A. History and development of the company
General
We were incorporated as an exempted company pursuant to the laws of Bermuda in February 2006. We maintain a registered office in Bermuda at Clarendon House, 2 Church Street, Hamilton HM11, Bermuda. Our principal executive office is located at Street 94 N° 11-30, 8th floor, Bogotá, Colombia, telephone number +57 601 743 2337.
The U.S. Securities and Exchange Commission (“SEC”) maintains an internet website that contains reports, proxy, information statements and other information about issuers, like us, that file electronically with the SEC. The address of that website is www.sec.gov. Our website address is www.geo-park.com. The information contained on, or that can be accessed through, our website is not part of, and is not incorporated into, this annual report.
Our Company
We are a leading independent energy company with over 20 years of successful operations across Latin America and a long-term strategy that seeks to maintain a risk-balanced portfolio across the region’s main basins. We currently manage a portfolio of assets in Colombia and Argentina, combining low-cost, high-margin conventional production in Colombia, with an unconventional development platform in the Vaca Muerta formation in Argentina. This portfolio supports a business model focused on capital discipline, operational efficiency and long-term cash flow generation.
We are focused on growth through significant assets, basins, and plays, including our portfolio in Colombia and our recently acquired assets in the Vaca Muerta shale formation in Argentina. Our operations span both conventional and unconventional resources across a diversified regional footprint.
Colombia, our core producing base, provides cash flow supported by operational efficiencies and ongoing development opportunities. Production is primarily concentrated in the Llanos Basin, where we operate the Llanos 34 Block and participate in additional operated and non-operated assets, such as CPO-5.
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Our unconventional development position in Vaca Muerta, Argentina is expected to contribute to scale and portfolio diversification over time, subject to market conditions and operational execution. Following the closing of the Acquisition in Argentina’s Vaca Muerta Formation in October 2025, we established a new unconventional operating platform in the Neuquén Basin.
During the year ended December 31, 2025, we produced a net average of 28,322 mboepd, of which 93.2%, 1.1%, 1.8% and 3.8% were, respectively, in Colombia, Argentina, Brazil and Ecuador, and of which 98.0% was oil.
Our performance targets focus on achieving sustainable growth by mid-term (2028) and long-term (2030). We seek to leverage a robust organic footprint complemented by strategic inorganic opportunities. Our financial strategy emphasizes maintaining reasonable debt levels with appropriate maturity profiles, supported by diversified financing sources and a proactive hedging strategy aligned with our cash flow needs.
We seek to deliver competitive shareholder returns while pursuing sustainable growth. Since 2018, we have returned around US$322.9 million to shareholders through buybacks and dividends. Dividend distributions are subject to board approval, in its sole discretion, and depend on a variety of factors, including but not limited to business performance, financial condition, growth plans and other considerations.
A clear set of priorities and key values have driven us through a two-decade track record of growth, sustainability performance and value delivery. Furthermore, our internal value system SPEED, which has been part of the Group’s culture since its inception, differentiates us from our peers, guides our decision-making process and is the basis for our value-generation approach to all our stakeholders.
Meeting the energy needs of a growing population while contributing to the energy transition requires us to conduct best-in-class oil and gas exploration and operation, to manage our assets in the most ethical and sustainable way, and to continue creating long-term value for our shareholders and all our stakeholders.
Our culture
Our culture is our binding force, which we protect and nurture to excel in delivering our business model.
Our culture was forged in the field when a small team began operating in remote blocks in southern Argentina and Chile, in demanding conditions that required resilience, collaboration and a strong sense of commitment. Since then, our people have been guided by a clear and enduring purpose – Creating Value and Giving Back – which shapes how we define success and how we make decisions. For GeoPark, results are measured not only in production, reserves and cash flow, but also in the health and safety of our people and the value we create for shareholders and the communities where we operate.
Our culture underpins our ability to execute our strategy, manage risk and adapt to changing operating and market conditions, and is articulated through a set of principles that guide everyday decisions and behavior across the Company:
• We Make Things Happen and We Do Them Right: We focus on clear objectives, execute with energy and accountability, and complete what we start with excellence and efficiency, while consistently prioritizing life, health, safety and care for the environment.
• We Grow with Passion, Courage and Discipline: We treat growth as continuous improvement and the ability to turn challenges into opportunities, while managing resources prudently, honoring commitments and maintaining rigorous planning and capital discipline.
• We Simplify with Agility and Innovation: We concentrate on what truly adds value, eliminate unnecessary complexity and use technology and data to enhance decision-making and operational performance.
• We Connect through Trust and Respect: We build trust over time through consistency between words and actions, open and direct communication, constructive feedback and appreciation of diverse perspectives.
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• We are One GeoPark: We encourage collaboration across functions, assets and countries, share knowledge and best practices, and contribute to building something larger than individual responsibilities.
We view culture as a shared asset that must be understood, practiced and protected, particularly in times of uncertainty or pressure. It plays a central role in how we design and execute our strategy, how we attract and develop talent, how we build long-term relationships with stakeholders and how we seek to create value for all those connected to GeoPark.
Our business strategy
To protect the value of our core platform and position the company for renewed growth, we developed our long-term strategic plan. Such plan outlines a disciplined roadmap for potential value creation, grounded in a two-fold approach that is designed to strengthen and seek to maximize the value of our core platform in Colombia while seeking to develop a new long-term growth engine in Argentina.
Colombia remains our operational and financial backbone, providing cash generation, predictable performance, and a resilient base supported by disciplined capital allocation, enhanced recovery initiatives and sustained operational excellence.
At the same time, we are advancing the accelerated development of our unconventional position in Vaca Muerta, a strategic platform that is expected to expand and diversify our future production and cash flow profile, subject to market conditions and operational execution. Together, these two pillars form a balanced, returns-focused strategy that is designed to protect near-term value while supporting the upfront investments required to potentially transform the scale of the business, enhance long-term cash flow resilience, and deliver enduring, disciplined growth.
Our capital allocation framework is designed to balance disciplined growth, financial strength and shareholder returns, while maintaining flexibility to adapt to changing market conditions. We prioritize the allocation of capital to high-return organic investment opportunities, particularly in our core assets in Colombia and the development of our unconventional platform in Argentina. In parallel, we selectively evaluate inorganic opportunities that may enhance our portfolio, subject to strict financial and strategic criteria. We also maintain a focus on preserving a strong balance sheet, including through active liability management and deleveraging initiatives when appropriate. In addition, over time we seek to return capital to shareholders through a combination of share appreciation, dividends and occassional share repurchase programs, taking into account our financial position, market conditions and investment opportunities. This balanced approach is intended to support sustainable long-term value creation, while preserving capital discipline and financial flexibility across commodity price cycles.
Within this framework, we remain focused on consolidating and growing our core positions in Colombia and Argentina, while we continue to monitor opportunities across Latin America that are aligned with our operational capabilities and regional expertise. In this context, we are selectively monitoring developments in Venezuela. Recent regulatory actions, including the January 29, 2026 reform of the Hydrocarbons Law, together with evolving U.S. sanctions policy and the issuance of general and specific licenses by the U.S. Department of the Treasury’s Office of Foreign Assets Control (OFAC), have introduced defined pathways for potential participation, enabling engagement in the oil and gas sector. Given Venezuela’s material hydrocarbon resource base distributed across its principal producing basins (including Maracaibo, Barinas-Apure, Orinoco and Eastern basins), the country may present potential long-term opportunities.
Any potential participation would be subject to strict compliance with applicable sanctions, export controls and regulatory requirements, and would depend on the availability and continued validity of relevant authorizations, including OFAC licenses. Such participation would also be contingent on the availability of appropriate legal and contractual protections and the enforceability of the applicable regulatory framework. While we are not currently conducting operations in Venezuela, any future involvement would depend on favourable geopolitical and regulatory conditions.
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2026 work plan and outlook
As part of our work program for 2026 (the “2026 Work Program”), we intend to optimize our portfolio by focusing on maximizing value and leveraging our differentiated asset base to support sustainable long-term growth. For further information on our capital allocation methodology, please see “—Our strengths— Capital allocation methodology.”
The 2026 Work Program is designed to protect near-term cash generation, accelerate the growth of GeoPark’s unconventional assets, and position us to scale production and value through 2028.
In 2026, we estimate capital expenditures ranging from US$190.0 million to US$220.0 million to support a production target of 27,000-30,000 boepd across Colombia (24,500-26,000 boepd), and Vaca Muerta (2,500-4,000 boepd), subject to market conditions and operational execution. Our production mix is anticipated to be approximately 97% oil and 3% natural gas, with 12% unconventional and 88% conventional. We plan to drill between 27 to 36 gross wells (including 6 to 8 gross exploration wells), with approximately 86% allocated to development activities and 14% to exploration and appraisal activities.
Medium-term (2026 – 2028) guidelines
In December 2025, we introduced updated medium-term guidelines for 2026–2028, intended to provide an operational and financial outlook aligned with our disciplined growth strategy. This execution roadmap through 2028 is anchored in a two-fold strategy that combines the protection and maximization of our core production and cash generation in Colombia with a renewed growth trajectory driven by our expanding position in Vaca Muerta, Argentina.
In Colombia, we are focused on sustaining and improving the performance of our flagship Llanos 34 Block and other key operated and non-operated assets. Production reached a positive inflection point in the fourth quarter of 2025 (earlier than the previously projected 2026), and volumes are anticipated to increase in 2026, supported by effective base optimization, enhanced recovery initiatives, and strong well performance. These efforts are further underpinned by the certified 22% increase in 2P Original Oil in Place (OOIP) in the Llanos 34 Block, which we believe supports a larger resource base and may strengthen the long-term production and economic outlook of the asset. Colombia is expected to remain a key foundation for generating sustainable free cash flow, balance sheet strength, and shareholder returns.
In Vaca Muerta, Argentina, with the successful integration of the Loma Jarillosa Este and Puesto Silva Oeste Blocks, we are confident that we can unlock significant long-term growth from our position in unconventional resources in the Neuquén Basin. Our team is focusing on accelerating drilling activity to deliver a step-change in production and cash flow.
The plan anticipates a steady increase in production from approximately 27,000–30,000 boepd in 2026 to 44,000–46,000 boepd by 2028, supported by a balanced capital program of US$190–220 million in 2026, scaling to US$350–380 million in 2028. This medium-term guidance underscores our commitment to delivering sustainable growth, enhancing cash flow generation, and maintaining financial resilience while advancing development across operated and non-operated assets.
These guidelines are reviewed periodically to reflect evolving business dynamics, new developments, and changes in market, regulatory, and operational conditions. As a result, actual outcomes may differ from current expectations, and alternative scenarios may be considered as circumstances evolve.
History
We were founded in 2002. We are a leading independent energy company with operations in Latin America. During 2025, we had operations or held working interests in Colombia, Argentina, Brazil, and Ecuador.
