026 | |||||||
Exploitation: 2052 | ||||||||||||||
REC-T 77 | 7.7 | 100% | — | GeoPark | — | Recôncavo | Exploration: 2026 | |||||||
Exploitation: 2052 | ||||||||||||||
POT-T 834 | 7.5 | 100% | — | GeoPark | — | Potiguar | Exploration: 2026 | |||||||
Exploitation: 2052 | ||||||||||||||
Manati (2) | 22.8 | 10% | Petrobras; Brava Energia S.A.; | Petrobras | 222 | Camamu-Almada | Exploitation: 2029 |
(1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
(2) | In process of divestment, pending customary regulatory approvals. For further information, please see “—Recent Developments—Divestment of non-operated working interest in the Manati gas field in Brazil.” |
For further information, please see “—Significant Agreements.”
Operations in Argentina
In May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in four adjacent unconventional blocks in the world-class Vaca Muerta shale formation in the Neuquén Basin in Argentina. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina (Vaca Muerta).”
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, 2024.
| Gross |
|
|
|
|
| ||||||
acres | ||||||||||||
(thousand | Working | Production | Expiration | |||||||||
Block | acres) | interest (1) | Operator | (boepd) | Basin | concession year | ||||||
Puelen | 260.2 | 18% | Pluspetrol | — | Neuquén | In process of relinquishment | ||||||
Los Parlamentos (2) | 330.9 | 50% | YPF | — | Neuquén | Exploration: 2023 |
(1) | Working interest corresponds to the working interests held by our respective subsidiaries in such block, net of any working interests held by other parties in each block. |
(2) | In October 2023, we agreed to transfer our 50% working interest in the Los Parlamentos Block to YPF and thus, once formally approved by local authorities, we will no longer be liable to remaining capital commitments or other legal obligations resulting from our participation in the block. |
For further information, please see “—Significant Agreements.”
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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, 2024, which is based on the D&M Reserves Report.
| Net proved reserves | ||||||||
| As of December 31, 2024 | ||||||||
| Total net | ||||||||
proved | |||||||||
Oil | Natural gas | reserves | |||||||
(mmbbl) | (bcf) | (mmboe)(1) | % Oil | ||||||
Net proved developed | |||||||||
Colombia | 50.0 | 0.9 | 50.1 | 99.7 | % | ||||
Ecuador | 0.5 | — | 0.5 | 100.0 | % | ||||
Brazil | 0.0 | 6.1 | 1.0 | 1.5 | % | ||||
Total net proved developed | 50.5 | 7.0 | 51.7 | 97.7 | % | ||||
Argentina (2) | 5.7 | 1.7 | 6.0 | 95.2 | % | ||||
Total net proved developed - Pro forma | 56.2 | 8.7 | 57.7 | 97.5 | % | ||||
Net proved undeveloped | |||||||||
Colombia | 6.4 | — | 6.4 | 100.0 | % | ||||
Ecuador | 0.4 | — | 0.4 | 100.0 | % | ||||
Total net proved undeveloped (3) | 6.8 | — | 6.8 | 100.0 | % | ||||
Argentina (2) | 30.4 | 9.7 | 32.0 | 94.9 | % | ||||
Total net proved undeveloped - Pro forma (3) | 37.2 | 9.7 | 38.8 | 95.8 | % | ||||
Total net proved (Colombia, Ecuador and Brazil) | 57.3 | 7.0 | 58.4 | 98.0 | % | ||||
Total net proved - Pro forma (Colombia, Ecuador, Brazil and Argentina) | 93.4 | 18.5 | 96.4 | 96.8 | % |
(1) | We calculate one barrel of oil equivalent as six mcf of natural gas. |
(2) | Reflects reserves estimates from the D&M Reserves Report for the Argentina (Vaca Muerta) acquisition. Closing of the acquisition is pending customary regulatory approvals from the respective provincial governments. For further information, please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina (Vaca Muerta).” |
(3) | We plan to put 100% of our reported 2024 year-end proved undeveloped reserves into production through activities to be implemented within five years of initial disclosure. |
We had net proved reserves of 58.4 mmboe at December 31, 2024, compared to net proved reserves of 66.2 mmboe as of December 31, 2023.
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The 12% decrease in net proved reserves in 2024 is mainly attributable to:
● | Production of 11.7 mmboe; |
● | Disposal of minerals in Chile of 2.9 mmboe; |
● | Lower-than-expected performance and unsuccessful activities from the existing wells in Ecuador and Brazil, resulting in a decrease of 0.8 mmbbl and 0.4 mmboe, respectively; |
● | Lower average prices in Colombia, resulting in a 1.2 mmboe decrease; and |
This was partially offset by:
● | Extensions and discoveries that resulted in an increase of 0.5 mmboe from the Perico new field in the CPO-5 Block and the Toritos Sur new field in the Llanos 123 Block, both in Colombia; |
● | Changes in a previously adopted development plan in Colombia, resulting in a 3.2 mmbbl increase; and |
● | Higher-than-expected performance from the existing wells in Colombia resulting in an increase of 5.5 mmbbl. |
During the year ended December 31, 2024, we had 4.9 mmboe of our proved undeveloped reserves from December 31, 2023, converted to proved developed reserves due to development drilling in the Llanos 34 Block in Colombia. For further information relating to the reconciliation of our net proved reserves for the years ended December 31, 2024, 2023 and 2022, please see Table 5 included in Note 38 (unaudited) to our Consolidated Financial Statements.
Internal controls over reserves estimation process
We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimating process and who have knowledge of the specific properties under evaluation. Our Chief 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:
● | estimates are prepared using generally accepted practices and methodologies; |
● | estimates are prepared objectively and free of bias; |
● | estimates and changes therein are prepared on a timely basis; |
● | estimates and changes therein are properly supported and approved; and |
● | estimates and related disclosures are prepared in accordance with regulatory requirements. |
Throughout each fiscal year, our technical team meets with Independent Qualified Reserves Engineers, who are provided with full access to complete and accurate information pertaining to the properties to be evaluated and all applicable personnel. This independent assessment of the internally-generated reserves estimates is beneficial in ensuring that interpretations and judgments are reasonable and that the estimates are free of preparer and management bias.
Recognizing that reserves estimates are based on interpretations and judgments, differences between the proved reserves estimates prepared by us and those prepared by an Independent Qualified Reserves Engineer of 10% or less, in aggregate, are considered to be within the range of reasonable differences. Differences greater than 10% must be resolved in the technical meetings. Once differences are resolved, the independent Qualified Reserves Engineer sends a preliminary copy of the reserves report to be reviewed by the Corporate Reserves team, the Executive Committee (integrated by the Chief Executive Officer, Chief Financial Officer, Chief Exploration and Development Officer, Chief Operating Officer,
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Chief Strategy, Sustainability and Legal Officer and Chief People Officer) and the Technical Committee (composed by three technical experts of our board of directors). A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be reviewed and analyzed by the Technical Committee which recommends to the Board of Directors to approve its disclosure and publication. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees of our board of directors.”
Independent reserves engineers
Reserves estimates as of December 31, 2024, for Colombia, Ecuador, Brazil and Argentina included elsewhere in this annual report are based on the D&M Reserves Report, dated March 21, 2025, and effective as of December 31, 2024. The D&M Reserves Report, a copy of which has been filed as an exhibit to this annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines at our request in order to estimate reserves and for the areas and period indicated therein.
DeGolyer and MacNaughton Corp. (“DeGolyer and MacNaughton” or “D&M), a Delaware corporation with offices in Dallas, Houston, Moscow, Algiers, Astana and Buenos Aires has been providing consulting services to the oil and gas industry since 1936. The firm has more than 200 professionals, including engineers, geologists, geophysicists, petrophysicists and economists that are engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
The D&M Reserves Report covered 100% of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton did not independently verify the accuracy and completeness of information and data furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, or any agreements relating to current and future operations of the fields and sales of production. However, if in the course of the examination something came to the attention of DeGolyer and MacNaughton that brought into question the validity or sufficiency of any such information or data, DeGolyer and MacNaughton did not rely on such information or data until it had satisfactorily resolved its questions relating thereto or had independently verified such information or data. DeGolyer and MacNaughton independently prepared reserves estimates to conform to the guidelines of the SEC, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years, under existing economic and operating conditions, consistent with the definition in Rule 4 10(a)(1)-(32) of Regulation S-X. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation. D&M’s primary economic assumptions in estimates included oil and gas sales prices determined according to SEC guidelines, future expenditures and other economic assumptions (including interests, royalties and taxes) as provided by us. The assumptions, data, methods and procedures used, including the percentage of our total reserves reviewed in connection with the preparation of the D&M Reserves Report were appropriate for the purpose served by such report, and DeGolyer and MacNaughton used all methods and procedures as it considered necessary under the circumstances to prepare such reports.
However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning the oil and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates.
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Technology used in reserves estimation
According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
There are various generally accepted methodologies for estimating reserves including volumetrics, decline analysis, material balance, simulation models and analogies. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. The particular method chosen should be based on the evaluator’s professional judgment as being the most appropriate, given the geological nature of the property, the extent of its operating history and the quality of available information. It may be appropriate to employ several methods in reaching an estimate for the property.
Estimates must be prepared using all available information (open and cased hole logs, core analyses, geologic maps, seismic interpretation, production/injection data and pressure test analysis). Supporting data, such as working interest, royalties and operating costs, must be maintained and updated when such information materially changes.
Proved undeveloped reserves
As of December 31, 2024, we had 6.8 mmboe in proved undeveloped reserves, a decrease of 11.3 mmboe, or 62%, compared to our December 31, 2023, proved undeveloped reserves of 18.1 mmboe. Changes for the year ended December 31, 2024, include:
(i) | a decrease of 4.9 mmbbl in Colombia due to the conversion of proved undeveloped reserves to proved developed reserves in the Llanos 34 Block; |
(ii) | a decrease of 7.4 mmbbl due to a lower-than-expected performance in Colombia (7.1 mmbbl) and Ecuador (0.3 mmbbl); |
(iii) | a decrease of 1.0 mmbbl due to lower oil average prices in Colombia; |
(iv) | a decrease of 0.6 mmbbl due to unsuccessful activities in Ecuador; |
(v) | a decrease of 0.6 mmboe due to the disposal of minerals in Chile; and |
This was partially offset by:
(vi) | an increase of 3.2 mmbbl in Colombia due to a change in a previously adopted development plan. |
Of our 6.8 mmboe of net proved undeveloped reserves, 6.4 mmboe (94.6%) and 0.4 mmboe (5.4%) were located in Colombia and Ecuador, respectively. No net proved undeveloped reserves were located in Brazil as of December 31, 2024.
During 2024, we incurred approximately US$39.4 million in capital expenditures in Colombia and Ecuador to convert such proved undeveloped reserves to proved developed reserves.
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The following table shows the evolution of total net proved undeveloped (“PUD”) reserves in the year ended December 31, 2024.
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2023 | 18.1 | |
(All amounts shown in mmboe) | ||
Less: PUD Reserves converted to proved developed reserves: | ||
-Colombia | (4.9) | |
Less: PUD Reserves revisions and movement to/from other categories: | ||
-Colombia | (4.9) | |
-Ecuador | (0.9) | |
Less: Disposal of minerals in place | ||
-Chile | (0.6) | |
Total Net Proved Undeveloped (“PUD”) Reserves at December 31, 2024 | 6.8 |
Production, revenues and price history
The following table sets forth certain information on our production of oil and natural gas in Colombia, Ecuador, Brazil, Chile and Argentina for each of the years ended December 31, 2024, 2023 and 2022.
Average daily production(1) | ||||||||||||||||||||||||||
As of December 31, | ||||||||||||||||||||||||||
2024 | 2023 | 2022 | ||||||||||||||||||||||||
| Colombia |
| Ecuador |
| Brazil |
| Chile (2) |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Colombia |
| Ecuador | Brazil |
| Chile |
| Arg (3) | ||
Oil production | ||||||||||||||||||||||||||
Average crude oil production (bopd) | 31,867 | 1,668 | 3 | 5 | 32,795 | 926 | 16 | 221 | 33,640 | 848 | 21 | 441 | 80 | |||||||||||||
Average sales price of crude oil (US$/bbl) | 65.8 | 69.8 | 96.1 | — | 66.8 | 69.9 | 82.1 | 68.0 | 82.7 | 89.9 | 103.1 | 94.7 | 56.7 | |||||||||||||
Natural Gas production | ||||||||||||||||||||||||||
Average natural gas production (mcfpd) | 685 | — | 1,313 | 363 | 573 | — | 6,065 | 8,993 | 776 | — | 8,967 | 11,387 | 416 | |||||||||||||
Average sales price of natural gas (US$/mcf) | 7.2 | — | 5.9 | 3.2 | 3.9 | — | 6.5 | 3.4 | 4.5 | — | 6.4 | 3.8 | 2.0 | |||||||||||||
Oil and gas production cost | ||||||||||||||||||||||||||
Average operating cost (US$/boe) | 14.1 | 21.8 | 48.2 | 20.6 | 11.5 | 37.5 | 10.9 | 13.0 | 6.6 | 27.1 | 7.4 | 16.1 | 24.0 | |||||||||||||
Average royalties and economic rights in cash (US$/boe) | 1.1 | — | 2.8 | 0.6 | 7.9 | — | 3.1 | 0.9 | 21.0 | — | 3.1 | 1.5 | 5.0 | |||||||||||||
Average production cost (US$/boe)(4) | 15.2 | 21.8 | 50.9 | 21.2 | 19.4 | 37.5 | 14.0 | 13.9 | 27.6 | 27.1 | 10.5 | 17.6 | 29.0 |
(1) | We present production figures net of interests due to others, but before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. |
(2) | Divested in January 2024. |
(3) | “Arg” is Argentina. |
(4) | Calculated pursuant to FASB ASC 932. |
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The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Ecuador, Brazil, Chile and Argentina for each of the years ended December 31, 2024, 2023 and 2022.
2024 | 2023 | 2022 | ||||||||||
| Oil |
| Gas |
| Oil |
| Gas |
| Oil |
| Gas | |
Mbbl | MMcf | Mbbl | MMcf | Mbbl | MMcf | |||||||
Tigana oil field(1) | 3,865 | — | 3,904 | — | 4,057 | — | ||||||
Jacana oil field(1) | 3,534 | — | 4,411 | — | 4,678 | — | ||||||
Rest of Colombia | 4,264 | 251 | 3,655 | 209 | 3,543 | 283 | ||||||
Ecuador | 610 | — | 338 | — | 310 | — | ||||||
Brazil | 1 | 481 | 6 | 2,214 | 8 | 3,273 | ||||||
Chile | 2 | 133 | 81 | 3,283 | 161 | 4,156 | ||||||
Argentina | — | — | — | — | 29 | 152 | ||||||
Total | 12,277 | 864 | 12,395 | 5,705 | 12,786 | 7,864 |
(1) | The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia are separately included in the table above as those oil fields individually contain more than 15% of our total proved reserves as of each of the years indicated above. |
Drilling activities
The following table sets forth the exploratory wells we drilled during the years ended December 31, 2024, 2023 and 2022.
Exploratory wells(1) | ||||||||||||||||||||||||
2024 | 2023 | 2022 | ||||||||||||||||||||||
| Colombia |
| Ecuador |
| Brazil |
| Chile(2) |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Colombia |
| Ecuador |
| Brazil |
| Chile | |
Productive(3) | ||||||||||||||||||||||||
Gross | 9.0 | 5.0 | — | — | 7.0 | 3.0 | — | — | 4.0 | 4.0 | — | — | ||||||||||||
Net | 4.1 | 2.5 | — | — | 3.3 | 1.5 | — | — | 2.6 | 2.0 | — | — | ||||||||||||
Dry(4) | ||||||||||||||||||||||||
Gross | 2.0 | — | — | — | 6.0 | — | — | — | 4.0 | — | — | — | ||||||||||||
Net | 0.6 | — | — | — | 2.8 | — | — | — | 2.3 | — | — | — | ||||||||||||
Total | ||||||||||||||||||||||||
Gross | 11.0 | 5.0 | — | — | 13.0 | 3.0 | — | — | 8.0 | 4.0 | — | — | ||||||||||||
Net | 4.7 | 2.5 | — | — | 6.0 | 1.5 | — | — | 4.9 | 2.0 | — | — |
(1) | Includes appraisal wells. |
(2) | Divested in January 2024. |
(3) | A productive well is an exploratory, development, or extension well that is not a dry well. |
(4) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. |
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The following table sets forth the development wells we drilled during the years ended December 31, 2024, 2023 and 2022.
Development wells | ||||||||||||||||||||||||
2024 | 2023 | 2022 | ||||||||||||||||||||||
| Colombia |
| Ecuador |
| Brazil |
| Chile(1) |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Colombia |
| Ecuador |
| Brazil |
| Chile | |
Productive(2) | ||||||||||||||||||||||||
Gross | 21.0 | — | — | — | 25.0 | — | — | — | 28.0 | — | — | 1.0 | ||||||||||||
Net | 8.7 | — | — | — | 11.8 | — | — | — | 12.0 | — | — | 1.0 | ||||||||||||
Dry(3) | ||||||||||||||||||||||||
Gross | 1.0 | — | — | — | 7.0 | — | — | — | 2.0 | — | — | 1.0 | ||||||||||||
Net | 0.3 | — | — | — | 3.7 | — | — | — | 0.9 | — | — | 1.0 | ||||||||||||
Total | ||||||||||||||||||||||||
Gross | 22.0 | — | — | — | 32.0 | — | — | — | 30.0 | — | — | 2.0 | ||||||||||||
Net | 9.0 | — | — | — | 15.5 | — | — | — | 12.9 | — | — | 2.0 |
(1) | Divested in January 2024. |
(2) | A productive well is an exploratory, development, or extension well that is not a dry well. |
(3) | A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well. |
Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in Colombia, Ecuador, Brazil and Argentina as of December 31, 2024.
Acreage(1) | ||||||||
| Colombia |
| Ecuador |
| Brazil |
| Argentina | |
(in thousands of acres) | ||||||||
Total developed acreage | ||||||||
Gross | 27.4 | 1.6 | 4.1 | — | ||||
Net | 13.8 | 0.8 | 0.4 | — | ||||
Total undeveloped acreage | ||||||||
Gross | 3,212.8 | 31.7 | 57.3 | 591.1 | ||||
Net | 1,580.8 | 15.9 | 38.1 | 212.3 | ||||
Total developed and undeveloped acreage | ||||||||
Gross | 3,240.2 | 33.3 | 61.4 | 591.1 | ||||
Net | 1,594.6 | 16.7 | 38.5 | 212.3 |
(1) | Developed acreage is defined as acreage assignable to productive wells. Undeveloped acreage is defined as acreage on which wells have not been drilled or completed to a point that would permit the production of commercial quantities of oil or gas regardless of whether such acreage contains proved reserves. Net acreage is based on our working interest. |
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Productive wells
The following table sets forth our total gross and net productive wells as of February 28, 2025. Productive wells consist of producing wells and wells capable of producing, including natural gas wells awaiting pipeline connections to commence deliveries and oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Productive wells(1) | ||||||
| Colombia |
| Ecuador |
| Brazil | |
Oil wells | ||||||
Gross | 229.0 | 12.0 | - | |||
Net | 113.8 | 6.0 | - | |||
Gas wells | ||||||
Gross | 2.0 | - | 6.0 | |||
Net | 0.3 | - | 0.6 |
(1) | Includes wells drilled by other operators, prior to our commencing operations, and wells drilled in blocks in which we are not the operator. A productive well is an exploratory, development, or extension well that is not a dry well. |
Present activities
From January 1, 2025, to February 28, 2025, we produced a net average of approximately 36.8 mboepd on a pro-forma basis, including 29.8 mboepd from our operations in Colombia and Ecuador and 7.0 mboepd from our recent acquisition in Argentina (Vaca Muerta).
The main highlights of the 2025 drilling campaign year-to-date are detailed as follows:
● | drilling the Bisbita Oeste-1 and Toritos Oeste-1 appraisal wells in the Llanos 123 Block in Colombia; |
● | drilling the Curucucu-2 development well in the Llanos 34 Block in Colombia; and |
● | drilling the Bienparado Norte-1 and Bienparado Sur-1 exploration wells in the PUT-8 Block in Colombia, which are under evaluation. |
In our recent acquisition in Argentina (Vaca Muerta), the Mata Mora 2092, 2093 and 2094 wells were drilled and put into production at PAD 9, with 3,900 boepd gross production at the end of February 2025.
Marketing and delivery commitments
Colombia
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.
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In 2024, we entered into several commercial agreements for the sale of our Colombian production, with two key agreements detailed below, considering their terms and the financial facilities linked to the offtake:
● | 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, for a minimum of 20 months and up to 36 months, starting on July 1, 2024. As part of this transaction, we obtained access to committed funding from Vitol, with an initial limit of up to US$300.0 million, which decreases by US$10.0 million per month. 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, we drew US$152.0 million under this offtake and prepayment agreement. Between February and March 2025, we repaid US$126.4 million in cash and US$6.4 million in kind from that amount and, as of the date of this annual report, US$ 19.2 million remain outstanding. |
● | In August 2024, we executed an offtake and prepayment agreement with C.I. Trafigura Petroleum Colombia S.A.S. (“Trafigura”), one of the world’s leading commodity traders. The offtake agreement provides for GeoPark to sell and deliver the light crude oil production from the CPO-5 Block in Colombia to Trafigura, for 12 months, starting on August 1, 2024. As part of this transaction, GeoPark obtained access to committed funding from Trafigura for up to an initial US$100.0 million in prepaid future oil sales over the period of the offtake agreement, which decreases over the life of the contract. Funds committed by Trafigura are available until June 30, 2025, subject to certain conditions. 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 3.50% per annum. As of the date of this annual report, we have not drawn any amount under this prepayment agreement. |
Regarding the transportation infrastructure, we can highlight the following:
● | Llanos Basin: We have made historic efforts to improve our optionality related to evacuation infrastructure. In 2015, we partnered with Oleoducto de Los Llanos Orientales S.A. (ODL) to establish an unloading facility at the Jaguey Station, 42 km from the Llanos 34 Block, reducing trucking distance and costs. In 2019, we connected the Llanos 34 Block to the ODL pipeline via a flowline, eliminating trucking for Jacana production volumes and improving cost efficiency and operational reliability. This flowline was authorized by the Ministry of Energy and Mines to become a pipeline in November 2020 as the Oleoducto del Casanare (ODCA), setting regulated tariffs and enabling third-party crude transportation. Subsequently, in late 2020, we inaugurated an unloading facility in Jacana and connected the Tigana field to ODCA, further reducing reliance on trucking. Since 2021, ODCA has been central to our crude transportation from Jacana, Tigana, and other fields, with third-party transport agreements, including a 2022 connection of the Cabrestero Block. In 2023, an agreement with Ecopetrol enabled transport of royalty volumes from Jacana, Tigana, and Tua fields, optimizing ODCA capacity. Additionally, in 2024 we concluded a dilution project at Tigana Station, along with our partner in the Llanos 34 Block, to further increase volumes transported through ODCA and reduce transport costs. |
● | Putumayo Basin: In the case of the Platanillo Block in the Putumayo Basin, we gather the crude via truck and flowlines to pump it towards Ecuador via the Oloeducto Binacional Amerisur (“OBA”). This pipeline is operated by us and our affiliates and connects us to the Ecuadorian pipeline system via RODA allowing us to sell our production FOB in Esmeraldas port in Ecuador. We hold transport contracts with RODA and SOTE for the transport, storage and loading of our crude in Ecuador. |
Ecuador
Ecuador has a well-developed crude oil market with broad access to international markets and an extensive pipeline transportation system. Our oil production, which began in 2022, is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of our sales are exported on a competitive basis to industry leading participants including traders, refineries, and other producers. The oil price is linked to Brent and adjusted by a differential that varies month to month and resembles Oriente crude reference price.
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Brazil
Our production in Brazil consists of natural gas, condensate and crude oil. Natural gas production is sold through a long-term, extendable agreement with Petrobras, which provides for the delivery and transportation of the gas produced in the Manati field to the EVF gas treatment plant in the State of Bahia. The contract is in effect until delivery of the maximum committed volume or June 2030, whichever occurs first. The contract allows for sales above the maximum committed volume if mutually agreed by both seller and buyer. The price for the gas is fixed in reais and is adjusted annually in accordance with the Brazilian inflation index. In July 2015, we signed an amendment to the existing gas sales agreement with Petrobras that covers 100% of the remaining gas reserves in the Manati field. The low gas prices seen in the Brazilian market during 2023 have represented a risk in the commercialization of gas from the Manati field. The contractually agreed price considers inflation but is not affected by market conditions, which reduces the appetite of the client, who has access to more favorable conditions.
The condensate produced in the Manati field is subject to a condensate purchase agreement with Petrobras, pursuant to which Petrobras has committed to purchase all of our condensate production in the Manati field, but only in the amounts that we produce, without any minimum or maximum deliverable commitment from us. Considering this prerogative, in February 2023, we signed an agreement with DAX Oil Refino S.A. (“DAX”), a local private refinery, for the selling of condensate until February 2025. Through this agreement, we increased our portfolio of clients and improved our revenues. The agreement with DAX can be renewed upon an amendment signed by the purchasers and the seller.
Argentina
Since 2019, oil production from the Vaca Muerta shale formation has experienced remarkable growth. In December 2024, Vaca Muerta reached an oil production of 446,854 bopd, marking an interannual growth of 26.9%. It currently contributes more than 50% of Argentina’s total oil production, with high potential to continue increasing in the following years. This growth has driven the need for increased capacity projects to secure pipeline access for current and future production. Three oil pipelines currently cross the block to facilitate exports.
Through our partnership with PGR, we have secured participation in critical capacity projects such as the one known as “Duplicar Plus” by the local company Oldelval and the other known as “Vaca Muerta Sur I” by YPF (from Loma Campana to Allen). We continue to evaluate additional projects to support anticipated production growth.
Our collaboration with PGR leverages the commercial strengths of both companies, maximizing the potential of these assets. Approximately 90% of oil sales are transported by pipeline, estimating 50% for export and 50% for the domestic market in 2025.
Gas production accounts for around 6% of total output, with approximately 75% sold to third parties and approximately 25% used for internal consumption.
Corporate
GeoPark Limited, our holding company incorporated under the laws of Bermuda, has entered into a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside our Putumayo Basin production. Sales of this crude oil purchased from third parties accounted for 1% of our consolidated revenue in 2024.
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Significant Agreements
Colombia
E&P contracts
We have entered into E&P contracts granting us the right to explore and operate, as well as working interests in eighteen blocks in Colombia. These E&P contracts are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and (2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable. Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties to the relevant E&P contract. The exploitation period for an area may be extended until such time as such area is no longer commercially viable and certain other conditions are met.
Pursuant to our E&P contracts, we are required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a field-by-field basis. See Note 33.1 to our Consolidated Financial Statements.
Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P contract governing such area, the ANH is entitled to receive a “windfall profit”, to be paid periodically, calculated pursuant to such E&P contract.
In each of the exploration and exploitation periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P contract.
Our E&P contracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses, ANH regulation or termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian law, if certain conditions are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government during a certain period. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our contracts 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, production sharing agreements and concession agreements are subject to early termination in certain circumstances.”
Eastern Llanos Basin:
Llanos 34 Block E&P contract. On March 13, 2009, the E&P contract was awarded to Unión Temporal Llanos 34, currently integrated by GeoPark Colombia S.A.S. with 45%, and Verano Limited (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,
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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 33.1 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 agreed to transfer, subject to regulatory approval, our non-operated working interest in the Llanos 32 Block to our joint operation partner for a total consideration of US$19.0 million, minus working capital adjustment of US$3.7 million. As of the date of this annual report, we have received the net proceeds from the transaction, which are subject to final settlement.
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 that are in the exploratory phase. 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, due to the presence of indigenous communities in the area, we conducted the due prior consultation process with these communities and reached agreements, thereby concluding the process on August 29, 2023. Regarding the environmental permits, in May 2024, the environmental national authority of Colombia (“Autoridad Nacional de Licencias Ambientales” or “ANLA”) granted us the environmental license for both blocks, enabling exploration and development activities. The investment commitments consist of acquisition of 3D seismic, 2D seismic reprocess and drilling of one exploration well in each block for an estimated amount of US$9.7 million for the Llanos 86 Block and US$8.6 million for the Llanos 104 Block, at our working interest, before June 19, 2026. As of the date of this annual report, the outstanding commitment in the blocks is the drilling of one exploration well in the Llanos 104 Block.
In the Llanos 87 Block, after fulfilling the total exploration investments committed in the block, we made two discoveries: Tororoi and Zorzal. Therefore, we submitted to the ANH an evaluation program, which includes the drilling of one exploratory well during the two-year term ending July 27, 2025.
The Llanos 123 Block entered exploratory phase 2 in 2024. Accordingly, as of the date of this annual report, our investment commitment consists of drilling one exploratory well for US$3.3 million, at GeoPark’s working interest, before January 14, 2027. In December 2024, we submitted the environmental impact study and the environmental license application for the development phase of the Llanos 123 Block.
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, and the ANH approval is pending.
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CPO-5 Block E&P contract. We hold a 30% working interest since the acquisition of Amerisur in 2020 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 fields called Flamenco, Halcon and Perico.
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, by the former operator in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coati-1 well. Pursuant to the Coati Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons 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 block consist of 3D seismic and 2D seismic acquisition for US$4.5 million. The evaluation area is currently suspended. On November 3, 2022, GeoPark submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and transfer the pending commitments to other E&P contracts. GeoPark completed the transfer of the pending commitments in the block and the ANH approval is pending.
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 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
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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 the acquisition of Amerisur 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. As of the date of this annual report, the field has been temporarily shut down due to its cost structure.
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. Outstanding investment commitments of US$13.1 million related to this block correspond to the drilling of 3 exploratory wells and the acquisition of 112 sq. km. of 3D seismic before May 19, 2025. Part of the 3D seismic committed in the block was acquired during 2020 and 2021. On October 25, 2022, we submitted to the ANH a request to transfer part of the investment commitment related to the pending 3D seismic to the Platanillo Block, and the partner reported the transfer of the outstanding committed value to one of its blocks. This transfer of commitments is subject to authorization from the ANH. During 2023, the actions required to obtain environmental licenses were carried out, including holding of a public environmental hearing. As a result, in August 2023, the environmental authority granted the license for the Bienparado project, which was confirmed in January 2024. Additionally, the Nyctibius project public environmental hearing is pending. As of the date of this annual report, drilling of the first two wells in the block is in process.
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). Pursuant to the Putumayo 9 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 9 Block E&P contract. The ANH also has an additional economic right equivalent to 18% of production, net of royalties. In accordance with the Putumayo 9 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 14 Block E&P contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block. On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers,
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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). During this preliminary phase, and once the suspension is lifted, GeoPark must request from the Ministry of Interior a certificate that indicates presence or no presence of indigenous communities and develop previous consultation, if applicable. Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the block over three-years term of phase 1 would be 3D seismic acquisition and 2 exploratory wells for US$11.5 million, at our working interest.
Pursuant to the Putumayo 36 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 36 Block E&P contract, and the payment of 25% of the Economic Right for the use of the subsoil for institutional strengthening and Technology Transfer. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the Putumayo 36 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Tacacho and Terecay Blocks E&P contracts. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks. Sierracol Energy is the owner of the remaining 50% working interest in each E&P contract. The contracts are in phase 1 of the exploration period, which are currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area. The outstanding investment commitments consist of 2D seismic acquisition, processing and interpretation for US$4.1 million at our working interest. Pursuant to the Tacacho and Terecay Blocks E&P contracts and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the blocks. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Tacacho and Terecay Blocks E&P contracts. In accordance with the Tacacho and Terecay Blocks operation contracts, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. On September 21, 2022, we submitted to the ANH requests for termination of the E&P contracts and, in January 2024, we submitted additional third-party reports as supporting documentation to such request. As of the date of this annual report, the requests are under review by the ANH.
Overriding Royalty Agreements
We are obligated to pay an overriding royalty of 4% and 2.5%, plus a 20% grossing up over the overriding royalty, to the previous owners of the Llanos 34 and Llanos 32 Blocks, and the CPO-5 Block, respectively, based on the production and sale of hydrocarbons discovered in the blocks. During 2024, the Group has accrued US$26.1 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 2024, these agreements had no impact on our results.
Ecuador
Production sharing contracts
We entered into two production sharing contracts with the Ministry of Energy and Mines. While we are the operators in the Espejo Block, Frontera operates the Perico Block. The production sharing contracts in Ecuador are generally divided into two stages: (i) an exploration period of 4 years, which may be extended to 6 years; and (ii) a production period of 20 years. The exploitation or production period commences upon Governmental approval of the exploitation and development
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plan of a commercial field (although early production during the exploration period is allowed). The extension of the production period requires entering into an amendment to the contract with the Government of Ecuador, which may imply revision of contractual conditions. As of the date of this annual report, we have drilled the four exploratory wells in each block, and we have completed the acquisition of 60 sq km of 3D seismic in the Espejo Block. GeoPark has already performed all the committed exploratory activities, and the Ecuadorian Mines and Energy Ministry approval is pending.
In the Espejo and Perico production sharing contracts, production is measured and distributed among the contractor and the Government at the delivery point where a production sharing formula is applied based on international oil prices of the Oriente marker in the previous month and the offer made as base point in each tender. No further royalties apply. In addition, we are obliged to make a yearly payment of US$24,000 as compensation for the use of water and natural construction materials, which increases to US$60,000 during the production stage. Furthermore, there is an institutional development fee of US$100,000 payable every year.
Brazil
Overview of concession agreements
The Brazilian oil and gas industry is governed mainly by the Brazilian Petroleum Law, which provides for the granting of concessions to operate petroleum and gas fields in Brazil, subject to oversight by the ANP. A concession agreement is divided into two phases: (1) exploration and (2) development and production. The exploration phase consists of one exploratory period that begins on the date of execution of the concession agreement, which can last from three to eight years (subject to earlier termination upon the total return of the concession area or the declaration of commercial viability with respect to a given area), while the development and production phase, which begins for each field on the date a declaration of commercial viability is submitted to the ANP, can last up to 27 years. Upon each declaration of commercial viability, a concessionaire must submit to the ANP a development plan for the field within 180 days. The concessions may be renewed for an additional period equal to their original term if renewal is requested with at least 12 months’ notice and provided that a default under the concession agreement has not occurred and is then continuing. Even if obligations have been fulfilled under the concession agreement and the renewal request was appropriately filed, renewal of the concession is subject to the discretion of the ANP.
The main terms and conditions of a concession agreement are set forth in Article 43 of the Brazilian Petroleum Law, and include: (1) definition of the concession area; (2) validity and terms for exploration and production activities; (3) conditions for the return of concession areas; (4) guarantees to be provided by the concessionaire to ensure compliance with the concession agreement, including required investments during each phase; (5) penalties in the event of noncompliance with the terms of the concession agreement; (6) procedures related to the assignment of the agreement; and (7) rules for the return and vacancy of areas, including removal of equipment and facilities and the return of assets. Assignments of participation interests in a concession are subject to the approval of the ANP, and the replacement of a performance guarantee is treated as an assignment.
The main rights of the concessionaires (including us in our concession agreements) are: (1) the exclusive right of drilling and production in the concession area; (2) the ownership of the hydrocarbons produced; (3) the right to sell the hydrocarbons produced; and (4) the right to export the hydrocarbons produced. However, a concession agreement set forth that, in the event of a risk of a fuel supply shortage in Brazil, the concessionaire must fulfill the needs of the domestic market. In order to ensure the domestic supply, the Brazilian Petroleum Law granted the ANP the power to control the export of oil, natural gas and oil products.
Among the main obligations of the concessionaire are: (1) the assumption of costs and risks related to the exploration and production of hydrocarbons, including responsibility for environmental damages; (2) compliance with the requirements relating to acquisition of assets and services from domestic suppliers; (3) compliance with the requirements relating to execution of the minimum exploration program proposed in the winning bid; (4) activities for the conservation of reservoirs; (5) periodic reporting to the ANP; (6) payments for government participation; and (7) responsibility for the costs associated with the deactivation and abandonment of the facilities in accordance with Brazilian law and best practices in the oil industry.
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A concessionaire is required to pay to the Brazilian government the following: a license fee, rent for the occupation or retention of areas, a special participation fee, royalties, and taxes. Rental fees for the occupation and maintenance of the concession areas are payable annually. For purposes of calculating these fees, the ANP takes into consideration factors such as the location and size of the relevant concession, the sedimentary basin and the geological characteristics of the relevant concession. A special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulations, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation fee, whenever due, varies between 0% and 40% of net revenues depending on (1) the volume of production and (2) whether the concession is onshore or in shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based on the quarterly net revenues of each field, which consist of gross revenues calculated using reference prices established by the ANP (reflecting international prices and the exchange rate for the period) less royalties paid, investment in exploration, operational costs, and depreciation adjustments and applicable taxes. The Brazilian Petroleum Law also requires that the concessionaire of onshore fields pay to the landowners a special participation fee that varies between 0.5% to 1.0% of the net operational income originated by the field production.