Our history can be summarized by our growth in each country and our performance in the capital markets:
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Colombia
We entered the Colombian market in 2012 through an acquisition that provided an attractive platform of reserves and resources, including a 45% operated working interest in the Llanos 34 Block. At the time of acquisition, the Llanos 34 Block had no production or reserves. Through our disciplined operational execution and exploration expertise, we transformed the Llanos 34 Block into one of the most prolific oil blocks in Colombia, discovering 13 oil fields and drilling over 245 wells. As of December 31, 2025, the block has produced more than 198 million barrels of oil, with a gross daily production of over 38,000 bopd, and the block’s Jacana and Tigana fields ranking among Colombia’s top 12 producing oil fields.
During 2019, jointly with Hocol, an affiliate of Ecopetrol, we acquired five low-cost, low-risk and high-potential exploration blocks in the Llanos Basin, surrounding the Llanos 34 Block. Since 2023, we have drilled and brought into production oil exploration wells in the Llanos 87 and Llanos 123 Blocks, transitioning them from exploratory blocks to production, contributing 2,243 boepd to our net average production for the year ended December 31, 2025 (4,486 boepd gross). Additionally, in the Llanos 86 and Llanos 104 Blocks, the completion of 3D seismic acquisition and processing, along with the approval of environmental licenses, enabled the identification of new drilling opportunities.
In January 2020, we acquired a group of companies which owned thirteen production, development, and exploration blocks in Colombia, distributed as follows: twelve operated blocks in the Putumayo basin (including the producing Platanillo Block) and one non-operated block in the Llanos basin (the producing CPO-5 Block), a cross-border oil pipeline from Colombia to Ecuador and transportation rights through the Ecuadorian pipelines to the port of Esmeraldas. Through targeted investments and optimized field operations, the CPO-5 Block has grown from a gross production level of approximately 8,120 bopd in December 2019 to an average gross production of 21,615 bopd during the year ended December 31, 2025 (net production of 6,484 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 8 producing oil fields.
During the year ended December 31, 2025, based on statistics published by the ANH, we were among the three largest private oil operators in Colombia.
Argentina
In October 2025, we entered the Vaca Muerta shale formation in Argentina with operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta and has produced 1,234 boepd during the fourth quarter of 2025.
Brazil
Since 2013, we have participated in several Bid Rounds promoted by the Brazilian ANP. In 2014, we acquired a 10% non-operated working interest in the BCAM-40 Concession, which included an interest in the Manati gas field operated by Petrobras. Although we continue to hold certain exploratory blocks in Brazil, in March 2025 we entered into an agreement to divest our interest in the BCAM-40 Concession, with the transfer of the working interest in December 2025.
Ecuador
In May 2019, we signed participation contracts for a 50% operated working interest in the Espejo Block and a 50% non-operated working interest in the Perico Block in Ecuador. Since then, we have advanced exploration and development activities, transitioning these assets from exploration to production in 2022, when we recorded our first oil sales following the successful exploration campaign in the Perico Block. In July 2025, we entered into an agreement to divest our interests in both blocks, and the transaction closed in December 2025.
Other Latin American countries
During our history as operators, we have also had operations in Chile and Peru, and we have participated in bid rounds in Mexico. As of the date of this annual report, we do not have operations in these countries.
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Funding
In February 2014, we commenced trading on the NYSE and raised US$98 million (before underwriting commissions and expenses), including the over-allotment option granted to and exercised by the underwriters, through the issuance of 13,999,700 common shares.
Between 2005 and 2025, we raised approximately US$200 million in equity offerings at the holding company level and over US$2.2 billion through debt arrangements with multilateral agencies such as the IFC, prepayment facilities, international bond issuances and bank financings, described further below, which have been used to fund our capital expenditures program and acquisitions and to increase our liquidity.
In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. The Notes due 2027 are fully and unconditionally guaranteed by GeoPark Colombia, S.L.U. The Notes due 2027, which were partially repurchased for a nominal amount of US$405.3 million in January 2025, mature on January 17, 2027.
In May 2024, we executed an offtake and prepayment agreement with Vitol C.I. Colombia S.A.S. (“Vitol”), one of the world’s leading energy and commodity companies. The offtake agreement provides for GeoPark to sell and deliver production from the Llanos 34 Block in Colombia to Vitol. As part of this transaction, we obtained access to committed funding from Vitol. Amounts drawn under this prepayment facility can be repaid through future oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.75% per annum. In November 2024, we drew US$152.0 million under this prepayment agreement. During 2025, we repaid US$142.2 million in cash and US$7.6 million in kind from that amount and, as of December 31, 2025, US$2.2 million remained outstanding. In January 2026, we renewed this offtake and prepayment agreement, extending its term through December 31, 2028 and expanding deliveries to include Llanos 34 (beginning January 2026) and CPO-5 and Llanos 123 (beginning May 2026). The renewed facility provides committed funding with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million), available to be drawn until June 30, 2027 (subject to certain conditions), at a SOFR risk-free rate plus a margin of 3.50% per annum. Amounts drawn may be repaid through future oil deliveries or prepaid at any time without penalty.
During the third quarter of 2024, our wholly owned subsidiary GeoPark Argentina S.A., obtained an “AA+(arg)” credit rating from Fitch Ratings’ local Argentine affiliate, FIX, and received approval from the Argentine securities regulator (Comisión Nacional de Valores, or “CNV” by its Spanish acronym) for the creation of a program to issue up to US$500.0 million in debt securities over the next five years, providing strategic financial flexibility to support the future development of the Argentine assets in the Vaca Muerta shale formation.
On November 29, 2024, GeoPark Colombia S.A.S., as borrower, and GeoPark Limited, as guarantor, signed a senior unsecured credit agreement with Banco BTG Pactual S.A. and Banco Latinoamericano de Comercio Exterior S.A. as mandated lead arrangers and bookrunners, which provides us with access to up to US$100.0 million, with an availability period until May 2026 and with a final maturity in September 2026. As of the date of this annual report, we have not drawn any amount under this credit facility.
On December 3, 2024, GeoPark Argentina S.A., executed a promissory note with AdCap Securities Argentina S.A. for an amount in local currency equivalent to US$10.0 million, minus interests and other issuance costs, which were deducted at the execution date. The interest rate was 3% per annum and final maturity was July 3, 2025.
On January 31, 2025, we issued US$550.0 million aggregate principal amount of 8.75% senior notes due 2030 (the “Notes due 2030”). The net proceeds from the Notes due 2030 were used to repurchase a portion of our Notes due 2027 for a nominal amount of US$405.3 million, to repay part of the abovementioned prepayment drawn from Vitol and, the remainder was used for general corporate purposes, including capital expenditures. From June to October 2025, we executed a deleveraging process by repurchasing through open market transactions and cancelling with the trustee a nominal amount of US$108.3 million of our Notes due 2030.
In August 2025, we executed an offtake and prepayment agreement with BP Products North America Inc. (“BP”). Under this arrangement, GeoPark agreed to sell and deliver, on an FOB Coveñas basis, crude oil production from the CPO-
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5, Llanos 87 and Llanos 123 blocks for a 12-month term starting on August 1, 2025 with the option for unilateral early termination after nine months. As part of this transaction, BP made available a committed prepayment facility of up to US$50.0 million, which decreases over the life of the agreement through monthly step-downs until April 2026. Amounts drawn under the prepayment facility may be amortized through future crude oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.50% per annum. In January 2026, we drew US$15.0 million from the prepayment facility.
On December 24, 2025, we executed a loan agreement with Bancolombia Panamá, S.A. for US$3.0 million to finance sustainable capital requirements associated to the Orinoquia Regenera project in Colombia. The loan carries a variable interest rate of SOFR risk-free rate plus a margin of 1.8% per annum and matures on December 20, 2029. Principal is repayable semi-annually in equal installments following a grace period of two years, and interest is payable semi-annually on the outstanding balance.
In addition, after the balance sheet date, we entered into additional short-term bank financings. For further information please see “Item 4. Information on the Company—B. Business Overview— Recent Developments— Funding.”
B. Business Overview
We have grown our business through drilling, developing and producing oil and gas, winning new licenses and acquiring strategic assets and businesses. We continually evaluate the potential acquisition of strategic assets that will allow us to continue growing our business in line with our recent operating and financial successes. Since our inception, we have supported our growth through our prospect development efforts, drilling program, long-term strategic partnerships and alliances with key industry participants, accessing debt and equity capital markets, developing and retaining a technical team with vast experience and creating a successful track record of finding and producing oil and gas in Latin America. A key factor behind our success ratio is our experienced team of geologists, geophysicists and engineers, including professionals with specialized expertise in the geology of Colombia, Argentina and Brazil.
Our assets
We have a portfolio of assets that includes working and/or economic interests in 24 onshore hydrocarbon blocks, including 6 in production as of December 31, 2025, and provides the ability to quickly optimize capital allocation as market conditions change. Our assets give us access to over three million gross exploratory and productive acres.
According to the D&M Reserves Report, as of December 31, 2025, the blocks in Colombia and Argentina, in which we have working interests had 58.6 mmboe of net proved reserves, with 81.0%, 19.0% of such net proved reserves located in Colombia and Argentina, respectively. For further information about the reserves certification process, please see “—Oil and natural gas reserves and production.”
The following table sets forth our net proved reserves and other data as of and for the year ended December 31, 2025.
For the year ended December 31, 2025
Oil Revenues
Oil Gas equivalent (in thousands % of total
Country (mmbbl) (bcf) (mmboe) % Oil of US$) revenues
Colombia 47.5 — 47.5 100.0 % 461,418 93.7 %
Argentina 10.7 2.5 11.1 96.2 % 5,783 1.2 %
Brazil — — — — % 6,435 1.3 %
Ecuador — — — — % 18,463 3.7 %
Other — — — — % 419 0.1 %
Total 58.2 2.5 58.6 99.3 % 492,518 100.0 %
We produced a net average of 28.2 mboepd during the year ended December 31, 2025, of which 93.2%, 1.1%, 1.8% and 3.8%, were in Colombia, Argentina, Brazil and Ecuador, respectively, and of which 98.0% was oil.
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The following table sets forth our average net production during the last five years, as measured by boepd.
For the year ended December 31,
2025 2024 2023 2022 2021
Average net production (mboepd) 28.2 33.9 36.6 38.6 37.6
% oil 98% 99% 93% 91% 86%
The following table sets forth our production of oil and natural gas in the blocks in which we had a working and/or economic interest during the year ended December 31, 2025.
Average daily production
For the year ended December 31, 2025
Colombia Argentina (1) Brazil Ecuador Total
Oil production
Total crude oil production (bopd) 26,297 287 8 1,078 27,670
Natural gas production
Total natural gas production (mcf/day) 154 146 3,080 — 3,380
Oil and natural gas production
Total oil and natural gas production (mboepd) 26,323 311 521 1,078 28,233
(1) Production in Argentina began in October 2025 following the acquisition of the Loma Jarillosa Este and the Puesto Silva Oeste Blocks in the Neuquén Basin. Average daily production in December 2025 was approximately 1,584 bopd.
Acquisition in Argentina’s Vaca Muerta Formation
On September 25, 2025, we entered into an agreement to acquire a 100% operated working interest in the Loma Jarillosa Este and Puesto Silva Oeste Blocks located in the Neuquen Province, Argentina, targeting black oil in the Vaca Muerta formation. The transaction is consistent with our strategic intent to establish a position in Vaca Muerta, one of the world’s most prolific unconventional oil and gas plays.
Additionally, a new unconventional exploitation concession for the Puesto Silva Oeste Block was issued for a 35-year term, requiring us to transfer a 5% economic interest to the provincial state-owned company, GyP, resulting in a 95% economic interest in the Puesto Silva Oeste Block. GeoPark will carry GyP’s portion of the capital expenditures in the Puesto Silva Oeste Block on a fully recoverable basis from up to 100% of GyP’s share of production.
The agreement established a cash consideration of US$115.0 million, subject to an interim period adjustment related to the net cash flows from operations since January 1, 2025 (the effective date of the acquisition). On September 25, 2025, we granted a security deposit of US$22.7 million. Subsequently, the transaction closed on October 16, 2025, upon which we acquired control of the assets and paid the remaining US$92.3 million of consideration, plus the interim period adjustment of US$0.5 million.
The Loma Jarillosa Este concession covers 6,054 acres and expires in 2057, while the Puesto Silva Oeste concession covers 6,301 acres and expires in 2060. Production from these blocks was approximately 1,494 boepd between October 16, 2025 and December 31, 2025, composed of 92% oil and 8% gas. According to the D&M Reserves Report, as of December 31, 2025, the acquired assets contained estimated proved reserves of 11.1 mmboe.
This transaction marks our entry as operator in the Vaca Muerta formation, expanding our presence in Argentina and strengthening our position in one of Latin America’s most prolific hydrocarbon basins.
Portfolio Optimization
We review our asset portfolio on a regular basis to ensure alignment with our strategic objectives. Through this continuous assessment, certain assets may be identified as non-core due to their performance, strategic relevance, or prevailing market conditions. As a result of these evaluations, during 2025, we divested non-core assets in Colombia (the
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Llanos 32 Block), Ecuador (the Perico and Espejo Blocks) and Brazil (the Manati gas field). These divestments allow us to concentrate our resources on our core assets, enhancing our operational focus and efficiency. These initiatives further strengthen our balance sheet, simplify our cost structure, and are fully aligned with our long-term plan to build a highly profitable, dependable, and sustainable oil and gas portfolio in Latin America.
Our strengths
We believe that we benefit from the following competitive strengths:
High quality and diversified asset base built through a successful track record of organic growth and acquisitions
Our assets include a diverse portfolio of oil and natural gas-producing reserves, operating infrastructure, operating licenses and valuable geological surveys in Latin America. Throughout our history, we have delivered continuous growth in our production, and our management team has been able to identify under-exploited assets and turn them into valuable, productive assets, and to allocate resources effectively based on prevailing conditions. Furthermore, our recent Acquisition in Argentina’s Vaca Muerta Formation gives us access to one of the world’s most promising unconventional plays, amplifying our diversified portfolio. For further information on our organic growth and acquisitions in each country, see “—A. History and Development of the Company—History” and “—Our operations.”
Significant drilling inventory and resource potential from existing asset base
Our portfolio includes large land holdings in high-potential hydrocarbon basins and blocks with multiple drilling leads and prospects in different geological formations, which provide several attractive opportunities with varying levels of risk. Our drilling inventory and our development plans target locations that provide attractive economics and support a predictable production profile, as demonstrated by our expansions in Colombia. Our geoscience team continues to identify new potential accumulations and expand our inventory of prospects and drilling opportunities.
Risk-balanced asset portfolio
We intend to continue to focus on maintaining a risk-balanced portfolio of assets, combining cash flow-generating assets with upside potential opportunities, and on increasing production and reserves through finding, developing and producing oil and gas reserves in the countries in which we operate. In general, when we acquire assets we look for a mix of three elements: (i) producing fields, or existing discoveries with near-term possibility of production, to generate cash flows; (ii) an inventory of adjacent low-risk prospects that can offer medium-term upside for steady growth; and (iii) a periphery of higher-risk projects which have a potential to generate significant upside in the long run.
For example, our recent Acquisition in Argentina’s Vaca Muerta Formation includes proven production and reserves to provide us with a cash flow base and significant development upside. We believe that this acquisition firmly fits within our growth strategy by securing value accretive access to competitively advantaged assets, in big plays, and big proven basins to build and deliver a highly profitable, dependable, and sustainable oil and gas portfolio across Latin America.
We believe this approach will allow us to sustain continuous and profitable growth and also participate in higher risk growth opportunities with upside potential. See “—Our operations.”
Capital allocation methodology
Our multi-country platform and asset portfolio is managed through our capital allocation methodology, which also allows us to quickly adapt and grow. We prioritize capital expenditures in core assets and high-return projects that have the greatest impact on production, reserves growth, and cash flow generation, carefully considering their break-even price to remain resilient in the event of an oil price drop. All projects undergo a rigorous evaluation process based on expected returns, payback periods, and alignment with current market conditions. Under this methodology, we rank all of the projects based on economic, technical, environmental, social and corporate governance and strategic criteria, for the purpose of comparing projects. This also creates opportunities for improvements in projects that can, in turn, improve their
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ranking. We then select projects that meet the highest technical and economic standards, aligning with our strategy and prevailing market dynamics.
Also, our capital allocation process leverages multiple pricing scenarios, which are deliberately set below market expectations to stress-test the resilience of our projects. This approach ensures that the projects included in our business plan can be resilient if price declines or scenarios where performance falls short of expectations. By proactively preparing for adverse conditions, we enhance the robustness of our capital plan and the sustainability of our investments. Finally, once the production and reserve growth targets are defined, we agree on the amount of capital to be invested and allocate that capital to the highest value-adding projects. Additionally, given the inherent oil price volatility, we design our work programs to be flexible, which means that they can be increased or decreased depending on the oil price scenario.
Strong cash flow generation and funding
We benefit from a strong cash flow from operating activities. For the year ended December 31, 2025, cash flows from operating activities, excluding income tax payments of US$96.9 million and repayment of an advance payment drawn from Vitol of US$149.8 million, were US$261.4 million. Our cash flows from operating activities plays a significant role in funding our capital expenditures, inorganic acquisition, deleveraging process and shareholders return.
We also have historically benefited from access to debt and equity capital markets, as well as other funding sources, which have provided us with funds to finance our organic growth and the pursuit of potential new opportunities. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.”
Maintain financial strength
We seek to maintain a prudent and sustainable capital structure and a strong financial position to allow us to maximize the development of our assets and capitalize on business opportunities as they arise. We intend to remain financially disciplined by limiting substantially all our debt incurrence to identified projects with repayment sources. We expect to continue benefiting from diverse funding sources such as our partners and customers in addition to the international capital markets.
We believe that maintaining a disciplined capital structure and a conservative financial philosophy, including limiting debt incurrence to specified projects with defined repayment sources and using financial hedges, positions us to preserve liquidity and remain flexible in volatile commodity price environments. In 2025, we also implemented cost-efficiency initiatives, including workforce and structural cost reductions, further simplifying our cost base in line with our long-term plan. This financial flexibility enabled us to pursue new opportunities, including our transformative acquisition in the Vaca Muerta formation in Argentina. As of December 31, 2025, we had US$553.5 million of total outstanding financial indebtedness, 82% of which was scheduled to mature in January 2030, and maintained a net debt to Adjusted EBITDA ratio below 2x.
Pursue strategic acquisitions in Latin America
We have historically benefited from, and intend to continue to grow through, strategic acquisitions in Latin America. These acquisitions have provided us with additional attractive platforms in the region. Our expanded operating footprint in Colombia and Argentina, together with our strong partnerships and proven execution capabilities, positions us as a regional consolidator. We intend to continue to grow through strategic acquisitions in other countries in Latin America, which we may consider from time to time. Our acquisition strategy is aimed at maintaining a balanced portfolio of lower-risk cash flow-generating properties and assets that have upside potential, keeping a balanced mix of oil and gas-producing assets (though we expect to remain weighted towards oil) and focusing on both assets and corporate targets.
Our Colombian acquisitions, for example, highlight our ability to identify and execute on attractive growth opportunities, as we have grown to become one of the three largest private oil operator in Colombia. We acquired our interest in the Llanos 34 Block in the first quarter of 2012 for US$30.0 million and have achieved 1P reserve PV-10 of US$428.8 million as of December 31, 2025.
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In January 2020, we acquired a group of companies which owned thirteen production, development and exploration blocks in Colombia (twelve operated blocks in the Putumayo Basin and the non-operated CPO-5 Block in the Llanos Basin) and a cross-border oil pipeline from Colombia to Ecuador named OBA. Through targeted investments and optimized field operations, the CPO-5 Block has grown from a gross production level of approximately 8,120 bopd in December 2019, to an average gross production of 21,615 bopd during the year ended December 31, 2025 (net production of 6,484 boepd at our working interest). The block’s Indico field ranks among Colombia’s top 8 producing oil fields.
In October 2025, we entered the Vaca Muerta shale formation in Argentina with operated working interests in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta, with estimated recoverable resources of more than 60 million gross barrels of oil, and produced 1,584 boepd in December 2025. This acquisition provides immediate production, reserves, and long-term growth opportunities.
Maintain a high degree of operatorship to control production costs
As of the date of this annual report, we are and intend to continue to be the operator of a majority of the blocks and concessions in which we have working interests, including our world-class Llanos 34 Block, which was acquired in 2012 with no reserves or production and currently includes two of Colombia’s top 12 producing oil fields, Jacana and Tigana. Operating the majority of our blocks and concessions gives us the flexibility to allocate our capital and resources opportunistically and efficiently within a diversified asset portfolio. We believe that this strategy has allowed, and will continue to allow us, to leverage our unique culture, focused on excellence, and our talented technical, operating and management teams.
Long-term strategic partnerships and strong strategic relationships provide us with additional funding flexibility to pursue further acquisitions
We benefit from a number of strong partnerships and relationships. In Colombia, we maintain long-standing partnerships with Ecopetrol, the Colombian state-owned oil and gas company, including through its subsidiary Hocol, which is our partner in several blocks in the Llanos Basin. In Argentina, we operate in partnership with GyP, the provincial energy company of Neuquén, reinforcing our institutional relationship with the province in which our Vaca Muerta assets are located. In addition, our long-standing partnership with Parex Resources in the Llanos 34 Block has been instrumental in the development and growth of this flagship asset. Our commercial relationships with customers have also enabled us to enter into offtake and prepayment agreements with Vitol, Trafigura and BP in recent years, which have served as important sources of financing.