BCAM-40 Concession Agreement.
On August 6, 1998, the ANP and Petrobras executed the BCAM-40 Concession Agreement, under the regime established by the Brazilian Petroleum Law. The production phase will end in November 2029. On September 11, 2009, Petrobras announced the termination of BCAM-40 Concession’s exploration phase and the return of the exploratory area of the concession to the ANP, except for the Manati gas field.
Under the BCAM-40 Concession Agreement, the ANP is entitled to a monthly royalty payment equal to 7.5% of the production of oil and natural gas in the concession area. In addition, in case the special participation fee of 10% shall be applicable for a field in any quarter of the calendar year, the concessionaire is obliged to make qualified research and development investments equivalent to one percent of the field’s gross revenue. Area retention payments are also applicable under the concession agreement.
Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements.
During the ANP’s First Open Acreage Bid Round held in September 2019, we were awarded four exploratory blocks, one in the Potiguar Basin (Block POT-T-834) and three in the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). The Concession Agreements were executed in February 2020. In 2023, we started preliminary activities for the environmental licensing in Block POT-T-834. As of December 31, 2024, the estimated commitment in the blocks to be executed before August 14, 2026, amounted to US$0.5 million.
Under the Rounds 11, 12, 13, 14 and 1st Open Acreage Bid Round Concession Agreements, the ANP is entitled to a monthly royalty corresponding to up to 10% of the production of oil and natural gas in the concession area, in addition to the special participation fee described above, the payment for the occupation of the concession area of approximately R$7,600 per year and the payment to the owners of the land of the concession equivalent to one percent of the oil and natural gas produced in the concession area.
During bidding, a work program offer is made in the form of work units and the ANP asks for a guarantee of a monetary amount proportional to the offered units. However, depending on the work performed by the operator, the actual work program investment might have a different value to the guaranteed value.
Overview of consortium agreements
A consortium agreement is a standard document describing consortium members’ respective percentages of participation and appointment of the operator. It generally provides for joint execution of oil and natural gas exploration, development and production activities in each of the concession areas. These agreements set forth the allocation of expenses for each of the parties with respect to their respective participation interests in the concession. The agreements
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are supplemented by joint operating agreements, which are private instruments that typically regulate the aggregation of funds, the sharing of costs, mitigation of operational risks, preemptive rights and the operator’s activities.
An important characteristic of the consortia for exploration and production of oil and natural gas that differs from other consortia (Article 278, paragraph 1, of the Brazilian Corporate Law) is the joint liability among consortium members as established in the Brazilian Petroleum Law (Article 38, item II).
BCAM-40 Consortium Agreement
On January 14, 2000, Petrobras, Queiroz Galvão Perfurações (now Brava Energia S.A.) and Petroserv entered into a consortium agreement, or the BCAM-40 Consortium Agreement, for the performance of the BCAM-40 Concession Agreement. Petrobras is the operator of the BCAM-40 concession, with a 35% participation interest. Brava Energia S.A., GBS Estocagem de Gás Natural S.A. and GeoPark Brazil have a 45%, 10% and 10% participation interest, respectively. The BCAM-40 Consortium Agreement has a specified term of 40 years, terminating on January 14, 2040 and, at the time the obligations undertaken in the agreement are fully completed, the parties will have the right to terminate it. The BCAM-40 Concession consortium has also entered into a joint operating agreement, which sets out the rights and obligations of the parties in respect of the operations in the concession.
On March 27, 2025, we entered into an agreement to sell our 10% non-operated working interest in the Manati gas field in Brazil for a total consideration of US$1.0 million, subject to working capital adjustment, plus a contingent payment of an additional US$1.0 million, subject to the field’s future cash flow or its potential conversion into a natural gas storage facility. As of the date of this annual report, we have collected an advance payment of US$0.5 million. Closing of the transaction is pending customary regulatory approvals.
Petrobras Natural Gas Purchase Agreement
Brava Energia S.A., GeoPark Brazil, GBS Estocagem de Gás Natural S.A. and Petrobras are party to a natural gas purchase agreement providing for the sale of natural gas by Brava Energia S.A., GeoPark Brazil, GBS Estocagem de Gás Natural S.A. to Petrobras, in an amount of 812 billion cubic feet (“bcf”) over the term of agreement. The Petrobras Natural Gas Purchase Agreement is valid until the earlier of Petrobras’ receipt of this total contractual quantity or June 30, 2030. The agreement may not be fully or partially assigned except upon execution of an assignment agreement with the written consent of the other parties, which consent may not be unreasonably withheld provided that certain prerequisites have been met.
The agreement provides for the provision of “daily contractual quantities” to Petrobras peaking at 170.3 mmcfd in 2016 and progressively dropping until 2030. The parties may agree to lower volumes as dictated by Manati gas field’s depletion. Pursuant to the agreement, the base price is denominated in reais and is adjusted annually for inflation pursuant to the general index of market prices (IGPM). Additionally, the gas price applicable on a given day is subject to reduction as a result of the gas quantity acquired by Petrobras above the volume of the annual TOP commitment (85% of the daily contracted quantity) in effect on such day. The Petrobras Natural Gas Purchase Agreement provides that all of the Manati field’s daily production be sold to Petrobras.
Argentina
Overview of exploration permits
The Mata Mora Norte concession and the Mata Mora Sur exploration permit were granted to GyP in March 2021 by means of Decree issued by the Neuquén province No. 331/2021, which:
(i) | granted a 35-year unconventional hydrocarbons exploitation concession over the Mata Mora Norte portion of the Mata Mora Block, in accordance with the Federal Hydrocarbons Law, which includes a five-year pilot project entailing an investment of approximately US$ 110.0 million; |
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(ii) | maintained the reservation over the Mata Mora Sur portion of the Mata Mora Block for the purpose of carrying out certain exploratory activities, including 3D seismic of approximately US$3.0 million until April 27, 2026; and |
(iii) | approved the first addendum to the statutory joint venture agreement (the “Mata Mora UT”) dated as of March 2, 2021, entered into by Kilwer S.A. and Ketsal S.A., two subsidiaries of PGR (as holders of 90% participating interest), and GyP (as holder of a 10% participating interest), for the purpose of carrying out operations within the Mata Mora Block. |
The second addendum to the Mata Mora UT, by means of which we will be authorized by the Neuquén province to be incorporated to the Mata Mora UT, is pending approval.
If a commercial discovery is made before the expiration of the Mata Mora Sur exploration permit on April 27, 2026, we, along with our partners, shall apply for an exploitation concession, in accordance with the Federal Hydrocarbons Law. The approval of this concession would allow for the transition from exploration to full-scale development and production.
The Confluencia Norte and Confluencia Sur exploration permits (the “Confluencia Permits”) were granted pursuant to Decree of the Río Negro province No. 779/2023. Through this decree, Kilwer S.A. entered into:
(i) | two hydrocarbons exploration contracts dated August 14, 2023, with the Río Negro province, for the purpose of the activities to be carried out in the Río Negro Blocks under the exploration permits; and |
(ii) | a statutory joint venture agreement (together with the hydrocarbons exploration contracts described in (i) above, the “Río Negro UTs”) for the exploitation, development and exploration of the Río Negro Blocks dated August 14, 2023, with EDHIPSA, which potentially holds a non-operating participating interest of 10% in the Río Negro UTs, effective as of the commencement of exploitation of the Río Negro Blocks and subject to the exercise by EDHIPSA of its rights to hold such participating interest in the Río Negro UTs pursuant to Section 24 of each Río Negro UT. The assignment by PETSA (as absorbing and surviving entity of Kilwer S.A. pursuant to a merger process) of the Confluencia Permits was approved by the Río Negro province pursuant to Decree No. 370/2024. |
The Confluencia Permits were granted for an initial exploration period of 3 years and entitled to request a second exploration period of 2 years. Additionally, the Confluencia Permits allow us and PETSA to request an extension of up to 4 additional years. In the event there is a commercial discovery, we and PETSA shall request and obtain an exploitation concession, in the terms set forth in the Federal Hydrocarbons Law in Argentina, which includes presenting a pilot plan, paying a commerciality bonus, a yearly exploitation canon, a training, research and development payment, amongst other. In that event, we and PETSA will have to assign to EDHIPSA a 10% participating interest (5% each) of our rights and obligations of such concession. EDHIPSA, at its own choice, may elect to (i) maintain such 10% participating interest in the concession or (ii) receive monthly payments equivalent to 2.5% of all the hydrocarbons produced in the area (free from any deduction of royalties).
Title to properties
In each of the countries in which we operate, the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. In Colombia, Ecuador, Brazil and Argentina, local governments grant such rights through E&P contracts or contracts of association, exploration permits, exploitation concessions, production sharing contracts 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, Ecuador, Brazil and Argentina 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 or contracts of association, exploration permits, exploitation concessions, production sharing contracts and concession agreements are subject to customary
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royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.”
Our customers
In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. During 2024, the oil and gas production was sold to three clients that concentrated 95% of the Colombian subsidiaries’ revenue. In 2024, we executed offtake and prepayment agreements with Vitol and Trafigura, two of the world’s leading commodity traders, to sell production from our Llanos 34 and CPO-5 Blocks, respectively. In Ecuador, 100% of our sales were exported on a competitive basis to industry leading participants including traders and other producers. In Brazil, all our gas produced in the Manati field was sold to Petrobras. 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 and Trafigura. For further information, please see Note 3 to our Consolidated Financial Statements.
Seasonality
Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not played a significant role in our ability to conduct our operations, including drilling and completion activities.
Our competition
The oil and gas industry is competitive, and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring and developing licenses in the countries where we operate or plan to operate.
Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Competition in the oil and natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel.”
We may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.
Health, safety and environmental matters
General
We are genuinely committed to ensuring everyone returns home safely and to preventing environmental impacts resulting from our operations, in accordance with the legal framework, industry best practices and international standards in terms of socio-environmental, health and safety performance. We work closely with our suppliers and contractors to
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transfer the best HSE practices throughout our value chain and extend our responsibility towards safety and the environment, with binding contractual agreements, monthly safety and environmental performance evaluations, annual compliance evaluations and the construction of capacities and competencies necessary to be in line with our health, safety, and environmental commitment.
We have a health and safety management plan focused on hazard identification and risk control, including systematic tools implemented in all the operations involving both employees’ and contractors’ activities, ensuring compliance with applicable health and safety requirements.
We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and actions that ensure respect and protection of the environment in the territories where we operate.
In each of the countries where we operate, we ensure compliance with applicable health, safety and environmental requirements. All our operations have the environmental licenses and permits required under the applicable legislation, which are derived from the development of environmental studies with citizen participation for the definition of management measures and impact mitigation.
Our Health and Safety Management System (HSMS) certification is maintained under the ISO standard: 45001:2018, and includes all Colombian operations. We also implemented our HSMS in Ecuador based on corporate commitment.
Our Environmental Management System (EMS), certified under the ISO standard: 14001:2015 for our operations in Colombia, defines programs for the integral management of water resources; solid and liquid waste management; atmospheric emissions and energy; biodiversity and ecosystem services and training and awareness regarding the protection of the environment for employees and suppliers. In addition, it defines the roles and responsibilities of management regarding 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.
In 2024, GeoPark calculated its integral water footprint in all operated blocks in Colombia and Ecuador for the first time (2023 base line), using the NTC-ISO 14046:2017 methodology.
The assessment was verified by Colombia’s Standards Institute ICONTEC and included the amount of water used directly by GeoPark in its operations and indirectly through its supply chain, as well as assessing impacts associated with the availability and quality of water resources. The exercise enables GeoPark to establish a baseline of its corporate water footprint with which to define goals and actions to continue promoting sustainable water management in the territories it operates in.
In 2024, we did not 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 built the sewerage and the water waste treatment plant (90% of progress) for a local town with a
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population of more than 1,300, enhancing the quality of life of its inhabitants and improving the water quality of the river in which the discharge is made.
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 2024, included:
● | We continue being part of the Putumayo Regional Agreement for Biodiversity and Development, which integrates efforts by the private sector and national and regional entities to preserve the biodiversity and connectivity of this region of the Amazon. As part of this agreement, in 2024, we made a partnership with the Sinch Amazon Institute of Scientific Research, Wildlife Conservation Society - WCS and other Colombian O&G Company, to implement the project call “Ríos diversos” in order to characterize the water’s biological quality in the Putumayo watershed and study its relationship with the local communities. |
● | Publication of the book “Biodiversity in the Llanos 34 Block”, through which all the analyses and results of fauna and flora monitoring and biodiversity projects that the Company has historically carried out in its main asset are made available to interested parties. |
● | In 2024, based on a partnership with Colombia’s Alexander Von Humboldt Institute, we evaluated our dependencies, impacts, risks and opportunities associated with nature and particularly with biodiversity, using the recommendations of the Taskforce on Nature Related Financial Disclosure (“TNFD”) as a reference. This is part of the Socioecological Action Plan for our operations in Colombia, which are currently the Company’s largest in terms of production, intervention and growth projection. |
● | As part of our environmental obligations, we have more than 230 hectares under restoration and conservation action in strategic ecosystems of the Amazonia. |
● | In Ecuador, in the canton of Shushufindi, province of Sucumbios, we developed, in coordination with the local and provincial government, a project for the recovery of plant cover in areas of watercourses and estuaries with an ecosystem, landscape and watershed protection approach, in order to improve the natural balance and the biodiversity of the territory. |
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:
● | 35-40% Greenhouse Gas (“GHG”) emissions intensity reduction of Scope 1 and 2 emissions by 2025; |
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● | 40-60% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2030; and |
● | net zero Scope 1 and 2 emissions by or before 2050. |
All our abovementioned goals are defined against a 2020 baseline.
These goals take into account the execution of some operational and environmental projects. The following projects are the most relevant achieved during 2024 in Colombia:
● | repair of fugitive emissions in our main producing assets; |
● | access clean energy sources via the connection of the Llanos 34 Block to the Colombian electricity grid; |
● | reduce the use of boilers; and |
● | prepare for the use of previously flared gas, gradually decreasing routine flaring. |
Medium-term actions include energy efficiency, small-scale renewable projects, management of methane emissions, and potential participation in carbon markets, among others.
Longer-term actions may include carbon capture, use and storage projects, reforestation and afforestation initiatives.
As of the date of this annual report, we have other ongoing environmental initiatives related to climate adaptation, such as, in Colombia, we continue the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía, in the hydrographic zone of the Meta River, which will contribute to improve water management, comprehensive risk management and climate change adaptation.
Integral waste management and circular economy
Regarding the proper management of solid waste generated by our activities, we focus our management on the principles of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with applicable regulations. In 2023, we continue strengthening our circular economy strategic plan and the roadmap for its implementation. As part of this plan, we are carrying out more than 8 circular initiatives as part of the three (3) circularity models that we have prioritized: i) water management, ii) waste management, and iii) use of gas.
In 2024, GeoPark was 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 it promotes the efficient management of resource consumption, the maintenance of the value of products and materials, and the minimization of waste generation in its operations.
We continue improving our circular economy plan, defining circular criteria for materials acquisition. Additionally, we have 11 circular initiatives in place in the Company operated assets.
Spill Management
In 2024, we had zero recordable hydrocarbon spills (>=1Bbl uncontained) in our operations.
Our HS Plan
Our health and safety management plan is focused on undertaking realistic and practical programs based on recognized global practices. Our emphasis is on building key principles and company-wide ownership and then expanding programs as we continue growing. Our SPEED philosophy and our HS Plan have been developed with reference to ISO 45000 for
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occupational health and safety management issues, SA 8000 for social accountability and workers’ rights issues and general guidelines from international entities such as IOGP, IPIECA, IADC and ARPEL. In 2024, our HS Plan focused on four key strategies:
•Leadership and Governance: Reinforcing communications strategy with a focus on “Safety First” messages.
•People Management: Developing a training program for technical and HS competencies.
•Operation Management: Cultivating a culture of operational discipline.
•Contractors Management: Strengthening the procurement process to align with HS requirements.
Our HS Policy
Our policy seeks to meet or exceed safety regulations in the countries in which we operate. We believe that oil and gas can be produced in a safe and healthy environment safeguarding the well-being of all people. Within our SPEED philosophy we have a team that is exclusively focused on promoting the best health and safety practices. This professional and trained team is responsible for the achievement of the health and safety standards set by our board of directors and for training and supporting our personnel. Our senior executives, personnel in the field, visitors and contractors have also received training in proper health, safety and environmental management.
Since 2024, health and safety has become a review topic for the Board’s sustainability committee (SPEED Committee). In this way, the corporate governance of the area has been complemented by integrating it into all aspects of comprehensive sustainability.
Our health and safety practices and outcomes
We continue to improve and update management tools to strengthen our health and safety policy. We have implemented world-class programs focused on analyzing, assessing, and controlling hazards that may cause injury or illness to our employees, contractors, and visitors. Our main occupational health and safety programs are: the proactive observation program (POP), the authority to stop an activity (ADA), the safety operational standard (SOS), management of change (MOC), the incident reporting and investigation (IRIS), the road transportation safety (RTS), and the business continuity master plan (PMCN).
In 2024, we reached several significant milestones, among which the following stand out:
● | Our assets in Ecuador, which maintained a constant operation throughout 2024, had no recordable incidents affecting people. |
● | Zero recordable vehicular incidents and zero recordable oil spills in all operations in 2024. |
● | Total recordable injury rate (TRIR) and recordable vehicular incidents rate (MVC) goals achieved. |
● | Conduct retrospective and strategic meetings with contractors’ managers and perform quarterly reviews with contractor groups including D&C, ALS, O&M and Facilities. |
● | Maintained the ISO 45001 certification of our HS management system. |
As of December 31, 2024, and for the last twelve months, our HS indicators were the following:
● | People injury. Indicators calculated per 1,000,000 hours worked (for both employees and contractors): |
● | Lost time injury rate (LTIR) of 0.32. |
● | Total recordable incident rate (TRIR) of 0.64. |
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● | Zero fatal incidents in the operation. |
● | Vehicle incidents, calculated per 1,000,000 kilometers travelled: |
● | Zero recordable vehicular incidents rate (MVC). |
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.”
Industry and regulatory framework
Colombia
Regulation of the oil and gas industry
The ANH is responsible for managing all exploration acreage not subject to previously existing association contracts with Ecopetrol. Two decades ago, the ANH began offering all undeveloped and unlicensed exploration areas in the country under concession-fashion Exploration and Production Contracts (“E&P contracts”) and Technical Evaluation Agreements, (or “TEAs”), which resulted in a significant increase in Colombian exploration activity and competition, according to the ANH. The regime for ANH’s contracts is set forth in Agreement 008 of 2004 and Agreement 004 of 2012. The Agreement 004 of 2012 regulates E&P contracts entered into from May 4, 2012, and onwards. E&P contracts signed before that date are still regulated by Agreement 008 of 2004. Due to the oil price crisis of 2015, the ANH implemented transitory measures through Agreements 002, 003, 004 and 005 of 2015. On May 18, 2017, the ANH issued Agreement 002, which replaced Agreement 004 of 2012 and transitory measures adopted in 2014 and 2015. Agreement 002 of 2017 established rules for granting hydrocarbon areas and adopted criteria for the exploration and exploitation of hydrocarbons owned by Colombia, including the selection of contractors, and management, execution, termination, liquidation, monitoring, control, and supervision of corresponding contracts. Agreement 002 of 2017 (compiled by Acuerdo 009 of 2021) regulates contracts entered into from May 18, 2017, and onwards. E&P contracts entered into before that date are still regulated by the agreements under which they were executed. Since 2004, the ANH has promoted several bidding processes resulting in various E&P contracts.
In September 2023, the ANH issued Agreement 06, 2023, with the purpose of promoting exploration by granting extensions of exploratory and evaluation periods and the possibility for contractors to maintain areas for a longer period of time in exchange for additional exploratory commitments in the areas.
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Regulatory framework
Regulation of exploration and production activities
Pursuant to Colombian law, the state is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is the authority responsible for creating national energy policy and regulating all activities related to the exploration and production of hydrocarbons in Colombia.
Decree Law 1056 of 1953 (Código de Petróleos), or the Petroleum Code, establishes the general procedures and requirements that must be completed by a private investor and disclosure procedures that should be met during the performance of these activities.
Exploration and production activities were governed by Decree 1895 of 1973 until September 2009. Decree Law 2310 of 1974 (as complemented by Decree 743 of 1975) governed the contracts and contracting processes carried out by Ecopetrol and the rules applicable to such contracts and provided that Ecopetrol was responsible for administering the hydrocarbons resources in the Country. Decree 2310 of 1974 was replaced by Decree Law 1760 of 2003, which restructured the hydrocarbons sector, but all agreements entered into by Ecopetrol prior to 2003 with other oil companies are still regulated by Decree 2310 of 1974. By Decree Law 1760 of 2003, Ecopetrol was spun off and the ANH was created. One of the main purposes of this decree was to treat Ecopetrol as another oil and gas company in the market and to transfer regulatory functions to the ANH as administrator of the nation’s hydrocarbons. This enabled Ecopetrol to differentiate its role and avoid it being a party and judge to contractual matters.
Resolution 40537 of 2024, establishes a series of regulations regarding hydrocarbon exploration and exploitation. In the E&P contracts, operators are afforded access to blocks by committing to perform an exploratory work program. These E&P contracts provide companies with 100% of new production, less the participation of the ANH, which participation may differ for each E&P contract and depends on the percentage that each company has offered to the ANH to be granted with a block, applicable royalties and revenue taxes. In addition, the Colombian government also introduced TEAs, in which companies that enter into TEAs are the only ones to have the right to explore, evaluate and select desirable exploration areas by executing seismic and /or drilling stratigraphic wells and to propose work commitments on those areas, and have a preemptive right to enter into an E&P contract (Right to convert the TEA contract into an E&P contract), thereby providing companies with low-cost access to larger areas for preliminary evaluation prior to committing to broader exploration programs. Under a TEA, the contractor commits to exclusively perform the committed exploration activities.
Pursuant to Colombian law, oil companies are obliged to pay royalties (a percentage of their production) to the ANH in kind or in money as per ANH’s instruction and pursuant to the E&P contracts. Companies must also pay the ANH an economic right called participating interest in the production, commonly known as “X factor” among other economic rights established in the E&P contracts (i.e. high price provision, technology transfer, use of the subsurface). Producing fields pay royalties in accordance with the applicable law at the time of the discovery. Under the E&P contracts, ANH contractors also undertake obligations in favor of the communities located in the area of influence of the oil & gas projects, called “Proyectos en Beneficio de las Comunidades” or (PBC).
In 2022, ANH launched Ronda Colombia 2021 with an addition to the terms of reference to include the Exclusivity Economic Value (EEV). The EEV includes both the minimum amount required by the ANH and the additional amount eventually included in the proposal, and which should be offered by the initial offers and counteroffers to surpass the initial proposal and equalize or exceed the most favorable counteroffer presented in each round. EEV is represented in the number of exploratory wells offered by a company to be drilled during the E&P contract’s exploratory phase of six years. The companies should offer at least 1 EEV (minimum accepted by ANH) and grant a stand-by letter of credit for 100% of the estimated value of the well as per ANH’s reference values. In the event the company does not comply with the offered EEV, the letter of credit will be enforced by ANH. ANH granted 30 areas in Ronda Colombia 2021 in which we did not participate. However, Parex transferred to us a 50% non-operated working interest in the CPO4-1 Exploration and Production Contract, which was granted to it under Ronda Colombia 2021.
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Taxation
The Tax Statute and Law 9 of 1991 provide the primary features of the oil and gas industry’s tax and foreign exchange system in Colombia. Generally, national taxes under the general tax statute apply to all taxpayers, regardless of industry.
The latest tax reform was enacted in December 2022, including modifications to the corporate income tax rate and the tax treatment of royalties, in-kind and in cash. However, in November 2023, the Constitutional Court ruled that the modification that prohibited the deduction of royalties is unconstitutional, and such deductions are allowed as was the case until 2022. See Note 16 to our Consolidated Financial Statements.
The main taxes currently in effect are the income tax (35%, plus a surtax for companies developing crude oil extractive activities from 2023 onwards, ranging between 0% and 15%, depending on the Brent oil price level), capital gains tax (15%), sales or value added tax (19%), and the tax on financial transactions (0.4%).
Additional regional taxes also apply with some special rules for the companies belonging to the oil and gas industry. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax.
Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment in Colombia. Resolution 1/2018 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing exchange operations. Articles 94 to 97 of Resolution 1 provide for a special exchange regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies.
Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Central Bank and Ministry of Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 1 and may not be able to access the special exchange regime for a period of 10 years.
New tax regulations
On February 14, 2025, the Ministry of Finance and Public Credit of Colombia issued Decree No. 175, which establishes tax measures to finance the General Budget of the Nation (PGN). These measures are intended to address the expenses arising from the internal commotion declared in the Catatumbo region, Cúcuta’s metropolitan area, and the municipalities of Río de Oro and González in the department of Cesar. This state of internal commotion has resulted in significant disturbances, including armed confrontations, forced displacements, and threats to civilians, leading to an unexpected demand for additional resources in the PGN. As a result, two key tax measures have been introduced that affect our operations in Colombia.
The first significant change is the creation of a Special Tax for Catatumbo, which applies to the extraction of crude oil and coal at the time of their first sale or export. The tax rate is set at 1% on the value of crude oil and coal, with the tax base determined by the sale price for domestic transactions and the FOB value for exports.
The second change is an increase in the Stamp Tax Rate, which has been temporarily raised from 0% to 1% on public and private documents that record the creation, modification, or extinction of obligations. This tax is applicable to documents exceeding Colombian Pesos 298 million in value (approximately US$0.07 million) and will take effect five business days after the publication of the decree, although the exact publication date has not been confirmed. This modification will impact various legal and financial agreements, including contracts and other documents related to our operations that involve significant monetary obligations.
These tax changes, particularly the Special Tax for Catatumbo, could increase our financial liabilities in Colombia. If the tax is interpreted as multi-phase, it would result in a heavier tax burden, especially for companies involved in both the
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sale and export of hydrocarbons. We will need to review our contracts with marketers and other stakeholders to assess the financial impact and consider renegotiating terms where necessary to mitigate the effects of this additional tax.
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.
Ecuador
Regulatory framework
Petroleum Ownership and Regulation
Oil, gas, minerals and natural resources underground belong to the Republic of Ecuador, in accordance with the Ecuadorian Constitution. This is a primary concept in both the Constitution and the law. However, the State can allow private investment to explore and produce hydrocarbons under different types of contracts as provided under the law.
The Ministry of Energy and Mines (“Ministry of Energy”) regulates and oversees all hydrocarbon-related activities in the country, including exploration, production, transportation, refining and marketing. The Ministry of Energy has absorbed the functions and duties of the Secretariat of Hydrocarbons and, through the Vice-Ministry of Hydrocarbons, oversees awarding, executing and monitoring contracts with private companies for the exploration and production of hydrocarbons. On the other hand, the Agency for Regulation and Control of Energy and Non-Renewable Natural Resources (“ARCERNNR” by its Spanish acronym) has the legal duty to oversee, audit, collect levies and duties on operations, and conduct accounting control of all upstream and downstream hydrocarbon operations.
The Ministry of the Environment, Water and Ecological Transition of Ecuador (“MAATE” by its Spanish acronym) has the legal competence for granting environmental licenses for all oil and gas activities and to ensure such operations are conducted in compliance with environmental laws and regulations. The MAATE is independent from the Ministry of Energy.
Petroleum Laws and Regulations
The Ecuadorian Constitution contains the main provisions, which stipulate that all hydrocarbons belong to the State of Ecuador, that the national oil company is EP PETROECUADOR has preferential rights for oil exploration, production, transportation and sale, and that, in case a contract is executed with a private oil company, the State’s benefit must be more than that of the private company. The State’s benefit is understood as all taxes, production sharing and other economic benefits the State receives from oil production, while the company’s benefit is understood as all proceeds received from payment for the service of producing oil, or from the sales of its share of oil, less all amortization of investments, costs and taxes paid by the company.
The Hydrocarbons Law is the main body of law below the Ecuadorian Constitution and regulates the different types of contracts the government can enter into with international oil companies, as well as the rights, obligations and penalties for private companies. The main contracts that have been implemented in Ecuador from time to time are service contracts and fairly recently the production-sharing contracts (“PSC”). Under a service contract, the State of Ecuador pays a
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contractually agreed tariff per barrel. Under a PSC, the investing company receives a share of the oil produced which it can freely trade.
There are several regulations ranking below the Hydrocarbons Law that set further rules for all activities, including the regulation of hydrocarbon operations and special local rules on the accounting principles for each type of contract.
In addition to all the other generally applicable laws of the country, the Environmental Law, Labor Law (including local content in hiring of personnel) and Tax Law should be carefully considered.
Background for Contract types for Private Investment in Petroleum
During almost 50 years, Ecuador has been producing oil, through two types of contracts: production-sharing contracts and service contracts. Traditionally, the government has imposed service contracts when the price of oil was high and production-sharing contracts when the price of oil was low. In 2010, a legal reform required all oil companies that were operating under the umbrella of production-sharing contracts to transform their contracts into service contracts.
Service contracts can be executed by the Ministry of Hydrocarbons for exploration blocks or for fields already in production (followed a 2021 reform to the Law of Hydrocarbons). In both cases, the contracting company receives a pre-agreed tariff that is usually negotiated considering the amount of the investment, existing reserves, production cost and an estimated reasonable profit for the company.
In July 2018, Executive Decree No. 449 reinstated the production-sharing type of contracts locally referred to as Participation Contracts. In 2019, the Ministry of Energy executed several Participation Contracts for exploration and exploitation of hydrocarbons.
The contract term for a production-sharing contract is usually four years for exploration, extendable for two additional years, and 20 years for production, subject to an extension if reserves have been added and new investments are committed. As of the date of this annual report, we hold two production-sharing contracts with a 50% working interest in consortium with Frontera Energy (Espejo Block, operated, and non-operated Perico Block), which were awarded by the Ministry of Energy during the First Intracampos Bidding Round in April 2019.
Taxation
The guiding principle is that the government’s share will always be higher than the contracting company’s share. If the contracting company’s share is higher than 51%, it triggers a sovereignty margin adjustment in favor of the government.
The taxpaying unit under oil and gas production-sharing contracts is the consortium which, although not a separate legal entity, is considered a partnership for tax purposes. Therefore, taxable income is calculated by the consortium performing the income generating activities with respect to the production sharing agreement awarded to it.
Under a production-sharing contract, the government’s share is composed of the sales price or the reference price of the share of oil assigned to the government as per the contract, plus all taxes and contributions paid by the company. In this type of contract, the contracting company’s share is the higher of the sales price and the reference price of the company’s oil, less all amortization of investments, operating costs, transportation costs up to the port of Balao on the Pacific Coast and all taxes and contributions paid pursuant to the law and the contract.
Basically, the taxes are:
● | employee profit-sharing (15% of net profits before income tax, out of which 3% has to be distributed to the employees and 12% has to be paid to the government); |
● | 25% income tax rate; |
● | 15% value-added tax; |
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● | money outflow tax, applied to remittances abroad, except when it comes to distribution of profits, with the following rates: 4% until January 31, 2023; 3.75% from February 1, 2023, to June 30, 2023; 3.5% from July 1, 2023, to December 31, 2023; 2% from January 1, 2024, to March 31, 2024; and 5% from April 1, 2024 onwards; |
● | municipal taxes; and |
● | other fees and contributions charged by petroleum oversight authorities. |
GeoPark, as operator of the Espejo Consortium, has entered into an investment agreement with the Ecuadorian Government to carry out several activities under the production sharing agreement. As consideration, the Espejo Consortium, as an income tax payer, obtained a 5% reduction in the statutory income tax rate. Currently, the corporate income tax rate applicable to the Espejo Consortium is 20% by virtue of the investment agreement.
According to Ecuadorian legislation, no value-added tax (“VAT”) credit is available for hydrocarbon industries. This means that VAT-liable taxpayers cannot claim a VAT tax credit. As a result, neither the Espejo Consortium nor its member corporation can claim a VAT tax credit.
Production Risk
For any type of contract to be entered into in Ecuador, the investing company has to take on all exploration and production risks and investments, as well as environmental responsibilities in accordance with its corresponding environmental obligations.
Furthermore, the investing company must strictly abide by all employment laws, in terms of legal requirements concerning the maximum number of foreign employees. Some contracts have allowed for arbitration as a dispute resolution mechanism; however, certain matters, such as taxes, cannot be submitted to arbitration. This is also true for certain termination provisions in the event of the investing company breaching the law (such as transfer of rights without consent). The reform to the Law of Hydrocarbons enacted in 2021 allows the entry into investment treaties with the Government of Ecuador, allowing to freeze tax incentives in consideration for investment commitments and expanding local employment.
Brazil
Regulation of the oil and gas industry
Article 177 of the Brazilian Federal Constitution of 1988 provides for the Federal Government’s monopoly over the prospecting and exploration of oil, natural gas resources and other fluid hydrocarbon deposits, as well as over the refining, importation, exportation and sea or pipeline transportation of crude oil and natural gas. Initially, paragraph one of article 177 barred the assignment or concession of any kind of involvement in the exploration of oil or natural gas deposits to private industry. On November 9, 1995, however, Constitutional Amendment Number 9 altered paragraph one of article 177 so as to allow private or state-owned companies to engage in the exploration and production of oil and natural gas, subject to the conditions to be set forth by legislation.
Regulatory framework
Pricing policy
Until the enactment of the Brazilian Petroleum Law, the Brazilian government regulated all aspects of the pricing of oil and oil products in Brazil, from the cost of oil imported for use in refineries to the price of refined oil products charged to the consumer. Under the rules adopted following the Brazilian Petroleum Law, the Brazilian government changed its price regulation policies. Under these regulations, the Brazilian government: (1) introduced a new methodology for determining the price of oil products designed to track prevailing international prices denominated in U.S. Dollars, and (2) gradually eliminated controls on wholesale prices.
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Concessions
In addition to opening the Brazilian oil and natural gas industry to private investment, the Brazilian Petroleum Law created new institutions, including the ANP, to regulate and control activities in the sector. As part of this mandate, the ANP is responsible for licensing concession rights for the exploration, development and production of oil and natural gas in Brazil’s sedimentary basins through a transparent and competitive bidding process. The ANP has conducted 17 bidding rounds for exploration concessions from 1999 through 2021, four open acreage bid rounds, 6th Production Sharing Bidding Round and two Transfer of Right Surplus Bidding Round.
Taxation
The Brazilian Petroleum Law introduced significant modifications and benefits to the taxation of oil and natural gas activities. The main component of petroleum taxation is the government take, comprised of license fees, fees payable in connection with the occupation or title of areas, royalties and a special participation fee. The introduction of the Brazilian Petroleum Law presents certain tax benefits primarily with respect to indirect taxes. Such indirect taxes are very complex and can add significantly to project costs. Direct taxes are mainly corporate income tax and social contribution on net profit.
With the effectiveness of the Brazilian Petroleum Law and the regulations promulgated by the ANP, concessionaires are required to pay the Brazilian federal government the following: license fees, rent for the occupation or retention of areas, special participation fee, and royalties on production.
The minimum value of the license fees is established in the bidding rules for the concessions, and the amount is based on the assessment of the potential, as conducted by the ANP. The license fees must be paid upon the execution of the concession contract. Additionally, concessionaires are required to pay a rental fee to landowners varying from 0.5% to 1.0% of the respective hydrocarbon production.
The special participation fee is an extraordinary charge that concessionaires must pay in the event of obtaining high production volumes and/or profitability from oil fields, according to criteria established by applicable regulation, and is payable on a quarterly basis for each field from the date on which extraordinary production occurs. This participation rate, whenever due, may reach up to 40% of net revenues depending on (i) volume of production and (ii) whether the block is onshore, shallow water or deep water. Under the Brazilian Petroleum Law and applicable regulations issued by the ANP, the special participation fee is calculated based upon quarterly net revenues of each field, which consist of gross revenues calculated using reference prices published by the ANP (reflecting international prices and the exchange rate for the period) less: royalties paid; investment in exploration; operational costs; and depreciation adjustments and applicable taxes.
The ANP is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between 5% and 10% applied to reference prices for oil or natural gas, as established in the relevant bidding guidelines (edital de licitação) and concession agreement. In determining the percentage of royalties applicable to a particular concession, the ANP takes into consideration, among other factors, the geological risks involved, and the production levels expected.
State VAT (ICMS)
ICMS is a state sales tax. This tax is due on the local sale of oil and gas, based on the sale price, including the ICMS itself.