Maintain our commitment to environmental, safety, human rights and social responsibility
An important component of our business strategy is our corporate approach and commitment to our safety, environmental and social responsibilities, which is embodied in decisions that are guided by our Sustainability Framework and internal safety, environmental and social responsibility policies. We see this as a fundamental element in securing business initiatives for long-term growth. Our commitment to sustainable development has allowed us to generate positive impacts in the territories in which we operate, with important contributions to the protection of biodiversity and the environment, as well as to the wellbeing and reduction of multidimensional poverty in neighboring communities. We maintain a social license to operate, based on the construction and maintenance of mutually beneficial relationships with local communities, the return of value as allies for their social and economic development, the respect for their human rights and the care and preservation of the environment.
Our internal values program, SPEED, was developed in accordance with several international quality standards, including ISO 14001 (for environmental management issues), ISO 45001 (for occupational health and safety management issues), ISO 26000 (for social responsibility and workers’ rights issues), IFC guidelines for social and environmental performance, and guidelines from associations including IOGP, IPIECA, IADC and ARPEL. See “—Health, safety and environmental matters.”
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In 2025 we updated our sustainability framework, which articulates the following three key drivers into our operations and decision-making processes, ensuring long-term viability of the business and a shared positive impact:
1. Operational efficiency and decarbonization: our focus is on creating greater efficiencies in water, energy and waste management as well as reducing the carbon footprint of our operations.
2. Risk and opportunities management : we prioritize de adequate management of social, climate and nature related risks and we capture opportunities that generate value and make us more resilient in the long term.
3. Impact multiplier along the value chain: our sustainability initiatives go beyond our operations, engaging with our neighbors, supply chain and partners, to push forward energy transition and nature solutions.
Our Environmental Management System (“EMS”) has been certified under the ISO 14001:2015 standard since 2017. In 2023, the company successfully renewed this certification, which remains valid until August 2026. Covering the exploration and production activities in Colombia.
Since 2017, GeoPark has certified the greenhouse gas inventory of its operations in Scopes 1 and 2 in Colombia, through the NTC-ISO 14064-1 standard of the Colombian Institute of Technical Standards and Certification (“ICONTEC”). GeoPark was the second private company to get this certification in Colombia, allowing us to draw a roadmap to reduce our emissions of greenhouse gases and help the countries where we operate meet their commitments under the Paris Agreement. During 2025, we continued to incorporate clean energy sources in our operations, and implemented energy efficiency measures, while also managing our methane emissions in accordance with our decarbonization targets.
In 2024, a corporate water footprint assessment was carried out in accordance with ISO 14046:2015 for the first time. The footprint was verified by ICONTEC. GeoPark is the first oil and gas company in Colombia in implementing and obtaining an external verification of the water footprint assessment, which provides a comprehensive view of the quantity and quality of water used directly and indirectly in our operations.
In 2024, GeoPark received multiple national recognitions for its leadership in environmental sustainability. The company won first place from the Colombian Oil and Gas Association (“ACP”) in the Climate Change and Decarbonization Management and Circularity Models Implementation categories and was a finalist in Partnerships for Sustainable Development. Additionally, GeoPark earned two awards for ranking among the top 10 contributors to Colombia’s biodiversity information system, recognizing its impact on biodiversity data use and its efforts to strengthen open data reporting capacities.
In 2025, GeoPark received Ecuador’s Green Initiative award from the Ministry of Environment and Energy for its Reforestation of native species in Llano Grande and Laguna Seca project, which restored ecosystems affected by forest fires in 2024 and strengthened local biodiversity and ecological resilience.
Our Sustainable Housing program has been recognized among the most important public, private, and international cooperation initiatives contributing to poverty reduction in Colombia. More than 2,000 families living near our areas of operation have benefited from this program, which we have implemented in partnership with the Minuto de Dios Corporation. We continue strengthening this initiative to expand its positive impact and promote sustainable community development
GeoPark was named as one of the top benchmark Companies in the 2025 Impact Business Leadership special report published by EAFIT University as part of the institution’s 65th anniversary. GeoPark placed sixth in the general ranking and tenth in economic value and corporate governance, consolidating its position among the leading companies in sustainability and responsible leadership in Colombia.
Additionally, in 2025, MSCI Ratings Assessment recognized us as an ESG ‘leader’ by upgrading our rating to “AA”. In 2025 we participated for the fourth time in the Dow Jones Sustainability Index (DJSI), and in the S&P Global Corporate
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Sustainability Assessment (CSA) which led to S&P including GeoPark in its 2025 Sustainability yearbook and recognizing us as the “Industry Mover” for the Oil & Gas Upstream & Integrated sector.
Our approach on human rights seeks to conduct business in a way that is consistent with the UN Guiding Principles, the ten UN Global Compact Principles and the Voluntary Principles on Security and Human Rights. Our commitment to these standards is reflected in our SPEED program, as well as in all our policies and procedures. Human rights aspects are integrated into internal management processes, tools, communications, contracts, and trainings.
During 2024, we consolidated our human rights system, which is based on the following pillars: i) human rights policy, ii) human rights due diligence process, iii) grievance mechanisms, iv) human rights governance, v) communication and reporting, and vi) training and capacity building.
The highlights of this consolidation process were:
• 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.
Furthermore, in 2024, we focused on working with actors in our value chain in human rights capacity building and training.
As part of our commitment to sustainable development and the sustainability development goals, we joined the United Nations Global Compact in 2023.
To be even closer to our neighbors in Colombia, we opened a “Cuentame” office in Puerto Asis (Putumayo) in 2021, one in Tauramena (Casanare) in 2023, and one in Villanueva (Casanare) in 2024. The offices are open to the community, and through them GeoPark seeks to continue strengthening dialogue with all its stakeholders and encourage active community participation so that all neighbors can share proposals and ideas to promote harmonious coexistence and good neighborliness.
For further information related to health, safety and environmental matters, please see “—Health, safety and environmental matters.”
Transparency, ethics and anti-corruption
Transparency is a cornerstone of good governance and it is embodied in our corporate values. Transparency allows business to prosper in a predictable and competitive environment. We believe that doing business in an ethical and transparent manner is a prerequisite for sustainable business. We have zero-tolerance policy towards all forms of corruption. This policy is embedded across our Company through our corporate values, our Code of Ethics (Our Code), and our Ethics and Compliance Program. They prohibit all forms of corruption and bribery and reflect our values and our commitment to high ethical standards in business activities; they apply to all our employees, board members and third parties that act on behalf of the Group.
Our Ethics and Compliance Program is a structured system of policies, procedures, and controls designed to promote ethical behavior, transparency, and compliance across the organization. It seeks to prevent, detect, and address any action that could contravene laws, internal regulations, or ethical principles, while strengthening the Group’s integrity culture and protecting its reputation. The program includes periodic risk assessments, policy development, employee training, third-party due diligence, and communication initiatives that reinforce ethical awareness and responsible business conduct throughout all jurisdictions where GeoPark operates. It also includes an independently operated Ethics Line, a secure and
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confidential reporting channel available 24/7 enabling employees, contractors, and third parties to report potential misconduct in good faith and without fear of retaliation.
The program’s execution and implementation are led by the Compliance Department, under the direction of the Corporate Governance and Compliance Manager, who presents quarterly reports to the Audit Committee. The board’s Audit Committee oversees the effectiveness of the Ethics and Compliance Program, evaluates its controls and risk mitigation measures, and supervises the continuous improvement plans aimed at strengthening our ethical culture and ensuring transparent and compliant operations.
Highly committed founding shareholder and technical and management teams with proven industry expertise and technically-driven culture
Management and operating teams have significant experience in the oil and gas industry and a proven technical and commercial performance record in onshore fields, as well as complex projects in Latin America and around the world, including expertise in identifying acquisition and expansion opportunities. Moreover, we differentiate ourselves from other E&P companies through our technically-driven culture, which fosters innovation, creativity and timely execution. Our geoscientists, geophysicists and engineers are pivotal to the success of our business strategy, and we have created an environment and supplied the resources that enable our technical team to focus its knowledge, skills and experience on finding and developing oil and gas fields.
In addition, we strive to provide a safe and motivating workplace for employees in order to attract, protect, retain and train a quality team in the competitive marketplace for capable energy professionals. We also believe in the importance of local knowledge for operational success, which is why we continue to focus on securing local talent as we expand into new locations, through our Colombian, Argentine and Brazilian acquisitions.
Our management and operating team have an average experience in the energy industry of more than 25 years in companies such as Ecopetrol, Chevron, BP, Shell, Petrobras, Pluspetrol, Pan American Energy, Total and YPF, among others. Throughout our history, our management and operating team has had success in unlocking unexploited value from previously underdeveloped assets.
One of our founding shareholders and current Vice Chairman of the board, Mr. James F. Park, has been involved in E&P projects in Latin America since 1978. He has been closely involved in grass-roots exploration activities, drilling and production operations, surface and pipeline construction, legal and regulatory issues, crude oil marketing and transportation and capital raising for the industry. As of March 19, 2026, Mr. Park held 13.6% of our outstanding common shares.
In addition, as of March 19, 2026, our executive officers owned 0.6% of our outstanding common shares. Ownership of our shares by our executive directors and executive officers aligns their interests with those of our shareholders and helps retain the talent we need to continue to support our business strategy. See “Item 6. Directors, Senior Management and Employees—B. Compensation.”
Innovation
We have fostered a company-wide innovation culture that integrates technology, data and process improvements into our daily operations. In 2025, we continued to execute our innovation agenda through three primary areas of focus: data, processes and culture, with a particular emphasis on the organizational adoption of innovation, technology and artificial intelligence. These efforts were directed at improving the reliability of information used across the Group, increasing operational efficiency and strengthening internal competencies related to digital tools and artificial intelligence.
• Data. During 2025, we advanced multiple initiatives aimed at consolidating and standardizing operational and financial data. The “Exploration & Development Data Warehouse” and the “Financial Data Warehouse” reached stable operational status and were used to support internal reporting and analysis activities. We also continued to implement data governance and cybersecurity practices, including information-classification frameworks, access controls and monitoring tools.
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Artificial intelligence (“AI”) played an increasing role within this workstream. We progressed the development of an AI-first strategy, including the initial phase of an AI video-analytics solution intended to assist with safety observations and the development of an AI governance framework to help ensure that initiatives remain within defined guardrails. Employees also used internally developed AI assistants for certain repetitive analytical and documentation tasks. Based on internal estimates, data and AI initiatives delivered cumulative time savings during the year equivalent to approximately 12.5 full-time equivalent positions.
• Processes. We continued initiatives aimed at simplifying and digitizing selected workflows. Our process-automation program completed 26 automations during the year, with an additional 10 in execution at year-end. These automations covered activities within finance, human resources, compliance, operations and corporate reporting. We also advanced projects related to production-data monitoring, chemical-injection optimization, use of Supervisory Control And Data Acquisition data, compliance management and community-engagement systems. Several of these projects incorporated both automation and AI components.
• Culture. We expanded internal programs focused on digital capabilities, data governance and the responsible use of artificial intelligence. More than 300 employees actively used corporate AI tools during 2025 and more than 450 employees were trained in the safe use of AI in the work environment. In parallel, we advanced the next stages of our AI governance framework, seeking to build on the initial results achieved to date.
These activities contributed to the continued development of technology-enabled capabilities within the Group and supported our broader efforts to improve the quality of information, streamline selected processes and build internal proficiency in digital and AI-related tools.
Recent Developments
Proposed acquisition of Frontera Energy’s Colombian E&P assets (not consummated)
On January 29, 2026, we entered into an agreement with Frontera Energy Corporation (“Frontera”) to acquire 100% of Frontera Petroleum International Holdings B.V. (“Frontera International”), which consisted exclusively of oil and gas exploration and production assets in Colombia. On February 2, 2026, we paid an initial deposit of US$75.0 million, with the remaining balance payable at closing, subject to regulatory approvals and customary closing conditions.
On March 5, 2026, Frontera announced that its board of directors had determined that a binding offer from Parex Resources Inc. to acquire the Frontera E&P Assets constituted a “Superior Proposal” under the arrangement agreement with GeoPark, and that the five-business-day matching period had commenced.
Following such notification and after evaluating our match right, on March 9, 2026, we announced our decision not to raise our offer for Frontera’s Colombian E&P assets. As a result, we became entitled to receive the return of the deposit previously placed in escrow, plus any accrued interest, and a US$25.0 million break-up fee, in each case pursuant to the terms of the arrangement agreement.
Offtake and prepayment agreements with Vitol
In January 2026, we renewed our offtake and prepayment agreement with Vitol, extending its term through December 31, 2028. The new terms take effect in January 2026, with deliveries beginning in January 2026 for Llanos 34 and in May 2026 for CPO-5 and Llanos 123, and remaining in force through December 31, 2028. As part of this transaction, we obtained access to committed funding from Vitol with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million) at a SOFR risk-free rate plus a margin of 3.50% per annum. The committed funds are available for drawn until June 30, 2027, subject to certain conditions. Amounts drawn under this prepayment facility may be repaid through future oil deliveries or prepaid at any time without penalty.
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Funding
We obtained two short-term loans from Bancolombia Panamá, S.A. totaling US$25.0 million (US$17.0 million and US$8.0 million). The loans were disbursed in January 23, 2026. In February 2026, the terms of these loans were amended, and the loans were restructured to bear interest at a fixed annual rate of 5.06320% and to mature on February 3, 2027.
In addition, in February 2026, we obtained one short-term loan from Citibank Colombia S.A. in an aggregate principal amount of Colombian Pesos 145,280 million (equivalent to US$40.0 million). The loan was disbursed on February 6, 2026, bears interest at a floating rate of IBR (the Colombian interbank reference rate) plus 1.53% per annum, and matures on February 3, 2027. In connection with this borrowing, we entered into a cross-currency swap arrangement with Citibank N.A., New York to hedge the foreign exchange exposure associated with the loan and to secure the Colombian peso cash flows required to service principal and interest payments.
Finally, in February 2026, we entered into an unsecured committed credit facility with Banco de Galicia y Buenos Aires S.A. for up to US$49.0 million to finance working capital and capital expenditures in Argentina. The facility has a six-month availability period from signing, and borrowings thereunder may have terms of 24 months from the date of disbursement. The interest rate is 8.75% per annum on amounts drawn. As of the date of this annual report, no amounts have been drawn under this facility.
Strategic Equity Investment by Grupo Gilinski
Share Purchase Agreement
On March 5, 2026, GeoPark Limited entered into a Share Purchase Agreement (the “SPA”) with Colden, an affiliate of Jaime Gilinski, who leads Grupo Gilinski. Under the SPA, Colden invested approximately US$107.0 million to acquire 12,876,053 newly issued common shares of the Company at a price of US$8.31 per share. Immediately following the closing of the investment, Colden held approximately 20% of the Company’s outstanding common shares and was the Company’s largest shareholder.
The SPA contains certain representations and warranties by the Company and Colden, which the Company believes are customary for transactions of this type, as well as certain indemnification obligations relating to breaches of such representations and warranties and covenants by the Company.
Board Nomination, Voting Obligations and Governance Rights
Pursuant to the SPA, Colden has the right to nominate (i) three directors if Colden beneficially owns at least 28% of the Company’s outstanding common shares, (ii) two directors if Colden beneficially owns at least 15% but less than 28% of the Company’s outstanding common shares, and (iii) one director if Colden beneficially owns at least 7.5% but less than 15% of the Company’s outstanding common shares. Colden is entitled to nominate two directors based on its share ownership immediately following the closing of the investment. Subject to compliance with applicable law, NYSE requirements and certain corporate governance policies of the Company, the Company will include the Colden nominees in the slate of nominees recommended by the board at shareholder meetings at which directors are to be elected. One of Colden’s nominees, Gabriel Gilinski, was appointed to fill a then-existing vacancy on the board with an initial term expiring at the Company’s 2026 Annual Meeting. Colden’s board nomination rights include certain customary rights with respect to representation on committees of the board (other than the Audit Committee) and the removal and replacement of Colden’s nominee directors. If at any time Colden is entitled to nominate three directors, at least one such nominee must qualify as an independent director pursuant to applicable law, NYSE regulations and the Company’s independence criteria.
From the closing of the investment until the earlier of the Company’s second annual general meeting thereafter and the date when Colden no longer has the right to nominate any directors, Colden is obligated to vote its shares in accordance with the board’s recommendation with respect to the election or removal of directors.
For so long as Colden owns at least 15% of the Company’s outstanding common shares, the Company may not take certain specified actions without approval by Colden or at least one of the directors nominated by Colden , including
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(subject to certain exceptions): (i) issuing equity or equity-linked securities in excess of 5% of the Company’s fully diluted share capital; (ii) amending the Company’s governing documents in a manner adverse to Colden; (iii) entering into, modifying or terminating certain related-party transactions; (iv) changing the board size; (v) declaring or paying dividends; and (vi) repurchasing or otherwise acquiring the Company’s outstanding share capital.
Lock-Up, Ownership Limitations and Registration Rights
Under the SPA, from the closing of the investment until 18 months thereafter, Colden and its affiliates may not transfer any common shares of the Company without the Company’s prior written consent, subject to limited exceptions. Until the first anniversary of the closing of the investment, Colden is not permitted to acquire more than 32% of the Company’s outstanding common shares without the prior consent of the board. The SPA includes customary registration rights for Colden with respect to the common shares acquired in the investment.
Rights Agreement Amendment
In connection with the investment, the Company amended the Rights Agreement, by and between the Company and Computershare Trust Company, N.A., dated June 3, 2025 (the “Rights Agreement”), to provide that Colden will not be deemed an “Acquiring Person” under the Rights Agreement in the event of Colden’s acquisition of beneficial ownership of common shares so long as, after giving effect to such acquisition, Colden and its affiliates beneficially own no more than 32% of the outstanding common shares. Under the SPA, the Company agreed to terminate the Rights Agreement on or prior to the 2026 Annual Meeting and not to adopt a shareholder rights plan or take similar measures in the future with the purpose of preventing Colden from (i) acquiring up to 32% of the Company’s outstanding common shares or (ii) making a tender offer for all of the Company’s outstanding share capital.
Further acquisitions by Grupo Gilinski
On March 9, 2026, Spaldy Investments Limited, a business company that operates under the laws of the British Virgin Islands, deemed to be beneficially owned by Jaime Gilinski, acquired 200,000 of the Company’s common shares in the open market, at a weighted average price of US$8.83 per share, for an aggregate purchase price of US$1.8 million.
Between March 11, 2026 and March 19, 2026, Colden acquired a total of 3,587,190 common shares of the Company in the open market, at prices ranging from US$8.58 to US$10.20 per share, for an aggregate purchase price of US$32.9 million.
Recent Oil Price Volatility
In March 2026, oil prices experienced increased volatility, including a sharp rise in Brent crude oil prices, driven primarily by heightened geopolitical tensions in the Middle East and concerns regarding potential disruptions to global oil supply and transportation routes.
While higher oil prices may positively impact revenues, the overall financial effect on the Group may be partially offset, or in certain scenarios adversely affected, by the combined impact of existing hedging arrangements and higher government take in certain jurisdictions. In particular, higher price environments may result in increased royalties, price-linked contractual and fiscal mechanisms and tax surcharges, while realized prices may be capped by hedge ceilings.
Market conditions remain uncertain, and there can be no assurance as to the duration or sustainability of current price levels.
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Our operations
Operations in Colombia
Our Colombian assets currently give us access to 3,257,000 gross exploratory and productive acres across 18 blocks in what we believe to be one of South America’s most attractive oil and gas geographies. Since we entered Colombia in 2012, we have achieved successful exploration and development activities at our operated Llanos 34 Block, which as of December 31, 2025, accounts for 61.0% of our production and 62.2% of our proved reserves.
Our interests in Colombia include working interests and economic interests. “Working interests” are direct participation interests granted to us pursuant to an E&P contract with the ANH, whereas “economic interests” are indirect participation interests in the net revenues from a given block based on bilateral agreements with the concessionaires.
The map below illustrates the location of the blocks in Colombia where we hold working and/or economic interests.
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The table below summarizes information about the blocks in Colombia in which we have working interests as of and for the year ended December 31, 2025.
Gross acres
(thousand Working Production Concession
Block acres) interest(1) Partners(2) Operator (boepd) Basin expiration year
Coatí 15.6 100% — GeoPark — Putumayo Evaluation: Currently suspended
CPO-4-1 148.3 50% Parex Parex — Llanos Exploration: 2028
CPO-5 490.8 30% ONGC Videsh ONGC Videsh 6,484 Llanos Exploration: 2025
Exploitation: 2042-2045(3)
Llanos 34 59.1 45% Verano Energy GeoPark 17,211 Llanos Exploitation: 2039-2045(3)
Llanos 86 255.5 50% Hocol GeoPark — Llanos Exploration: 2026
Llanos 87 107.6 50% Hocol GeoPark 128 Llanos Exploration: 2023
Llanos 104 274.8 50% Hocol GeoPark — Llanos Exploration: 2026
Llanos 123 88.3 50% Hocol GeoPark 2,115 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 175 Putumayo Exploitation: 2033(3)
PUT-8 102.8 50% Sierracol Energy GeoPark 5 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) Corresponds to the working interests held by our respective local 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.
As of December 31, 2025, we had net proved reserves of 45.4 mmboe in various blocks in the Llanos Basin, with the Llanos 34 Block representing 80.4% of those reserves, and 2.1 mmboe in the Platanillo Block in the Putumayo Basin.
We previously held an indirect economic interest in the Abanico Block in Colombia through an association contract. The term of the Abanico Association Contract expired in October 2024, and the termination process with the operator is currently ongoing. This interest did not have a material impact on our operations or results during the year ended December 31, 2025.
For further information of each E&P Contract in Colombia, please see “—Significant Agreements.”