For intrastate transactions (carried out by a seller and a buyer located in the same Brazilian state) or imports, the ICMS rate is determined by the legislation of the state where the sale is made and generally varies from 17% to 20%. Interstate transactions (carried out between a seller and buyer located in different Brazilian states), in turn, are subject to reduced rates of 4% (if the products are imported and not submitted to a manufacturing process or, in case of further manufacturing, if the resulting product has a minimum imported content of 40%), 7% or 12%, depending on the states involved. One exception is that, due to the immunity established by the Brazilian Federal Constitution, ICMS is not due on interstate crude oil transactions when destined to industrialization and commercialization. On the other hand, in case of consumables
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or fixed assets, the buyer must pay to the state where the buyer is located, the ICMS DIFAL, which is calculated based on the difference between the interstate rate and the buyer’s own internal ICMS rate.
ICMS is calculated under the noncumulative regime, and therefore some input transactions could result in tax credits (for example the acquisition of inputs and fixed assets directly used in the company’s activity).
Social contribution taxes on gross revenue (PIS and COFINS)
PIS and COFINS are social contribution taxes charged on gross revenues earned by a Brazilian Federal Revenue noncumulative regime of calculation.
Under the noncumulative regime, PIS and COFINS are generally charged at a combined nominal rate of 9.25% (1.65% PIS and 7.6% COFINS) on national revenues earned by a legal entity. In that case, certain business costs result in tax credits to offset PIS and COFINS liabilities (e.g., input and services acquisitions, expenses of depreciation and amortization of machinery, equipment and other fixed assets acquired to be directly used in the company’s activities). PIS and COFINS paid upon the importation of certain inputs, assets and services contracted that are destined to the company’s activity are also creditable. Although upstream industries are generally subject to this regime, it is not clear yet when this benefit is applied according to the stage of the field, (exploration or production).
Since July 1, 2015, taxpayers subject to the noncumulative regime must calculate PIS and COFINS over certain financial revenues, applying rates of 0.65% and 4%, respectively.
Federal Industrialization VAT (IPI) and Municipality VAT (ISS)
IPI is a non-cumulative tax and may be due on goods acquisitions by importation or national transactions. The IPI rate will be applied depending on the NCM classification of the product according to TIPI (Table of IPI). On the acquisition of local goods subject to IPI, such tax is included in the price of the good. Considering that O&G activity (upstream) is not subject to IPI taxation, the amount of the tax cannot be considered as a credit (even though IPI is under the non-cumulative regime applicable for IPI’s taxpayers), which means that this will be a cost for the legal entity acquirer. In relation to the importation, the importer of record will be considered as the taxpayer and will be obliged to pay the IPI due on the transaction. For the same aforementioned reasons for the O&G companies (upstream), this will be considered as cost when the importation is subject to IPI.
ISS is a cumulative tax which is due on provided services and imported services. Usually, regarding local transactions, such tax is included in the price of the service charged by the service provider. In relation to the import of service, the Brazilian entity contractor is responsible for the payment of the ISS, which means that, depending on contractual arrangement, the tax burden may be supported by the Brazilian contractor or the foreign service provider.
ISS tax rate may vary from 2% to 5% and will depend on the nature of service, as well as where the service provider is located (in general, some exceptions may apply).
Additionally, in 2018, GeoPark Brazil was granted a tax benefit issued by SUDENE (Northeastern Development Superintendence), by means of the Constitutive Act No. 0069/2018, which approved the tax incentive to reduce by 75% the Income Tax and Additions, calculated over the company exploration profits, based on Article 1 of the Provisory Measure 2,199-14 of August 24, 2001, in accordance with the requirements established by the Decree 6,539 of August 18, 2008.
The benefit will be valid for 10 years, starting from January 1, 2018, under the condition of modernizing the entire project on the SUDENE operating area, observing all provided legal conditions and requirements that includes compliance with labor and social law and with all environmental protection and control regulations, annual submission of a declaration of income and a restriction to the distribution to partners or shareholders of the tax amount which is not paid due to the tax exemption.
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The noncompliance with the requirements provided constitutes a default of the beneficiary company in respect to SUDENE and shall be subject to the applicable penalties.
Argentina
Regulatory framework
The Hydrocarbon Law No. 17,319 (“Federal Hydrocarbons Law”) enacted in 1967 continues in force until today, subject to amendments introduced by the Laws No. 24,145, 26,197 and 27,007, and Section IV of the recently passed Law 27,742 (the “Ley de Bases y Puntos de Partida para la Libertad de los Argentinos” or “Ley de Bases”).
The Federal Hydrocarbons Law provided for the existence of a state-owned oil & gas company (originally, YPF) for whom private companies initially served as service contractors or joint venture partners. But it also provided for a concession & royalty system which became the prevailing contractual granting instrument after the deregulation of petroleum activities introduced by Decrees No. 1055/89, 1212/89 and 1589/89 (the “Petroleum Deregulation Decrees”) and the YPF Privatization Law 24,145 enacted in 1992.
On May 3, 2012, the Argentine Congress passed the Hydrocarbons Sovereignty Law 26,741 which (i) impaired the Deregulation Decrees; (ii) declared that achieving self-sufficiency in the supply of hydrocarbons, shall be a national public interest and a priority for Argentina; and (iii) expropriated 51% of the share capital of YPF then owned by the Spanish company Repsol.
Law No. 27,742 enacted the Incentive Regime for Large Investments (“RIGI”), which establishes a regulatory framework to promote investment in productive projects in certain industries in Argentina, regulating the terms and subjects entitled to participate in such regime, the specific requirements for inclusion in the RIGI, and the conditions under which such inclusion may not be requested; the specific functions and responsibilities of the application authority; tax and customs incentives for utility project vehicles (“VPU”), as well as foreign exchange incentives; stability, compatibility with other regimes and assignments under the RIGI; the termination of incentives under the RIGI; the infringement and recourse regime applicable to the VPU; among others. On August 23, 2024, the Executive Branch issued Decree No. 749/2024, which establishes operational aspects for the purpose of implementing the RIGI and establishes that RIGI does not apply to companies engaged in the extraction of oil and gas.
Eminent Domain and Jurisdiction of hydrocarbons resources
After a constitutional reform enacted in 1994 and passing of Law No. 26,197, eminent domain over hydrocarbon resources lying in the territory of a provincial state is now vested in such provincial state, while eminent domain over hydrocarbon resources lying offshore on the continental platform beyond the jurisdiction of the coastal provincial states is vested in the federal state. Thus, oil and gas exploration permits, and exploitation concessions are now granted by each provincial government.
Hydrocarbon Income Maximization and Exports
Achieving self-sufficiency has been an energy policy goal from the early days of the industry. Supply privileges favoring the domestic market over the export market, including hydrocarbon export restrictions, domestic price controls, price subsidies, export duties and domestic market supply obligations have been implemented several times throughout Argentina’s history.
Nevertheless, with the passing of Section IV of Law No.27,742, said policy goal was abandoned and replaced with a new primary objective for local hydrocarbons regulations to maximize investments and the income obtained from the exploitation of hydrocarbon resources.
By means of the Necessity and Urgency Decree (“DNU”) No. 70/2023, article 609 of Law No. 22,415 was replaced, establishing that the Federal Executive Branch may not establish prohibitions or restrictions to exports or imports for economic reasons and may only be established by Law.
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Exports of crude oil, as well as the export of most hydrocarbon products, are permitted provided the lack of objections from the Energy Secretariat in accordance with the regulations issued by the Executive Branch, which must consider (i) the usual requirements related to the access of technically proven resources; and (ii) that the eventual objection of the Energy Secretariat may only be formulated within thirty (30) days of the exports to be made known to it, and must be based on technical or economic reasons related to the security of supply.
Hydrocarbon Exploitation Concessions Terms
With regards to hydrocarbons concessions, three types of exploitation concessions are provided: (i) 25-years conventional concessions; (ii) 35-years unconventional hydrocarbon concessions and (iii) 30-years offshore concessions.
With regards to royalties, 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.
As a result of the privatization of YPF and Gas del Estado, a few common carriers of crude oil and natural gas were chartered and continue to operate to date. Effective February 8, 2019, and with the aim to promote transportation capacity expansions, Decree No. 115/2019 allowed interested shippers to reserve transportation capacity in new or expanded pipelines through freely negotiated capacity reservation agreements.
Taxation
Exploitation concessionaires are subject to the general federal and provincial tax regime. The most relevant federal taxes are the income tax (35%), the value-added tax (21%) and financial transactions tax (1.2%). The most relevant provincial taxes are the turnover tax (3% on average) and stamp tax. Corporate income tax rate may range from 25% to 35% on bands of income that can be adjusted annually.
Since May 2020, export duties are exempted as long as the international Brent price is equal to or lower than US$45/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/bbl (as per DNU No. 488/20). During 2023, the rate remained at 8%. On June 2, 2021, the National Congress enacted Law No. 27,630, amending the Income Tax Law, which established new tax rates applicable to corporations of 25%, 30% and 35%, respectively, depending on the net taxable income obtained in each tax period. These amendments are effective for fiscal years beginning on January 1, 2021. Also, the aforementioned law maintains the 7%
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tax rate on dividends paid to individuals. Subsequently, by means of Law No. 27,702, the Income Tax, Personal Property Tax and Tax on Debits and Credits in Bank Accounts are extended until December 31, 2027. These amendments are effective for fiscal years beginning on or after January 1, 2021, inclusive.
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:
● | Interest and expense deductions: issuers can deduct accrued interest, updates, and issuance and placement expenses from their income tax base. |
● | VAT exemption: financial transactions related to the issuance, subscription, transfer, redemption, and interest on ONs are exempt from VAT. |
● | Stamp tax exemption: issuance, subscription, and transfer of ONs under the public offering regime are exempt from stamp tax. |
For subscribers:
● | Domestic legal entities: capital gains and interest are subject to income tax and turnover tax. |
● | Individuals: domestic individuals are exempt from income and turnover tax on interest and capital gains. |
● | Foreign investors: foreign individuals and entities are not subject to income tax or turnover tax on income or capital gains from ONs. |
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 obtain approval from 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 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.
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Environmental
Hydrocarbon operations are subject to concurrent national and provincial environmental statutes and regulations, and to the concurrent jurisdiction of national and provincial environmental and hydrocarbon enforcement authorities. The different hydrocarbon producing provincial states have enacted and 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.
C. Organizational structure
We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 21 (“Subsidiary undertakings”) to our Consolidated Financial Statements.
D. Property, plant and equipment
See “—B. Business Overview—Title to properties.”
ITEM 4A. UNRESOLVED STAFF COMMENTS
Not applicable.
ITEM 5. OPERATING AND FINANCIAL REVIEW AND PROSPECTS
A. Operating results
The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto.
The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking statements.”
Factors affecting our results of operations
We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following:
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
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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 five-year period from March 1, 2020, to February 28, 2025, 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 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 Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles the Oriente crude reference price.
In Brazil, prices for gas produced in the Manati field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in reais and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Índice Geral de Preços—Mercado) (the “IGPM”).
We seek to partially mitigate our exposure to crude oil price volatility using derivatives by hedging a portion of our production for a limited period going forward. We use a combination of options to manage our production’s exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. For further information related to Commodity Risk Management Contracts, please see Note 8 to our Consolidated Financial Statements.
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$24.8 million (US$32.3 million in 2023).
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 occurred from 2023 and onwards due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. We have historically not hedged our costs to protect against fluctuations.
Availability and reliability of infrastructure
Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.”
Production levels
Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and oil and natural gas prices.
We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.”
Contractual obligations
In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P contracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our 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, production sharing agreements and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.”
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 May 2024, we entered into a farm-out agreement for the acquisition of non-operated working interests in four adjacent unconventional blocks in the world-class Vaca Muerta shale formation in the Neuquén Basin in Argentina. Closing of the transaction is pending customary regulatory approvals from the respective provincial governments. The
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acquired assets and liabilities, and the results from operations, will be consolidated within our financial information from closing date and onwards. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina (Vaca Muerta).”
Functional and presentational currency
Our Consolidated Financial Statements are presented in US$, which is our presentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is the real.
Geographical segment reporting
In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non-Ecuadorian, non-Brazilian, non-Chilean and non-Argentine operations, primarily consisting of our corporate head office operations.
As of December 31, 2024, we divided our business into five geographical segments—Colombia, Ecuador, Brazil, Chile (including results until its divestment in January 2024) and Argentina—that corresponded to our principal jurisdictions of operation. Activities not falling into these five geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment.
Description of principal line items
The following is a brief description of the principal line items of our consolidated statement of income.
Revenue
Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically transferred into a 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
Included realized and unrealized gains and losses arising from commodity risk management contracts that were accounted for as non-hedge derivatives.
The derivatives that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were accounted for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were recognized immediately as gains or losses in the results of the periods in which they occur as part of the Commodity risk management contracts line item in the Consolidated Statement of Income.
The derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, and onwards are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the Revenue line item in the Consolidated Statement of Income.
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Production and operating costs
Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, royalties and economic rights in cash are also included within this account. For a description of our production and operating costs, see “—Factors affecting our results of operations.”
Depreciation
Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content.
Geological and geophysical expenses
Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies.
Administrative expenses
Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions.
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 2024, we recognized write-off of unsuccessful exploration efforts of US$14.8 million (US$29.6 million in 2023). See Note 19 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.
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During 2024, no impairment losses were recognized or reversed. We recognized a net impairment loss of US$13.3 million in the Fell Block in 2023, due to the known selling price of the related net assets in the context of the divestment transaction of the Chilean business. See Note 35.3 to our Consolidated Financial Statements.
Financial results
Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses.
Recent accounting pronouncements
See Note 2.1.1 to our Consolidated Financial Statements.
Results of operations
The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes.
In preparation for continued volatility, we have developed a capital expenditure program for 2025 which is subject to change as a result of market conditions, developments regarding our business, results of operations and financial condition, and other factors. See “Item 4. Information on the Company—B. Business Overview—2025 Strategy and Outlook.”
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Year ended December 31, 2024, compared to year ended December 31, 2023
The following table summarizes certain of our financial and operating data for the years ended December 31, 2024 and 2023.
For the year ended December 31, |
| ||||||
% Change from |
| ||||||
| 2024 |
| 2023 |
| prior year | ||
(in thousands of US$, except for percentages) |
| ||||||
Revenue | |||||||
Sale of crude oil | 648,670 | 726,947 | (11) | % | |||
Sale of purchased crude oil | 7,177 | 5,464 | 31 | % | |||
Sale of gas | 5,076 | 25,024 | (80) | % | |||
Commodity risk management contracts designated as cash flow hedges | (85) | (810) | (90) | % | |||
Revenue | 660,838 | 756,625 | (13) | % | |||
Production and operating costs | (164,034) | (232,325) | (29) | % | |||
Geological and geophysical expenses | (12,595) | (11,192) | 13 | % | |||
Administrative expenses | (49,534) | (43,969) | 13 | % | |||
Selling expenses | (14,914) | (13,084) | 14 | % | |||
Depreciation | (130,659) | (120,934) | 8 | % | |||
Write-off of unsuccessful exploration efforts | (14,779) | (29,563) | (50) | % | |||
Impairment loss recognized for non-financial assets | — | (13,332) | (100) | % | |||
Other expenses | (777) | (21,319) | (96) | % | |||
Operating profit | 273,546 | 270,907 | 1 | % | |||
Financial expenses | (51,551) | (45,815) | 13 | % | |||
Financial income | 8,016 | 6,237 | 29 | % | |||
Foreign exchange gain (loss) | 12,160 | (16,820) | (172) | % | |||
Profit before income tax | 242,171 | 214,509 | 13 | % | |||
Income tax expense | (145,792) | (103,441) | 41 | % | |||
Profit for the year | 96,379 | 111,068 | (13) | % | |||
Net production volumes | |||||||
Oil (mbbl)(2) | 12,277 | 12,395 | (1) | % | |||
Gas (mcf)(3) | 864 | 5,705 | (85) | % | |||
Total net production (mboe) | 12,421 | 13,345 | (7) | % | |||
Average net production (boepd) | 33,937 | 36,563 | (7) | % | |||
Average realized sales price | |||||||
Oil (US$ per bbl) | 66.0 | 67.0 | (1) | % | |||
Gas (US$ per mmcf) | 5.9 | 4.6 | 28 | % | |||
Average unit costs per boe (US$) | |||||||
Operating cost | 15.2 | 12.5 | 22 | % | |||
Royalties and economic rights in cash | 1.1 | 7.2 | (85) | % | |||
Production costs(1) | 16.3 | 19.6 | (17) | % | |||
Geological and geophysical expenses | 1.3 | 0.9 | 32 | % | |||
Administrative expenses | 4.9 | 3.7 | 32 | % | |||
Selling expenses | 1.5 | 1.1 | 34 | % |
(1) | Calculated pursuant to FASB ASC 932. |
(2) | We present production figures before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. Oil production figures presented on page F-74 are net of royalties, economic rights and government’s production share. |
(3) | Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page F-75 is gas measured at the point of delivery. |
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The following table summarizes certain financial data.
For the year ended December 31, | ||||||||||||||||||||||||||||
2024 | 2023 | |||||||||||||||||||||||||||
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Other |
| Total |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Other |
| Total | |
(in thousands of US$) | ||||||||||||||||||||||||||||
Revenue | 619,762 | 30,567 | 2,934 | 398 | — | 7,177 |
| 660,838 |
| 702,401 | 19,097 | 14,019 | 15,644 | — | 5,464 |
| 756,625 | |||||||||||
Depreciation | (121,143) | (8,290) | (1,214) | — | (10) | (2) |
| (130,659) |
| (101,666) | (7,096) | (2,332) | (9,815) | (22) | (3) |
| (120,934) | |||||||||||
Impairment and write-off | (6,909) | (7,714) | (156) | — | — | — |
| (14,779) |
| (29,563) | — | — | (13,332) | — | — |
| (42,895) |
Revenue
For the year ended December 31, 2024, crude oil sales remained our principal source of revenue, accounting for 98% of our total revenue, followed by purchased crude oil sales of 1% and gas sales of 1%. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2023, to the year ended December 31, 2024.
For the year ended | ||||
December 31, | ||||
| 2024 |
| 2023 | |
(in thousands of US$) | ||||
Consolidated | ||||
Sale of crude oil | 648,670 | 726,947 | ||
Sale of purchased crude oil | 7,177 | 5,464 | ||
Sale of gas | 5,076 | 25,024 | ||
Commodity risk management contracts designated as cash flow hedges | (85) | (810) | ||
Total | 660,838 | 756,625 |
Year ended December 31, | Change from prior year |
| |||||||
| 2024 |
| 2023 |
|
| % |
| ||
(in thousands of US$, except for percentages) | |||||||||
By country | |||||||||
Colombia | 619,762 | 702,401 | (82,639) | (12) | % | ||||
Ecuador | 30,567 | 19,097 | 11,470 | 60 | % | ||||
Brazil | 2,934 | 14,019 | (11,085) | (79) | % | ||||
Chile | 398 | 15,644 | (15,246) | (97) | % | ||||
Other | 7,177 | 5,464 | 1,713 | 31 | % | ||||
Total | 660,838 | 756,625 | (95,787) | (13) | % |
Revenue decreased 13%, from US$756.6 million for the year ended December 31, 2023, to US$660.8 million for the year ended December 31, 2024. This decline was primarily driven by lower sales volumes during the year. Specifically, sales of crude oil decreased due to a reduction in sold volumes —from 10.8 mmbbl in 2023 to 9.8 mmbbl in 2024— resulting in net oil revenue of US$648.7 million for the year ended December 31, 2024, compared to US$726.9 million for the year ended December 31, 2023. Sales of gas also declined significantly, from US$25.0 million for the year ended December 31, 2023, to US$5.1 million for the year ended December 31, 2024, primarily due to lower natural gas deliveries in Brazil and Chile (following the suspended production in the Manati gas field in Brazil and the divestment of our Chilean operations in January 2024).
The US$95.8 million decrease in total net revenue is explained by i) a decrease of US$82.6 million in Colombia (largely due to lower oil deliveries); ii) an increase of US$11.5 million in Ecuador (driven by higher oil deliveries); iii) a decrease of US$11.1 million in Brazil (resulting from lower gas deliveries); iv) a decrease of US$15.2 million in Chile (following the divestment of operations in January 2024); and v) an increase of US$1.7 million (from the trading activities of the holding company, GeoPark Limited).
Revenue from our Colombian operations for the year ended December 31, 2024, was US$619.8 million, representing 93.8% of our total consolidated sales, compared to US$702.4 million for the year ended December 31, 2023 (92.8% of
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total consolidated sales). The decrease was primarily due to lower oil deliveries (from 10.5 mmbbl in 2023 to 9.4 mmbbl in 2024), impacted by higher royalties and economic rights paid “in kind” (which affect the quantity of oil available for sale) as compared to royalties and economic rights paid “in cash”, as well as the natural production decline in the Llanos 34 Block and operational disruptions caused by blockades in the Llanos 34 and the CPO-5 Blocks.
Revenue from Ecuador for the year ended December 31, 2024, was US$30.6 million, a 60% increase from US$19.1 for the year ended December 31, 2023. This growth was driven by higher oil deliveries (from 0.27 mmboe in 2023 to 0.44 mmboe in 2024), largely as a result of the successful drilling campaign in the Perico Block. The contribution of Ecuador to our total revenue rose from 2.5% in 2023 to 4.6% in 2024.
Revenue from Brazilian operations for the year ended December 31, 2024, was US$2.9 million, a 79% decrease from US$14.0 million for the year ended December 31, 2023. This decrease was due to significantly reduced gas deliveries (from 0.35 mmboe in 2023 to 0.08 mmboe in 2024), as production at the non-operated Manati gas field was temporarily suspended for unscheduled maintenance from mid-March 2024. The share of total revenue from Brazil dropped from 1.9% in 2023 to 0.4% in 2024.
Revenue from Chile for the year ended December 31, 2024, was US$0.4 million, compared to US$15.6 million for the year ended December 31, 2023, following the divestment of operations in January 2024. Consequently, Chile’s contribution to total revenue decreased from 2.1% in 2023 to 0.1% in 2024.
Revenue from the trading activities performed by our holding company, GeoPark Limited, for the year ended December 31, 2024, was US$7.2 million, compared to US$5.5 million for the year ended December 31, 2023. This represented 1.1% of total revenue in 2024, up from 0.7% in 2023.
Production and operating costs
The following table summarizes our production and operating costs for the years ended December 31, 2024 and 2023.
For the year ended December 31, | |||||||
% Change | |||||||
| 2024 |
| 2023 |
| from prior year | ||
(in thousands of US$, except for percentages) | |||||||
Consolidated (including Colombia, Ecuador, Brazil, Chile and Other) | |||||||
Royalties in cash | (4,189) | (12,845) | (67) | % | |||
Economic rights in cash | (6,484) | (72,032) | (91) | % | |||
Staff costs and share-based payments | (16,344) | (14,639) | 12 | % | |||
Well and facilities maintenance | (25,631) | (26,089) | (2) | % | |||
Operation and maintenance | (8,936) | (8,143) | 10 | % | |||
Consumables | (36,868) | (37,556) | (2) | % | |||
Equipment rental | (5,716) | (4,314) | 32 | % | |||
Transportation costs | (5,409) | (5,850) | (8) | % | |||
Field camp | (6,401) | (6,546) | (2) | % | |||
Safety and insurance costs | (4,937) | (5,487) | (10) | % | |||
Personnel transportation | (3,586) | (3,363) | 7 | % | |||
Consultant fees | (3,893) | (2,291) | 70 | % | |||
Gas plant costs | (1,753) | (1,865) | (6) | % | |||
Non-operated blocks costs | (22,305) | (20,421) | 9 | % | |||
Crude oil stock variation | (976) | (2,004) | (51) | % | |||
Purchased crude oil | (6,274) | (4,666) | 34 | % | |||
Other costs | (4,332) | (4,214) | 3 | % | |||
Total | (164,034) | (232,325) | (29) | % |
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Year ended December 31, | ||||||||||||||||||||
2024 | 2023 | |||||||||||||||||||
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Other |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Other | |
(in thousands of US$) | ||||||||||||||||||||
By country | ||||||||||||||||||||
Royalties in cash | (3,953) | — | (224) | (12) | — | (11,201) | — | (1,096) | (548) | — | ||||||||||
Economic rights in cash | (6,484) | — | — | — | — | (72,032) | — | — | — | — | ||||||||||
Staff costs and share-based payments | (16,337) | (5) | (2) | — | — | (12,006) | (30) | (2) | (2,601) | — | ||||||||||
Well and facilities maintenance | (23,524) | — | (1,764) | (343) | — | (23,280) | (2) | (1,439) | (1,368) | — | ||||||||||
Operation and maintenance | (8,747) | (189) | — | — | — | (8,143) | — | — | — | — | ||||||||||
Consumables | (36,502) | (318) | — | (48) | — | (36,078) | (121) | — | (1,357) | — | ||||||||||
Equipment rental | (5,138) | (578) | — | — | — | (3,461) | (838) | — | (15) | — | ||||||||||
Transportation costs | (5,359) | (55) | — | 5 | — | (5,145) | (73) | — | (632) | — | ||||||||||
Field camp | (6,369) | (30) | — | (2) | — | (5,761) | (9) | — | (776) | — | ||||||||||
Safety and insurance costs | (4,742) | (2) | (187) | (6) | — | (5,075) | (45) | (183) | (184) | — | ||||||||||
Personnel transportation | (3,556) | (17) | — | (13) | — | (3,211) | (45) | — | (107) | — | ||||||||||
Consultant fees | (3,778) | — | (37) | (78) | — | (2,241) | (42) | (8) | — | — | ||||||||||
Gas plant costs | (138) | — | (1,615) | — | — | (131) | — | (1,734) | — | — | ||||||||||
Non-operated blocks costs | (14,515) | (7,678) | (112) | — | — | (12,168) | (8,145) | (108) | — | — | ||||||||||
Crude oil stock variation | (357) | (619) | — | — | — | (1,012) | (891) | — | (101) | — | ||||||||||
Purchased crude oil | — | — | — | — | (6,274) | — | — | — | — | (4,666) | ||||||||||
Other costs | (4,135) | (58) | (199) | 60 | — | (3,301) | — | (376) | (537) | — | ||||||||||
Total | (143,634) | (9,549) | (4,140) | (437) | (6,274) | (204,246) | (10,241) | (4,946) | (8,226) | (4,666) |
Consolidated production and operating costs decreased 29%, from US$232.3 million for the year ended December 31, 2023, to US$164.0 million for the year ended December 31, 2024, primarily due to a decrease in royalties and economic rights paid in-cash.
Production and operating costs in Colombia decreased by 30%, to US$143.6 million for the year ended December 31, 2024, as compared to US$204.2 million for the year ended December 31, 2023, primarily due to lower royalties and economic rights which decreased by US$72.8 million, mainly due to a decrease in the mix of royalties and economic rights paid “in-cash” as compared to royalties and economic rights paid “in-kind”. This change caused variations in the ‘royalties in cash’ and ‘economic rights in cash’ line items from year to year, which are compensated for variations in the quantities of oil sales impacting the ‘revenue’ line item in the Consolidated Statement of Income. The decrease is partially offset by other factors such as inflationary pressures and the revaluation of the local currency in Colombia, affecting costs denominated in such local currency.
Production and operating costs in Ecuador were US$9.5 million for the year ended December 31, 2024, compared to US$10.2 million the year ended December 31, 2023, not showing significant variation from year to year.
Production and operating costs in Brazil decreased by 16%, to US$4.1 million for the year ended December 31, 2024, as compared to the year ended December 31, 2023, mainly resulting from lower royalties due to the suspended production in the Manati gas field.
Production and operating costs in Chile decreased by 95% to US$0.4 million due to its divestment in January 2024.
Purchases of crude oil for the trading operation performed by the holding company, GeoPark Limited, amounted to US$6.3 million and US$4.7 million for the years ended December 31, 2024, and 2023, respectively.
Geological and geophysical expenses
Geological and geophysical expenses increased by 13%, from US$11.2 million for the year ended December 31, 2023, to US$12.6 million for the year ended December 31, 2024, as the result of higher exploratory activities.
Administrative costs
Administrative costs increased by 13%, from US$44.0 million for the year ended December 31, 2023, to US$49.5 million for the year ended December 31, 2024, as the result of one-off expenses related to organizational structure
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optimization including severances and hiring bonuses, advisory services related to new business efforts including the acquisition in Argentina (“Vaca Muerta”) and the proposed acquisition of certain Repsol exploration and production assets in Colombia (detailed in Notes 35.1 and 35.2 to our Consolidated Financial Statements), and the impact of higher activity on the overhead billed by the operator in the Perico and Llanos 32 Blocks in Ecuador and Colombia, respectively.
Selling expenses
Year ended December 31, | Change from prior year | ||||||||
| 2024 |
| 2023 |
|
| % | |||
(in thousands of US$, except for percentages) | |||||||||
Colombia | (11,840) | (10,976) | (864) | 8 | % | ||||
Ecuador | (3,074) | (1,850) | (1,224) | 66 | % | ||||
Chile | — | (258) | 258 | (100) | % | ||||
Argentina | — | — | — | — | % | ||||
Total | (14,914) | (13,084) | (1,830) | 14 | % |
Selling expenses increased by 14%, from US$13.1 million for year ended December 31, 2023, to US$14.9 million for the year ended December 31, 2024, primarily due to higher deliveries in the Perico Block in Ecuador and deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses.
Depreciation
Year ended December 31, | Change from prior year |
| |||||||
| 2024 |
| 2023 |
|
| % |
| ||
(in thousands of US$, except for percentages) |
| ||||||||
Colombia | (121,143) | (101,666) | (19,477) | 19 | % | ||||
Ecuador | (8,290) | (7,096) | (1,194) | 17 | % | ||||
Brazil | (1,214) | (2,332) | 1,118 | (48) | % | ||||
Chile | — | (9,815) | 9,815 | (100) | % | ||||
Argentina | (10) | (22) | 12 | (55) | % | ||||
Other | (2) | (3) | 1 | (33) | % | ||||
Total | (130,659) | (120,934) | (9,725) | 8 | % |
Depreciation charges increased by 8% from US$120.9 million for the year ended December 31, 2023, to US$130.7 million for the year ended December 31, 2024, primarily due to an increase in the depreciation cost per boe in the CPO-5 Block in Colombia as a consequence of higher capitalized costs at the end of 2023 and lower proved and probable reserves at the end of 2024, as well as higher production sold in the Llanos 123 and Perico Blocks in Colombia and Ecuador, respectively, partially offset by the divestment of the Chilean business in January 2024 and the suspended production in the Manati gas field in Brazil since mid-March 2024.
Operating profit
Year ended December 31, | Change from prior year |
| |||||||
| 2024 |
| 2023 |
|
| % |
| ||
(in thousands of US$, except for percentages) |
| ||||||||
Colombia | 298,158 | 321,512 | (23,354) | (7) | % | ||||
Ecuador | (1,102) | (1,912) | 810 | (42) | % | ||||
Brazil | (7,159) | 4,514 | (11,673) | (259) | % | ||||
Chile | (116) | (21,878) | 21,762 | (99) | % | ||||
Argentina | (5,052) | (11,189) | 6,137 | (55) | % | ||||
Other | (11,183) | (20,140) | 8,957 | (44) | % | ||||
Total | 273,546 | 270,907 | 2,639 | 1 | % |
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We recorded an operating profit of US$273.5 million for the year ended December 31, 2024, compared to US$270.9 million for the year ended December 31, 2023, as a result of the reasons described above.
In 2024, we recorded write-off of unsuccessful exploration efforts of US$14.8 million that corresponded to two exploratory wells drilled in the CPO-5 Block (Colombia), and two exploratory wells drilled in the Espejo Block (Ecuador).
In 2023, we recorded write-off of unsuccessful exploration efforts of US$29.6 million that corresponded to three exploratory wells drilled in the Llanos 87 Block (Colombia), an exploratory well drilled in the Llanos 124 Block (Colombia) and other exploration costs incurred in the Llanos 94, Coati and Llanos 124 Blocks (Colombia).
During 2023, we also recognized an impairment loss of US$13.3 million in the Fell Block due to the known selling price of the related net assets in the context of the divestment transaction of the Chilean business. In addition, we recorded termination and other costs incurred from the divestment process in Chile, including a provision for investment commitments maintained by GeoPark after the transaction, for a total amount of US$9.7 million, together with the amount paid for transferring the working interest in the Los Parlamentos Block in Argentina to the joint operation partner of US$7.0 million.
Financial results
Net financial expense was US$43.5 million for the year ended December 31, 2024, compared to US$39.6 million for the year ended December 31, 2023. The variation mainly corresponds to costs related to the financing required for the proposed acquisition of certain Repsol exploration and production assets in Colombia and the offtake and prepayment agreements with Vitol and Trafigura. For further information about these transactions, please see “Item 4. Information on the Company—B. Business Overview—Proposed Acquisition of Certain Repsol Exploration and Production Assets in Colombia” and “Item 4. Information on the Company—A. History and development of the company—Funding”, respectively.
Foreign exchange gain (loss)
Foreign exchange difference was a gain of US$12.2 million for the year ended December 31, 2024, compared to a loss of US$16.8 million for the year ended December 31, 2023. The results in both years mainly correspond to the effect of the fluctuation of the local currency in Colombia on the liabilities held in that currency, such as the income tax payable, the provision for asset retirement obligation and other environmental liabilities, and the lease liabilities. The Colombian Peso devalued by 15% in 2024 and revalued by 21% in 2023.
Profit before income tax
Year ended December 31, | Change from prior year | ||||||||
| 2024 |
| 2023 |
|
| % | |||
(in thousands of US$, except for percentages) | |||||||||
Colombia | 302,277 | 287,243 | 15,034 | 5 | % | ||||
Ecuador | (1,506) | (3,188) | 1,682 | (53) | % | ||||
Brazil | (9,620) | 5,504 | (15,124) | (275) | % | ||||
Chile | (82) | (23,462) | 23,380 | (100) | % | ||||
Argentina | (4,202) | (6,933) | 2,731 | (39) | % | ||||
Other | (44,696) | (44,655) | (41) | 0 | % | ||||
Total | 242,171 | 214,509 | 27,662 | 13 | % |
For the year ended December 31, 2024, we recorded a profit before income tax of US$242.2 million, compared to a profit of US$214.5 million for the year ended December 31, 2023, primarily due to the reasons mentioned above.
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Income tax expense
Year ended December 31, | Change from prior year | ||||||||
| 2024 |
| 2023 |
|
| % | |||
(in thousands of US$, except for percentages) | |||||||||
Colombia | (141,525) | (96,770) | (44,755) | 46 | % | ||||
Ecuador | (2,686) | 198 | (2,884) | (1,457) | % | ||||
Brazil | (246) | (396) | 150 | (38) | % | ||||
Chile | — | (3,878) | 3,878 | (100) | % | ||||
Other | (1,335) | (2,595) | 1,260 | (49) | % | ||||
Total | (145,792) | (103,441) | (42,351) | 41 | % |
Our consolidated effective tax rate was 60% for the year ended December 31, 2024, compared to 48% in 2023. The increase in the effective tax rate was primarily due to the effect of the devaluation of the local currency in Colombia on the tax bases of property, plant and equipment, as well as tax losses that were non-deductible for being incurred in non-taxable jurisdictions or entities (mainly Bermuda and the Espejo Consortium in Ecuador). Current effective tax rate was 45% for the year ended December 31, 2024, compared to 50% in 2023, reflecting tax efficiencies; while the abovementioned effect of the devaluation of the local currency in Colombia on the tax bases of property, plant and equipment affected deferred effective tax rate.
In 2024 and 2023, 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 2024 and 2023 was 10%.
Profit for the year
Year ended December 31, | Change from prior year |
| |||||||
| 2024 |
| 2023 |
|
| % |
| ||
(in thousands of US$, except for percentages) |
| ||||||||
Colombia | 160,752 | 190,473 | (29,721) | (16) | % | ||||
Ecuador | (4,192) | (2,990) | (1,202) | 40 | % | ||||
Brazil | (9,866) | 5,108 | (14,974) | (293) | % | ||||
Chile | (82) | (27,340) | 27,258 | (100) | % | ||||
Argentina | (4,202) | (6,933) | 2,731 | (39) | % | ||||
Other | (46,031) | (47,250) | 1,219 | (3) | % | ||||
Total | 96,379 | 111,068 | (14,689) | (13) | % |
For the year ended December 31, 2024, we recorded a net profit of US$96.4 million as a result of the reasons described above, compared to a net profit of US$111.1 million for the year ended December 31, 2023.
Year ended December 31, 2023, compared to year ended December 31, 2022
For a discussion of the results of our operations for the year ended December 31, 2023, compared to the year ended December 31, 2022, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2023, compared to the year ended December 31, 2022” in our Annual Report on Form 20-F for the year ended December 31, 2023.
B. Liquidity and capital resources
Overview
Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including:
● | changes in oil and natural gas prices and our ability to generate cash flows from our operations; |
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● | our capital expenditure requirements; |
● | the level of our outstanding indebtedness and the interest we have to pay on this indebtedness; and |
● | changes in exchange rates which will impact our generation of cash flows from operations when measured in US$. |
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 2025 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—2025 Strategy and Outlook.”
Capital expenditures
In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview—2025 Strategy and Outlook”.
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, US$24.1 million and US$0.2 million, in Colombia, Ecuador and Brazil, respectively).
In the year ended December 31, 2023, we had total capital expenditures related to the purchase of property, plant and equipment of US$199.0 million (US$178.1 million and US$20.9 million in Colombia and Ecuador, respectively).
We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects. We expect to incur capital expenditures ranging from US$275.0 million to US$310.0 million during 2025 (including amounts we expect to spend at Vaca Muerta after the closing of the acquisition), of which approximately 70% will be allocated to Argentina and approximately 30% to Colombia, with a target to drill 23 to 31 gross wells plus infrastructure and facilities. Our 2025 work plan considers approximately 65% to be allocated to development and approximately 35% to be allocated to exploration and appraisal activities. This expected allocation of capital expenditures is subject to change as a result of market conditions, developments regarding our business, results of operation and financial condition, and other factors.
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Cash flows
The following table sets forth our cash flows for the periods indicated:
Year ended December 31, | ||||||
| 2024 |
| 2023 |
| 2022 | |
(in thousands of US$) | ||||||
Cash flows from (used in) | ||||||
Operating activities | 471,031 | 300,938 | 467,471 | |||
Investing activities | (226,855) | (198,590) | (153,673) | |||
Financing activities | (99,240) | (98,721) | (286,552) | |||
Net increase (decrease) in cash and cash equivalents | 144,936 | 3,627 | 27,246 |
Cash flows from operating activities
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.
For the year ended December 31, 2023, cash flows from operating activities were US$300.9 million, a 36% decrease from US$467.5 million for the year ended December 31, 2022, mainly resulting from the decrease in revenues reflecting lower oil and gas prices in 2023.
Cash flows used in investing activities
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 Argentina (Vaca Muerta) acquisition in May 2024.
For the year ended December 31, 2023, cash flows used in investing activities were US$198.6 million, a 29% increase from US$153.7 million for the year ended December 31, 2022. This variation is primarily explained by an increase of US$30.2 million in capital expenditures related to the purchase of property, plant and equipment.
Cash flows used in financing activities
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.
Cash flows used in financing activities were US$98.7 million for the year ended December 31, 2023, compared to US$286.6 million used in financing activities for the year ended December 31, 2022. This variation was mainly related to the repayment of financial debt during 2022.
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Indebtedness
As of December 31, 2024, and 2023, we had total outstanding indebtedness of US$514.3 million and US$501.0 million, respectively, as set forth in the table below.
As of December 31, | ||||
| 2024 |
| 2023 | |
(in thousands of US$) | ||||
Notes due 2027 | 504,535 | 500,981 | ||
Promissory note | 9,798 | — | ||
Total | 514,333 | 500,981 |
Our material outstanding indebtedness as of December 31, 2024 is described below.
Notes due 2027
General
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, after the balance sheet date, we repurchased a portion of our Notes due 2027 for a nominal amount of US$405.3 million though a concurrent tender offer. For further information about the partial repayment of the Notes due 2027, please refer to Note 37.1 to our Consolidated Financial Statements.
Ranking
The Notes due 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U. (the “Guarantor”). The Notes due 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantor (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantor; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantor and their respective subsidiaries to the extent of the value of the collateral securing such obligations.
Optional redemption
We may, at our option, redeem all or part of the Notes due 2027, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 17 of the years indicated below:
Year |
| Percentage |
|
2024 | 102.750 | % | |
2025 | 101.375 | % | |
2026 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 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.
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Covenants
The Notes due 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company.
In the event the Notes due 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable.
The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to 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
Events of default under the indentures governing the Notes due 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2027 to become or to be declared due and payable.
Promissory note
On December 3, 2024, our local subsidiary in Argentina 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 is 3% per annum and final maturity will be July 3, 2025.
Off-balance sheet arrangements
We did not have any off-balance sheet arrangements as of December 31, 2024, or as of December 31, 2023.
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—2025 Strategy and Outlook.”
E. Critical accounting policies and estimates
Not applicable.
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ITEM 6. DIRECTORS, SENIOR MANAGEMENT AND EMPLOYEES
A.Directors and executive officers
Board of directors
Our board of directors is currently composed of nine members. Our directors are elected by shareholders annually at the Company’s annual general meeting and can hold office for such term as the shareholders may determine or, in the absence of such determination, until the next annual general meeting or until their successors are elected or appointed or their office is otherwise vacated. The term for the current directors expires on the date of our next annual general meeting of shareholders to be held in 2025.
The current members of the board of directors were appointed at our annual general meeting held on July 24, 2024. The table below sets forth certain information concerning our current board of directors. All ages are current as of April 2, 2025.
|
|
| At the Company | |||
Name | Position | Age | since | |||
Sylvia Escovar Gómez (1)(2) | Chair and Director | 63 | 2020 | |||
James F. Park | Deputy Chair, Director and Co-founder | 69 | 2002 | |||
Robert Bedingfield (1)(2) | Director | 76 | 2015 | |||
Constantin Papadimitriou (1)(2) | Director | 64 | 2018 | |||
Somit Varma (1)(2) | Director | 64 | 2020 | |||
Brian F. Maxted (1) | Director | 67 | 2022 | |||
Carlos E. Macellari | Director | 71 | 2022 | |||
Marcela Vaca | Director | 56 | 2012 | |||
Andrés Ocampo | Chief Executive Officer and Director | 47 | 2010 |
(1) | Independent director under SEC Audit Committee rules. |
(2) | Member of the Audit Committee. |
Biographical information of the current members of our board of directors is set forth below. Unless otherwise indicated, the current business address for our directors is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Sylvia Escovar Gómez has been a member of our board of directors since August 2020 and was appointed as Chair on June 6, 2021. An economist by training, she received her undergraduate degree from the Universidad de Los Andes in Colombia. She has had a long and prestigious career in both the public and private sectors, having worked for the World Bank, the Central Bank of Colombia and the Colombian National Department of Planning. Previously, she served as Deputy Secretary of Education and Deputy Secretary of Finance for Bogota’s government as well as Vice President of Finance of Fiduciaria Bancolombia. Ms. Escovar was the CEO of Terpel S.A., a fuel distribution company that operates in Colombia, Ecuador, Panama, Peru and the Dominican Republic from 2012 until December 2020. In 2014, Ms. Escovar was named the top businessperson of the year by Portafolio, Colombia’s leading financial daily. In 2018, she received the National Order of Merit for spearheading private sector support for peacebuilding and reconciliation in Colombia. In 2020, she was the only woman on the Corporate Reputation Business Monitor’s list of Colombian leaders with the best reputation to rank in the top 10. In 2023, Forbes named Sylvia Escovar as one of the 100 most powerful women in Colombia. Ms. Escovar’s other Board memberships include Grupo Bancolombia, Empresa de Telecomunicaciones de Bogotá, Organización Corona S.A., Organización Terpel and Grupo Energía Bogotá.
James F. Park since co-founding the Company in 2002, has served for 20 years as our Chief Executive Officer until his retirement effective June 30, 2022. He initially 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 and advisor to the team. Beginning as a drilling rig roughneck in his teenage years, Mr. Park has more than 50 years of experience in all phases of the upstream oil and gas business, with a record of achievement in the acquisition, technical operation, and
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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 - and with a successful emphasis on people, communities, and the environment. He earned a Bachelor of Science in Geophysics from the University of California at Berkeley and previously worked as a research scientist focused on earthquakes and tectonics at the University of Texas. Mr. Park is a member of the board of directors of GoodRock LLC, Spark Resources LLC and Rocabuena S.A.S., and is a former Board member of the humanitarian non-profit SEE (Surgical Eye Expeditions) International, and the service and advocacy non-profit Girls, Inc. He is a member of the AAPG and SPE, has a degree in environmental management, and has lived in Latin America since 2002.
Robert Bedingfield has been a member of our board of directors since March 2015. He holds a degree in Accounting from the University of Maryland and is a Certified Public Accountant. Until his retirement in June 2013, he was one of Ernst & Young’s most senior Global Lead Partners with more than 40 years of experience, including 32 years as a partner in Ernst & Young’s accounting and auditing practices, as well as serving on Ernst & Young’s Senior Governing Board. He has extensive experience serving Fortune 500 companies; including acting as Lead Audit Partner or Senior Advisory Partner for Lockheed Martin, AES, Gannett, General Dynamics, Booz Allen Hamilton, Marriott and the US Postal Service. Since 2000, Mr. Bedingfield has been a Trustee, and at times an Executive Committee Member, and the Audit Committee Chair of the University of Maryland at College Park Board of Trustees. Mr. Bedingfield served on the National Executive Board (1995 to 2003) and National Advisory Council (since 2003) of the Boy Scouts of America. From 2013 to 2023, Mr. Bedingfield served as Board Member and Chairman of the Audit Committee of NYSE-listed Science Applications International Corp (SAIC). Mr. Bedingfield became age ineligible to serve on SAIC’s board on June 7, 2023.
Constantin Papadimitriou has been a member of our board of directors since May 2018. He is a respected and successful international investor and businessman, with more than 30 years of investment experience in global capital markets and in resource and industrial projects and was an early investor in GeoPark. Mr. Papadimitriou was for 18 years the Head of General Oriental Investments S.A., the Investment Manager of the Cavenham Funds, as part of the Cavamont Group founded by the Late Sir James Goldsmith. During his tenure at the Cavamont group, Mr. Papadimitriou was initially responsible for Treasury Management, then the Private Equity Portfolio as well as representing the group on the Boards of associated companies including investments in the oil and gas, mining, real estate, and gaming sectors (including Basic Petroleum, a Nasdaq-listed Guatemalan oil and gas company). He is a founding partner of Diorasis International, a company mainly focusing on investments in Greece and the broader Balkans in Aquaculture, and he also chairs the Greek Language School of Geneva and Lausanne. Mr. Papadimitriou holds an Economics and Finance degree and a post-graduate Diploma in European Studies from Geneva University. Mr. Papadimitriou is currently a member of the board of directors of Cavamont Holdings Limited, Diorasis International S.A. and Tellco AG.
Somit Varma has been a member of our board of directors since August 2020. He has been a proven and respected investor in oil, gas, mining, and infrastructure projects across the globe for more than three decades. During his time at the International Finance Corporation (IFC), he was the Global Head of Oil, Gas, Mining and Chemicals, Chairman of the IFC Oil, Gas, Mining and Chemicals Investment Committee and Chairman of the Global Gas Flaring Reduction Partnership. From 2011 until July 2020, Mr. Varma was a partner of the Energy Group at Warburg Pincus LLC, one of the world’s premier private equity firms. Throughout his tenure at Warburg Pincus, Mr. Varma served on the boards of several international energy companies where he worked with management teams on a diverse set of issues including new acquisitions, strategic partnerships, capital allocation, risk management, succession planning, and growing and mentoring teams. Mr. Varma was Chairman of the Energy and Infrastructure Council of EMPEA, the global industry association for private capital in emerging markets. He is also currently an advisor to a global private equity firm and a family office. Mr. Varma earned his MBA at Boston University before attending the Executive Development Program at Harvard Business School.
Brian F. Maxted has been a member of our board of directors since July 2022. He holds a bachelor’s degree in geology from the University of Sheffield and a master’s degree in organic geochemistry and petrology from the University of Newcastle-upon-Tyne. Mr. Maxted is a proven oil and gas explorer, private equity entrepreneur and public company leader in the upstream E&P business, with a global track record of significant basin and play discoveries over 30 years. He spent the first part of his professional life from the late 1970s working for BP in locations including Europe, Africa, 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
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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.
Carlos E. Macellari has been a member of our board of directors since July 2022. He holds a bachelor’s degree in geology from the Universidad Nacional de La Plata in Argentina, and a master’s degree and a PhD in geology from Ohio State University. He has over 30 years of successful exploration, development and management experience in the oil and gas industry across several continents, at Tecpetrol, Repsol YPF, Hocol, Benton Oil & Gas, Enron Oil & Gas International and Pecten International (Shell Oil). As Director of Exploration and Development for Tecpetrol, he led the subsurface team responsible for making Fortín de Piedra the largest gas producing block in Argentina, and the discovery and development of the Pendare Field in Colombia. As Worldwide Director of Geology, he also led the technical group behind Repsol’s exploration success in locations such as Libya, Algeria, Pre-Salt Brazil, the Gulf of Mexico, Venezuela and Peru. He has published over 50 technical papers and has been guest lecturer in numerous international forums. He is the founder of the Journal of South American Earth Sciences, has lectured several courses in the USA, Colombia, Spain and Argentina and is currently a professor for postgraduate students at Universidad Nacional de La Plata. At present he is an independent consultant on oil and gas exploration and production after founding and managing Andes Energy Consulting and since 2024 independent board member at Olympic Peru Inc.
Marcela Vaca joined GeoPark in August 2012 and served as General Director until August 2022. She has been a member of our board of directors since July 2022. She has more than 20 years of experience in planning, legal, environmental and social articulation and management of hydrocarbon exploration and production projects in Colombia and elsewhere in Latin America. Under her leadership as Director for Colombia and General Director, GeoPark became one of the leading oil and gas companies in the country. She plays a crucial role in advancing GeoPark’s diversity, equality and inclusion efforts, and promotes female empowerment as a key to the economic development of Latin America. Prior to joining our company, for nine years Ms. Vaca was the CEO of the Hupecol Group, where her achievements included leading the development of the Caracara field and the construction of the Jaguar–Santiago Pipeline. From November 2000 to June 2003, she worked as Legal, Administrative and External Affairs Manager at GHK Company Colombia. Bloomberg Linea includes Ms. Vaca in its 500 most influential people in Latin America, and in 2020, 2021 and 2022 Forbes named her as one of the 50 most powerful women in Colombia. Ms. Vaca was a member of the board of directors of the Colombian Oil Association (ACP, Asociación Colombiana de Petróleo) from 2010 to 2021 and served as Chair of the Board until March 2022. Ms. Vaca graduated in Law with a specialization in Commercial Law from the Pontificia Universidad Javeriana in Colombia and is a Fulbright Scholar with a Summa Cum Laude Master (LLM) from Georgetown University in the USA. Currently, Ms. Vaca serves as board member at Corficolombiana, Fundación Juanfe and Women in Connection, a private non profit association.
Andrés Ocampo has served as our Chief Executive Officer and as a member of our board of directors since July 2022. He previously served as our Chief Financial Officer (from November 2013 through June 2022) and Director of Growth and Capital Markets (from January 2011 through October 2013), and has been with our company since July 2010. Mr. Ocampo holds a Bachelor’s degree in Economics from Universidad Católica Argentina, has more than 17 years of experience in business and finance. Mr. Ocampo has been instrumental in helping GeoPark reach some of its greatest milestones, including its entry into Colombia and Brazil, the IPO on the New York Stock Exchange, the acquisition of Amerisur Resources and significant acreage expansion in Colombia. Our board of directors appointed Mr. Ocampo to serve as Chief Executive Officer of the Company effective July 1, 2022, by virtue of his wide experience in business management and finance together with his character, vision, knowledge of the Company and his proven ability to lead successful teams. Before joining our Company, Mr. Ocampo worked at Crédit Agricole Corporate & Investment Bank and Citigroup, focusing on the oil and gas and commodities industries.
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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 April 2, 2025.
|
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| At the Company | |||
Name | Position | Age | since | |||
Andrés Ocampo | Chief Executive Officer and Director | 47 | 2010 | |||
Jaime Caballero Uribe | Chief Financial Officer | 50 | 2024 | |||
Rodrigo Dalle Fiore | Chief Exploration and Development Officer | 46 | 2023 | |||
Rodolfo Martín Terrado | Chief Operations Officer | 50 | 2018 | |||
Mónica Jiménez | Chief Strategy, Sustainability and Legal Officer | 49 | 2022 | |||
Agustina Wisky | Chief People Officer | 48 | 2002 |
Biographical information of our executive officers is set forth below. Unless otherwise indicated, the current business address of our executive officers is Calle 94 No. 11-30, 8th floor, Bogotá, Colombia.
Jaime Caballero Uribe has served as our Chief Financial Officer since January 2024. He has more than 25 years of industry and finance experience, including senior positions in large corporations as well as in start-ups and entrepreneurial businesses. Until August 2023, Mr. Caballero was Group CFO at Ecopetrol, the largest corporation in Colombia and one of the 400 largest companies in the world where he helped the management team achieve various performance records, including the delivery of more than US$20 billion in growth financing and debt refinance. During his tenure, he was recognized by the Institutional Investor publication as one of the top three sector CFOs in Latin America. Previously, he held multiple positions at BP plc over 17 years, where his most recent appointment was CFO for the Brazil Region, which includes Colombia, Uruguay and Venezuela. Mr. Caballero holds a degree in Law from Universidad de Los Andes, an MBA in Energy Business from Fundação Getulio Vargas, and certificates in CFO Excellence from Wharton and Energy Innovation and Emerging Technologies from Stanford. Mr. Caballero currently serves as a board member of Agricola Cerro Prieto S.A.
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).
Rodolfo 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 25 years of experience in the oil industry, working in field development and operations. 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 a member of the Society of Petroleum Engineers (SPE). Prior to joining GeoPark, Mr. Terrado worked for Petrolera Argentina San Jorge and Chevron San Jorge S.A. in different international operations, including in Argentina, the United States and Venezuela. Mr. Terrado previously led heavy oil operations in Venezuela assets and his prior responsibilities include waterflooding, CO2 flooding and unconventionals.
Mónica Jiménez has served as our Chief Strategy, Sustainability and Legal Officer and Secretary of the Company since August 2022. She leads the strategy and sustainability (ESG) within the Company and leads the governance and
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legal team. Mrs. Jiménez is an experienced attorney in corporate and international law in Canada and Colombia with extensive experience in international commercial and investment arbitration. After living in Canada for more than 16 years, Mrs. Jiménez was Vice President of Corporate Affairs and Secretary General of Ecopetrol (NYSE), Colombia’s largest company, before joining GeoPark. Mrs. Jiménez studied Law at Universidad the Los Andes, has a postgraduate degree in Civil Liability and Damages from the Universidad Externado de Colombia, and a Master of Science in Development Studies from the London School of Economics (LSE). Recognized as one of the leading in-house lawyers in Colombia by The Legal 500 GC Powerlist: Colombia 2022, 2023 and 2024, Mrs. Jiménez is a current member of the International Court of Arbitration of the International Chamber of Commerce (ICC). She has served as board member of several companies and is currently a member of the Board of Grupo Bolivar S.A. and Cenconsud.
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 furthermore included in the Bloomberg Gender-Equality Index (GEI) in 2022, which evaluates the performance of listed companies that are committed to transparency in gender reporting.
B. Compensation
Executive officers and director compensation
For the year ended December 31, 2024, we paid an aggregate of US$1.8 million to the members of our board of directors for their services in all capacities. This does not include payments made to executive directors Mr. Andrés Ocampo and Mr. Carlos Macellari (who served as interim Chief Exploration Officer from June 1, 2024, to December 31, 2024), 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 11 to our Consolidated Financial Statement.
During this same period, we paid an aggregate of US$9.6 million for salaries and other benefits (including with respect to grants of awards under the LTIP Executives and contingent amounts or deferred compensation accrued for the year, even if payable at a later date) to the executive officers of the Company for their services in all capacities.
Annual Bonus Program
Our Corporate Governance Guidelines set forth that the Compensation Committee will evaluate annually the performance of the Chief Executive Officer and the other executive officers of the Company based on objective and relevant corporate goals and that the board of directors, in consultation with and at the recommendation of the Compensation Committee will review executive officers’ annual performance evaluations. In addition, the Charter of the Compensation Committee establishes that the Committee shall review and approve written annual and longer-term corporate goals and 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 our board of directors. The total bonus amount approved by our board of directors on March 27, 2025, based on a 2024 Scorecard result of 80%, amounts to US$1.4 million, of which 20% is contingent on closing of the Argentina (Vaca Muerta) acquisition.
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CEO Consultant Agreement
Mr. James F. Park (former CEO of the Company and current non-executive member of the board of directors and consultant of the Company, advising on M&A and strategic matters) has a consulting agreement with the Company, 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 CEO, Andrés Ocampo, which provides for severance benefits consistent with those provided under the Severance Plan.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control, the executive will be entitled to receive the following, subject to the execution of a release of claims: (i) cash severance in an amount equal to 2 times the sum of (a) the executive’s annual base salary, (b) the average of any cash bonuses paid in the two years preceding the termination date and (c) an amount equal to the lesser of 15% of the executive’s annual base salary or US$50,000; and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of employment. In addition, the Severance Plan provides that, in the event an executive has relocated at the Company’s request and is terminated during the 12 months following the change in control, the executive will be provided the costs for relocation back to their home country.
In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability, other than in the 24 months following a change in control, then, subject to the execution of a release of claims, the executive will be entitled to the following benefits: (i) cash severance in an amount equal to 1.5 times (or, in the case of the CEO, 2 times) the sum of (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, and (ii) to the extent permitted by applicable law, continued health benefits, at the Company’s cost, for 12 months following their termination of employment. In addition, the executive’s unvested equity awards will accelerate pro-rata (in the case of performance equity awards, subject to achievement of the applicable performance metrics).
Pursuant to the Severance Plan, in the event of a change in control, outstanding performance equity awards will convert into a number of time-based equity awards based on actual performance through the date of the change in control and, except as set forth below, will vest in accordance with the awards’ original schedule, subject to the executive’s continued service through such date. In the event of a termination of the executive’s employment without cause, resignation for good reason or termination due to the executive’s death or disability within 24 months following a change in control: (i) all outstanding time-vesting equity awards will fully accelerate and vest; and (ii) performance equity awards, as converted in accordance with clause (i) above, will fully accelerate and vest. In the event that the acquiror cashes out outstanding equity awards at closing of the change in control, then, at closing, (i) performance awards will accelerate, and vest based on actual performance through the date of the change in control and (ii) all outstanding time-vesting equity awards will fully accelerate and vest.
GeoPark Limited 2018 Equity Incentive Plan
Given the expiration of our Stock Awards Plan on November 3, 2018, on November 5, 2018, we adopted the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those participating employees and executives to perform at the highest level and to further the best interests of the Company and our shareholders. The Plan is designed as an omnibus plan, pursuant to which we may grant awards in the form of options, share appreciation rights, restricted shares, restricted stock units, performance awards, other share-based awards or other cash-based awards throughout the ten (10)-year term
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of the Plan. Subject to adjustments as set forth in the Plan, the maximum number of shares available for issuance under the Plan is 5,000,000 shares. The applicable award documentation will set forth the terms and conditions of the awards granted under the Plan, including, but not limited to, the vesting conditions and the effect on a termination of service or a Change in Control on awards.
The following table sets forth the common share awards granted to our employees and executive officers under the Plan which are outstanding as of the date of this annual report:
Number of underlying common shares outstanding | Grant date | Vesting date | |||
800,000 (1) | 01/01/2020 | 01/02/2023 | |||
215,000 (2) | 03/31/2022 | 03/31/2025 | (3) | ||
25,000 (4) | 03/31/2022 | 03/31/2025 | |||
197,197 (5) | 02/14/2023 | 01/02/2026 | |||
1,000,000 (6) | 01/02/2023 | 01/02/2026 | |||
55,000 (7) | (8) | (8) | |||
351,971 (9) | 02/14/2024 | 01/02/2027 | |||
287,656 (10) | 02/14/2025 | 01/02/2028 | |||
200,000 (11) | (12) | (12) |
(1) | On November 6, 2019, our board of directors approved a share-based compensation program for approximately 800,000 shares to be granted in 2020. Considering the performance conditions, the Compensation Committee determined that only a total of 152,030 shares have vested. As of December 31, 2024, 91,759 shares have been exercised, with a remaining amount of 60,271 shares to be exercised. |
(2) | Retention and Hiring Bonus scheme. |
(3) | The vesting date is March 31, 2025, or 3 years from grant date. |
(4) | Employment agreement. The awards granted under this agreement vest in three annual installments (March 31, 2023, March 31, 2024, and March 31, 2025). As of December 31, 2024, 16,666 shares have been exercised, with a remaining amount of 8,333 shares to be exercised. |
(5) | LTIP Executives. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2026. |
(6) | LTIP Employees approved in December 2022. The vesting date of the RSUs is annually during a three-year period and the vesting date of the PSUs will be on January 2, 2026. |
(7) | One-time Bonus. |
(8) | The vesting date is 3 years from each grant date, which ranges between January 2027 and February 2028. |
(9) | 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. |
(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, 2028. |
(11) | Retention and Hiring Bonus scheme. |
(12) | The vesting date is 3 years from each grant date. For further information, please see “Item 6. Directors, Senior Management and Employees—B. Compensation—Employees—Retention and Hiring Bonus Scheme.” |
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”).
Employees
Long-Term Incentive Program to Employees (“LTIP Employees”)
In December 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new Long-Term Incentive program for employees and new hirings. Main characteristics of the program are:
● | All employees (non-top management) and new hirings are eligible. |
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● | 3-year program, with a grant date of January 2, 2023, or the date on which the employees are hired. |
● | The components of the program are the following: |
- | 30% Time-based RSUs: vesting annually ratably in three equal installments; |
- | 30% Company Performance: measured over three-year performance period (December 2022-December 2025); and |
- | 40% Absolute Performance Shares: share price at the date of vesting must be higher than the share price at the date of grant or date of hiring. |
● | The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026. |
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 grant date. Employees must remain with the Group until the vesting date and achieve a minimum individual performance evaluation score of 2 (target).
Executive officers
Long-Term Incentive Program to Executive Officers (“LTIP Executives”)
In March 2022, our board of directors, based on the recommendation of the Compensation Committee, approved a new Long-Term Incentive program for the executive officers. Main characteristics of the program are:
● | All executive officers are eligible. |
● | Grants are awarded annually to executive officers. |
● | The components of the program are the following: |
- | 20% Time-based Restricted Share Units (RSUs) vesting ratably in three equal installments on each of the first three anniversaries of the grant date; |
- | 35% Relative Performance Share Units based on relative total shareholder return (TSR) and measured over three-year performance period relative to peer group; and |
- | 45% Absolute Performance Share Units (PSUs) based on absolute total shareholder return (TSR) and measured over three-year performance period. |
In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated 571,984 total shares, to vest during a three-year period. On February 17, 2023, February 26, 2024, and March 4, 2025, the Compensation Committee approved new grants of 197,197, 351,971 and 287,656 shares to vest during a three-year period.
On January 25, 2023, February 26, 2024, and March 25, 2025, the Compensation Committee determined that 246,110, 86,602 and 93,326 shares, respectively, should be delivered to the participants according to the abovementioned grants.
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.
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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 6, 2025, there were 1,946,268 outstanding shares that had been awarded but which had not yet vested, representing approximately 4% of the total issued share capital as of that date.
Stock Ownership Guidelines
In December 2022, to further align the interests of our executive officers with those of the Company’s shareholders, our board of directors approved minimum stock ownership guidelines applicable to the Company’s executive officers, as determined by the board of directors. Each such executive officer is required to hold, within five years after the adoption of the guidelines or, if later, within five years after becoming subject to the policy, a number of shares with an aggregate value of at least three times his or her annual base salary. Shares beneficially owned by the applicable officer or held in a family trust established by the applicable executive officer and shares underlying vested equity awards (which, in the case of stock options, are at- or in-the-money) are taken into account for purposes of determining compliance with these guidelines. Until an officer has met his or her ownership requirement, he or she is required to retain at least 50% of shares received from the vesting, settlement or exercise of equity awards (and which remain outstanding after tax withholding and payment of any applicable exercise price).
C. Board practices
Overview
Directors are expected to provide stewardship to promote the long-term success of the Company. They are expected to fulfill their fiduciary duties and duty of care in the best interests of the Company, considering the various needs of its stakeholders (shareholders, employees, communities, suppliers and clients), providing advice to and oversight of management’s activities. Within its responsibilities, the board of directors oversees the Company’s strategic 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 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. All of our directors were elected at our annual shareholders’ meeting held on July 24, 2024. Their term expires on the date of our next annual shareholders’ meeting, to be held in 2025. The board of directors meets regularly throughout the year, at least on a quarterly basis.
Committees of our board of directors
Our board of directors has established an Audit Committee, a Compensation Committee, a Nomination and Corporate Governance Committee, a Strategy & Risk Committee, a Technical Committee and a SPEED/Sustainability Committee. 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 four independent directors. The current members of the Audit Committee are Mr. Robert Bedingfield (who serves as Chairman of the committee), Mr. Constantin Papadimitriou, Ms.
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Sylvia Escovar and Mr. Somit Varma. Mr. Robert Bedingfield is regarded as audit committee financial expert. The Nomination and Corporate Governance Committee determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou, Ms. Sylvia Escovar and Mr. Somit Varma are independent, as such term is defined under SEC rules applicable to foreign private issuers.
The main purposes of the Audit Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to assist the board of directors in its oversight of: (i) the integrity of the Company’s financial statements and the company’s accounting and financial reporting processes and financial statement audits; (ii) the independent auditor’s performance, qualifications and independence; (iii) the Company’s compliance with legal and regulatory requirements and the Company’s ethical standards; and (iv) the performance of the Company’s internal audit function.
Compensation Committee
The Compensation Committee is currently composed of four independent directors. The current members of the compensation committee are Mr. Constantin Papadimitriou (who serves as Chairman of the committee), Mr. Robert Bedingfield, Mr. Brian F. Maxted and Mr. Somit Varma.
The main purposes of the Compensation Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) evaluate and recommend for approval by the independent members of the board the remuneration, benefits and incentive compensation arrangements for the executive officers of the Company; (ii) 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 Mr. Somit Varma (who serves as Chairman of the committee), Ms. Sylvia Escovar and Mr. Robert Bedingfield.
The main purposes of the Nomination and Corporate Governance Committee, without prejudice of any additional objectives or functions foreseen in its charter, are to (i) review board 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.
Strategy & Risk Committee
The Strategy & Risk Committee was created in December 2020, and is currently composed of five directors. The current members of the Strategy & Risk Committee are Mr. James F. Park (who serves as Chairman of the committee), Mr. Constantin Papadimitriou. Mr. Somit Varma, Mr. Brian F. Maxted and Mr. Carlos E. Macellari.
The main purposes of the Strategy and Risk Committee, without prejudice of any additional objectives or functions foreseen in its Charter, are to assist the board 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 three directors. The current members of the technical committee are Mr. Brian F. Maxted (who serves as Chairman of the committee), Mr. Carlos E. Macellari and Mr. James F. Park.
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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 Chairman of the committee), Ms. Sylvia Escovar, Mr. James F. Park and Mr. Andrés Ocampo.
The main purposes of the SPEED/Sustainability Committee, without prejudice of any additional objectives or functions foreseen in its Charter, are to assist the Board in (i) its guidance and oversight function of the Company’s strategy concerning the SPEED/Sustainability matters, including the safety of its operations, the initiatives to give back value to stakeholders, the wellbeing of employees, preservation of the environment, community development, and any other matters related to sustainability; and (ii) its review of the performance on the topics above.
Liability insurance
We maintain liability insurance coverage for all of our directors and officers, the level of which is reviewed annually.
D. Employees
As of December 31, 2024, we had 476 employees, representing an increase of 1.3% from December 31, 2023.
The following table sets forth a breakdown of our employees by geographic segment for the periods indicated.
Year ended December 31, | ||||||
| 2024 |
| 2023 |
| 2022 | |
Colombia | 448 | 412 | 388 | |||
Ecuador | 5 | 5 | 8 | |||
Brazil | 3 | 4 | 4 | |||
Chile | — | 27 | 49 | |||
Argentina | 15 | 15 | 24 | |||
Corporate | 5 | 7 | 9 | |||
Total | 476 | 470 | 482 |
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, 2024, none of our employees were represented by labor unions or covered by collective bargaining agreements. We believe that relations with our employees are satisfactory.
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E. Share ownership
As of March 6, 2025, members of our board of directors and our executive officers held as a group 9,868,968 of our common shares and 19.2% 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 6, 2025.
|
| Percentage of |
| ||
outstanding |
| ||||
Shareholder | Common shares | common shares |
| ||
James F. Park (1) | 8,817,251 | 17.2 | % | ||
Sylvia Escovar | 90,622 | * | |||
Robert Bedingfield | 198,085 | * | |||
Constantin Papadimitriou | 84,583 | * | |||
Somit Varma | 97,589 | * | |||
Brian Maxted | 25,727 | * | |||
Carlos Macellari | 39,376 | * | |||
Marcela Vaca | 24,638 | * | |||
Andrés Ocampo | * | * | |||
Jaime Caballero Uribe | * | * | |||
Rodrigo Dalle Fiore | * | * | |||
Rodolfo Martín Terrado | * | * | |||
Mónica Jiménez | * | * | |||
Agustina Wisky | * | * | |||
Sub-total executive officers' ownership | 491,097 | 1.0 | % | ||
Total | 9,868,968 | 19.2 | % |
* | Indicates ownership of less than 1% of outstanding common shares. |
(1) | Held by Mr. Park directly and indirectly through GoodRock, LLC and Spark Resources LLC. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2025. |
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 prohibits 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
Not applicable.
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ITEM 7. MAJOR SHAREHOLDERS AND RELATED PARTY TRANSACTIONS
A. Major shareholders
The following table presents the beneficial ownership of our common shares as of March 6, 2025, except for certain shareholders whose last available data is as of December 31, 2024, or as noted below. The percentages reported herein are based on the shares outstanding as of March 6, 2025.
|
| Percentage of |
| ||
outstanding |
| ||||
Shareholder | Common shares | common shares |
| ||
James F. Park (1) | 8,817,251 | 17.2 | % | ||
Renaissance Technologies LLC (2) | 3,176,376 | 6.2 | % | ||
Socoservin Overseas SPF S.à.r.l. (3) | 2,889,315 | 5.6 | % | ||
Cobas Asset Management, SGIIC, SA (4) | 2,490,017 | 4.9 | % | ||
Other shareholders | 33,936,817 | 66.1 | % | ||
Total | 51,309,776 | 100.0 | % |
(1) | 7,305,133 and 500,000 shares are held by GoodRock, LLC and Spark Resources LLC, respectively, which are controlled by James F. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2025. |
(2) | The information listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13F filed with the SEC on February 13, 2025. |
(3) | The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’ most recent Schedule 13G filed with the SEC on April 3, 2024. The percentage of outstanding common shares was calculated on the basis of GeoPark Limited outstanding shares as of March 6, 2025, and as such may not match the percentage in the aforementioned filing. |
(4) | The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset Management’s most recent Schedule 13G filed with the SEC on February 18, 2025. |
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 6, 2025, we had 12 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, 2024, 2023 and 2022, please see Note 34 to our Consolidated Financial Statements.
C. Interests of Experts and Counsel
Not applicable.
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ITEM 8. FINANCIAL INFORMATION
A. Consolidated statements and other financial information
Financial statements
See “Item 18. Financial Statements,” which contains our audited financial statements prepared in accordance with IFRS.
Legal proceedings
From time to time, we may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, 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 6, May 15, August 14 and November 6, 2024 the Company’s Board of Directors declared cash dividends of US$0.136, US$0.147, US$0.147 and US$0.147 per share, respectively, which were paid on March 28, June 14, September 12 and December 6, 2024.
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.”
ITEM 9. THE OFFER AND LISTING
A. Offering and listing details
Not applicable.
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B. Plan of distribution
Not applicable.
C. Markets
Our common shares have been listed on the NYSE under the symbol “GPRK” since February 7, 2014.
D. Selling shareholders
Not applicable.
E. Dilution
Not applicable.
F. Expenses of the issue
Not applicable.
ITEM 10. ADDITIONAL INFORMATION
A. Share capital
Not applicable.
B. Memorandum of association and bye-laws
The following description of our memorandum of association and bye-laws does not purport to be complete and is subject to, and qualified by reference to, all of the provisions of our memorandum of association and bye-laws.
General
We are an exempted company limited by shares incorporated under the laws of Bermuda. We are registered with the Registrar of Companies in Bermuda under registration number 33273. The rights of our shareholders will be governed by Bermuda law and by our memorandum of association and bye-laws. Bermuda company law differs in some material 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 6, 2025, there are 51,309,776 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
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or with the sanction of a resolution passed by a majority of the votes cast at a separate general meeting of the holders of the shares of the class at which meeting the necessary quorum shall be two persons at least, in person or by proxy, holding or representing one-third of the issued shares of the class. The rights conferred upon the holders of the shares of any class issued with preferred or other rights shall not, unless otherwise expressly provided by the terms of issue of the shares of that class, be deemed to be varied by the creation or issue of further shares ranking pari passu therewith.