Operations in Argentina
In October 2025, we entered the Vaca Muerta shale formation in Argentina with a 100% operated working interest in the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the Neuquén Basin. In the case of Puesto Silva Oeste Block, GeoPark holds an 95% of the economic interest on the Block while the remaining 5% is held by GyP. The acquired blocks cover over 12,300 gross acres in the black oil window of Vaca Muerta, with estimated recoverable resources of more than 60 million gross barrels of oil, and produced 1,584 boepd in December 2025. This acquisition provides immediate production, reserves, and long-term growth opportunities. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina’s Vaca Muerta Formation.”
In May 2024, we had entered into a farm-out agreement for the acquisition of non-operated working interests in four unconventional blocks in the Vaca Muerta formation. However, in May 2025, the seller exercised its contractual right to withdraw from the transaction, and as a result the acquisition was not completed. All advance payments previously made by us were fully reimbursed.
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The map below illustrates the location of the blocks in Argentina where we hold working interests.
The table below summarizes information about the blocks in Argentina in which we had working interests as of and for the year ended December 31, 2025.
Gross
acres
(thousand Working Production Expiration
Block acres) interest (1) Partners(2) Operator (boepd) Basin concession year
Loma Jarillosa Este 6.1 100% — GeoPark 304 Neuquén Exploitation: 2057
Puesto Silva Oeste 6.3 95% GyP GeoPark 7 Neuquén Exploitation: 2060
(1) Corresponds to the working interests held by our respective local subsidiary in such block, net of any working or economic interests held by other parties in each block. In the case of Puesto Silva Oeste Block, GeoPark was assigned with the 100% working interest in the hydrocarbons exploitation concession, and subsequently transferred a 5% economic interest to the provincial state-owned company, GyP, resulting in a 95% economic interest retained by GeoPark. For further information please see “Item 4. Information on the Company—B. Business Overview—Significant Agreements—Argentina—Overview of Unconventional Concessions—Puesto Silva Oeste Unconventional Concession.”
(2) Partners with working interests.
For further information, please see “—Significant Agreements.”
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Operations in Brazil
In March 2025, we entered into an agreement to divest our 10% non-operated working interest in the Manati gas field, with the transfer of the working interest in December 2025. During 2025, the Manati gas field produced 521 boepd. In addition, in June 2025, we relinquished the POT-T-785 Block upon completion of all contractual exploration commitments. The ANP has granted approval for the relinquishment; however, approval regarding local content commitments is still pending. After this divestment and relinquishment, our Brazilian assets give us access to 30,700 of gross exploratory acres across 4 exploratory blocks.
The following table sets forth information as of December 31, 2025, on our concessions in Brazil in which we have a current or future working interest:
Gross acres
(thousand Working Concession
Concession acres) interest(1) Operator Basin expiration year
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
(1) Corresponds to the working interests held by our respective local subsidiary in such block, net of any working interests held by other parties in each block.
For further information, please see “—Significant Agreements.”
Operations in Ecuador
In July 2025, we entered into an agreement to sell our 50% working interests in the Perico and Espejo Blocks. The divestment transaction closed in December 2025. During 2025, the Perico and Espejo Blocks produced 1,078 boepd.
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Oil and natural gas reserves and production
Our reserves
The following table sets forth our oil and natural gas net proved reserves as of December 31, 2025, which is based on the D&M Reserves Report.
Net proved reserves
As of December 31, 2025
Total net
proved
Oil Natural gas reserves
(mmbbl) (bcf) (mmboe)(1) % Oil
Net proved developed
Colombia 43.4 — 43.4 100.0 %
Argentina 1.8 0.4 1.9 96.2 %
Total net proved developed 45.2 0.4 45.3 99.8 %
Net proved undeveloped
Colombia 4.1 — 4.1 100.0 %
Argentina 8.9 2.1 9.2 96.2 %
Total net proved undeveloped (2) 13.0 2.1 13.3 97.4 %
Total net proved 58.2 2.5 58.6 99.3 %
(1) We calculate one barrel of oil equivalent as six mcf of natural gas.
(2) 100% of our reported 2025 year-end proved undeveloped reserves are planned to put into production through activities to be implemented within five years of initial disclosure.
We had net proved reserves of 58.6 mmboe at December 31, 2025, compared to net proved reserves of 58.4 mmboe as of December 31, 2024.
The 0.3% increase in net proved reserves in 2025 is mainly attributable to:
● Purchase of minerals in Argentina of 11.2 mmboe;
● Higher-than-expected performance from existing wells in Colombia, resulting in an increase of 3.7 mmbbl;
This was partially offset by:
● Production of 10.3 mmboe;
● Disposal of minerals in Colombia, Brazil and Ecuador of 1.8 mmboe, 0.8 mmboe and 0.5 mmbbl, respectively; and
● Lower average prices in Colombia, resulting in a 1.3 mmboe decrease.
During the year ended December 31, 2025, we had 1.3 mmboe of our proved undeveloped reserves from December 31, 2024, converted to proved developed reserves due to development drilling in the Llanos 123 and Llanos 34 Blocks in Colombia. For further information relating to the reconciliation of our net proved reserves for the years ended December 31, 2025, 2024 and 2023, please see Table 5 included in Note 37 (unaudited) to our Consolidated Financial Statements.
Internal controls over reserves estimation process
We maintain an internal staff of petroleum engineers and geosciences professionals who work closely with our independent reserves engineers to ensure the integrity, accuracy and timeliness of data furnished to our independent reserves engineers in their estimating process and who have knowledge of the specific properties under evaluation. Our
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Chief Exploration and Development Officer, Rodrigo Dalle Fiore, is primarily responsible for overseeing the preparation of our reserves estimates and for the internal control over our reserves estimation. He has over 20 years of experience in Latin America’s oil and gas industry, with a strong background in unconventional resources, strategic growth, and operational leadership. See “Item 6. Directors, Senior Management and Employees—A. Directors and executive officers.”
In order to ensure the quality and consistency of our reserves estimates and reserves disclosures, we maintain and comply with a reserves process that satisfies the following key control objectives:
● 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 and Chief People Officer) and the Technical Committee (composed by four technical experts of our board of directors). A final copy of the Reserves Report is sent by the Independent Qualified Reserve Engineer to be reviewed and analyzed by the Technical Committee which recommends to the board of directors to approve its disclosure and publication. See “Item 6. Directors, Senior Management and Employees—C. Board Practices—Committees of our board of directors.”
Independent reserves engineers and geoscience professionals
Reserves estimates as of December 31, 2025, for Colombia and Argentina included elsewhere in this annual report are based on the D&M Reserves Report, dated March 3, 2026, and effective as of December 31, 2025. The D&M Reserves Report, a copy of which has been filed as an exhibit to this annual report, was prepared in accordance with SEC rules, regulations, definitions and guidelines, including Rule 4-10(a)(1)-(32) of Regulation S-X, at our request in order to estimate reserves and for the areas and period indicated therein.
DeGolyer and MacNaughton Corp. (“DeGolyer and MacNaughton” or “D&M), a Delaware corporation with offices in Dallas, Houston, Buenos Aires, Madrid, Algiers, Baku, Astana and New Delhi, has been providing consulting services to the oil and gas industry since 1936. The firm has more than 180 professionals, including engineers, geologists, geophysicists, petrophysicists and economists, engaged in the appraisal of oil and gas properties, the evaluation of hydrocarbon and other mineral prospects, basin evaluations, comprehensive field studies and equity studies related to the domestic and international energy industry. DeGolyer and MacNaughton restricts its activities exclusively to consultation and does not accept contingency fees, nor does it own operating interests in any oil, gas or mineral properties, or securities or notes of its clients. The firm subscribes to a code of professional conduct, and its employees actively support their related technical and professional societies. The firm is a Texas Registered Engineering Firm.
The D&M Reserves Report covered 100% of our total reserves. In connection with the preparation of the D&M Reserves Report, DeGolyer and MacNaughton prepared its own estimates of our proved reserves. In the process of the reserves evaluation, DeGolyer and MacNaughton relied on information furnished by us with respect to ownership interests, oil and gas production, well test data, historical costs of operation and development, product prices, and agreements relating to current and future operations of the fields and sales of production, without independent verification of the
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accuracy and completeness of such information and data, except that if, in the course of its examination, any information appeared to be inconsistent or insufficient, it did not rely on such information until it had satisfactorily resolved its questions or independently verified such information.
DeGolyer and MacNaughton independently prepared reserves estimates in accordance with SEC guidelines, including the criteria of “reasonable certainty,” as it pertains to expectations about the recoverability of reserves in future years under existing economic and operating conditions, consistent with Rule 4-10(a) of Regulation S-X. The reserves estimates were prepared using appropriate geologic and petroleum engineering principles and techniques consistent with generally accepted industry practices, including those set forth in the standards of the Society of Petroleum Engineers. The method or combination of methods used in the analysis of each reservoir was selected based on the maturity of the reservoir, quality and completeness of available data, and production performance, and reflects the independent judgment of DeGolyer and MacNaughton.
D&M’s primary economic assumptions included oil and gas sales prices determined in accordance with SEC guidelines, as well as future expenditures and other economic inputs (including working interests, royalties and taxes) provided by us. The reserves estimates were limited to the economic life of the properties or the applicable concession terms, whichever occurs first. DeGolyer and MacNaughton issued the D&M Reserves Report based upon its evaluation and used all methods and procedures that it considered necessary under the circumstances.
However, uncertainties are inherent in estimating quantities of reserves, including many factors beyond our and our independent reserves engineers’ control. Reserves engineering is a subjective process of estimating subsurface accumulations of oil and natural gas that cannot be measured in an exact manner, and the accuracy of any reserves estimate is a function of the quality of available data and its interpretation. As a result, estimates by different engineers often vary, sometimes significantly. In addition, physical factors such as the results of drilling, testing and production subsequent to the date of an estimate, economic factors such as changes in product prices or development and production expenses, and regulatory factors, such as royalties, development and environmental permitting and concession terms, may require revision of such estimates. Our operations may also be affected by unanticipated changes in regulations concerning the oil and gas industry in the countries in which we operate, which may impact our ability to recover the estimated reserves. Accordingly, oil and natural gas quantities ultimately recovered will vary from reserves estimates.
Technology used in reserves estimation
According to SEC guidelines, proved reserves are those quantities of oil and gas which, by analysis of geoscience and engineering data, can be estimated with “reasonable certainty” to be economically producible—from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations—prior to the time at which contracts providing the right to operate expire, unless evidence indicates that renewal is reasonably certain, regardless of whether deterministic or probabilistic methods are used for the estimation.
The project to extract the hydrocarbons must have commenced or the operator must be reasonably certain that it will commence the project within a reasonable time. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil and/or natural gas actually recovered will equal or exceed the estimate. Reasonable certainty can be established using techniques that have been proved effective by actual production from projects in the same reservoir or an analogous reservoir or by other evidence using reliable technology that establishes reasonable certainty. Reliable technology is a grouping of one or more technologies (including computational methods) that have been field tested and have been demonstrated to provide reasonably certain results with consistency and repeatability in the formation being evaluated or in an analogous formation.