Our bye-laws give our board of directors the power to issue any unissued shares of the company on such terms and conditions as it may determine, subject to the terms of the bye-laws and any resolution of the shareholders to the contrary.
Common shares
Holders of our common shares are entitled to one vote per share on all matters submitted to a vote of holders of common shares. Under our bye-laws, each common share is entitled to dividends, if, as and when dividends are declared by our board of directors, subject to any preferred dividend right of the holders of any preference shares, if any. Holders of common shares have no pre-emptive, redemption, conversion or sinking fund rights. In the event of our liquidation, dissolution or winding up the holders of common shares are entitled to share equally and ratably in our assets, if any, remaining after the payment of all of our debts and liabilities, subject to any liquidation preference on any outstanding preference shares.
Board composition
Our bye-laws provide that the minimum number of directors shall be three or such other number as shall be determined from time to time by 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 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.
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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 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
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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.
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Shareholder proposals
Under Bermuda law, shareholders holding at least 5% of the total voting rights of all the shareholders having at the date of the requisition a right to vote at the meeting to which the requisition relates or any group composed of at least 100 shareholders may require a proposal to be submitted to an annual general meeting of shareholders by giving a requisition in writing to the company. Under our bye-laws, any shareholders wishing to nominate a person for election as a director or propose business to be transacted at a meeting of shareholders must provide (among other things) advance notice, as set out in our bye-laws. Shareholders may only propose a person for election as a director at an annual general meeting.
Shareholder action by written consent
Our bye-laws provide that, except for the removal of auditors and directors, any actions which shareholders may take at a general meeting of shareholders may be taken by the shareholders through the unanimous written consent of all the shareholders who would be entitled to vote on the matter at the general meeting.
Amendment of memorandum of association and bye-laws
Our memorandum of association and bye-laws may be amended with the approval of a majority of our board of directors and by a resolution by a majority of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws.
Under Bermuda law, the holders of an aggregate of not less than 20% in par value of the company’s issued share capital or any class thereof have the right to apply to the Supreme Court of Bermuda for an annulment of any amendment of the memorandum of association adopted by shareholders at any general meeting, other than an amendment which alters or reduces a company’s share capital as provided in the Companies Act. Where such an application is made, the amendment becomes effective only to the extent that it is confirmed by the Bermuda court. An application for an annulment of an amendment of the memorandum of association must be made within twenty-one days after the date on which the resolution altering the company’s memorandum of association is passed and may be made on behalf of persons entitled to make the application by one or more of their number as they may appoint in writing for the purpose. No application may be made by shareholders voting in favour of the amendment.
Business combinations
The amalgamation or merger of a Bermuda company with another company or corporation (other than certain affiliated companies) requires the amalgamation or merger agreement to be approved by the company’s board of directors and by its shareholders. Under the Companies Act, unless the company’s bye-laws provide otherwise, the approval of 75% of the shareholders voting at a meeting is required to pass a resolution to approve the amalgamation or merger agreement, and the quorum for such meeting must be two persons holding or representing more than one-third of the issued shares of the company. Our bye-laws provide that an amalgamation or merger will require the approval of our board of directors and of our shareholders by a resolution adopted by 65% or more of the votes cast by shareholders who (being entitled to do so) vote in person or by proxy at any general meeting of the shareholders in accordance with the provisions of the bye-laws. Under Bermuda law, in the event of an amalgamation or merger of a Bermuda company with another company or corporation, a shareholder who did not vote in favor of the amalgamation or merger and who is not satisfied that fair value 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.
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Compulsory Acquisition of Shares Held by Minority Holders
An acquiring party is generally able to acquire compulsorily the common shares of minority holders in the following ways:
(1)By a procedure under the Companies Act 1981 known as a “scheme of arrangement”. A scheme of arrangement could be effected by obtaining the agreement of the company and of holders of common shares, representing in the aggregate a majority in number and at least 75% in value of the common shareholders present and voting at a court ordered meeting held to consider the scheme of arrangement. The scheme of arrangement must then be sanctioned by the Bermuda Supreme Court. If a scheme of arrangement receives all necessary agreements and sanctions, upon the filing of the court order with the Registrar of Companies in Bermuda, all holders of common shares could be compelled to sell their shares under the terms of the scheme of arrangement.
(2)If the acquiring party is a company it may compulsorily acquire all the shares of the target company, by acquiring pursuant to a tender offer 90% of the shares or class of shares not already owned by, or by a nominee for, the acquiring party (the offeror), or any of its subsidiaries. If an offeror has, within four months after the making of an offer for all the shares or class of shares not owned by, or by a nominee for, the offeror, or any of its subsidiaries, obtained the approval of the holders of 90% or more of all the shares to which the offer relates, the offeror may, at any time within two months beginning with the date on which the approval was obtained, require by notice any nontendering shareholder to transfer its shares on the same terms as the original offer. In those circumstances, nontendering shareholders will be compelled to sell their shares unless the Supreme Court of Bermuda (on application made within a one-month period from the date of the offeror’s notice of its intention to acquire such shares) orders otherwise.
(3) Where one or more parties holds not less than 95% of the shares or a class of shares of a company, such holder(s) may, pursuant to a notice given to the remaining shareholders or class of shareholders, acquire the shares of such remaining shareholders or class of shareholders. When this notice is given, the acquiring party is entitled and bound to acquire the shares of the remaining shareholders on the terms set out in the notice, unless a remaining shareholder, within one month of receiving such notice, applies to the Supreme Court of Bermuda for an appraisal of the value of their shares. This provision only applies where the acquiring party offers the same terms to all holders of shares whose shares are being acquired.
Dividends and repurchase of shares
Pursuant to our bye-laws, our board of directors has the authority to declare dividends and authorize the repurchase of shares subject to applicable law. Under Bermuda law, a company may not declare or pay a dividend if there are reasonable grounds for believing that the company is, or would after the payment be, unable to pay its liabilities as they become due or the realizable value of its assets would thereby be less than its liabilities. Under Bermuda law, a company cannot purchase its own shares if there are reasonable grounds for believing that the company is, or after the repurchase would be, unable to pay its liabilities as they become due.
Shareholder suits
Class actions and derivative actions are generally not available to shareholders under Bermuda law. The Bermuda courts, however, would ordinarily be expected to permit a shareholder to commence an action in the name of a company 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.
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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.”
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Our bye-laws contain a provision by virtue of which our shareholders waive any claim or right of action that they might have, individually or in the right of the company, against any director for any act or failure to act in performance of such director’s duties, including the breach of any fiduciary duty, except in respect of any fraud or dishonesty of such director or to recover any gain, personal profit or advantage to which such director is not legally entitled. Class actions and derivative actions generally are available to shareholders under Delaware law for, among other things, breach of fiduciary duty, corporate waste and actions not taken in accordance with applicable law. In such actions, the court has discretion to permit the winning party to recover attorneys’ fees incurred in connection with such action.
Indemnification of Directors. We may indemnify our directors and officers in their capacity as directors or officers for any loss arising or liability attaching to them by virtue of any rule of law in respect of any negligence, default, breach of duty or breach of trust of which a director or officer may be guilty in relation to the company other than in respect of his own fraud or dishonesty. See “Item 10—B. Memorandum of association and bye-laws—Enforcement of Judgments.” Our bye-laws provide that we shall indemnify our officers and directors in respect of their acts and omissions, except in respect of their fraud or dishonesty, or to recover any gain, personal profit or advantage to which such Director is not legally entitled, and (by incorporation of the provisions of the Companies Act) that we may advance money to our officers and directors for the costs, charges and expenses incurred by our officers and directors in defending any civil or criminal proceedings against them on condition that the directors and officers repay the money if any allegations of fraud or dishonesty is proved against them provided, however, that, if the Companies Act requires, an advancement of expenses shall be made only upon delivery to the Company of an undertaking, by or on behalf of such indemnitee, to repay all amounts if it shall ultimately be determined by final judicial decision that such indemnitee is not entitled to be indemnified for such expenses under our bye-laws or otherwise. Under Delaware law, a corporation may indemnify a director or officer of the corporation against expenses (including attorneys’ fees), judgments, fines and amounts paid in settlement actually and reasonably incurred in defense of an action, suit or proceeding by reason of such position if such director or officer acted in good faith and in a manner he or she reasonably believed to be in or not opposed to the best interests of the corporation and, with respect to any criminal action or proceeding, such director or officer had no reasonable cause to believe his or her conduct was unlawful. In addition, we have entered into customary indemnification agreements with our directors.
As a result of these differences, investors could have more difficulty protecting their interests than would shareholders of a corporation incorporated in the United States.
Tax matters. Under current Bermuda law, we are not subject to tax on income or capital gains in Bermuda. We have obtained an assurance from the Minister of Finance of Bermuda under the Exempted Undertakings Tax Protection Act 1966 that, in the event that any legislation is enacted in Bermuda imposing any tax computed on profits, income, any capital asset, gain or appreciation, or any tax in the nature of estate duty or inheritance, such tax shall not be applicable to us or to any of our operations or shares, debentures or other obligations, until March 31, 2035, except insofar as such tax applies to persons ordinarily resident in Bermuda or is payable by us in respect of real property owned or leased by us in Bermuda. On December 27, 2023, Bermuda enacted the Corporate Income Tax Act 2023 (the “CIT Act”). The CIT Act provides for the taxation of the Bermuda constituent entities of multi-national groups that excess EUR 750 million revenue for at least two of the last four fiscal years beginning on or after January 1, 2025. We are incorporated in Bermuda as an exempted company and pay annual Bermuda government fees. In addition, all entities employing individuals in Bermuda 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
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may, subject to the provisions of the Companies Act, establish a branch register outside of Bermuda. A company is required to keep at its registered office a register of directors and officers that is open for inspection for not less than two hours in any business day by members of the public without charge. A company is also required to file with the Registrar of Companies in Bermuda a list of its directors to be maintained on a register, which register will be available for public inspection subject to such conditions as the Registrar may impose and on payment of such fee as may be prescribed. Bermuda law does not, however, provide a general right for shareholders to inspect or obtain copies of any other corporate records.
Registrar or transfer agent
A register of holders of the common shares is maintained by Conyers Corporate Services (Bermuda) Limited in Bermuda, and a branch register is maintained in the United States by Computershare Trust Company, N.A., who serves as branch registrar and transfer agent.
Enforcement of Judgments
We are incorporated as an exempted company limited by shares under the laws of Bermuda, and substantially all of our assets are located in Colombia, Ecuador, Brazil and Argentina. In addition, most of our directors and executive officers reside outside the United States, and all or a substantial portion of the assets of such persons are located outside the United States. As a result, it may be difficult for investors to effect service of process on those persons in the United States or to enforce in the United States judgments obtained in U.S. courts against us or those persons based on the civil liability provisions of the U.S. securities laws.
There is no treaty in force between the United States and Bermuda providing for the reciprocal recognition and enforcement of judgments in civil and commercial matters. However, the courts of Bermuda would recognize any final and conclusive monetary in personam judgement obtained in a U.S. court (other than a sum of money payable in respect of multiple damages, taxes or other charges of a like nature or in respect of a fine or other penalty) and would give a judgement based thereon provided that (i) the U.S. court that entered the judgment is recognized by the Bermuda court as having jurisdiction over us or our directors and officers, as determined by reference to Bermuda conflict of law rules, (ii) such court did not contravene the rules of natural justice of Bermuda, such judgment was not obtained by fraud, the enforcement of the judgment would not be contrary to the public policy of Bermuda, (iii) no new admissible evidence relevant to the action is submitted prior to the rendering of the judgment by the courts of Bermuda, and (iv) there is due compliance with the correct procedures under the laws of Bermuda.
An action brought pursuant to a public or penal law, the purpose of which is the enforcement of a sanction, power or right at the instance of the state in its sovereign capacity, may not be entertained by a Bermuda court. Certain remedies available under the laws of U.S. jurisdictions, including certain remedies under U.S. federal securities laws, may not be available under Bermuda law or enforceable in a Bermuda court, as they may be contrary to Bermuda public policy. Further, no claim may be brought in Bermuda against us or our directors and officers in the first instance for violations of U.S. federal securities laws because these laws have no extraterritorial jurisdiction under Bermuda law and do not have force of law in Bermuda. A Bermuda court may, however, impose civil liability on us or our directors and officers if the facts alleged in a complaint constitute or give rise to a cause of action under Bermuda law. However, section 281 of the Companies Act allows a Bermuda court, in certain circumstances, to relieve officers and directors of Bermuda companies of liability for acts of negligence, breach of duty or trust or other defaults.
C. Material contracts
See “Item 4. Information on the Company—B. Business Overview—Significant Agreements.”
D. Exchange controls
Not applicable.
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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:
● | certain financial institutions; |
● | a dealer or trader in securities who uses a mark-to-market method of tax accounting; |
● | a person holding common shares as part of a straddle, wash sale or conversion transaction or entering into a constructive sale with respect to the common shares; |
● | a person whose functional currency for U.S. federal income tax purposes is not the U.S. Dollar; |
● | a partnership or other entities classified as partnerships for U.S. federal income tax purposes; |
● | a tax-exempt entity, including an “individual retirement account” or “Roth IRA;” |
● | a person that owns or is deemed to own 10% or more of our shares by vote or value; |
● | a person who acquired our shares pursuant to the exercise of an employee stock option or otherwise as compensation; or |
● | a person holding common shares in connection with a trade or business conducted outside of the United States. |
If an entity that is classified as a partnership for U.S. federal income tax purposes holds common shares, the U.S. federal income tax treatment of a partner will generally depend on the status of the partner and the activities of the
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partnership. Partnerships holding common shares and partners in such partnerships should consult their tax advisers as to the particular U.S. federal income tax consequences of their investment in our common shares.
This discussion is based on the Internal Revenue Code of 1986, as amended (the “Code”), administrative pronouncements, judicial decisions, and final, temporary and proposed Treasury regulations, all as of the date hereof, any of which is subject to change, possibly with retroactive effect. U.S. Holders should consult their tax advisers concerning the U.S. federal, state, local and foreign tax consequences of owning and disposing of our common shares in their particular circumstances.
A “U.S. Holder” is a beneficial owner of our common shares for U.S. federal income tax purposes that is:
· | a citizen or individual resident of the United States; |
· | a corporation, or other entity taxable as a corporation, created or organized in or under the laws of the United States, any state therein or the District of Columbia; or |
· | an estate or trust the income of which is subject to U.S. federal income taxation regardless of its source. |
This discussion assumes that we are not, and will not become, a passive foreign investment company, as described below.
Taxation of distributions
Distributions paid on our common shares, other than certain pro rata distributions of common shares, will generally be treated as dividends to the extent paid out of our current or accumulated earnings and profits (as determined under U.S. federal income tax principles). Because we do not maintain calculations of our earnings and profits under U.S. federal income tax principles, it is expected that distributions will generally be reported to U.S. Holders as dividends. Subject to the passive foreign investment company rules described below, dividends paid by qualified foreign corporations to certain non-corporate U.S. Holders may be taxable at favorable rates. A foreign corporation is treated as a qualified foreign corporation with respect to dividends paid on stock that is readily tradable on an established securities market in the United States, such as the NYSE where our common shares are traded. Non-corporate U.S. Holders should consult their tax advisers to determine whether the favorable rate will apply to dividends they receive and whether they are subject to any special rules that limit their ability to be taxed at this favorable rate.
A dividend generally will be included in a U.S. Holder’s income when received, will be treated as foreign-source income to U.S. Holders and will not be eligible for the dividends-received deduction generally available to U.S. corporations under the Code with respect to dividends paid by domestic corporations.
Sale or other taxable disposition of common shares
Gain or loss realized on the sale or other taxable disposition of our common shares will be capital gain or loss, and will be long-term capital gain or loss if the U.S. Holder held our common shares for more than one year. Long-term capital 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
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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 tax on transfers of shares, described under "—Colombian tax on transfers of shares" below, respectively, you generally will not be entitled to claim a foreign tax credit for any Colombian taxes imposed on gains from taxable dispositions of our common shares (although it is possible that such taxes may reduce the amount realized on the disposition). With regards to the possible application of Argentine income tax on transfers of our shares made by an Argentine resident, any gain on a transfer of our shares will be subject to income tax at a rate of 15%.
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 2024, and we do not expect to be a PFIC in the foreseeable future. However, because the composition of our income and assets will vary over time, there can be no assurance that we will not be a PFIC for any taxable year. The determination of whether we are a PFIC is made annually and is based upon the composition of our income and assets (including the income and assets of, among others, entities in which we hold at least a 25% interest), and the nature of our activities.
If we were a PFIC for any taxable year during which a U.S. Holder held our common shares, gain recognized by a U.S. Holder on a sale or other disposition (including certain pledges) of our common shares would generally be allocated ratably over the U.S. Holder’s holding period for the common shares. The amounts allocated to the taxable year of the sale or other disposition and to any year before we became a PFIC would be taxed as ordinary income. The amount allocated to each other taxable year would be subject to tax at the highest rate in effect for individuals or corporations for that year, as appropriate, and an interest charge would be imposed on the tax on such amount. Further, to the extent that any distribution received by a U.S. Holder on its common shares exceeds 125% of the average of the annual distributions on the shares received during the preceding three years or the U.S. Holder’s holding period, whichever is shorter, that distribution would be subject to taxation in the same manner as gain, as described immediately above. Certain elections may be available that would result in alternative treatments (such as mark-to-market treatment) of our common shares. U.S. Holders should consult their tax advisers to determine whether any of these elections would be available and, if so, what the consequences of the alternative treatments would be in their particular circumstances.
Furthermore, if we were a PFIC or, with respect to a particular U.S. Holder, were treated as a PFIC for the taxable year in which we paid a dividend or the prior taxable year, the preferential dividend rates discussed above with respect to dividends paid to certain non-corporate U.S. Holders would not apply.
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
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Colombian Tax Code rules. When the underlying assets are held by a Colombian branch, any taxable base determined shall be allocated first to amortization/depreciation recapture taxed as ordinary income.
When a subsequent indirect transfer is made, the tax basis of the underlying Colombian assets corresponds to the purchase price paid and allocated to the underlying Colombian assets. However, Decree 1103 clarifies that the tax basis of the entity owning the underlying asset in Colombia is not stepped up.
See “Item 3. Key Information—D. Risk Factors—Risks related to our common shares—The transfer of our common shares may be subject to capital gains taxes pursuant to indirect transfer rules in Colombia.”
F. Dividends and paying agents
Not applicable.
G. Statement by experts
Not applicable.
H. Documents on display
We are subject to the informational requirements of the Exchange Act. Accordingly, we are required to file reports and other information with the SEC, including annual reports on Form 20-F and reports on Form 6-K. The SEC maintains an Internet website that contains reports and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov.
I. Subsidiary information
Not applicable.
ITEM 11. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
We are exposed to a variety of market risks, including commodity price risk, interest rate risk, currency risk and credit (counterparty and customer) risk. The term “market risk” refers to the risk of loss arising from adverse changes in interest rates, oil and natural gas prices and foreign currency exchange rates.
For further information on our market risks, please see Note 3 to our Consolidated Financial Statements.
ITEM 12. DESCRIPTION OF SECURITIES OTHER THAN EQUITY SECURITIES
A. Debt securities
Not applicable.
B. Warrants and rights
Not applicable.
C. Other securities
Not applicable.
D. American Depositary Shares
Not applicable.
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PART II
ITEM 13. DEFAULTS, DIVIDEND ARREARAGES AND DELINQUENCIES
A. Defaults
No matters to report.
B. Arrears and delinquencies
No matters to report.
ITEM 14. MATERIAL MODIFICATIONS TO THE RIGHTS OF SECURITY HOLDERS AND USE OF PROCEEDS
Not applicable.
ITEM 15. CONTROLS AND PROCEDURES
A. Disclosure Controls and Procedures
As of December 31, 2024, 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:
● | pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect transactions and dispositions of our assets; |
● | provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements, in accordance with generally accepted accounting principles, and that receipts and expenditures are being made only in accordance with authorization of our management and directors; and |
● | provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of our assets that could have a material effect on our financial statements. |
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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.
As disclosed in Item 15 Controls and Procedures in our Annual Report on Form 20-F for the fiscal year ended December 31, 2023, we had identified a material weakness in internal control related to ineffective information technology general controls (ITGCs) over the timely removal of user access upon personnel termination. Notwithstanding, we also concluded that the material weakness did not result in any identified misstatements to the consolidated financial statements, and there were no changes to previously released financial results.
During 2024, management implemented certain remediation actions that included: (i) developing a training program addressing ITGCs and related policies, including educating control owners on the principles and requirements of each control, with a focus on those related to user access over IT systems impacting financial reporting; (ii) developing and maintaining documentation underlying ITGCs to promote knowledge transfer upon personnel and function changes; (iii) implementing an IT management review and testing plan to monitor ITGCs with a specific focus on timely removal of user access to applications systems supporting our financial reporting processes upon personnel termination; and (iv) enhanced quarterly reporting on the remediation measures to the Audit Committee of the board of directors.
Under the supervision and with the participation of our management, including our Chief Executive Officer, our Chief Financial Officer, and our Chief Strategy, Sustainability and Legal Officer, we conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2024, based on the criteria established in Internal Control - Integrated Framework of the Committee of Sponsoring Organizations of the Treadway Commission (2013).
Based on this evaluation, management has assessed the effectiveness of the Group’s internal control over financial reporting as of December 31, 2024 and concluded that as of such date, it was effective and the previously disclosed material weakness has been remediated.
C. Attestation Report of the Registered Public Accounting Firm
The effectiveness of the Group’s internal control over financial reporting as of December 31, 2024, has been audited by independent registered public accounting firm, Ernst & Young Audit S.A.S. (a member of Ernst & Young Global Limited). See pages F-4 to F-5 of this annual report.
D. Changes in Internal Control over Financial Reporting
Except for the changes in connection with our implementation of the remediation plan discussed above, there have been no changes in the Group’s internal control over financial reporting that occurred during the year ended December 31, 2024, that have materially affected, or are reasonably likely to materially affect, our internal controls over financial reporting.
ITEM 16. RESERVED
ITEM 16A. Audit committee financial expert
We have determined that Mr. Robert Bedingfield, Mr. Constantin Papadimitriou, Ms. Sylvia Escovar and Mr. Somit Varma are independent, as such term is defined under SEC rules applicable to foreign private issuers. In addition, Mr. Robert Bedingfield and Ms. Sylvia Escovar are regarded as audit committee financial experts.
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ITEM 16B. Code of Ethics
We have adopted a code of ethics applicable to the board of directors and all employees. Since its effective date on September 24, 2012, we have not waived compliance with the code of ethics and we amended the code of ethics on March 4, 2025. The code of ethics is available at the Company’s website.
ITEM 16C. Principal Accountant Fees and Services
The independent registered public accounting firm for the fiscal year ended December 31, 2024 and 2023 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:
| 2024 |
| 2023 | |
(in millions of US$) | ||||
Audit fees | 1.02 | 0.98 | ||
Audit related fees | 0.04 | 0.03 | ||
Tax services fees | — | — | ||
Total | 1.06 | 1.01 |
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 statue 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.
Tax Fees
Tax fees are fees billed for professional services for tax compliance and tax advice.
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.
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ITEM 16D. Exemptions from the listing standards for audit committees
None.
ITEM 16E. Purchases of equity securities by the issuer and affiliated purchasers.
We have 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, 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 2024:
|
|
| Total Number of |
| Maximum Number (or |
| |||
Total | 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 |
| |||||
2024 | Purchased | per Share | Programs | Programs |
| ||||
April 23, 2024 | 4,369,181 | 10.00 | 4,369,181 | — |
ITEM 16F. Change in registrant’s certifying accountant
Not applicable.
ITEM 16G. Corporate governance
Our common shares are listed on the NYSE. We are therefore required to comply with certain of the NYSE’s corporate governance listing standards (the “NYSE Standards”). As a foreign private issuer, we may follow our home country’s corporate governance practices in lieu of most of the NYSE Standards. Our corporate governance practices differ in certain significant respects from those that U.S. companies must adopt in order to maintain NYSE listing and, in accordance with Section 303A.11 of the NYSE Listed Company Manual, a brief, general summary of those differences is provided as follows.
Director independence
The NYSE Standards require a majority of the membership of NYSE-listed company boards to be composed of independent directors. Neither Bermuda law, the law of our country of incorporation, nor our memorandum of association or bye-laws require a majority of our board to consist of independent directors.
At the date of this annual report, 67% of our board of directors is independent.
Non-management directors’ executive sessions
The NYSE Standards require non-management directors of NYSE-listed companies to meet at regularly scheduled executive sessions without management. Our memorandum of association and bye-laws do not require our non-management directors to hold such meetings.
141
Committee member composition
The NYSE Standards require domestic NYSE-listed companies to have a nominating/corporate governance committee and a compensation committee that are composed entirely of independent directors. Bermuda law, the law of our country of incorporation, does not impose similar requirements.
Independence of the compensation committee and its advisers
On January 11, 2013, the SEC approved NYSE listing standards that require that the board of directors of a domestic listed company consider two factors (in addition to the existing general independence tests) in the evaluation of the independence of compensation committee members: (i) the source of compensation of the director, including any consulting, advisory or other compensatory fees paid by the listed company, and (ii) whether the director has an affiliate relationship with the listed company, a subsidiary of the listed company or an affiliate of a subsidiary of the listed company. In addition, before selecting or receiving advice from a compensation consultant or other adviser, the compensation committee of a listed company will be required to take into consideration six specific factors, as well as all other factors relevant to an adviser’s independence.
Foreign private issuers, such as us, will be exempt from these requirements if home country practice is followed. Bermuda law does not impose similar requirements, so we will not be required to implement the NYSE listing standards relating to compensation committees of domestic listed companies. All of the members of our compensation committee are independent, and the charter of our compensation committee does not require the compensation committee to consider the independence of any advisers that assist them in fulfilling their duties.
Additional audit committee functions
The NYSE Standards require that audit committees of domestic companies to serve a number of functions in addition to reviewing and approving the company’s financial statements, engaging auditors and assessing their independence, and obtaining the legal and other professional advice of experts when necessary. For instance, the NYSE Standards require that the audit committee meet independently with management in a separate session in order to maximize the effectiveness of the committee’s oversight function. In addition, audit committees must obtain and review a report by the independent auditors describing the firm’s internal quality-control procedures and any issues raised by these procedures. Finally, audit committees are responsible for designing and implementing an internal audit function that assesses the company’s risk management processes and systems of internal control on an ongoing basis.
Foreign private issuers such as us are exempt from these additional requirements if home country practice is followed. Bermuda law does not impose similar requirements, and consequently, our audit committee does not perform these additional functions. Our Audit Committee is composed exclusively of independent members.
Miscellaneous
In addition to the above differences, we are not required to: make our audit and compensation committees prepare a written charter that addresses either purposes and responsibilities or performance evaluations in a manner that would satisfy the NYSE’s requirements; acquire shareholder approval of equity compensation plans in certain cases; or adopt and make publicly available corporate governance guidelines.
We are incorporated under, and are governed by, the laws of Bermuda. For a summary of some of the differences between provisions of Bermuda law applicable to us and the laws applicable to companies incorporated in Delaware and their shareholders, See “Item 10. Additional Information—B. Memorandum of association and bye-laws.”
ITEM 16H. Mine safety disclosure
Not applicable.
142
ITEM 16I. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections
Not applicable.
ITEM 16J. Insider trading policies
We have
ITEM 16K. Cybersecurity
GeoPark prioritizes cybersecurity risk management as an integral part of our overall enterprise risk management model. Our cybersecurity risk management practices provide a framework for handling cybersecurity threats and incidents and facilitating coordination across our different departments.
Beginning in 2022,
Under the NIST framework,
In 2024, we reinforced our defenses against cyber threats by enhancing our cybersecurity capabilities with the onboarding of new roles to the cybersecurity team, implementing measurement and improvement processes, and conducting a third-party assessment of our cybersecurity strategy and framework. We design and implement a cybersecurity course for employees and third parties. Additionally, we optimize our platforms using industry-leading protection systems, such as Crowd Strike, Palo Alto firewalls, Multifactor Authentication, Microsoft Defense, Darktrace, Patch Automation Software, Umbrella, and SDWAN. To strengthen our technology infrastructure and enhance data protection practices, we developed a site recovery solution for critical applications, involving redundant systems in different geographical locations and intercloud backups across multiple service providers.
143
As part of our risk management process, we seek to determine if there are any risks that have not been identified or that have not been properly assessed. Accordingly, our IT team and the Cybersecurity and Compliance Manager conduct annual reviews that inventory, evaluate, and assess cybersecurity risks, including those related to third-party service providers, at both the information and operational infrastructure level. With the goal of having an independent judgment, we complement the internal annual review with the
Following the annual review described above, mitigation plans are generated by the Cybersecurity and Compliance Manager and approved by the IT director to remove any identified risks or bring them to acceptable levels. Once approved, the IT Director and the Cybersecurity and Compliance Manager present the mitigation plans to the Audit Committee. Furthermore, we also engage a third-party cybersecurity expert for purposes of conducting an annual audit which seeks to assess and evaluate the effectiveness of cybersecurity controls currently in place. The results of the annual audit are shared with our Audit Committee.
As cyber-threats continue to evolve, we may be required to invest significant additional resources to continue modifying and enhancing our protective measures and to investigate and remediate any information security vulnerabilities. We have a cybersecurity insurance policy, and it acknowledges that evolving cyber-threats may require significant additional resources.
144
PART III
ITEM 17. Financial statements
We have responded to Item 18 in lieu of this item.
ITEM 18. Financial statements
Financial Statements are filed as part of this annual report, see pages F-1 to F-73 to this annual report.
ITEM 19. Exhibits
Exhibit no. |
| Description |
---|---|---|
1.1 |
| |
1.2 |
| |
1.3 |
| |
1.4 |
| |
2.1 |
| |
2.2 | ||
2.3 | ||
2.4 | Indenture dated January 31, 2025, among GeoPark Limited and the Bank of New York Mellon. * | |
2.5 | ||
4.1 |
| |
4.2 | ||
4.3 | ||
8.1 |
| |
11.1 | ||
12.1 |
| Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* |
12.2 |
| Certification pursuant to section 302 of the Sarbanes-Oxley Act of 2002.* |
13.1 |
| |
13.2 |
| |
15.1 | Consent of Ernst & Young Audit S.A.S. (member of Ernst & Young Global Limited). * | |
15.2 |
| Consent of Pistrelli, Henry Martin y Asociados S.A. (member of Ernst & Young Global Limited). * |
15.3 | ||
97.1 | ||
99.1 |
| |
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 | 104 Cover Page Interactive Data File (formatted in Inline XBRL and included in Exhibit 101) |
* | Filed with this Annual Report on Form 20-F. |
145
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.
| GEOPARK LIMITED | |
|
|
|
| By: | /s/ Andrés Ocampo |
|
| Name: Andrés Ocampo |
| Title: Chief Executive Officer and Director |
Date: April 2, 2025
146
INDEX TO CONSOLIDATED FINANCIAL STATEMENTS
| Page | |
Consolidated Financial Statements—GeoPark Limited | ||
Reports of Independent Registered Public Accounting Firm: |
| F-2 |
Report of Independent Registered Public Accounting Firm: | F-6 | |
Consolidated Statement of Income for the years ended December 31, 2024, 2023 and 2022. |
| F-7 |
Consolidated Statement of Comprehensive Income for the years ended December 31, 2024, 2023 and 2022. | F-8 | |
Consolidated Statement of Financial Position as of December 31, 2024 and 2023. |
| F-9 |
Consolidated Statement of Changes in Equity for the years ended December 31, 2024, 2023 and 2022. |
| F-10 |
Consolidated Statement of Cash Flows for the years ended December 31, 2024, 2023 and 2022. |
| F-11 |
| F-12 |
F-1
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of GeoPark Limited
Opinion on the Financial Statements
We have audited the accompanying consolidated statement of financial position of GeoPark Limited (the Company) as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, changes in equity and cash flows for each of the two years in the period ended December 31, 2024, 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, 2024 and 2023, and the results of its operations and its cash flows for each of the two years in the period ended December 31, 2024, 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, 2024, 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 April 2, 2025 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 Matter
The critical audit matter communicated below is a matter arising from the current period audit of the financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the financial statements and (2) involved our especially challenging, subjective or complex judgments. The communication of the critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.
F-2
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 and gas reserves that are estimated by independent reserves engineers. As described in Note 19 to the consolidated financial statements, the carrying amount of the Company’s oil and gas properties and production facilities and machinery as of December 31, 2024 was $612 million, and the DD&A expense recognized during the year was $122 million. The estimation of proved and probable oil and gas reserves requires an evaluation of inputs, such as historical oil and gas production and the future prices of oil and gas, 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 and gas reserves. | |
How We Addressed the Matter in Our Audit | We obtained an understanding, evaluated the design and tested the operating effectiveness of the Company’s 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 and gas production and future prices of oil and gas provided to the independent reserves engineers for use in the estimation of proved and probable oil and gas 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 and gas reserves estimates. Furthermore, we evaluated the completeness and accuracy of the data related to historical production and future prices of oil and gas used by the independent reserves engineers in estimating proved and probable oil and gas 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 and gas reserves amounts used in the calculations to the reserves report prepared by the independent reserves engineers. |
/s/ Ernst & Young Audit S.A.S.
We have served as the Company’s auditor since 2023.
April 2, 2025
F-3
Report of Independent Registered Public Accounting Firm
To the Shareholders and the Board of Directors of GeoPark Limited
Opinion on Internal Control over Financial Reporting
We have audited GeoPark Limited’s internal control over financial reporting as of December 31, 2024, 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, 2024, based on the COSO criteria.
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, 2024 and 2023, the related consolidated statements of income, comprehensive income, changes in equity and cash flow for each of the two years in the period ended December 31, 2024, and the related notes, and our report date April 2, 2025 expressed an unqualified opinion thereon.
Basis for Opinion
The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects.
Our audit included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.
F-4
Definition and Limitations of Internal Control Over Financial Reporting
A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.
Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.
/s/ Ernst & Young Audit S.A.S.
Bogotá, Colombia
April 2, 2025
F-5
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 income, comprehensive income, changes in equity and cash flows for the year ended December 31, 2022, and the related notes (collectively referred to as the “consolidated financial statements”) of GeoPark Limited (the Company). In our opinion, the consolidated financial statements present fairly, in all material respects, the Company’s results of operations and cash flows for the year ended December 31, 2022, in conformity with International Financial Reporting Standards Accounting Standards (IFRS) as issued by the International Accounting Standards Board (IASB).
Basis for Opinion
These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on the Company’s financial statements based on our audit. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (PCAOB) and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.
We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement, whether due to error or fraud. Our audit included performing procedures to assess the risks of material misstatement of the financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the financial statements. Our audit also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the financial statements. We believe that our audit provides a reasonable basis for our opinion.
/s/ PISTRELLI, HENRY MARTIN Y ASOCIADOS S.R.L.
Member of Ernst & Young Global Limited
We served as the Company’s auditor from 2020 to 2023.
March 8, 2023
F-6
CONSOLIDATED STATEMENT OF INCOME
Amounts in US$´000 |
| Note |
| 2024 |
| 2023 |
| 2022 |
REVENUE | 7 | | | | ||||
Commodity risk management contracts loss | 8 | — | — | ( | ||||
Production and operating costs | 9 | ( | ( | ( | ||||
Geological and geophysical expenses | 12 | ( | ( | ( | ||||
Administrative expenses | 13 | ( | ( | ( | ||||
Selling expenses | 14 | ( | ( | ( | ||||
Depreciation | 10 | ( | ( | ( | ||||
Write-off of unsuccessful exploration efforts | 19 | ( | ( | ( | ||||
Impairment loss for non-financial assets | 19-36 | | ( | | ||||
Other (expenses) income (a) | ( | ( | | |||||
OPERATING PROFIT | | | | |||||
Financial expenses | 15 | ( | ( | ( | ||||
Financial income | 15 | | | | ||||
Foreign exchange gain (loss) | 15 | | ( | | ||||
PROFIT BEFORE INCOME TAX | | | | |||||
Income tax expense | 16 | ( | ( | ( | ||||
PROFIT FOR THE YEAR | | | | |||||
Earnings per share (in US$). Basic | 18 | | | | ||||
Earnings per share (in US$). Diluted | 18 | | | |
a)
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-7
CONSOLIDATED STATEMENT OF COMPREHENSIVE INCOME
Amounts in US$´000 |
| 2024 |
| 2023 |
| 2022 |
Profit for the year | | | | |||
Other comprehensive income: |
| |||||
Items that may be subsequently reclassified to profit or loss |
| |||||
Currency translation differences | ( | | | |||
(Loss) Gain on cash flow hedges (a) | ( | | | |||
Income tax benefit (expense) relating to cash flow hedges | | ( | ( | |||
Other comprehensive (loss) profit for the year | ( | | | |||
Total comprehensive profit for the year | | | |
a) |
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-8
CONSOLIDATED STATEMENT OF FINANCIAL POSITION
Amounts in US$´000 |
| Note |
| 2024 |
| 2023 |
ASSETS | ||||||
NON-CURRENT ASSETS | ||||||
Property, plant and equipment | 19 | | | |||
Right-of-use assets | 27 | | | |||
Prepayments and other receivables | 21 | | | |||
Other financial assets | 24 | | | |||
Deferred income tax asset | 17 | | | |||
TOTAL NON-CURRENT ASSETS | | | ||||
CURRENT ASSETS | ||||||
Inventories | 22 | | | |||
Trade receivables | 23 | | | |||
Prepayments and other receivables | 21 | | | |||
Derivative financial instrument assets | 24 | | | |||
Other financial assets | 24 | | | |||
Cash and cash equivalents | 24 | | | |||
Assets held for sale | 35.3 | | | |||
TOTAL CURRENT ASSETS | | | ||||
TOTAL ASSETS | | | ||||
EQUITY | ||||||
Equity attributable to owners of the Company | ||||||
Share capital | 25.1 | | | |||
Share premium | | | ||||
Translation reserve | ( | ( | ||||
Other reserves | | | ||||
Retained earnings | | | ||||
TOTAL EQUITY | | | ||||
LIABILITIES | ||||||
NON-CURRENT LIABILITIES | ||||||
Borrowings | 26 | | | |||
Lease liabilities | 27 | | | |||
Provisions and other long-term liabilities | 28 | | | |||
Deferred income tax liability | 17 | | | |||
TOTAL NON-CURRENT LIABILITIES | | | ||||
CURRENT LIABILITIES | ||||||
Borrowings | 26 | | | |||
Lease liabilities | 27 | | | |||
Derivative financial instrument liabilities | 24 | | | |||
Current income tax liabilities | 16 | | | |||
Trade and other payables | 29 | | | |||
Liabilities associated with assets held for sale | 35.3 | | | |||
TOTAL CURRENT LIABILITIES | | | ||||
TOTAL LIABILITIES | | | ||||
TOTAL EQUITY AND LIABILITIES | | |
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-9
CONSOLIDATED STATEMENT OF CHANGES IN EQUITY
Attributable to owners of the Company | ||||||||||||
|
|
|
|
| Retained |
| ||||||
Earnings | ||||||||||||
Share | Share | Translation | Other | (Accumulated | ||||||||
Amount in US$‘000 | Capital | Premium | Reserve | Reserves | Losses) | Total | ||||||
Equity as of January 1, 2022 | | | ( | | ( | ( | ||||||
Comprehensive income: | ||||||||||||
Profit for the year | | | | | | | ||||||
Other comprehensive profit for the year | | | | | | | ||||||
Total Comprehensive profit for the year 2022 | | | | | | | ||||||
Transactions with owners: | ||||||||||||
Share-based payment (Note 31) | | | | | | | ||||||
Repurchase of shares (Note 25.1.3) | ( | ( | | | | ( | ||||||
Cash distribution (Note 25.2) | | | | ( | | ( | ||||||
Total 2022 | ( | ( | | ( | | ( | ||||||
Balances as of December 31, 2022 | | | ( | | ( | | ||||||
Comprehensive income: | ||||||||||||
Profit for the year | | | | | | | ||||||
Other comprehensive profit for the year | | | | | | | ||||||
Total Comprehensive profit for the year 2023 | | | | | | | ||||||
Transactions with owners: | ||||||||||||
Share-based payment (Note 31) | | | | | ( | | ||||||
Repurchase of shares (Note 25.1.3) | ( | ( | | | | ( | ||||||
Cash distribution (Note 25.2) | | | | ( | | ( | ||||||
Total 2023 | ( | ( | | ( | ( | ( | ||||||
Balances as of December 31, 2023 | | | ( | | | | ||||||
Comprehensive income: | ||||||||||||
Profit for the year | | | | | | | ||||||
Other comprehensive (loss) profit for the year | | | ( | ( | | ( | ||||||
Total Comprehensive (loss) profit for the year 2024 | | | ( | ( | | | ||||||
Transactions with owners: | ||||||||||||
Share-based payment (Note 31) | | | | | | | ||||||
Repurchase of shares (Note 25.1.3) | ( | ( | | | | ( | ||||||
Cash distribution (Note 25.2) | | | | ( | | ( | ||||||
Total 2024 | ( | ( | | ( | | ( | ||||||
Balances as of December 31, 2024 | | | ( | | | |
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-10
CONSOLIDATED STATEMENT OF CASH FLOWS
Amounts in US$‘000 |
| Note |
| 2024 |
| 2023 |
| 2022 |
Cash flows from operating activities | ||||||||
Profit for the year | | | | |||||
Adjustments to reconcile profit to net cash flows for: |
|
| ||||||
Income tax expense | 16 | | | | ||||
Depreciation | 10 | | | | ||||
Loss on disposal of property, plant and equipment | | | | |||||
Impairment loss for non-financial assets | 19-36 | | | | ||||
Write-off of unsuccessful exploration efforts | 19 | | | | ||||
Interest and amortization of debt issue costs | 15 | | | | ||||
Borrowings cancellation costs | 15 | | | | ||||
Amortization of other long-term liabilities | 28 | ( | ( | ( | ||||
Unwinding of long-term liabilities | 15 | | | | ||||
Share-based payment expenses | | | | |||||
Foreign exchange (gain) loss | 15 | ( | | ( | ||||
Unrealized gain on commodity risk management contracts | 8 | | | ( | ||||
Income tax paid (a) | ( | ( | ( | |||||
Changes in working capital | 5 | | ( | ( | ||||
Cash flows from operating activities – net | | | | |||||
Cash flows from investing activities | ||||||||
Purchase of property, plant and equipment | ( | ( | ( | |||||
Advance payment for acquisitions of business | 35.1 | ( | | | ||||
Proceeds from the sale of long-term assets | | | | |||||
Cash flows used in investing activities – net | ( | ( | ( | |||||
Cash flows from financing activities | ||||||||
Proceeds from borrowings | 5 | | | | ||||
Principal paid | 5 | ( | | ( | ||||
Interest paid | 5 | ( | ( | ( | ||||
Borrowings cancellation and other costs paid | 5 | | | ( | ||||
Lease payments | 5 | ( | ( | ( | ||||
Repurchase of shares | 25.1 | ( | ( | ( | ||||
Cash distribution | 25.2 | ( | ( | ( | ||||
Cash flows used in financing activities – net | ( | ( | ( | |||||
Net increase in cash and cash equivalents | | | | |||||
Cash and cash equivalents at January 1 | | | | |||||
Currency translation differences | ( | | | |||||
Cash and cash equivalents at the end of the year | | | | |||||
Cash and cash equivalents are comprised by: | ||||||||
Cash in bank and bank deposits | | | | |||||
Cash in hand | | | | |||||
Cash and cash equivalents | | | |
a) |
The accompanying notes are an integral part of these Consolidated Financial Statements.
F-11
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 2024 annual report (Form 20-F) on April 2, 2025.
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, 2024, as follows:
Lease Liability in a Sale and Leaseback - Amendments to IFRS 16
The amendments to IFRS 16 specify the requirements that a seller-lessee uses in measuring the lease liability arising in a sale and leaseback transaction, to ensure the seller-lessee does not recognize any amount of the gain or loss that relates to the right of use it retains. These amendments had no impact on the Consolidated Financial Statements of the Group.
Classification of Liabilities as Current or Non-current - Amendments to IAS 1
The amendments to IAS 1, paragraphs 69 to 76, specify the requirements for classifying liabilities as current or non-current. The amendments clarify:
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● | what is meant by a right to defer settlement; |
● | that a right to defer must exist at the end of the reporting period; |
● | that classification is unaffected by the likelihood that an entity will exercise its deferral right; and |
● | that only if an embedded derivative in a convertible liability is itself an equity instrument would the terms of a liability not impact its classification. |
In addition, it is required to disclose when a liability arising from a loan agreement is classified as non-current and the entity’s right to defer settlement is contingent on compliance with future covenants within twelve months.
These amendments had no impact on the Consolidated Financial Statements of the Group.
Supplier Finance Arrangements - Amendments to IAS 7 and IFRS 7
The amendments to IAS 7 Statement of Cash Flows and IFRS 7 Financial Instruments: Disclosures clarify the characteristics of supplier finance arrangements and require additional disclosure of such arrangements. The disclosure requirements in the amendments are intended to assist users of financial statements in understanding the effects of supplier finance arrangements on an entity’s liabilities, cash flows and exposure to liquidity risk.
As a result of implementing the amendment, the Group has provided additional disclosures about its supplier finance arrangement. Please refer to Note 24 and Note 29.
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.
Lack of exchangeability – Amendments to IAS 21
In August 2023, the IASB issued amendments to IAS 21 The Effects of Changes in Foreign Exchange Rates to specify 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.
The amendments will be effective for annual reporting periods beginning on or after January 1, 2025. Early adoption is permitted but will need to be disclosed. When applying the amendments, an entity cannot restate comparative information.
The amendments are not expected to have a material impact on the Group’s Consolidated Financial Statements.
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.
IFRS 18 also requires disclosure of newly defined management-defined performance measures, subtotals of income and expenses, and 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.
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IFRS 18, and the amendments to IAS 7, 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.
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.
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$
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, Chief Strategy, Sustainability and Legal Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports.
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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, Ecuador and Argentina 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.
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
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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 are 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 33.1.2.
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.
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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$
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
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
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effects of this recalculation are included in the Consolidated Financial Statements in the period in which this recalculation is determined and reflected as an adjustment to the provision and the corresponding property, plant and equipment asset.
2.12.2 Deferred Income
Government grants and other contributions relating to the purchase of property, plant and equipment are included in non-current liabilities as deferred income and they are credited to the Consolidated Statement of Income over the expected lives of the related assets. Grants from the government are recognized at their fair value where there is a reasonable assurance that the grant will be received and the Group will comply with all attached conditions.
2.13 Impairment of non-financial assets
Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable.
An impairment loss is recognized for the excess of the asset’s carrying amount over its recoverable amount. The recoverable amount is the higher of an asset’s fair value less costs to sell and value in use. For the purposes of assessing impairment, assets are grouped at the lowest levels for which there are separately identifiable cash flows (cash-generating units), generally a licensed area. Non-financial assets other than goodwill that suffered impairment are reviewed for possible reversal of the impairment at each reporting date.
No asset should be kept as an exploration and evaluation asset for a period of more than three years, except if it can be clearly demonstrated that the carrying value of the investment will be recoverable.
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 amount of the initial measurement of lease liability, |
● | any lease payments made at or before the commencement date less any lease incentives received, |
● | any initial direct costs, and |
● | restoration costs. |
The Group leases various offices, facilities, machinery and equipment. Lease contracts are typically made for fixed periods of
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range of different terms and conditions. Right-of-use assets are depreciated on a straight-line basis over the shorter of the lease term and the estimated useful lives of the assets.
If ownership of the leased asset transfers to the Group at the end of the lease term or the cost reflects the exercise of a purchase option, depreciation is calculated using the estimated useful life of the asset. The right-of-use assets are also subject to impairment.
2.14.2 Lease liabilities
At the commencement date of the lease, the Group recognizes lease liabilities measured at the present value of lease payments to be made over the lease term. Lease liabilities include the net present value of the following lease payments:
● | fixed payments, less any lease incentives receivable, |
● | variable lease payments that are based on an index or a rate, |
● | amounts expected to be payable by the lessee under residual value guarantees, |
● | the exercise price of a purchase option if the lessee is reasonably certain to exercise that option, and |
● | payments of penalties for terminating the lease, if the lease term reflects the lessee exercising that option. |
In calculating the present value, the lease payments are discounted using the interest rate implicit in the lease. If that rate cannot be determined, the Group’s incremental borrowing rate is used, being the rate that the lessee would have to pay to borrow the funds necessary to obtain an asset of similar value in a similar economic environment with similar terms and conditions. After the commencement date, the amount of lease liabilities is increased to reflect the accretion of interest and reduced for the lease payments made. In addition, the carrying amount of lease liabilities is remeasured if there is a modification, a change in the lease term, a change in the lease payments (e.g., changes to future payments resulting from a change in an index or rate used to determine such lease payments) or a change in the assessment of an option to purchase the underlying asset.
2.14.3 Short-term leases and leases of low-value assets
The Group applies the short-term lease recognition exemption to its short-term leases of machinery and equipment (i.e., those leases that have a lease term of 12 months or less from the commencement date and do not contain a purchase option). It also applies the lease of low-value assets recognition exemption to leases of IT equipment and small items of 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.
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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.
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.
As of December 31, 2023, the Group classified non-current assets and liabilities corresponding to the Chilean companies as held for sale due to the divestment process that was agreed to in December 2023 and which closed in January 2024. See Note 35.3.
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
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managing the financial assets and the contractual terms of the cash flows. The Group reclassifies debt investments when and only when its business model for managing those assets changes.
All financial assets not at fair value through profit or loss are initially recognized at fair value, plus transaction costs. Transaction costs of financial assets carried at fair value through profit or loss, if any, are expensed to profit or loss.
Derecognition of financial assets occurs when the rights to receive cash flows from the investments expire or are transferred and substantially all the risks and rewards of ownership have been transferred. An assessment for impairment is undertaken at each balance sheet date.
Interest and other cash flows resulting from holding financial assets are recognized in the Consolidated Statement of Income when receivable, regardless of how the related carrying amount of financial assets is measured.
Amortized cost are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. They are included in current assets, except for maturities greater than twelve months after the balance sheet date. These are classified as non-current assets. These financial assets comprise trade and other receivables and cash and cash equivalents in the Consolidated Statement of Financial Position. They arise when the Group provides money, goods or services directly to a debtor with no intention of trading the receivables. These financial assets are subsequently measured at amortized cost using the effective interest method, less provision for impairment, if applicable.
Any change in their value through impairment or reversal of impairment is recognized in the Consolidated Statement of Income. All of the Group’s financial assets are classified as amortized cost.
2.19 Other financial assets
Non-current other financial assets include contributions made for environmental obligations according to a Colombian and Brazilian government request and are restricted for those purposes.
Current other financial assets include short-term investments with original maturities up to twelve months and over three months.
2.20 Impairment of financial assets
The Group assesses on a forward-looking basis the expected credit losses associated with its debt instruments. The impairment methodology applied depends on whether there has been a significant increase in credit risk. For trade receivables, the Group applies the simplified approach permitted by IFRS 9, which requires expected lifetime losses to be recognized from initial recognition of the receivables.
2.21 Cash and cash equivalents
Cash and cash equivalents includes cash in hand, deposits held at call with banks, other short-term highly liquid investments with original maturities of three months or less that are readily convertible to known amounts of cash and which are subject to an insignificant risk of changes in value, and bank overdrafts, 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.
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2.23 Derivatives and hedging activities
Derivative financial instruments are recognized in the Consolidated Statement of Financial Position as assets or liabilities and initially and subsequently measured at fair value. They are presented as current assets or liabilities if they are expected to be settled within 12 months after the end of the reporting period.
The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy.
2.23.1 Cash flow hedges that qualify for hedge accounting
The effective portion of changes in the fair value of derivatives that are designated and qualify as cash flow hedges is recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion is recognized immediately in the Consolidated Statement of Income.
When forward contracts are used to hedge forecast transactions, the Group designates the change in fair value of the forward contract as the hedging instrument. Gains or losses relating to the effective portion of the change in the fair value of the forward contracts are recognized in Other Reserves within Equity.
Where the hedged item subsequently results in the recognition of a non-financial asset, both the deferred hedging gains and losses and the deferred time value of the option contracts or deferred forward points, if any, are included within the initial cost of the asset.
When a hedging instrument expires, or is sold or terminated, or when a hedge no longer meets the criteria for hedge accounting, any cumulative deferred gain or loss and deferred costs of hedging in Equity at that time remains in Equity until the forecast transaction occurs, resulting in the recognition of a non-financial asset. When the forecast transaction is no longer expected to occur, the cumulative gain or loss and deferred costs of hedging that were reported in Equity are immediately reclassified to the Consolidated Statement of Income.
For more information about derivatives designated as cash flow hedges please refer to Note 8.
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 8 and for more information about derivatives related to currency risk management please refer to Note 3 Currency risk.
2.24 Borrowings
Borrowings are obligations to pay cash and are recognized when the Group becomes a party to the contractual provisions of the instrument.
Borrowings are recognized initially at fair value, net of transaction costs incurred. Borrowings are subsequently stated at amortized cost; any difference between the proceeds (net of transaction costs) and the redemption value is recognized in the Consolidated Statement of Income over the period of the borrowings using the effective interest method.
Direct issue costs are charged to the Consolidated Statement of Income on an accrual basis using the effective interest method.
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2.25 Share capital
Equity comprises the following:
● | “Share capital” representing the nominal value of equity shares. |
● | “Share premium” representing the excess over nominal value of the fair value of consideration received for equity shares, net of expenses of the share issuance. |
● | “Translation reserve” representing the differences arising from translation of investments in overseas subsidiaries. |
● | “Other reserves” representing: |
- | the difference between the proceeds from transactions with non-controlling interests received against the book value of the shares acquired in subsidiaries, and |
- | the changes in the fair value of the effective portion of derivatives designated as cash flow hedges. |
● | “Retained earnings (Accumulated losses)” representing: |
- | accumulated earnings and losses, and |
- | the equity element attributable to shares granted according to IFRS 2 but not issued at year end. |
2.26 Share-based payment
The Group operates a number of equity-settled share-based compensation plans comprising share awards payments to employees and other third-party contractors. Share-based payment transactions are measured in accordance with IFRS 2.
The fair value of the share awards payments is determined at the grant date by reference to the market value of the shares, calculated using the Geometric Brownian Motion method or the Monte Carlo simulation, and recognized as an expense over the vesting period.
Service and non-market performance conditions are not taken into account when determining the grant date fair value of awards, but the likelihood of the conditions being met is assessed as part of the Group’s best estimate of the number of equity instruments that will ultimately vest. Market performance conditions are reflected within the grant date fair value. Any other conditions attached to an award, but without an associated service requirement, are considered to be non-vesting conditions. Non-vesting conditions are reflected in the fair value of an award and lead to an immediate expensing of an award unless there are also service and/or performance conditions.
No expense is recognized for awards that do not ultimately vest because non-market performance and/or service conditions have not been met. Where awards include a market or non-vesting condition, the transactions are treated as vested irrespective of whether the market or non-vesting condition is satisfied, provided that all other performance and/or service conditions are satisfied.
At each reporting date, the entity revises its estimates of the number of options that are expected to vest. It recognizes the impact of the revision to original estimates, if any, in the Consolidated Statement of Income, with a corresponding adjustment to equity.
When the awards are exercised, the Company issues new shares. The proceeds received net of any directly attributable transaction costs are credited to share capital (nominal value) and share premium.
Note 3 Financial Instruments-risk management
The Group is exposed through its operations to the following financial risks:
● | Currency risk |
● | Price risk |
● | Credit risk– concentration |
● | Funding and liquidity risk |
● | Interest rate risk |
● | Capital risk |
F-23
The policy for managing these risks is set by the Board of Directors. Certain risks are managed centrally, while others are managed locally following guidelines communicated from the corporate department. The policy for each of the above risks is described in more detail below.
Currency risk
In Colombia, Ecuador and Argentina the functional currency is the U.S. Dollar. The fluctuation of the local currencies of these countries against the U.S. Dollar, except for Ecuador where the local currency is 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 enters into derivative financial instruments in order to anticipate any currency fluctuation with respect to income taxes to be paid during the first half of the following year. In January 2023, GeoPark entered into derivative financial instruments (zero-premium collars) with local banks in Colombia, for an amount equivalent to US$
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 2024, the Colombian Peso devalued by
If the Colombian Peso and the Argentine Peso had each devalued an additional
In Brazil, the functional currency is the local currency, which is the Brazilian Real. The fluctuation of the U.S. Dollar against the Brazilian Real does not impact the loans, costs and revenues held in Brazilian Real; but it does impact the balances denominated in U.S. Dollar. Such is the case of the provision for asset retirement obligation and the lease liabilities.
During 2024, the Brazilian Real devalued by
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 Ecuador, the oil price is linked to Brent and adjusted by a differential that varies month to month and resembles Oriente crude reference.
In Brazil, prices for gas produced in the Manati field are based on a long-term off-take contract with Petrobras. The price of gas sold under this contract is denominated in Brazilian Real and is adjusted annually for inflation pursuant to the Brazilian General Market Price Index (Indice Geral de Preços do Mercado), or IGPM.
GeoPark seeks to partially mitigates its exposure to crude oil price volatility using derivatives by hedging a portion of its production for a limited period going forward. The Group uses a combination of options to manage its exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. GeoPark has also obtained credit lines from different counterparties to minimize the potential cash exposure of the derivative contracts (see Note 8).
If oil and gas prices had fallen by
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 2024, the oil and gas production was sold to
In Ecuador, oil is transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and
In Brazil, all the gas from the Manati field is sold to Petrobras, the State-owned company, which is also the operator of the Manati field (
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
The forementioned companies all have a good credit standing and despite the concentration of the credit risk, the Directors do not consider there to be a significant collection risk.
GeoPark executes oil prices hedges via over-the-counter derivatives. Should oil prices drop, the Group could stand to collect from its counterparties under the derivative contracts. The Group’s hedging counterparties are leading financial institutions and trading companies; therefore the Directors do not consider there to be a significant collection risk. See disclosure in Notes 8 and 24.
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, 2024,
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 2024, the Group maintained a cash position of US$
The Indentures governing the Company Notes 2027 include incurrence test covenants related to compliance with certain thresholds of Net Debt to Adjusted EBITDA ratio and Adjusted EBITDA to Interest ratio. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit the Group’s capacity to incur additional indebtedness, as specified in the indentures governing the Notes. As of the date of these Consolidated Financial Statements, the Group is in compliance with all the indentures’ provisions and covenants.
During the third quarter of 2024, GeoPark Argentina S.A., obtained an “AA+(arg)” credit rating from Fitch Ratings’ local Argentine affiliate, FIX, and received approval from the Argentinian securities regulator (Comisión Nacional de Valores, or “CNV” by its Spanish acronym) for the creation of a program to issue up to US$
On December 3, 2024, GeoPark Argentina S.A. executed a promissory note with AdCap Securities Argentina S.A. for Argentine Pesos
In addition to that, after the balance sheet date, the Company successfully placed senior notes in a principal amount of US$
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 US$
As of December 31, 2024, the outstanding debt affected by a variable rate is the prepayment received from Vitol in November 2024 (see Note 30.1) of US$
If the variable interest rate had increased by
As of December 31, 2024, there were
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, 2024 and 2023, GeoPark is in compliance with the debt covenant ratios associated with the Company’s Notes due 2027. See Note 26.
The following table summarizes the Group’s capital structure balances:
Amounts in US$‘000 |
| 2024 |
| 2023 | |
Total Equity | | | |||
Net Debt (a) | | | |||
Working capital (b) | | |
a) | Calculated as total debt, including ‘current and non-current borrowings’ as shown in the Consolidated Statement of Financial Position, plus the prepayment received from Vitol (see Note 30.1), less cash and cash equivalents. |
b) | Calculated as ‘current assets’ less ‘current liabilities’. |
Note 4 Accounting estimates and assumptions
Estimates and assumptions are used in preparing financial statements. Although these estimates are based on management’s best knowledge of current events and actions, actual results may differ. Estimates and judgements are continually evaluated and are based on historical experience and other factors, including expectations of future events that are believed to be reasonable under the circumstances.
The key estimates and assumptions used in these Consolidated Financial Statements are noted below:
● | The process of estimating reserves is complex. It requires significant judgements and decisions based on available geological, geophysical, engineering and economic data. The estimation of economically recoverable oil and |
F-27
natural gas reserves and related future net cash flows was performed based on the Reserve Report as of December 31, 2024, prepared by DeGolyer and MacNaughton Corp., an independent international oil and gas consulting firm based in Dallas, Texas, in line with the principles contained in the Society of Petroleum Engineers (SPE) and the Petroleum Resources Management Reporting System (PRMS) framework. |
It incorporates many factors and assumptions including:
o | expected reservoir characteristics based on geological, geophysical and engineering assessments; |
o | future production rates based on historical performance and expected future operating and investment activities; |
o | future oil and gas prices and quality differentials; |
o | assumed effects of regulation by governmental agencies; |
o | tax rates by jurisdiction; and |
o | future development and operating costs. |
Management believes these factors and assumptions are reasonable based on the information available to them at the time of preparing the estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impacting oil and gas prices and costs change.
Such changes may impact the Group’s reported financial position and results, which include: (a) the carrying value of exploration and evaluation assets; oil and gas properties and other property, plant and equipment; may be affected due to changes in estimated future cash flows, (b) depreciation and amortization charges in the Consolidated Statement of Income may change where such charges are determined using the unit of production method, or where the useful life of the related assets change, (c) provisions for abandonment may require revision -where changes to reserves estimates affect expectations about when such activities will occur and the associated cost of these activities- and, (d) the recognition and carrying value of deferred income tax assets may change due to changes in the judgements regarding the existence of such assets and in estimates of the likely recovery of such assets.
● | Cash flows estimates for impairment assessments of non-financial assets require assumptions about three primary elements: future prices, reserves and discount rate (weighted average cost of capital). Estimates of future prices require significant judgments about highly uncertain future events. Historically, oil and gas prices have exhibited significant volatility. The Group’s forecasts for oil and gas revenues are based on prices derived from future price forecasts amongst industry analysts and internal assessments. Estimates of future cash flows are generally based on assumptions of long-term prices and operating and development costs, and are also sensitive to the applicable discount rate for each cash-generating unit. Given the significant assumptions required and the possibility that actual conditions may differ, management considers the assessment of impairment to be a critical accounting estimate (see Note 36). |
● | The Group adopted the successful efforts method of accounting. The Management of the Group makes assessments and estimates regarding whether an exploration and evaluation asset should continue to be carried forward as such when insufficient information exists. This assessment is made on a quarterly basis considering the advice from qualified experts. |
The application of the Group’s accounting policy for exploration and evaluation expenditure requires judgement to determine whether future economic benefits are likely from future either exploitation or sale, or whether activities have not reached a stage which permits a reasonable assessment of the existence of reserves. The determination of reserves and resources is, in itself, an estimation process that involves varying degrees of uncertainty depending on how the resources are classified. These estimates directly impact when the Group defers exploration and evaluation expenditure. The deferral policy requires management to make certain estimates and assumptions about future events and circumstances, in particular, whether an economically viable extraction operation can be established. Any such estimates and assumptions may change as new information becomes available. If, after expenditure is capitalized, information becomes available suggesting that the recovery of the
F-28
expenditure is unlikely, the relevant capitalized amount is written-off in the Consolidated Statement of Income in the period when the new information becomes available.
● | Oil and gas assets held in property plant and equipment are mainly depreciated on a unit of production (“UOP”) basis at a rate calculated by reference to proven and probable reserves and incorporating the estimated future cost of developing and extracting those reserves. Future development costs are estimated using assumptions as to the numbers of wells required to produce those reserves, the cost of the wells and future production facilities. This results in a depreciation charge proportional to the depletion of the anticipated remaining production from the block. |
The life of each item, which is assessed at least annually, has regard to both its physical life limitations and present assessments of economically recoverable reserves of the block at which the asset is located. These calculations require the use of estimates and assumptions, including the amount of recoverable reserves and estimates of future capital expenditure. The calculation of the UOP rate of depreciation will be impacted to the extent that actual production in the future is different from current forecast production based on total proved and probable reserves, or future capital expenditure estimates change. Changes to proved and probable reserves could arise due to changes in the factors or assumptions used in estimating reserves, including: (a) the effect on proved and probable reserves of differences between actual commodity prices and commodity price assumptions and (b) unforeseen operational issues.
● | Obligations related to the abandonment of wells once operations are terminated may result in the recognition of significant obligations. Estimating the future abandonment costs is difficult and requires management to make estimates and judgments because most of the obligations are many years in the future. Technologies and costs are constantly changing as well as political, environmental, safety and public relations considerations. The Group has adopted the following criterion for recognizing well plugging and abandonment related costs: the present value of future costs necessary for well plugging and abandonment is calculated for each area at the present value of the estimated future expenditure. The liabilities recognized are based upon estimated future abandonment costs, wells subject to abandonment, time to abandonment, and future inflation rates. |
The expected timing, extent and amount of expenditure may also change, for example, in response to changes in oil and gas reserves or changes in laws and regulations or their interpretation. Therefore, significant estimates and assumptions are made in determining the provision for decommissioning. As a result, there could be significant adjustments to the provisions established which would affect future financial results.
The provision at reporting date represents management’s best estimate of the present value of the future abandonment costs required.
● | From time to time, the Group may be subject to various lawsuits, claims and proceedings that arise in the normal course of business, including employment, commercial, tax, environmental, safety and health matters. For example, from time to time, the Group receives notice of environmental, health and safety violations. Based on what the Group’s Management currently knows, such claims are not expected to have a material impact on the Consolidated Financial Statements. |
Note 5 Consolidated Statement of Cash Flows
The Consolidated Statement of Cash Flows shows the Group’s cash flows for the year for operating, investing and financing activities and the change in cash and cash equivalents during the year.
Cash flows from operating activities are computed from the results for the year adjusted for non-cash operating items, changes in net working capital and corporate tax. Income tax paid is presented as a separate item under operating activities.
F-29
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:
Amounts in US$‘000 |
| Note | 2024 |
| 2023 |
| 2022 | |
Increase (Decrease) in asset retirement obligation | 28 | | | ( | ||||
Increase (Decrease) in provisions for other long-term liabilities | | | ( | |||||
Purchase of property, plant and equipment on deferred terms | — | ( | | |||||
Additions / changes in estimates of right-of-use assets | 27 | | | |
Changes in working capital shown in the Consolidated Statement of Cash Flows are disclosed as follows:
Amounts in US$‘000 |
| 2024 |
| 2023 |
| 2022 |
Decrease (Increase) in Inventories | | ( | ( | |||
Decrease (Increase) in Trade receivables | | | ( | |||
Increase in Prepayments and other receivables and Other assets (a) | ( | ( | ( | |||
Customer advance payments (b) | | — | | |||
(Decrease) Increase in Trade and other payables | ( | | ( | |||
| ( | ( |
a) | Includes withholding taxes from clients for US$ |
b) | Funds drawn under the offtake and prepayment agreement with Vitol (see Note 30.1). |
F-30
The following chart shows the movements in the borrowings and lease liabilities for each of the periods presented:
|
| Lease |
| |||
Amounts in US$‘000 | Borrowings | Liabilities | Total | |||
As of January 1, 2022 | | | | |||
Addition to lease liabilities | — | | | |||
Accrual of borrowing's interests | | — | | |||
Exchange difference | — | ( | ( | |||
Foreign currency translation | | | | |||
Unwinding of discount | — | | | |||
Principal paid | ( | — | ( | |||
Interest paid | ( | — | ( | |||
Borrowings cancellation costs | | — | | |||
Borrowings cancellation and other costs paid | ( | — | ( | |||
Lease payments | — | ( | ( | |||
As of December 31, 2022 | | | | |||
Addition to lease liabilities | — | | | |||
Accrual of borrowing's interests | | — | | |||
Exchange difference | — | | | |||
Liabilities associated with assets held for sale (Note 35.3) | — | ( | ( | |||
Foreign currency translation | — | | | |||
Unwinding of discount | — | | | |||
Interest paid | ( | — | ( | |||
Lease payments | — | ( | ( | |||
As of December 31, 2023 | | | | |||
Addition to lease liabilities | — | | | |||
Proceeds from borrowings | | — | | |||
Accrual of borrowing's interests | | — | | |||
Exchange difference | — | ( | ( | |||
Disposal of Chilean business | — | ( | ( | |||
Foreign currency translation | | ( | ( | |||
Unwinding of discount | — | | | |||
Principal paid | ( | — | ( | |||
Interest paid | ( | — | ( | |||
Lease payments | — | ( | ( | |||
As of December 31, 2024 | | | |
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, Chief Strategy, Sustainability and Legal Officer and Chief People Officer. This committee reviews the Group’s internal reporting in order to assess performance and allocate resources. Management has determined the operating segments based on these reports. The committee considers the business from a geographic perspective. 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 |
| Colombia |
| Ecuador |
| Brazil (a) |
| Chile (b) |
| Argentina |
| Corporate |
| Total |
2024 | ||||||||||||||
Revenue | | | | | | | | |||||||
Sale of crude oil | | | | | | | | |||||||
Sale of purchased crude oil | — | — | — | — | — | | | |||||||
Sale of gas | | | | | | | | |||||||
Commodity risk management contracts designated as cash flow hedges | ( | — | — | — | — | — | ( | |||||||
Production and operating costs | ( | ( | ( | ( | | ( | ( | |||||||
Royalties in cash | ( | | ( | ( | | | ( | |||||||
Economic rights in cash | ( | — | — | — | — | — | ( | |||||||
Share-based payment | ( | ( | | | | | ( | |||||||
Operating costs | ( | ( | ( | ( | | ( | ( | |||||||
Adjusted EBITDA | | | ( | ( | ( | ( | | |||||||
Depreciation | ( | ( | ( | — | ( | ( | ( | |||||||
Write-off of unsuccessful exploration efforts | ( | ( | ( | | | | ( | |||||||
Total assets | | | | — | | | | |||||||
Purchase of property, plant and equipment | | | | — | — | — | |
(a) | Production in the Manati gas field was temporarily suspended since mid-March 2024 due to unscheduled maintenance activities. |
(b) | Divested in January 2024. See Note 35.3. |
Amounts in US$ ‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile (a) |
| Argentina |
| Corporate |
| Total |
2023 | ||||||||||||||
Revenue | | | | | | | | |||||||
Sale of crude oil | | | | | | | | |||||||
Sale of purchased crude oil | — | — | — | — | — | | | |||||||
Sale of gas | | | | | | | | |||||||
Commodity risk management contracts designated as cash flow hedges | ( | | | | | | ( | |||||||
Production and operating costs | ( | ( | ( | ( | | ( | ( | |||||||
Royalties in cash | ( | | ( | ( | | | ( | |||||||
Economic rights in cash | ( | | | | | | ( | |||||||
Share-based payment | ( | ( | | ( | | | ( | |||||||
Operating costs | ( | ( | ( | ( | | ( | ( | |||||||
Adjusted EBITDA | | | | | ( | ( | | |||||||
Depreciation | ( | ( | ( | ( | ( | ( | ( | |||||||
Recognition of impairment losses | — | — | — | ( | — | — | ( | |||||||
Write-off of unsuccessful exploration efforts | ( | | | | | | ( | |||||||
Total assets | | | | | | | | |||||||
Purchase of property, plant and equipment | | | | | | | |
(a) | Divested in January 2024. See Note 35.3. |
F-32
Amounts in US$ ‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile (a) |
| Argentina |
| Corporate |
| Total |
2022 | ||||||||||||||
Revenue | | | | | | | | |||||||
Sale of crude oil | | | | | | | | |||||||
Sale of purchased crude oil | — | — | — | — | — | | | |||||||
Sale of gas | | | | | | | | |||||||
Realized loss on commodity risk management contracts | ( | | | | | | ( | |||||||
Production and operating costs | ( | ( | ( | ( | ( | ( | ( | |||||||
Royalties in cash | ( | | ( | ( | ( | | ( | |||||||
Economic rights in cash | ( | — | — | — | — | — | ( | |||||||
Share-based payment | ( | ( | | ( | | | ( | |||||||
Operating costs | ( | ( | ( | ( | ( | ( | ( | |||||||
Adjusted EBITDA | | | | | ( | ( | | |||||||
Depreciation | ( | ( | ( | ( | ( | ( | ( | |||||||
Write-off of unsuccessful exploration efforts | ( | ( | | | | | ( | |||||||
Total assets | | | | | | | | |||||||
Purchase of property, plant and equipment | | | | | | | |
(a) | Divested in January 2024. See Note 35.3. |
A reconciliation of Adjusted EBITDA to Profit for the year is provided as follows:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Adjusted EBITDA | | | | |||
Unrealized gain on commodity risk management contracts | — | — | | |||
Depreciation | ( | ( | ( | |||
Share-based payment | ( | ( | ( | |||
Write-off of unsuccessful exploration efforts | ( | ( | ( | |||
Impairment loss for non-financial assets | — | ( | — | |||
Lease accounting - IFRS 16 | | | | |||
Others (a) | | ( | | |||
Operating profit | | | | |||
Financial expenses | ( | ( | ( | |||
Financial income | | | | |||
Foreign exchange gain (loss) | | ( | | |||
Profit before tax | | | | |||
Income tax expense | ( | ( | ( | |||
Profit for the year | | | |
a) | Includes allocation to capitalized projects (Note 12). In 2024, also includes additions to provisions for environmental and tax contingencies in Brazil of US$ |
F-33
Note 7 Revenue
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Sale of crude oil | | | | |||
Sale of purchased crude oil | | | | |||
Sale of gas | | | | |||
Commodity risk management contracts designated as cash flow hedges (a) | ( | ( | — | |||
| | |
(a) | Realized result on commodity risk management contracts designated as cash flow hedges. See Note 8. |
Note 8 Commodity risk management contracts
The Group has entered into derivative financial instruments to manage its exposure to oil price risk. These derivatives are zero-premium collars and were placed with major financial institutions and commodity traders. The Group entered into the derivatives under ISDA Master Agreements and Credit Support Annexes, which provide credit lines for collateral posting thus alleviating possible liquidity needs under the instruments and protect the Group from potential non-performance risk by its counterparties.