There are various generally accepted methodologies for estimating reserves including volumetrics, decline curve analysis, material balance, simulation models and analogies. In practice, reserves estimates are typically based on a combination of these methods, selected as appropriate depending on the geological characteristics of the reservoir, its stage of development, production history and the quality and completeness of available data. For unconventional reservoirs, performance-based methodologies may be applied, including production diagnostics, decline-curve analysis and, where appropriate, model-based analysis. Estimates may be prepared using either deterministic (single estimate) or probabilistic (range of possible outcomes and probability of occurrence) methods. It may be appropriate to employ several methods in reaching an estimate for a given property.
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Estimates are prepared using all available information, including open- and cased-hole logs, core analyses, geologic and structure maps, seismic interpretation, production and injection data, and pressure test analysis. Supporting data, such as working interests, royalties, operating costs and development plans, are incorporated into the evaluation and updated when such information materially changes.
Proved undeveloped reserves
As of December 31, 2025, we had 13.3 mmboe in proved undeveloped reserves, a increase of 6.5 mmboe, or 96%, compared to our December 31, 2024, proved undeveloped reserves of 6.8 mmboe. Changes for the year ended December 31, 2025, include:
(i) Purchase of minerals in Argentina of 9.2 mmbbl;
(ii) an increase of 1.0 mmbbl due to a higher-than-expected performance in Colombia;
This was partially offset by:
(iii) a decrease of 1.3 mmbbl in Colombia due to the conversion of proved undeveloped reserves to proved developed reserves in the Llanos 123 and Llanos 34 Blocks;
(iv) a decrease of 1.6 mmbbl due to lower oil average prices in Colombia; and
(v) a decrease of 0.8 mmboe due to the disposal of minerals in Colombia (0.4 mmbbl) and Ecuador (0.4 mmbbl).
Of our 13.3 mmboe of net proved undeveloped reserves, 4.1 mmboe (30.6%) and 9.2 mmboe (69.4%) were located in Colombia and Argentina, respectively.
During 2025, we incurred approximately US$5.5 million in capital expenditures in Colombia to convert such proved undeveloped reserves to proved developed reserves.
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Production, revenues and price history
The following table sets forth certain information on our production of oil and natural gas in the countries in which we operate, for each of the years ended December 31, 2025, 2024 and 2023.
Average daily production(1)
As of December 31,
2025 2024 2023
Colombia Argentina Brazil Ecuador Colombia Brazil Ecuador Chile (2) Colombia Brazil Ecuador Chile
Oil production
Average crude oil production (bopd) 26,297 287 8 1,078 31,867 3 1,668 5 32,795 16 926 221
Average sales price of crude oil (US$/bbl) 59.0 55.1 75.6 62.3 65.8 96.1 69.8 — 66.8 82.1 69.9 68.0
Natural Gas production
Average natural gas production (mcfpd) 154 146 3,080 — 685 1,313 — 363 573 6,065 — 8,993
Average sales price of natural gas (US$/mcf) — 0.8 4.2 — 7.2 5.9 — 3.2 3.9 6.5 — 3.4
Oil and gas production cost
Average operating cost (US$/boe) 15.0 31.5 18.0 26.2 14.1 48.2 21.8 20.6 11.5 10.9 37.5 13.0
Average royalties and economic rights in cash (US$/boe) 1.1 6.5 1.5 — 1.1 2.8 — 0.6 7.9 3.1 — 0.9
Average production cost (US$/boe)(3) 16.0 38.0 19.4 26.2 15.2 50.9 21.8 21.2 19.4 14.0 37.5 13.9
(1) We present production figures net of interests due to others, but before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes.
(2) Divested in January 2024.
(3) Calculated pursuant to FASB ASC 932.
The following table sets forth certain information on our production of oil and natural gas by final product sold in Colombia, Argentina, Brazil, Ecuador and Chile for each of the years ended December 31, 2025, 2024 and 2023.
2025 2024 2023
Oil Gas Oil Gas Oil Gas
Mbbl MMcf Mbbl MMcf Mbbl MMcf
Tigana oil field (1) 2,652 — 3,865 — 3,904 —
Jacana oil field (1) 3,096 — 3,534 — 4,411 —
Rest of Colombia 3,850 56 4,264 251 3,655 209
Loma Jarillosa Este (1) 102 53 — — — —
Rest of Argentina 3 — — — — —
Brazil 3 1,124 1 481 6 2,214
Ecuador 394 — 610 — 338 —
Chile — — 2 133 81 3,283
Total 10,100 1,234 12,277 864 12,395 5,705
(1) The Tigana (discovered in 2013) and Jacana (discovered in 2015) oil fields in Colombia and the Loma Jarillosa Este oil and gas field (acquired in 2025) in Argentina are separately included in the table above as those fields individually contain more than 15% of our total proved reserves as of each of the years indicated above.
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Drilling activities
The following table sets forth the exploratory wells we drilled during the years ended December 31, 2025, 2024 and 2023.
Exploratory wells(1)
2025 2024 2023
Colombia Colombia Ecuador Colombia Ecuador
Productive(2)
Gross 9.0 9.0 5.0 7.0 3.0
Net 4.5 4.1 2.5 3.3 1.5
Dry(3)
Gross 1.0 2.0 — 6.0 —
Net 0.5 0.6 — 2.8 —
Total
Gross 10.0 11.0 5.0 13.0 3.0
Net 5.0 4.7 2.5 6.0 1.5
(1) Includes appraisal wells. In Colombia, appraisal wells drilled were 5 (2.5 net) in 2025, 8 (3.6 net) in 2024 and none in 2023. In Ecuador, appraisal wells drilled were 3 (1.5 net) in 2024 and 2 (1.0 net) in 2023.
(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.
The following table sets forth the development wells we drilled during the years ended December 31, 2025, 2024 and 2023.
Development wells
2025 2024 2023
Colombia Colombia Ecuador Colombia Ecuador
Productive(1)
Gross 6.0 21.0 — 25.0 —
Net 2.7 8.7 — 11.8 —
Dry(2)
Gross — 1.0 — 7.0 —
Net — 0.3 — 3.7 —
Total
Gross 6.0 22.0 — 32.0 —
Net 2.7 9.0 — 15.5 —
(1) A productive well is an exploratory, development, or extension well that is not a dry well.
(2) A dry well is an exploratory, development, or extension well that proves to be incapable of producing either oil or gas in sufficient quantities to justify completion as an oil or gas well.
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Developed and undeveloped acreage
The following table sets forth certain information regarding our total gross and net developed and undeveloped acreage in Colombia, Argentina and Brazil as of December 31, 2025.
Acreage(1)
Colombia Argentina Brazil
(in thousands of acres)
Total developed acreage
Gross 24.1 1.2 —
Net 12.6 1.2 —
Total undeveloped acreage
Gross 3,207.6 11.2 30.7
Net 1,581.0 10.8 30.7
Total developed and undeveloped acreage
Gross 3,231.7 12.4 30.7
Net 1,593.6 12.0 30.7
(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.
Productive wells
The following table sets forth our total gross and net productive wells as of February 28, 2026. Productive wells consist of producing wells and wells capable of producing, including oil wells awaiting connection to production facilities. Gross wells are the total number of producing wells in which we have an interest, and net wells are the sum of our fractional working interests owned in gross wells.
Productive wells(1)
Colombia Argentina
Oil wells
Gross 229.0 9.0
Net 113.4 8.9
(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, 2026, to February 28, 2026, we produced a net average of approximately 26,911 mboepd from our operations in Colombia and Argentina.
The main highlights of the activity during January and February 2026 are detailed as follows:
● drilling the Jacana 57 and the Jacana 67 development wells in the Llanos 34 Block in Colombia;
● drilling and completing the Bisbita Norte 1 development well and completing the Bisbita Sur 1 appraisal well in the Llanos 123 Block in Colombia; and
● performing 5 workovers: 3 in the Loma Jarillosa Este Block in Argentina and 2 in the Llanos 34 Block in Colombia.
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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.
In 2025, we continued executing commercial agreements for the sale of our Colombian production under competitive market terms. The most relevant arrangements include the following:
● Vitol: 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 trading companies. The agreement provides for GeoPark to sell and deliver crude oil from the Llanos 34 Block to Vitol over a minimum term of 20 months, with optional extensions of up to 36 months, starting on July 1, 2024. As part of this transaction, we obtained access to a committed prepayment facility from Vitol with an initial limit of up to US$300.0 million, decreasing by US$10.0 million per month. The facility allowed the Group to draw funds secured by future oil deliveries, repayable either through physical deliveries or in cash, without penalties for early repayment, at an interest rate based on the SOFR risk-free rate plus a margin of 3.75 % per annum. In November 2024, we drew US$152.0 million under the facility. During 2025, US$142.2 million was repaid in cash and US$7.6 million in kind through oil deliveries. As of December 31, 2025, US$2.2 million remained outstanding.
In January 2026, we renewed our offtake and prepayment agreement with Vitol, extending its term through December 31, 2028. The new terms take effect in January 2026, with deliveries beginning in January 2026 for Llanos 34 and in May 2026 for CPO-5 and Llanos 123, and remaining in force through December 31, 2028. As part of this transaction, we obtained access to committed funding from Vitol with an initial limit of up to US$500.0 million (US$330.0 million committed with an option to increase by up to US$170.0 million) at a SOFR risk-free rate plus a margin of 3.50% per annum. The committed funds are available to be drawn until June 30, 2027, subject to certain conditions. Amounts drawn under this prepayment facility may be repaid through future oil deliveries or prepaid at any time without penalty.
● BP Products North America Inc. (“BP”): In August 2025, we executed an offtake and prepayment agreement with BP. Under this arrangement, we agreed to sell and deliver, on an FOB Coveñas basis, crude oil production from the CPO-5, Llanos 87 and Llanos 123 blocks for a 12-month term starting on August 1, 2025 with the option for unilateral early termination after nine months. As part of this transaction, BP made available a committed prepayment facility of up to US$50.0 million initially, which decreases over the life of the agreement through monthly step-downs until April 2026. Amounts drawn under the prepayment facility may be amortized through future crude oil deliveries or prepaid at any time without penalty. The interest cost is based on a SOFR risk-free rate plus a margin of 3.50% per annum. In January 2026, we drew US$15.0 million from the prepayment facility.
In connection with this new commercial arrangement, GeoPark secured the necessary transportation capacity in the Oleoductos de Colombia (“ODC”) system, ensuring the full evacuation of contracted volumes from the producing fields to the Coveñas marine terminal. These transportation agreements guarantee operational continuity and delivery reliability under the FOB Coveñas terms.
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● Trafigura: The offtake and prepayment agreement executed in August 2024 with C.I. Trafigura Petroleum Colombia S.A.S. (“Trafigura”) for the sale of light crude oil from the CPO-5 Block was successfully completed in July 2025, upon expiration of its 12-month term. All contractual obligations were fulfilled as agreed, and the volumes previously marketed under this agreement are now included in the new offtake structure described below.