The Group’s derivatives that hedge cash flows from the sales of crude oil for periods through December 31, 2022, were accounted for as non-hedge derivatives and therefore all changes in the fair values of these derivative contracts were recognized immediately as gains or losses in the results of the periods in which they occurred as part of the ‘Commodity risk management contracts’ line item in the Consolidated Statement of Income.
The table below summarizes the results on non-hedge derivative commodity risk management contracts:
| 2024 |
| 2023 |
| 2022 | |
Realized loss on commodity risk management contracts | — | — | ( | |||
Unrealized gain on commodity risk management contracts | — | — | | |||
— | — | ( |
The Group’s derivatives that hedge cash flows from the sales of crude oil for periods from January 1, 2023, onwards are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in ‘Other Reserves’ within ‘Equity’. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in ‘Other Reserves’ is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the ‘Revenue’ line item in the Consolidated Statement of Income.
The following table presents the Group’s production hedged during the year ended December 31, 2024, and for the following periods as a consequence of the derivative contracts in force as of December 31, 2024:
Period |
| Reference |
| Type |
| Volume |
| Weighted average |
January 1, 2024 - March 31, 2024 | ICE BRENT | | ||||||
April 1, 2024 - June 30, 2024 | ICE BRENT | | ||||||
July 1, 2024 - August 31, 2024 | ICE BRENT | | ||||||
September 1, 2024 - September 30, 2024 | ICE BRENT | | ||||||
October 1, 2024 - December 31, 2024 | ICE BRENT | | ||||||
January 1, 2025 - March 31, 2025 | ICE BRENT | | ||||||
April 1, 2025 - June 30, 2025 | ICE BRENT | | ||||||
July 1, 2025 - August 31, 2025 | ICE BRENT | | ||||||
September 1, 2025 - September 30, 2025 | ICE BRENT | |
F-34
Note 9 Production and operating costs
Amounts in US$ '000 |
| 2024 |
| 2023 |
| 2022 |
Staff costs (Note 11) | | | | |||
Share-based payment (Note 11) | | | | |||
Royalties in cash (a) | | | | |||
Economic rights in cash (a) | | | | |||
Well and facilities maintenance | | | | |||
Operation and maintenance | | | | |||
Consumables (b) | | | | |||
Equipment rental | | | | |||
Transportation costs | | | | |||
Field camp | | | | |||
Safety and insurance costs | | | | |||
Personnel transportation | | | | |||
Consultant fees | | | | |||
Gas plant costs | | | | |||
Non-operated blocks costs (c) | | | | |||
Crude oil stock variation | | | ( | |||
Purchased crude oil | | | | |||
Other costs | | | | |||
| | |
a) | Royalties and economic rights in Colombia are payable to the National Hydrocarbons Agency (“ANH”) and are determined on a field-by-field basis depending on different variables such as crude quality and price levels, among others (see Note 33.1). During 2024 and 2023, the mix of royalties and economic rights paid “in-kind” increased as compared to royalties and economic rights paid ‘in-cash”. These changes caused variations in the ‘royalties in cash’ and ‘economic rights in cash’ line items from year to year, which are compensated by variations in the quantities of oil sales impacting the ‘Revenue’ line item in the Consolidated Statement of Income. |
b) | Consumables include energy costs of US$ |
c) | Non-operated block costs show the increase in activities in the CPO-5 and Perico Blocks in Colombia and Ecuador, respectively. |
F-35
Note 10 Depreciation
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Depreciation of property, plant and equipment (Note 19) | ||||||
Oil and gas properties | | | | |||
Production facilities and machinery | | | | |||
Furniture, equipment and vehicles | | | | |||
Buildings and improvements | | | | |||
| | | ||||
Depreciation associated with crude oil stock variation | ||||||
Capitalized costs for oil stock variation | | | ( | |||
| | ( | ||||
Depreciation of right-of-use assets (Note 27) | ||||||
Production facilities and machinery | | | | |||
Buildings and improvements | | | | |||
| | | ||||
Depreciation total | | | | |||
Related to: | ||||||
Productive assets | | | | |||
Administrative assets | | | | |||
Depreciation total | | | |
Note 11 Staff costs and Directors’ Remuneration
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Wages and salaries | | | | |||
Share-based payments (Note 31) | | | | |||
Social security charges | | | | |||
Director’s fees and allowance | | | | |||
| | | ||||
Recognized as follows: | ||||||
Production and operating costs | | | | |||
Geological and geophysical expenses | | | | |||
Administrative expenses | | | | |||
Selling expenses | | | | |||
| | | ||||
Board of Directors’ and key managers’ remuneration | ||||||
Salaries and fees | | | | |||
Share-based payments | | | | |||
Other benefits in kind | — | — | | |||
| | |
F-36
Directors’ Remuneration
| Non-Executive |
| Director Fees |
| Cash Equivalent | |
Directors’ Fees | Paid in Shares | Total Remuneration | ||||
(in US$) | (No. of Shares) | (in US$) | ||||
James F. Park (a) | | | — | |||
Andrés Ocampo (b) | | | — | |||
Robert Bedingfield (c) | | | | |||
Constantin Papadimitriou (d) | | | | |||
Somit Varma (e) | | | | |||
Sylvia Escovar Gomez (f) | | | | |||
Brian Maxted (g) | | | | |||
Carlos Macellari (h) | | | | |||
Marcela Vaca (i) | | | |
(a) | Mr. Park has a consulting agreement with the Company to act as CEO advisor and provide support and assistance in addition to his role as Vice Chairman, non-executive Director and Strategy and Risk Committee Chairman, and he relinquished his fees as a member of the Board. |
(b) | Mr. Ocampo has a service contract to act as Chief Executive Officer, and he is not entitled to receive additional compensation as a member of the Board. |
(c) | Audit Committee Chairman. |
(d) | Compensation Committee Chairman. |
(e) | Nomination and Corporate Governance Committee Chairman. |
(f) | Independent Chair of the Board. |
(g) | Technical Committee Chairman. |
(h) | Mr. Macellari had a service contract to act as interim Chief Exploration and Development Officer from June 1, 2024, to December 31, 2024. During this period, he was not entitled to receive compensation as a member of the Board. |
(i) | SPEED Committee Chairman. |
Note 12 Geological and geophysical expenses
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Staff costs (Note 11) | | | | |||
Share-based payment (Note 11) | | | | |||
Communication and IT costs | | | | |||
Consultant fees | | | | |||
Allocation to capitalized project | ( | ( | ( | |||
Other services | | | | |||
| | |
Note 13 Administrative expenses
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Staff costs (Note 11) | | | | |||
Share-based payment (Note 11) | | | | |||
Consultant fees (a) | | | | |||
Safety and insurance costs | | | | |||
Travel expenses | | | | |||
Non-operated blocks expenses (b) | | | | |||
Director’s fees and allowance (Note 11) | | | | |||
Communication and IT costs | | | | |||
Allocation to joint operations | ( | ( | ( | |||
Other administrative expenses | | | | |||
| | |
F-37
a) | The increase in consultant fees in 2024 is mainly due to advisory services related to new business efforts, including the acquisition in Argentina (“Vaca Muerta”) and the proposed acquisition of certain Repsol exploration and production assets in Colombia, detailed in Notes 35.1 and 35.2, respectively. |
b) | The increase in non-operated blocks expenses in 2024 is mainly due to the impact of higher activity on the overhead billed by the operator in the Perico and Llanos 32 Blocks in Ecuador and Colombia, respectively. |
Note 14 Selling expenses
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Staff costs (Note 11) | | | | |||
Shared-based payment (Note 11) | | | — | |||
Transportation (a) | | | | |||
Selling taxes and other | | | | |||
| | |
a) | The rise in transportation costs in 2023 is mainly attributed to deliveries at different sales points in the CPO-5 Block in Colombia. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses. |
Note 15 Financial results
Amounts in US$ '000 |
| 2024 |
| 2023 |
| 2022 |
Financial expenses | ||||||
Interest and amortization of debt issue costs | ( | ( | ( | |||
Borrowings cancellation costs | — | — | ( | |||
Bank charges and other financial results (a) | ( | ( | ( | |||
Unwinding of long-term liabilities | ( | ( | ( | |||
( | ( | ( | ||||
Financial income | ||||||
Interest received | | | | |||
| | | ||||
Foreign exchange gains and losses | ||||||
Foreign exchange gain (loss), net | | ( | | |||
Realized result on currency risk management contracts | — | | — | |||
Unrealized result on currency risk management contracts | ( | — | — | |||
| ( | | ||||
Total Financial results | ( | ( | ( |
a) | Includes costs related to the financing required for the proposed acquisition of certain Repsol exploration and production assets in Colombia (see Note 35.2) and the prepayment agreements with Vitol and Trafigura (see Note 30). |
Note 16 Income tax
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Current income tax liabilities | | | ||
| |
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Current income tax charge | ( | ( | ( | |||
Deferred income tax benefit (charge) (Note 17) | ( | | ( | |||
( | ( | ( |
F-38
The tax on the Group’s profit before tax differs from the theoretical amount that would arise using the weighted average tax rate applicable to profits of the consolidated entities as follows:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Profit before tax (a) | | | | |||
Income tax calculated at domestic tax rates applicable to Profit in the respective countries (mainly Colombia) | ( | ( | ( | |||
Tax losses where no deferred income tax benefit is recognized | ( | ( | ( | |||
Effect of currency translation on tax base | ( | | ( | |||
Changes in the income tax rate (b) | | ( | ( | |||
Write-down of deferred income tax benefits previously recognized (c) | ( | ( | ( | |||
Previously unrecognized tax losses | | | | |||
Income tax on dividends (d) | ( | ( | ( | |||
Non-taxable results (e) | | | | |||
Income tax | ( | ( | ( |
(a) | Includes tax losses from non-taxable jurisdictions (Bermuda) of US$ |
(b) | Income tax rate in Colombia includes a surcharge that varies depending on different Brent oil prices (see below). |
(c) | Includes write-down of tax losses and other deferred income tax assets in Brazil and Chile where there is insufficient evidence of future taxable profits to offset them, in accordance with the expected future cash-flows as of December 31, 2024, 2023 and 2022. |
(d) | Includes income tax payable in Spain due to dividends received from subsidiaries. |
(e) | Includes non-deductible expenses and non-taxable gains in each jurisdiction. |
Under current Bermuda law, the Company is not required to pay any taxes in Bermuda on income or capital gains. The Company has received an undertaking from the Minister of Finance in Bermuda that, in the event of any taxes being imposed, they will be exempt from taxation in Bermuda until March 2035. Additionally, Bermuda Pillar Two is applicable starting in 2025.
The statutory income tax rate in Colombia is
Income tax rates in other countries where the Group operates (Ecuador, Brazil, Argentina and Spain) ranges from
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
F-39
The Group has tax losses available which can be utilized against future taxable profit in the following countries:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Colombia | | — | | |||
Brazil (a) | | | | |||
Chile (a) (c) | — | | | |||
Argentina (b) | | | | |||
Spain (a) | — | | | |||
Total tax losses as of December 31 | | | |
a) | Taxable losses have no expiration date. |
b) | Tax losses accumulated as of December 31, 2024, are: US$ |
c) | The Chilean business was divested on January 18, 2024. |
As of December 31, 2024, deferred income tax assets in respect of tax losses in Argentina and a portion of tax losses in Brazil have not been recognized as there is insufficient evidence of future taxable profits to offset them.
Note 17 Deferred income tax
The gross movement on the deferred income tax account is as follows:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Deferred income tax as of January 1 | ( | ( | ||
Currency translation differences | ( | | ||
Income tax expense relating to cash flow hedges recognized in OCI | | ( | ||
Income statement benefit (charge) | ( | | ||
Deferred income tax as of December 31 | ( | ( |
The breakdown and movement of deferred income tax assets and liabilities as of December 31, 2024, and 2023, are as follows:
| At the |
|
| Currency |
|
| ||||
beginning | Charged to | translation | At the end | |||||||
Amounts in US$ ‘000 | of year | net profit | differences | Reclassification | of year | |||||
Deferred income tax assets | ||||||||||
Difference in depreciation rates and other | | ( | | — | ( | |||||
Tax losses | | | ( | — | | |||||
Total 2024 | | ( | ( | — | | |||||
Total 2023 | | ( | | ( | |
|
|
| Income tax expense |
|
| |||||
At the beginning | Charged to | relating to | At the end | |||||||
Amounts in US$ ‘000 | of year | net profit | cash flow hedges | Reclassification | of year | |||||
Deferred income tax liabilities | ||||||||||
Difference in depreciation rates and other | ( | ( | | — | ( | |||||
Total 2024 | ( | ( | | — | ( | |||||
Total 2023 | ( | | ( | | ( |
F-40
Note 18 Earnings per share
Amounts in US$ ‘000 except for shares |
| 2024 |
| 2023 |
| 2022 |
Numerator: Profit for the year | | | | |||
Denominator: Weighted average number of shares used in basic EPS | | | | |||
Earnings per share (US$) – basic | | | |
Amounts in US$ ‘000 except for shares |
| 2024 |
| 2023 |
| 2022 |
Weighted average number of shares used in basic EPS | | | | |||
Effect of dilutive potential common shares | ||||||
Stock awards at US$ | | | | |||
Weighted average number of common shares for the purposes of diluted earnings per shares | | | | |||
Earnings per share (US$) – diluted | | | |
Note 19 Property, plant and equipment
|
| Furniture, |
| Production |
| Buildings |
|
| Exploration |
| ||||
Oil & gas | equipment | facilities and | and | Construction in | and evaluation | |||||||||
Amounts in US$’000 | properties | and vehicles | machinery | improvements | progress | assets(a) | Total | |||||||
Cost as of January 1, 2022 | | | | | | | | |||||||
Additions / ARO change | ( | (b) | | | ( | | | | ||||||
Currency translation differences | | | | | | | | |||||||
Disposals | | ( | ( | ( | | | ( | |||||||
Write-off / Impairment | | | | | | ( | (d) | ( | ||||||
Transfers | | | | | ( | ( |
| | ||||||
Cost as of December 31, 2022 | | | | | | |
| | ||||||
Additions / ARO change | | (b) | | | | | |
| | |||||
Currency translation differences | | | | | | |
| | ||||||
Disposals | | ( | | ( | ( | |
| ( | ||||||
Write-off / Impairment | ( | (c) | | | | | ( | (e) | ( | |||||
Transfers | | | | | ( | ( | | |||||||
Assets held for sale (Note 35.3) | ( | ( | ( | ( | | | ( | |||||||
Cost as of December 31, 2023 | | | | | | | | |||||||
Additions / ARO change | | (b) | | | | | | | ||||||
Currency translation differences | ( | ( | ( | ( | | ( | ( | |||||||
Disposals | | ( | | ( | | | ( | |||||||
Write-off / Impairment | | (c) | | | | | ( | (f) | ( | |||||
Transfers | | | | | ( | ( | | |||||||
Cost as of December 31, 2024 | | | | | | | | |||||||
Depreciation and write-down as of January 1, 2022 | ( | ( | ( | ( | | | ( | |||||||
Depreciation | ( | ( | ( | ( | | | ( | |||||||
Disposals | | | | | | | | |||||||
Currency translation differences | ( | ( | ( | ( | | | ( | |||||||
Depreciation and write-down as of December 31, 2022 | ( | ( | ( | ( | | | ( | |||||||
Depreciation | ( | ( | ( | ( | | | ( | |||||||
Disposals | | | | | | | | |||||||
Currency translation differences | ( | ( | ( | ( | | | ( | |||||||
Assets held for sale (Note 35.3) | | | | | | | | |||||||
Depreciation and write-down as of December 31, 2023 | ( | ( | ( | ( | | | ( | |||||||
Depreciation | ( | ( | ( | ( | | | ( | |||||||
Disposals | | | | | | | | |||||||
Currency translation differences | | | | | | | | |||||||
Depreciation and write-down as of December 31, 2024 | ( | ( | ( | ( | | | ( | |||||||
Carrying amount as of December 31, 2022 | | | | | | | | |||||||
Carrying amount as of December 31, 2023 | | | | | | | | |||||||
Carrying amount as of December 31, 2024 | | | | | | | |
(a) | Exploration wells movement and balances are shown in the table below; mining property associated with unproved reserves and resources, seismic and other exploratory assets amount to US$ |
F-41
Amounts in US$ ‘000 |
| Total |
Exploration wells as of December 31, 2022 | | |
Additions | | |
Write-offs | ( | |
Transfers | ( | |
Exploration wells as of December 31, 2023 | | |
Additions | | |
Write-offs | ( | |
Transfers | ( | |
Exploration wells as of December 31, 2024 | |
As of December 31, 2024, the carrying amount included
(b) | Corresponds to the effect of change in estimate of assets retirement obligations. |
(c) | See Note 36. |
(d) | Corresponds to exploration costs incurred in previous years in the Tacacho and Terecay Blocks (Colombia), |
(e) | Corresponds to |
(f) | Corresponds to |
F-42
Note 20 Subsidiary undertakings
The following chart illustrates main companies of the Group structure as of December 31, 2024:
(1) | GeoPark Ecuador S.A. holds |
During the year ended December 31, 2024, the following change to the Group structure has taken place:
● | On January 18, 2024, the Chilean subsidiaries GeoPark Chile S.p.A., GeoPark Fell S.p.A., GeoPark TdF S.p.A. and GeoPark Magallanes Limitada were divested. |
● | On July 22, 2024, GeoPark Colombia, S.L.U. acquired |
● | On September 2, 2024, the Ecuadorian subsidiary, AmerisurExplor Ecuador S.A. (which, as noted in the Group’s 2023 Annual Report on Form 20-F, was a dormant company) was dissolved and liquidated. |
● | On October 24, 2024, and November 27, 2024, the new subsidiaries GPK Panama, S.A. and GPRK Holding Panama, S.A., respectively, were incorporated in Panama, as part of the process related to the proposed acquisition of certain Repsol exploration and production assets in Colombia (see Note 35.2). |
● | On December 19, 2024, GeoPark Argentina S.A. capitalized a contribution received from GeoPark Colombia S.A.S and, therefore, its updated shareholding structure became as follows: (i) GeoPark Colombia S.A.S.: |
F-43
Details of all the subsidiaries of the Group as of December 31, 2024, are set out below:
| Name and registered office |
| Ownership interest | |
Subsidiaries | ||||
(a) | Indirectly owned. |
(b) | Dormant companies. |
(c) | In process of liquidation. |
(d) | On February 11 2025, Panamanian subsidiaries GPK Panama, S.A. and GPRK Holding Panama, S.A. finalized a merger process, with GPK Panama, S.A. being the surviving company. |
F-44
Details of the joint operations of the Group as of December 31, 2024, are set out below:
| Name and registered office |
| Ownership interest | |
Joint operations | ||||
(a) | GeoPark is the operator. |
(b) | In process of divestment. See Note 37.2. |
(c) | In process of relinquishment. |
(d) | GeoPark agreed to transfer its |
Note 21 Prepayments and other receivables
Amounts in US$ '000 |
| 2024 |
| 2023 |
V.A.T. | | | ||
Income tax payments in advance | | | ||
Other prepaid taxes | | | ||
To be recovered from co-venturers (Note 34) | | | ||
Prepayments and other receivables | | | ||
Advanced payment for business transaction in Argentina (a) | | — | ||
| | |||
Classified as follows: | ||||
Current | | | ||
Non-current | | | ||
| |
(a) | This advanced payment was composed of US$ |
F-45
Movements on the Group provision for impairment of prepayments and other receivables are as follows:
Amounts in US$ '000 |
| 2024 |
| 2023 |
At January 1 | | | ||
Foreign exchange gain (loss) | ( | | ||
| |
Note 22 Inventories
Amounts in US$ '000 |
| 2024 |
| 2023 |
Crude oil | | | ||
Materials and spares | | | ||
| |
The carrying amount of inventories is not pledged as security for liabilities.
Note 23 Trade receivables
Amounts in US$ '000 |
| 2024 |
| 2023 |
Trade receivables | | | ||
| |
As of December 31, 2024, and 2023, there are
The credit period for trade receivables is
The carrying value of trade receivables is considered to represent a reasonable approximation of its fair value due to their short-term nature.
Note 24 Financial instruments by category
Assets as per statement | ||||
of financial position | ||||
Amounts in US$ '000 |
| 2024 |
| 2023 |
Financial assets at fair value through profit or loss | ||||
Derivative financial instrument assets | | | ||
| | |||
Other financial assets at amortized cost | ||||
Trade receivables (Note 23) | | | ||
To be recovered from co-venturers (Note 34) | | | ||
Other financial assets (a) | | | ||
Cash and cash equivalents (b) | | | ||
| | |||
Total financial assets | | |
(a) | Non-current other financial assets as of December 31, 2023, related to restricted deposits made for environmental obligations according to Brazilian government regulations, which were recovered and replaced by a bank guarantee in September 2024. Current other financial assets correspond to the security deposit granted in relation to the proposed acquisition of certain Repsol exploration and production assets in Colombia (see Note 35.2) and short-term investments with original maturities up to twelve months and over three months. |
(b) | Cash and cash equivalents include US$ |
F-46
Liabilities as per statement | ||||
of financial position | ||||
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Liabilities at fair value through profit and loss | ||||
Derivative financial instrument liabilities | | | ||
| | |||
Other financial liabilities at amortized cost | ||||
Trade payables | | | ||
Customer advance payments (Note 29) | | | ||
To be paid to co-venturers (Note 34) | | | ||
Lease liabilities (Note 27) | | | ||
Borrowings (Note 26) | | | ||
| | |||
Total financial liabilities | | |
24.1 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:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Trade receivables | ||||
Counterparties with an external credit rating (Moody’s, S&P, Fitch) | ||||
A3 | | | ||
Baa1 | | | ||
Baa3 | | | ||
Ba1 | | | ||
Ba2 | | | ||
B2 | | | ||
Counterparties without an external credit rating | ||||
Group 1 (a) | | | ||
Total trade receivables | | |
(a) | Group 1 – |
All trade receivables are denominated in U.S. Dollar, except in Brazil where they are denominated in Brazilian Real.
F-47
Cash at bank and other financial assets (a)
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Counterparties with an external credit rating (Moody’s, S&P, Fitch, BRC Investor Services) | ||||
Aa3 | | — | ||
A1 | | | ||
A2 | | | ||
A3 | | | ||
Baa1 | | | ||
Baa2 | | | ||
Baa3 | | | ||
Ba1 | | — | ||
Ba2 | | | ||
Ba3 | | | ||
B1 | | — | ||
B3 | | | ||
Caa1 | | — | ||
Counterparties without an external credit rating | | | ||
Total | | |
(a) | The remaining balance sheet item ‘cash and cash equivalents’ corresponds to cash on hand amounting to US$ |
24.2 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 | |
Amounts in US$ ‘000 | year | and 2 years | and 5 years | years | ||||
As of December 31, 2024 | ||||||||
Borrowings | | | | | ||||
Lease liabilities | | | | | ||||
Trade payables | | | | | ||||
Customer advance payments (Note 30.1) | | | | | ||||
To be paid to co-venturers (Note 34) | | | | | ||||
| | | | |||||
As of December 31, 2023 | ||||||||
Borrowings | | | | | ||||
Lease liabilities | | | | | ||||
Trade payables | | | | | ||||
To be paid to co-venturers (Note 34) | | | | | ||||
| | | |
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.
F-48
24.3 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).
24.3.1 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, 2024 and 2023, on a recurring basis:
|
|
| As of December 31, | |||
Amounts in US$ ‘000 | Level 1 | Level 2 | 2024 | |||
Assets | ||||||
Derivative financial instrument assets | ||||||
Commodity risk management contracts | | | | |||
Total Assets | | | | |||
Liabilities | ||||||
Derivative financial instrument liabilities | ||||||
Commodity risk management contracts | | | | |||
Total Liabilities | | | |
As of December 31, | ||||||
Amounts in US$ ‘000 | Level 1 | Level 2 | 2023 | |||
Assets | ||||||
Derivative financial instrument assets | ||||||
Commodity risk management contracts | | | | |||
Total Assets | | | | |||
Liabilities | ||||||
Derivative financial instrument liabilities | ||||||
Commodity risk management contracts | | | | |||
Total Liabilities | | | |
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, 2024.
24.3.2 Valuation techniques used to determine fair values
Specific valuation techniques used to value financial instruments include:
● | The use of quoted market prices or dealer quotes for similar instruments. |
● | The mark-to-market fair value of the Group’s outstanding derivative instruments is based on independently provided market rates and determined using standard valuation techniques, including the impact of counterparty credit risk and are within level 2 of the fair value hierarchy. |
● | The fair value of the remaining financial instruments is determined using discounted cash flow analysis. All of the resulting fair value estimates are included in level 2. |
F-49
24.3.3 Fair values of other financial instruments (unrecognized)
The Group also has a number of financial instruments which are not measured at fair value in the balance sheet. For the majority of these instruments, the fair values are not materially different to their carrying amounts, since the interest receivable/payable is either close to current market rates or the instruments are short-term in nature.
Borrowings are comprised primarily of fixed rate debt and variable rate debt with a short-term portion where interest has already been fixed. They are classified under other financial liabilities and measured at their amortized cost.
The fair value of these financial instruments as of December 31, 2024, amounts to US$
Note 25 Equity
25.1 Share capital and Share premium
Issued share capital |
| 2024 |
| 2023 |
Common stock (amounts in US$ ‘000) | | | ||
The share capital is distributed as follows: |
| |||
Common shares, of nominal US$ | | | ||
Total common shares in issue | | | ||
Authorized share capital | ||||
US$ per share | | | ||
Number of common shares (US$ | | | ||
Amount in US$ | | |
Details regarding the share capital of the Company are set out below.
25.1.1 Common shares
As of December 31, 2024, the outstanding common shares confer the following rights on the holder:
● | the right to |
● | ranking pari passu, the right to any dividend declared and payable on common shares |
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|
| Shares |
| Shares |
| |||
movement | closing | US$(`000) | ||||||
GeoPark common shares history | Month | (millions) | (millions) | Closing | ||||
Shares outstanding at the end of 2022 | | | ||||||
Stock awards | | | | |||||
Repurchase of shares | ( | | | |||||
Stock awards | | | | |||||
Repurchase of shares | ( | | | |||||
Repurchase of shares | ( | | | |||||
Repurchase of shares | ( | | | |||||
Shares outstanding at the end of 2023 | | | ||||||
Stock awards | | | | |||||
Repurchase of shares | ( | | | |||||
Stock awards | | | | |||||
Buyback program | | | | |||||
Buyback program | | | | |||||
Shares outstanding at the end of 2024 | | |
25.1.2 Stock Award Program and Other Share Based Payments
Non-Executive Directors Fees
During 2024, the Company issued
Stock Award Program and Other Share Based Payments
In March 2024,
During 2024,
On February 3, 2023,
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25.1.3 Buyback Program
The Company had recurring buyback programs to repurchase its own shares. The latest renewal took place on November 8, 2023, and established a program to repurchase up to
On March 20, 2024, GeoPark announced a tender offer to purchase up to US$
25.2 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 | US$ per share | in US$ ‘000 | |||
March 9, 2022 | March 31, 2022 | | | |||
May 11, 2022 | June 10, 2022 | | | |||
August 10, 2022 | September 8, 2022 | | | |||
November 9, 2022 | December 7, 2022 | | | |||
Cash distributions for the year ended December 31, 2022 | | |||||
March 8, 2023 | March 31, 2023 | | | |||
May 3, 2023 | May 31, 2023 | | | |||
August 9, 2023 | September 7, 2023 | | | |||
November 8, 2023 | December 11, 2023 | | | |||
Cash distributions for the year ended December 31, 2023 | | |||||
March 6, 2024 | March 28, 2024 | | | |||
May 15, 2024 | June 14, 2024 | | | |||
August 14, 2024 | September 12, 2024 | | | |||
November 6, 2024 | December 6, 2024 | | | |||
Cash distributions for the year ended December 31, 2024 | |
These distributions are deducted from Other Reserves.
Note 26 Borrowings
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Outstanding amounts as of December 31 | ||||
Notes due 2027 | | | ||
Promissory note | | — | ||
| | |||
Classified as follows: | ||||
Current | | | ||
Non-current | | |
In January 2020, the Company placed US$
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amount. The reopening was priced above par at
The indenture governing the Notes due 2027 includes incurrence test covenants that provide, among other things, that the Net Debt to Adjusted EBITDA ratio should not exceed
In August 2024, GeoPark Brasil Exploração e Produção de Petróleo e Gás Ltda. executed a loan agreement with Banco Santander for Brazilian Reais
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 GeoPark with access to up to US$
On December 3, 2024, GeoPark Argentina S.A. executed a promissory note with AdCap Securities Argentina S.A. for Argentine Pesos
As of the date of these Consolidated Financial Statements, the Group had access to the abovementioned US$
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Note 27 Leases
The Consolidated Statement of Financial Position shows the following amounts relating to leases:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
Right of use assets | ||||
Production, facilities and machinery | | | ||
Buildings and improvements | | | ||
| | |||
Lease liabilities | ||||
Current | | | ||
Non-current | | | ||
| |
The Consolidated Statement of Income shows the following amounts relating to leases:
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
| 2022 |
Depreciation charge of Right of use assets | ||||||
Production, facilities and machinery | ( | ( | ( | |||
Buildings and improvements | ( | ( | ( | |||
( | ( | ( | ||||
Unwinding of long-term liabilities (included in Financial results) | ( | ( | ( | |||
Expenses related to short-term leases (included in Production and operating cost and Administrative expenses) | ( | ( | ( | |||
Expenses related to low-value leases (included in Administrative expenses) | ( | ( | ( |
The table below summarizes the amounts of Right-of-use assets recognized and the movements during the reporting years:
Amounts in US$‘000 |
| 2024 |
| 2023 |
Right-of-use assets as of January 1 | | | ||
Additions / changes in estimates | | | ||
Foreign currency translation | ( | | ||
Assets held for sale (Note 35.3) | — | ( | ||
Depreciation | ( | ( | ||
Right-of-use assets as of December 31 | | |
The table below summarizes the amounts of Lease liabilities recognized and the movements during the reporting years:
Amounts in US$‘000 |
| 2024 |
| 2023 |
Lease liabilities as of January 1 | | | ||
Additions / changes in estimates | | | ||
Exchange difference | ( | | ||
Foreign currency translation | ( | | ||
Liabilities associated with assets held for sale (Note 35.3) | — | ( | ||
Divestment of Chilean business | ( | — | ||
Unwinding of discount | | | ||
Lease payments | ( | ( | ||
Lease liabilities as of December 31 | | |
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Note 28 Provisions and other long-term liabilities
| Asset retirement |
| Deferred |
|
| |||
Amounts in US$ ‘000 | obligation (a) | Income (b) | Other (c) | Total | ||||
As of January 1, 2023 | | | | | ||||
Addition to provision / changes in estimates | | | | | ||||
Exchange difference | | | | | ||||
Foreign currency translation | | — | ( | | ||||
Amortization | | ( | | ( | ||||
Unwinding of discount | | — | | | ||||
Amounts used during the year | ( | — | ( | ( | ||||
Liabilities associated with assets held for sale (Note 35.3) | ( | — | — | ( | ||||
As of December 31, 2023 | | | | | ||||
Addition to provision / changes in estimates | | | | | ||||
Exchange difference | | ( | ( | ( | ||||
Foreign currency translation | ( | — | | ( | ||||
Amortization | — | ( | — | ( | ||||
Unwinding of discount | | | | | ||||
Amounts used during the year | ( | — | ( | ( | ||||
As of December 31, 2024 | | | | |
(a) | The provision for ‘asset retirement obligation’ relates to the estimation of future disbursements related to the abandonment and decommissioning of oil and gas wells (see Note 4). |
(b) | ‘Deferred income’ relates to government grants and other contributions relating to the purchase of property, plant and equipment in Colombia. The amortization is in line with the related assets. |
(c) | ‘Other’ mainly includes environmental obligations in Colombia and Peru, and environmental and tax contingencies in Brazil. |
Note 29 Trade and other payables
Amounts in US$ ‘000 |
| 2024 |
| 2023 |
V.A.T | | | ||
Trade payables | | | ||
Customer advance payments (a) | | — | ||
Other short-term advance payments (b) | — | | ||
Outstanding commitments in Chile (c) | | | ||
Staff costs to be paid | | | ||
Royalties to be paid | | | ||
Taxes and other debts to be paid | | | ||
To be paid to co-venturers (Note 34) | | | ||
| | |||
Classified as follows: | ||||
Current | | | ||
Non-current | — | — |
(a) | Funds drawn under the offtake and prepayment agreement with Vitol (see Note 30.1). |
(b) | Advance payment collected in relation with the sale of the Group’s business in Chile (see Note 35.3). |
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(c) | Investment commitments in the Campanario and Isla Norte Blocks as a result of sale agreement of the Group’s business in Chile (see Note 35.3), net of amounts already incurred as of December 31, 2024. |
The average credit period (expressed as creditor days) during the year ended December 31, 2024, was
The fair value of these short-term financial instruments is not individually determined as the carrying amount is a reasonable approximation of fair value.
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, 2024, trade payables subject to supplier finance arrangements amounting to US$
Note 30 Offtake and prepayment agreements
30.1 Vitol
In May 2024, GeoPark 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, for a minimum of
As part of this transaction, GeoPark obtained access to committed funding from Vitol, with an initial limit of up to US$
30.2 Trafigura
In August 2024, GeoPark executed an offtake and prepayment agreement with C.I. Trafigura Petroleum Colombia S.A.S. (“Trafigura”), one of the world’s leading commodity traders. The offtake agreement provides for GeoPark to sell and deliver the light crude oil production from the CPO-5 Block in Colombia to Trafigura, for
As part of this transaction, GeoPark obtained access to committed funding from Trafigura for up to US$
F-56
Note 31 Share-based payment
The Group has established different stock awards programs and other share-based payment plans to incentivize the directors, executive officers and employees, enabling them to benefit from the increased market capitalization of the Company.
During 2018, GeoPark announced the 2018 Equity Incentive Plan (the “Plan”) to motivate and reward those employees, directors, consultants and advisors of the Group to perform at the highest level and to further the best interests of the Company and its shareholders. This Plan is designed as a master plan, with a
In 2020, a share-based compensation program for employees was approved for approximately
On March 8, 2022, and March 4, 2025, the Company’s Board of Directors approved pools of approximately
During 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program (“LTIP”) for executive officers. Main characteristics of the program are:
● | All executive officers are eligible. |
● | Grants are awarded annually to executive officers. |
● | The components of the Program are the following: |
- |
- |
- |
In 2022, the Compensation Committee approved grants with respect to the LTIP Executives of an estimated
On January 25, 2023, February 26, 2024, and March 25, 2025, the Compensation Committee determined that
In December 2022, the Company’s Board of Directors, based on the recommendation of the Compensation Committee, approved a Long-Term Incentive program for employees and new hirings. Main characteristics of the program are:
● | All employees (non-top management) and new hirings are eligible. |
● | -year program, with a grant date of January 2, 2023, or the date on which the employees are hired. |
● | The components of the program are the following: |
- |
- |
- |
● | The vesting date of the Performance Shares (Company and Absolute) will be on January 2, 2026. |
F-57
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 |
| Awards at |
| Charged to net profit/loss | |||||
beginning | in the year | forfeited | exercised | year end |
| 2024 |
| 2023 |
| 2022 | ||||||
Programs | No. of Shares | Amounts in US$ '000 | ||||||||||||||
Oriented to Employees | ||||||||||||||||
LTIP for Employees | | | ( | ( | | | | | ||||||||
Retention Program 2022 | | | ( | ( | | | | | ||||||||
Compensation Program 2020 | | — | — | ( | | | | | ||||||||
Oriented to Directors and Executive Officers | ||||||||||||||||
LTIP for Executives | | | ( | ( | | | | | ||||||||
Shares granted to Non-Executive Directors | | | — | ( | | | | | ||||||||
Shares granted to Executive Officers | | | ( | ( | | | | | ||||||||
Value Creation Plan 2019 | | — | — | | | | | | ||||||||
| | ( | ( | | | | |
The awards that are forfeited correspond to employees that had left the Group before vesting date.
Note 32 Interests in Joint operations
The Group has interests in joint operations, which are engaged in the exploration of hydrocarbons in Colombia, Ecuador, Brazil, and Argentina.
GeoPark is the operator in the Llanos 34, Llanos 86, Llanos 87, Llanos 104, Llanos 123, Llanos 124, Mecaya, PUT-8, PUT-9, PUT-36, Tacacho and Terecay Blocks in Colombia, and in the Espejo Block in Ecuador.
F-58
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 / |
|
|
| Other |
| Total |
| Total |
| Net Assets/ |
|
| Operating | |||
Joint operation | Interest | PP&E | Assets | Assets | Liabilities | (Liabilities) | Revenue | profit (loss) | ||||||||
2024 | ||||||||||||||||
GeoPark Colombia S.A.S. | ||||||||||||||||
Llanos 34 Block | | % | | | | ( | | | | |||||||
Llanos 32 Block | | % | | | | ( | | | | |||||||
Llanos 86 Block | | % | | | | | | | ( | |||||||
Llanos 87 Block | | % | | | | ( | | | ( | |||||||
Llanos 94 Block (a) | | % | | | — | ( | ( | | ( | |||||||
Llanos 104 Block | | % | | | | | | | ( | |||||||
Llanos 123 Block | | % | | | | ( | | | | |||||||
Llanos 124 Block | | % | | | — | ( | ( | | ( | |||||||
CPO-5 Block | | % | | | | ( | | | | |||||||
CPO-4-1 Block | | % | | | | | | | ( | |||||||
Amerisur Exploración Colombia Limitada Sucursal Colombia | ||||||||||||||||
Mecaya Block | | % | | | | ( | | | ( | |||||||
PUT-8 Block | | % | | | | ( | | | ( | |||||||
PUT-9 Block | | % | | | | | | | ( | |||||||
PUT-36 Block | | % | | | | | | | ( | |||||||
Tacacho Block | | % | | | | | | | ( | |||||||
Terecay Block | | % | | | | | | | ( | |||||||
GeoPark Ecuador S.A. | ||||||||||||||||
Espejo Block | | % | | | | ( | | | ( | |||||||
Perico Block | | % | | | | ( | | | | |||||||
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. |
| |||||||||||||||
Manati Field | | % | | | | ( | ( | | ( | |||||||
GeoPark Argentina S.A. |
| |||||||||||||||
Los Parlamentos Block | | % | | | — | ( | ( | | ( | |||||||
Puelen Block | | % | | | — | | — | | ( |
(a) | On August 14, 2024, the Llanos 94 Block working interest transferred to the joint operation partner. |
F-59
Subsidiary / |
|
|
| Other |
| Total |
| Total |
| Net Assets/ |
|
| Operating | |||
Joint operation | Interest | PP&E | Assets | Assets | Liabilities | (Liabilities) | Revenue | profit (loss) | ||||||||
2023 | ||||||||||||||||
GeoPark Colombia S.A.S. | ||||||||||||||||
Llanos 34 Block | | % | | | | ( | | | | |||||||
Llanos 32 Block | | % | | | | ( | | | | |||||||
Llanos 86 Block | | % | | | | | | | ( | |||||||
Llanos 87 Block | | % | | | | ( | | | ( | |||||||
Llanos 94 Block | | % | | | | ( | ( | | ( | |||||||
Llanos 104 Block | | % | | | | | | | ( | |||||||
Llanos 123 Block | | % | | | | ( | | | | |||||||
Llanos 124 Block | | % | | | | ( | | | ( | |||||||
CPO-5 Block | | % | | | | ( | | | | |||||||
CPO-4-1 Block | | % | | | | | | | ( | |||||||
Amerisur Exploración Colombia Limitada Sucursal Colombia | ||||||||||||||||
Mecaya Block | | % | | | | ( | | | ( | |||||||
PUT-8 Block | | % | | | | | | | ( | |||||||
PUT-9 Block | | % | | | | | | | ( | |||||||
PUT-36 Block | | % | | | | | | | ( | |||||||
Tacacho Block | | % | | | | | | | ( | |||||||
Terecay Block | | % | | | | | | | ( | |||||||
GeoPark Ecuador S.A. | ||||||||||||||||
Espejo Block | | % | | | | ( | | | ( | |||||||
Perico Block | | % | | | | ( | | | | |||||||
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. | ||||||||||||||||
Manati Field | | % | | | | ( | | | | |||||||
POT-T‑785 Block | | % | | | | | | | | |||||||
GeoPark TdF S.p.A. | ||||||||||||||||
Flamenco Block | | % | | | | ( | ( | | ( | |||||||
Campanario Block | | % | | | | ( | ( | | ( | |||||||
Isla Norte Block | | % | | | | ( | ( | | ( | |||||||
GeoPark Argentina S.A. | ||||||||||||||||
Los Parlamentos Block | | % | | | | | | | ( | |||||||
Puelen Block | | % | | | | ( | ( | | ( |
F-60
Subsidiary / |
|
|
| Other |
| Total |
| Total |
| Net Assets/ |
|
| Operating | |||
Joint operation | Interest | PP&E | Assets | Assets | Liabilities | (Liabilities) | Revenue | profit (loss) | ||||||||
2022 | ||||||||||||||||
GeoPark Colombia S.A.S. | ||||||||||||||||
Llanos 34 Block | | % | | | | ( | | | | |||||||
Llanos 32 Block | | % | | | | ( | | | | |||||||
Llanos 86 Block | | % | | | | — | | | ( | |||||||
Llanos 87 Block | | % | | | | ( | | | ( | |||||||
Llanos 94 Block | | % | | | | ( | | | ( | |||||||
Llanos 104 Block | | % | | | | — | | | ( | |||||||
Llanos 123 Block | | % | | | | — | | | ( | |||||||
Llanos 124 Block | | % | | | | — | | | ( | |||||||
CPO-5 Block | | % | | | | ( | | | | |||||||
CPO-4-1 Block | | % | | | | — | | | | |||||||
Amerisur Exploración Colombia Limitada Sucursal Colombia | ||||||||||||||||
Mecaya Block | | % | | | | ( | | | ( | |||||||
PUT-8 Block | | % | | | | — | | | ( | |||||||
PUT-9 Block | | % | | | | — | | | ( | |||||||
PUT-36 Block | | % | | | | — | | | ( | |||||||
Tacacho Block | | % | | | — | — | — | | ( | |||||||
Terecay Block | | % | | | — | — | — | | ( | |||||||
GeoPark Ecuador S.A. | ||||||||||||||||
Espejo Block | | % | | | | ( | | | ( | |||||||
Perico Block | | % | | | | ( | | | | |||||||
GeoPark Brasil Exploração y Produção de Petróleo e Gas Ltda. | ||||||||||||||||
Manati Field | | % | | | | ( | | | | |||||||
POT-T‑785 Block | | % | | | | — | | | | |||||||
GeoPark TdF S.p.A. | ||||||||||||||||
Flamenco Block | | % | | | — | ( | ( | | ( | |||||||
Campanario Block | | % | | | — | ( | ( | | ( | |||||||
Isla Norte Block | | % | | | — | ( | ( | | ( | |||||||
GeoPark Argentina S.A. | ||||||||||||||||
CN-V Block | | % | | | — | ( | ( | | ( | |||||||
Los Parlamentos Block | | % | | | — | ( | ( | | ( | |||||||
Puelen Block | | % | | | | ( | ( | | ( | |||||||
Sierra del Nevado Block | | % | | | | ( | ( | | ( |
Capital commitments are disclosed in Note 33.2.
Note 33 Commitments
33.1 Royalty and economic rights commitments
33.1.1 Royalty
In Colombia, royalties on production are payable to the Colombian Government and are determined on a field-by-field basis using the level of production sliding scale detailed below:
Average daily production in barrels |
| Production Royalty rate |
The production royalty rate depends on the crude quality. When the API is lower than
F-61
In Brazil, the Brazilian National Petroleum, Natural Gas and Biofuels Agency (ANP) is responsible for determining monthly minimum prices for petroleum produced in concessions for purposes of royalties payable with respect to production. Royalties generally correspond to a percentage ranging between
33.1.2 Overriding royalty
GeoPark is obligated to pay an overriding royalty of
33.1.3 Economic rights
According to each E&P Contract, the Colombian National Hydrocarbons Agency (“ANH”) has an economic right, offered by the operator at the moment of the ANH bid. This economic right, which is based on the production of the block after royalty discount, is equal to
When the accumulated production of each field or block (depending on each E&P contract), including the royalties’ volume, exceeds
33.2 Capital commitments
During 2024, the Group incurred investments of US$
33.2.1 Colombia
The future investment commitments assumed by GeoPark, at its working interest, are up to:
● | Llanos 104 Block: 1 exploratory well (US$ |
● | Llanos 123 Block: 1 exploratory well (US$ |
● | CPO-4-1 Block: 1 exploratory well (US$ |
● | CPO-5 Block: 3D seismic acquisition, processing and interpretation and 1 exploratory well (US$ |
● | Coati Block: 3D seismic and 2D seismic acquisition (US$ |
F-62
● | Mecaya Block: 3D seismic or 1 exploratory well (US$ |
● | PUT-8 Block: 3D seismic acquisition and reprocessing and 3 exploratory wells (US$ |
● | PUT-9 Block: 3D seismic acquisition and 2 exploratory wells (US$ |
● | PUT-14 Block: 2D seismic acquisition and 1 exploratory well (US$ |
● | The PUT-36 Block is in a preliminary phase that is suspended as of the date of these Consolidated Financial Statements. During this preliminary phase, GeoPark must request from the Ministry of Interior a certificate that indicates presence or no presence of indigenous communities and develop previous consultation, if applicable. Only when this process has been completed and the corresponding regulatory approvals have been obtained, the blocks will enter into phase 1, where the exploratory commitments are mandatory. The investment commitments for the block over |
● | Tacacho Block: 2D seismic acquisition, processing and interpretation (US$ |
● | Terecay Block: 2D seismic acquisition, processing and interpretation (US$ |
33.2.2 Ecuador
The investment commitments assumed by GeoPark, at its
33.2.3 Brazil
The future investment commitments assumed by GeoPark are up to:
● | POT-T-785 Block: electromagnetic survey before April 29, 2025 (US$ |
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● | REC-T-58 Block: 3D seismic and electromagnetic survey before August 14, 2026 (US$ |
● | REC-T-67 Block: 3D seismic and electromagnetic survey before August 14, 2026 (US$ |
● | REC-T-77 Block: 3D seismic and electromagnetic survey before August 14, 2026 (US$ |
● | POT-T-834 Block: 3D seismic and electromagnetic survey before August 14, 2026 (US$ |
33.2.4 Chile
The remaining investment commitments to be assumed
● | Campanario Block: 2 exploratory wells before April 15, 2025 (US$ |
● | Isla Norte Block: 1 exploratory well before February 9, 2025 (US$ |
As of December 31, 2024, the Group has established guarantees for its total commitments.
As part of the divesting process detailed in Note 35.3, GeoPark remains responsible for these outstanding investment commitments and consequently recognized a corresponding liability as of December 31, 2024, net investments already incurred.
Note 34 Related parties
Controlling interest
The main shareholders of GeoPark Limited as of December 31, 2024, based on Schedules 13F and 13G filed with the SEC, are:
| Common |
| Percentage of outstanding |
| |
Shareholder | shares | common shares |
| ||
James F. Park (a) | | | % | ||
Renaissance Technologies LLC (b) | | | % | ||
Socoservin Overseas SPF S.à.r.l. (c) | | | % | ||
Cobas Asset Management, SGIIC, SA (d) | | | % | ||
Other shareholders | | | % | ||
| | % |
(a) | Held by James F. Park directly and indirectly through GoodRock, LLC and Spark Resources LLC, which are controlled by Mr. Park. The information set forth above and listed in the table is based solely on the disclosure set forth in Mr. Park’s most recent Schedule 13G filed with the SEC on February 14, 2025. |
(b) | The information set forth above and listed in the table is based solely on the disclosure set forth in Renaissance’s most recent Schedule 13F filed with the SEC on February 13, 2025. |
(c) | The information set forth above and listed in the table is based solely on the disclosure set forth in Socoservin Overseas’ most recent Schedule 13G filed with the SEC on April 3, 2024. The percentage of outstanding common shares was calculated on the basis of GeoPark Limited outstanding shares as of December 31, 2024, and as such may not match the percentage in the aforementioned filing. |
(d) | The information set forth above and listed in the table is based solely on the disclosure set forth in Cobas Asset Management’s most recent Schedule 13G filed with the SEC on February 18, 2025. |
F-64
Balances outstanding and transactions with related parties
|
| Balances |
|
| ||||
Transaction | at year | |||||||
Account (Amounts in US$´000) | in the year | end | Related Party | Relationship | ||||
2024 | ||||||||
To be recovered from co-venturers | — | | Joint Operations | |||||
To be paid to co-venturers | — | ( | Joint Operations | |||||
2023 | ||||||||
To be recovered from co-venturers | — | | Joint Operations | |||||
To be paid to co-venturers | — | ( | Joint Operations | |||||
2022 | ||||||||
To be recovered from co-venturers | — | | Joint Operations | |||||
To be paid to co-venturers | — | ( | Joint Operations | |||||
Geological and geophysical expenses | | — | Carlos Gulisano | |||||
Administrative expenses | | — | Pedro E. Aylwin |
(a) | Corresponding to consultancy services. Carlos Gulisano acted as a Director of the Company until July 2022. |
(b) | Corresponding to wages and salaries acting as Director of Legal and Governance and fees for consultancy services. In addition, Aylwin, Mendoza, Luksic & Valencia Law firm, where Pedro Aylwin is a partner and has a participation through Asesorías e Inversiones A&P Ltda, provided general legal services to all the Chilean entities, in Chilean corporate, labor, environmental, regulatory, and commercial laws. |
There have been no other transactions with the Board of Directors, Executive officers, significant shareholders or other related parties during the year besides the intercompany transactions which have been eliminated in the Consolidated Financial Statements, the normal remuneration of Board of Directors and other benefits informed in Note 11.
Note 35 Business transactions
35.1 Acquisition in Argentina (“Vaca Muerta”)
On May 13, 2024, GeoPark announced that it signed a farm-out agreement with Phoenix Global Resources (“PGR”), a subsidiary of Mercuria Energy Trading (“Mercuria”), for the acquisition of non-operated working interest (“WI”) in
The agreement includes an upfront consideration of US$
In May 2024, GeoPark made an advance payment of US$
Closing of the transaction is pending customary regulatory approvals from the respective provincial governments. Upon closing, GeoPark will pay the remaining US$
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event that the transaction is not consummated, GeoPark will not be required to make any of the outstanding payments due at closing, and all advance payments made to date will be reimbursed to GeoPark.
GeoPark is currently in the process of obtaining customary regulatory approvals, a standard procedure for transactions within the sector, with timelines that are guided more by administrative deadlines than concerns regarding the viability of the transaction. Although the agreement stipulates a
period from the acceptance of the offer to complete the approval process, GeoPark and its partner have the option to extend the contractually agreed deadline for the closing of the transaction in the event of such a delay.In accordance with the acquisition method of accounting, the acquisition cost will be allocated to the underlying assets acquired and liabilities assumed based primarily upon their estimated fair values at the date of acquisition. An income approach (being the net present value of expected future cash flows) will be 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 our business model. The excess of acquisition cost, if any, over the net identifiable assets acquired represents goodwill.
35.2 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)
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
As of December 31, 2024, GeoPark recorded a security deposit of US$
35.3 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$
As part of the agreement, GeoPark remains 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. In November 2024, GeoPark signed an agreement with the new owner of the blocks to fulfil those committed activities. As of December 31, 2024, the outstanding amount to be incurred was US$
Additionally, GeoPark keeps the private right over unconventional activities that would be carried out in the Fell Block and
The divestment transaction closed on January 18, 2024, and consequently GeoPark received an additional payment of US$
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As of December 31, 2023, the amount of Property, plant and equipment and Right-of-use assets corresponding to the abovementioned subsidiaries and the liabilities associated with them have been classified as held for sale for US$
35.4 Transfer of Working Interest in the Los Parlamentos Block in Argentina
On October 27, 2023, GeoPark agreed to transfer its
35.5 Divestment of the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina
In August 2021, the Company’s Board of Directors approved the decision to evaluate farm-out or divestment opportunities to sell its
On November 3, 2021, GeoPark signed a sale and purchase and assignment agreement for a total consideration of US$
The divestment transaction closed on January 31, 2022, after the corresponding regulatory approvals were granted and GeoPark received the remaining outstanding payment from the purchaser. In April 2022, GeoPark paid a working capital adjustment amounting to US$
As of December 31, 2021, the amount of Property, plant and equipment related to the blocks and the liabilities associated with them had been classified as held for sale. Immediately before the classification as held for sale, the recoverable amount of the blocks was estimated and an impairment reversal of US$
35.6 Farm-out of the REC-T-128 Block in Brazil
In 2021, GeoPark performed a farm-out transaction to sell its
Note 36 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
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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 December 31, 2024, 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, CPO-5 and Platanillo Blocks in Colombia and the Perico Block in Ecuador. 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:
● | Future oil prices: Based on Brent price forecasts provided by international consultancy firms, weighted with internal estimates and aligned with the price curves used by DeGolyer and MacNaughton (D&M). For the first five years, the Brent prices per barrel used were as follows: US$ |
● | Price scenarios: Three scenarios (low, mid, and high) were modeled and weighted to properly reflect pricing uncertainty. |
● | Production and reserves: Production levels were projected based on certified risked P1, P2, and P3 reserves, as applicable, and linked to the price curves. |
● | Operating and structure costs: Estimated using internal historical data and consistent with GeoPark’s 2025 approved budget. |
● | Capital expenditures: Projected to reflect the drilling campaign necessary to develop certified reserves. |
● | Income taxes: Projections include expected applicable income tax rates (see Note 16). |
● | Discount rate: The post-tax discount rate was determined with reference to market participant assumptions and an assessment of GeoPark’s Weighted Average Cost of Capital (WACC) for each CGU. For the CGUs located in Colombia, a discount rate of |
● | Costs of disposal: Estimated based on GeoPark's recent similar transactions, reflecting the expenses expected to be incurred in a potential disposal process. |
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,
Amounts in US$‘000 |
| 2024 |
| 2023 |
| 2022 |
Chile (a) | | ( | | |||
| ( | |
(a) | Recognition of impairment loss in the Fell Block due to the known selling price of the related net assets in the context of the transaction described in Note 35.3 in 2023. |
With regard to the assessment of fair value less cost of disposal for the identified CGUs subject to impairment indicators, Management believes that there are no reasonably possible changes in any of the above key assumptions that would cause the carrying value of the CGUs to materially exceed its recoverable amount. A
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Note 37 Subsequent events
37.1 Borrowings
On January 31, 2025, the Company successfully placed a principal amount of US$
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
The net proceeds from the Notes due 2030 were used by the Company to repurchase part of its Notes due 2027 for a nominal amount of US$
37.2 Business transactions
37.2.1 Divestment of non-operated working interest in the Llanos 32 Block in Colombia
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$
37.2.2 Divestment of non-operated working interest in the Manati gas field in Brazil
On March 27, 2025, GeoPark signed an agreement to sell its
37.3 Cost efficiency measures
In March 2025, the Group implemented cost efficiency measures which include the immediate reduction of the workforce. These measures were undertaken to enhance cost efficiency and better align the organizational structure with the Group’s strategic objectives and operational challenges. In connection with these measures, the Group incurred termination costs of approximately US$
37.4 Other events after the reporting period
Other events after the reporting period are detailed in Notes 30.1, 31 and 35.2.
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Note 38 Supplemental information on oil and gas activities (unaudited)
The following information is presented in accordance with ASC No. 932 “Extractive Activities- Oil and Gas”, as amended by ASU 2010 - 03 “Oil and Gas Reserves. Estimation and Disclosures”, issued by FASB in January 2010 in order to align the current estimation and disclosure requirements with the requirements set in the SEC final rules and interpretations, published on December 31, 2008. This information includes the Group’s oil and gas production activities carried out in each country.
Table 1 - Costs incurred in exploration, property acquisitions and development
The following table presents those costs capitalized as well as expensed that were incurred during each of the years ended December 31, 2024, 2023 and 2022. 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.
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2024 | ||||||||||||
Acquisition of properties | ||||||||||||
Proved | | | | | | | ||||||
Unproved | | | | | | | ||||||
Total property acquisition | | | | | | | ||||||
Exploration | | | | | | | ||||||
Development (a) | | | | | | | ||||||
Total costs incurred | | | | | | |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2023 | ||||||||||||
Acquisition of properties | ||||||||||||
Proved | | | | | | | ||||||
Unproved | | | | | | | ||||||
Total property acquisition | | | | | | | ||||||
Exploration | | | | | | | ||||||
Development (a) | | | | ( | | | ||||||
Total costs incurred | | | | ( | | |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2022 | ||||||||||||
Acquisition of properties | ||||||||||||
Proved | — | | | | | — | ||||||
Unproved | — | | | | | — | ||||||
Total property acquisition | — | | | | | — | ||||||
Exploration | | | | | | | ||||||
Development (a) | | | ( | | | | ||||||
Total costs incurred | | | ( | | | |
(a) | Includes the effect of change in estimate of assets retirement obligations. |
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Table 2 - Capitalized costs related to oil and gas producing activities
The following table presents the capitalized costs as of December 31, 2024, 2023 and 2022, for proved and unproved oil and gas properties, and the related accumulated depreciation as of those dates.
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile (b) |
| Total |
As of December 31, 2024 | ||||||||||
Proved properties (a) | ||||||||||
Equipment, camps and other facilities | | — | | — | | |||||
Mineral interest and wells | | | | — | | |||||
Other uncompleted projects | | — | | — | | |||||
Unproved properties | | | | — | | |||||
Gross capitalized costs | | | | | | |||||
Accumulated depreciation | ( | ( | ( | — | ( | |||||
Total net capitalized costs | | | | | |
(a) | Includes capitalized amounts related to asset retirement obligations. |
(b) | Divested in January 2024. See Note 35.3. |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile (b) |
| Total |
As of December 31, 2023 | ||||||||||
Proved properties (a) | ||||||||||
Equipment, camps and other facilities | | | | | | |||||
Mineral interest and wells | | | | | | |||||
Other uncompleted projects | | | | | | |||||
Unproved properties | | | | | | |||||
Gross capitalized costs | | | | | | |||||
Accumulated depreciation | ( | ( | ( | ( | ( | |||||
Total net capitalized costs | | | | | |
(a) | Includes capitalized amounts related to asset retirement obligations and impairment loss recognized in Chile for US$ |
(b) | Classified as ‘Assets held for sale’ as of December 31, 2023, due to the divestment process closed in January 2024. See Note 35.3. |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Total |
As of December 31, 2022 | ||||||||||
Proved properties (a) | ||||||||||
Equipment, camps and other facilities | | | | | | |||||
Mineral interest and wells | | | | | | |||||
Other uncompleted projects | | | | | | |||||
Unproved properties | | | | — | | |||||
Gross capitalized costs | | | | | | |||||
Accumulated depreciation | ( | ( | ( | ( | ( | |||||
Total net capitalized costs | | | | | |
(a) | Includes capitalized amounts related to asset retirement obligations. |
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Table 3 - Results of operations for oil and gas producing activities
The breakdown of results of the operations shown below summarizes revenues and expenses directly associated with oil and gas producing activities for the years ended December 31, 2024, 2023 and 2022. Income tax for the years presented was calculated utilizing the statutory tax rates.
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2024 | ||||||||||||
Revenue | | | | | — | | ||||||
Production costs, excluding depreciation | ||||||||||||
Operating costs | ( | ( | ( | ( | — | ( | ||||||
Royalties and economic rights in cash | ( | | ( | ( | — | ( | ||||||
Total production costs | ( | ( | ( | ( | | ( | ||||||
Exploration expenses | ( | ( | ( | — | ( | ( | ||||||
Accretion expense (a) | ( | ( | ( | — | — | ( | ||||||
Impairment loss for non-financial assets | — | | — | — | — | — | ||||||
Depreciation, depletion and amortization | ( | ( | ( | | | ( | ||||||
Results of operations before income tax | | | ( | ( | ( | | ||||||
Income tax expense | ( | ( | | | | ( | ||||||
Results of oil and gas operations | | | ( | ( | ( | |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2023 | ||||||||||||
Revenue | | | | | | | ||||||
Production costs, excluding depreciation | ||||||||||||
Operating costs | ( | ( | ( | ( | | ( | ||||||
Royalties and economic rights in cash | ( | — | ( | ( | | ( | ||||||
Total production costs | ( | ( | ( | ( | | ( | ||||||
Exploration expenses | ( | ( | ( | ( | ( | ( | ||||||
Accretion expense (a) | ( | ( | ( | ( | | ( | ||||||
Impairment loss for non-financial assets | — | — | — | ( | | ( | ||||||
Depreciation, depletion and amortization | ( | ( | ( | ( | | ( | ||||||
Results of operations before income tax | | | | ( | ( | | ||||||
Income tax expense | ( | ( | ( | — | | ( | ||||||
Results of oil and gas operations | | | | ( | ( | |
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Year ended December 31, 2022 | ||||||||||||
Revenue | | | | | | | ||||||
Production costs, excluding depreciation | ||||||||||||
Operating costs | ( | ( | ( | ( | ( | ( | ||||||
Royalties and economic rights in cash | ( | — | ( | ( | ( | ( | ||||||
Total production costs | ( | ( | ( | ( | ( | ( | ||||||
Exploration expenses | ( | ( | — | ( | ( | ( | ||||||
Accretion expense (a) | ( | | ( | ( | | ( | ||||||
Depreciation, depletion and amortization | ( | ( | ( | ( | — | ( | ||||||
Results of operations before income tax | | | | | ( | | ||||||
Income tax expense | ( | ( | ( | ( | — | ( | ||||||
Results of oil and gas operations | | | | | ( | |
(a) | Represents accretion of ARO and other environmental liabilities. |
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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, 2024, 2023, 2022 and 2021 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, 2024, 2023, 2022 and 2021 are summarized as follows, expressed in thousands of barrels (Mbbl) and millions of cubic feet (MMcf):
As of December 31, 2024 | As of December 31, 2023 | As of December 31, 2022 | As of December 31, 2021 | |||||||||||||
| Oil and |
|
| Oil and |
|
| Oil and |
|
| Oil and |
| |||||
condensate | Natural gas | condensate | Natural gas | condensate | Natural gas | condensate | Natural gas | |||||||||
(Mbbl) | (MMcf) | (Mbbl) | (MMcf) | (Mbbl) | (MMcf) | (Mbbl) | (MMcf) | |||||||||
Net proved developed | ||||||||||||||||
Colombia (a) | | | | | | | | | ||||||||
Ecuador (b) | | | | | | | — | — | ||||||||
Brazil (c) | | | | | | | | | ||||||||
Chile (d) | | | | | | | | | ||||||||
Argentina (e) | | | | | | | | | ||||||||
Total consolidated | | | | | | | | | ||||||||
Net proved undeveloped | ||||||||||||||||
Colombia (f) | | | | | | | | | ||||||||
Ecuador (b) | | | | | | | — | — | ||||||||
Chile (d) | | | | | | | | | ||||||||
Argentina (g) | | | | | | | | | ||||||||
Total consolidated | | | | | | | | | ||||||||
Total proved reserves | | | | | | | | |
(a) | Various blocks in the Llanos Basin and the Platanillo Block in the Putumayo Basin account for |
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(b) | Perico Block accounts for |
(c) | BCAM-40 Block accounts for |
(d) | Fell Block accounted for |
(e) | Aguada Baguales, Puesto Touquet and El Porvenir Blocks accounted for |
(f) | Various blocks in the Llanos Basin account for |
(g) | Aguada Baguales Block accounted for |
Table 5 - Net proved reserves of oil, condensate and natural gas
Net proved reserves (developed and undeveloped) of oil and condensate:
Thousands of barrels |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Reserves as of December 31, 2021 | | — | | | | | ||||||
Increase (decrease) attributable to: | ||||||||||||
Revisions (a) | ( | — | ( | | — | ( | ||||||
Extensions and discoveries (b) | | | — | — | — | | ||||||
Disposal of Minerals in place (c) | — | — | — | — | ( | ( | ||||||
Production | ( | ( | ( | ( | ( | ( | ||||||
Reserves as of December 31, 2022 | | | | | — | | ||||||
Increase (decrease) attributable to: | ||||||||||||
Revisions (d) | | | | ( | — | | ||||||
Extensions and discoveries (e) | | | — | — | — | | ||||||
Production | ( | ( | ( | ( | — | ( | ||||||
Reserves as of December 31, 2023 | | | | | — | | ||||||
Increase (decrease) attributable to: | ||||||||||||
Revisions (f) | | ( | ( | — | — | | ||||||
Extensions and discoveries (g) | | — | — | — | — | | ||||||
Disposal of Minerals in place (h) | — | — | — | ( | — | ( | ||||||
Production | ( | ( | ( | ( | — | ( | ||||||
Reserves as of December 31, 2024 | | | | — | — | |
(a) | For the year ended December 31, 2022, the Group’s oil and condensate proved reserves were revised downward by |
- A decrease of
- Such decrease was partially offset by a higher average oil prices resulted in a
- Higher than expected performance from the existing wells that increase the proved reserves in Colombia (
(b) | In Colombia, the extensions and discoveries are primary due to the Cante Flamenco new field in CPO-5 Block and in Ecuador are due to the Jandaya, Yin and Tui new fields in the Perico Block and the Pashuri field in the Espejo Block. |
(c) | The disposal of minerals in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 35.5). |
(d) | For the year ended December 31, 2023, the Group’s oil and condensate proved reserves were revised upwards by |
- An increase of
- An increase of
- An increase of
- An increase of
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- Such increase was partially offset by lower-than-expected performance from the existing wells in Chile by
(e) | The extensions and discoveries are primarily due to various fields in the Llanos Basin in Colombia and the Jandaya field extension in the Perico Block in Ecuador. |
(f) | For the year ended December 31, 2024, the Group’s oil and condensate proved reserves were revised upwards by |
- An increase of
- An increase of
- Such increase was partially offset by lower average oil prices by
- A decrease of
- A decrease of
(g) | The extensions and discoveries are primarily due to the Perico new field in the CPO-5 Block and the Toritos Sur new field in the Llanos 123 Block, both in Colombia. |
(h) | The disposal of minerals in Chile is due to the divestment of the Chilean business, which closed in January 2024 (see Note 35.3). |
Net proved reserves (developed and undeveloped) of natural gas:
Millions of cubic feet |
| Colombia |
| Brazil |
| Chile |
| Argentina |
| Total |
Reserves as of December 31, 2021 | | | | | | |||||
Increase (decrease) attributable to: | ||||||||||
Revisions (a) | | ( | | — | | |||||
Disposal of Minerals in place (b) | — | — | — | ( | ( | |||||
Production | ( | ( | ( | ( | ( | |||||
Reserves as of December 31, 2022 | | | | — | | |||||
Increase (decrease) attributable to: | ||||||||||
Revisions (c) | | | ( | — | | |||||
Production | ( | ( | ( | — | ( | |||||
Reserves as of December 31, 2023 | | | | — | | |||||
Increase (decrease) attributable to: | ||||||||||
Revisions (d) | | ( | — | — | ( | |||||
Disposal of Minerals in place (e) | — | — | ( | — | ( | |||||
Production | ( | ( | ( | — | ( | |||||
Reserves as of December 31, 2024 | | | — | — | |
(a) | For the year ended December 31, 2022, the Group’s proved natural gas reserves were revised upwards by |
- An increase of proved reserves due to better performance of existing wells in Chile (
- Higher average prices resulted in an increase of
- The above was partially offset by lower-than-expected performance of Manati field in Brazil (
(b) | The disposal of minerals in Argentina is due to the decision of selling the Group’s working interest and operatorship in the Aguada Baguales, El Porvenir and Puesto Touquet Blocks in Argentina (see Note 35.5). |
(c) | For the year ended December 31, 2023, the Group’s proved natural gas reserves were revised upwards by |
(d) | For the year ended December 31, 2024, the Group’s proved natural gas reserves were revised downwards by |
(e) | The disposal of minerals in Chile is due to the divestment of Chilean business, which closed in January 2024 (see Note 35.3). |
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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 2024, 2023 and 2022 and using a
This standardized measure is not intended to be and should not be interpreted as an estimate of the market value of the Group’s reserves. The purpose of this information is to give standardized data to help the users of the financial statements to compare different companies and make certain projections. It is important to point out that this information does not include, among other items, the effect of future changes in prices, costs and tax rates, which past experience indicates that are likely to occur, as well as the effect of future cash flows from reserves which have not yet been classified as proved reserves, of a discount factor more representative of the value of money over the lapse of time and of the risks inherent to the production of oil and gas. These future changes may have a significant impact on the future net cash flows disclosed below. For all these reasons, this information does not necessarily indicate the perception the Group has on the discounted future net cash flows derived from the reserves of hydrocarbons.
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Total |
As of December 31, 2024 | ||||||||||
Future cash inflows | | | | — | | |||||
Future production costs | ( | ( | ( | — | ( | |||||
Future development costs | ( | ( | ( | — | ( | |||||
Future income taxes | ( | | ( | | ( | |||||
Undiscounted future net cash flows | | | | — | | |||||
( | ( | | — | ( | ||||||
Standardized measure of discounted future net cash flows | | | | — | | |||||
As of December 31, 2023 | ||||||||||
Future cash inflows | | | | | | |||||
Future production costs | ( | ( | ( | ( | ( | |||||
Future development costs | ( | ( | ( | ( | ( | |||||
Future income taxes | ( | ( | ( | | ( | |||||
Undiscounted future net cash flows | | | | | | |||||
( | ( | ( | | ( | ||||||
Standardized measure of discounted future net cash flows | | | | | | |||||
As of December 31, 2022 | ||||||||||
Future cash inflows | | | | | | |||||
Future production costs | ( | ( | ( | ( | ( | |||||
Future development costs | ( | ( | ( | ( | ( | |||||
Future income taxes | ( | — | ( | — | ( | |||||
Undiscounted future net cash flows | | | | | | |||||
( | ( | ( | ( | ( | ||||||
Standardized measure of discounted future net cash flows | | | | | |
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Table 7 - Changes in the standardized measure of discounted future net cash flows from proved reserves
Amounts in US$‘000 |
| Colombia |
| Ecuador |
| Brazil |
| Chile |
| Argentina |
| Total |
Present value as of December 31, 2021 | | — | | | | | ||||||
Sales of hydrocarbon, net of production costs | ( | ( | ( | ( | | ( | ||||||
Net changes in sales price and production costs | | — | ( | | | | ||||||
Changes in estimated future development costs | | ( | ( | ( | | | ||||||
Extensions and discoveries less related costs | | | | | | | ||||||
Development costs incurred | | — | | | | | ||||||
Revisions of previous quantity estimates | ( | — | ( | | | ( | ||||||
Disposal of Minerals in place | | — | | | ( | ( | ||||||
Net changes in income taxes | ( | — | | | | ( | ||||||
Accretion of discount | | — | | | | | ||||||
Present value as of December 31, 2022 | | | | | | | ||||||
Sales of hydrocarbon, net of production costs | ( | ( | ( | ( | | ( | ||||||
Net changes in sales price and production costs | ( | ( | | ( | | ( | ||||||
Changes in estimated future development costs | | ( | ( | | | ( | ||||||
Extensions and discoveries less related costs | | | | | | | ||||||
Development costs incurred | | | | | | | ||||||
Revisions of previous quantity estimates | | | | ( | | | ||||||
Net changes in income taxes | | ( | ( | | | | ||||||
Accretion of discount | | | | | | | ||||||
Present value as of December 31, 2023 | | | | | | | ||||||
Sales of hydrocarbon, net of production costs | ( | ( | | | | ( | ||||||
Net changes in sales price and production costs | ( | ( | ( | | | ( | ||||||
Changes in estimated future development costs | ( | ( | | | | ( | ||||||
Extensions and discoveries less related costs | | — | | | | | ||||||
Development costs incurred | | | | | | | ||||||
Revisions of previous quantity estimates | | ( | ( | | | | ||||||
Disposal of Minerals in place | | — | | ( | | ( | ||||||
Net changes in income taxes | | | ( | | | | ||||||
Accretion of discount | | | | | | | ||||||
Present value as of December 31, 2024 | | | | | | |
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