Regarding the transportation infrastructure, we can highlight the following:
● Llanos Basin: We have developed a flexible and reliable crude oil transportation system that has significantly reduced trucking requirements, improved cost efficiency and enhanced operational reliability. Our core infrastructure is anchored by the Oleoducto del Casanare (“ODCA”), a regulated pipeline that connects the Llanos 34 Block and adjacent fields to the Oleoducto de Los Llanos Orientales (“ODL”) system. ODCA enables the evacuation of production from the Jacana and Tigana fields, as well as third-party volumes, under regulated tariffs. Over time, we have expanded and optimized this system through additional field connections, unloading facilities, third-party transportation agreements and operational enhancements, including dilution capabilities, allowing us to increase throughput and optimize transportation costs while improving overall system flexibility.
● Putumayo Basin: Production from the Platanillo Block is transported through a combination of trucking and flowlines to the OBA, which is operated by us and our affiliates. OBA connects to the Ecuadorian pipeline system through RODA, providing access to the SOTE pipeline and enabling exports through the port of Esmeraldas in Ecuador. We hold transportation, storage and loading contracts with RODA and SOTE, allowing us to market our crude on an FOB basis at Esmeraldas. In early 2026, certain regulatory measures adopted in Ecuador affected the economics of crude oil imports into the country, impacting deliveries to Esmeraldas. As a result, we temporarily redirected certain volumes to alternative delivery points within Colombia, which involve higher transportation costs but provide improved netbacks compared to the applicable Ecuadorian charges. We will continue monitoring the binational agreements that could be reached between Ecuador and Colombia to resolve the transitory logistic scheme.
Argentina
Crude oil from our operated assets in Argentina is sold under pricing formulas referenced to Brent and adjusted by the Medanito differential, the Neuquén Basin benchmark. Realized prices also reflect quality and logistics adjustments, including API gravity, treatment costs and transportation to regional hubs. As these fields are not yet connected to the pipeline network, crude oil is currently evacuated by truck, which we seek to optimize while advancing long-term midstream solutions. Our commercial strategy focuses on maximizing netbacks through improved evacuation efficiency, securing future pipeline capacity and developing direct relationships with local refiners and traders.
Following the acquisition, we entered into a transitional marketing arrangement with Pluspetrol S.A. (“Pluspetrol”) under two complementary agreements signed on October 16, 2025. Under the first agreement, a commission-based marketing arrangement, Pluspetrol provides marketing services for all crude oil produced. Under the second agreement, Pluspetrol may purchase any unallocated volumes of up to 200 cubic meters per day under a formula linked to export-parity Medanito prices and applicable treatment and transportation costs. These agreements were initially signed through January 31, 2026. On that date, we only extended the commission-based marketing agreement until September 30, 2026, limiting it to 65% of the production from the Loma Jarillosa Este Block. For the remaining 35% of the production from the Loma Jarillosa Este Block and 100% of the production from the Puesto Silva Oeste Block, we sell to Trafigura Argentina S.A. at wellhead. Both agreements include automatic quarterly extensions unless either party provides 45 days' notice. While this structure is designed to ensure uninterrupted offtake during the transition period, we are simultaneously developing our own commercial platform, including direct market relationships and firm transportation arrangements, to assume full commercialization once the Pluspetrol S.A. and Trafigura Argentina S.A. agreements conclude.
Brazil
Our production in Brazil, until the divestment of our working interest in the Manati field in December 2025, consisted of natural gas, condensate and crude oil. Natural gas production was sold through a long-term agreement with Petrobras,
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which provided for the delivery and transportation of the gas produced in the Manati field to the EVF gas treatment plant in the State of Bahia. In 2025, the condensate produced in the Manati field was subject to a condensate purchase agreement with H.L Oil Industrias de Transformacao LTDA.
Ecuador
Ecuador has a well-developed crude oil market with broad access to international markets and an extensive pipeline transportation system. Our oil production, until the divestment of our working interests in the Perico and Espejo Blocks in December 2025, was transported through the Ecuadorian pipeline system, with Esmeraldas as the delivery point, and 100% of our sales were exported on a competitive basis to industry leading participants including traders, refineries, and other producers. The oil price was linked to Brent and adjusted by a differential that varied month to month and resembled Oriente crude reference price.
Corporate
GeoPark Limited, our holding company incorporated under the laws of Bermuda, has a crude purchase agreement with an oil producer in the Putumayo Basin. The volumes purchased are transported and exported alongside our Putumayo Basin production. Sales of this crude oil purchased from third parties accounted for 0.1% of our consolidated revenue in 2025.
Significant Agreements
Colombia
E&P contracts
We have entered into E&P contracts that grant us the right to explore and operate in eighteen blocks in which we hold working interests. These E&P contracts are generally divided into two periods: (1) the exploration period, which may be subdivided into various exploration phases and (2) the exploitation period, determined on a per-area basis and beginning on the date we declare an area to be commercially viable. Commercial viability is determined upon the completion of a specified evaluation program or as otherwise agreed by the parties to the relevant E&P contract. The exploitation period for an area may be extended until such time as such area is no longer commercially viable and certain other conditions are met.
Pursuant to our E&P contracts, we are required, as are all oil and gas companies undertaking exploratory and production activities in Colombia, to pay a royalty to the Colombian government based on our production of hydrocarbons, as of the time a field begins to produce. Under Law 756 of 2002, as modified by Law 1530 of 2012, the royalties we must pay in connection with our production of light and medium oil are calculated on a field-by-field basis. See Note 32.1 to our Consolidated Financial Statements.
Additionally, in the event that an exploitation area has produced amounts in excess of an aggregate amount established in the E&P contract governing such area, the ANH is entitled to receive a “windfall profit”, to be paid periodically, calculated pursuant to such E&P contract.
In each of the exploration and exploitation periods, we are also obligated to pay the ANH a subsoil use fee. During the exploration period, this fee is scaled depending on the contracted acreage. During the exploitation period, the fee is assessed on the amount of hydrocarbons produced, multiplied by a specified dollar amount per barrel of oil produced or thousand cubic feet of gas produced. Further, the ANH has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the relevant E&P contract.
Our E&P contracts are generally subject to early termination for a breach by the parties, a default declaration, application of any of the contract’s unilateral termination clauses, ANH regulation or termination clauses mandated by Colombian law. Anticipated termination declared by the ANH results in the immediate enforcement of monetary guaranties against us and may result in an action for damages by the ANH. Pursuant to Colombian law, if certain conditions
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are met, the anticipated termination declared by the ANH may also result in a restriction on the ability to engage contracts with the Colombian government during a certain period. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our contracts and/or rights to explore and develop oil and natural gas reserves are subject to contractual expiration dates and operating conditions, and our E&P contracts, exploration permits, exploitation concessions and concession agreements are subject to early termination in certain circumstances.”
Eastern Llanos Basin:
Llanos 34 Block E&P contract. On March 13, 2009, the E&P contract was awarded to Unión Temporal Llanos 34, currently integrated by GeoPark Colombia S.A.S. with 45%, and Verano Limited (a subsidiary of Parex Energy) with 55% working interest. The Llanos 34 Block E&P contract provides a 24-year exploitation period for each production area, beginning on the date of a commercial declaration. The exploitation period may be extended for periods of up to 10 years at a time if certain conditions are met and subject to ANH approval. As of the date of this annual report there are production areas for the Aruco, Chachalaca, Chiricoca, Curucucu, Guaco, Jacamar, Jacana, Max, Tarotaro, Tigana, Tigui, Tilo and Tua fields.
Pursuant to the Llanos 34 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Llanos 34 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Llanos 34 Block E&P contract. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the Llanos 34 Block E&P contract, when the accumulated production of each commercial field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. See Note 32.1 to our Consolidated Financial Statements.
Llanos 32 Block. We had a 12.5% working interest in the Llanos 32 Block. Verano Energy is the operator of this block and had an 87.5% working interest. Economic rights to the ANH are similar to those under the Llanos 34 Block. On March 14, 2025, we transfered our non-operated working interest in the Llanos 32 Block to the joint operation partner for a total consideration of US$19.0 million, minus working capital adjustment of US$3.7 million. The assignment was formalized through an amendment to the E&P Contract in November 2025.
Abanico Block. In October 1996, Ecopetrol and Explotaciones CMS Nomeco Inc. entered into the Abanico Block association contract. Frontera Energy Colombia Corp is the operator of, and has a 100% working interest in, the Abanico Block. We do not maintain a direct working interest in the Abanico Block, but rather have a 10% economic interest in the net revenues from the block pursuant to a joint operating agreement. In October 11, 2024, the Abanico Block association contract’s term expired and the termination process is ongoing with the operator.
Llanos 86, Llanos 87, Llanos 104, Llanos 123 and Llanos 124 Blocks. We and Hocol (a subsidiary of Ecopetrol), each with fifty percent (50%) working interest, executed E&P contracts over these blocks in 2019, as a result of the Permanent Competitive Process launched by ANH. We are the operator of these contracts. In these E&P contracts, we are required to pay subsurface rights to the ANH, calculated based on the total acreage of the blocks, or the remaining area if in case of relinquishment had taken place. There is also an additional annual 25% markup of said subsurface rights payable as a fee for institutional development and technological transfer. Upon production, and in addition to legal royalties, the ANH is entitled to receive a percentage of total production net of royalties, at the delivery point (multiplied by a factor set in the contract and based on international oil prices). That percentage is 2% in the Llanos 86, 3% in the Llanos 87 E&P contract and Llanos 104 E&P contracts and 1% in the Llanos 123 and Llanos 124 E&P contracts. There is an additional 5-10% share payable to the ANH applicable upon extensions to the production period and when the accumulated gross aggregate production of the area of the contract exceeds 5 million barrels and the WTI exceeds a defined price. ANH becomes entitled to an additional share on production in accordance with a formula set in the contract.
In the Llanos 86 and Llanos 104 Blocks, the completion of 3D seismic acquisition and processing, along with the approval of environmental licenses, enabled the identification of drilling opportunities, such as Matraquero and Vencejo in the Llanos 104 Block, already drilled, and Tijereta in the Llanos 86 Block, which is planned to be drilled in the first half of 2026.
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In the Llanos 87 Block, after fulfilling the total exploration investments committed in the block, we made two discoveries: Tororoi and Zorzal. Accordingly, we are currently conducting an evaluation program approved by the ANH, which remains in effect through April 27, 2026.
The Llanos 123 Block, after fulfilling the total exploration investments committed in the block, in September 2025, we submitted to the ANH the declaration of commerciality of the Toritos and Saltador areas under evaluation.
In the Llanos 124 Block, as of the date of this annual report, the total investments needed to fulfill the exploratory activities committed in the block have already been incurred.
CPO-5 Block E&P contract. We hold a 30% working interest and the operator is ONGC Videsh. As of the date of this annual report, the contract is in phase 2 of the exploration period, with no outstanding investment commitments. There are two commercial fields called Mariposa and Indico, and we also drilled and put into production exploration wells in the evaluation areas La Urraca and Halcon.
Pursuant to the CPO-5 Block E&P contract and applicable law, we are required to pay royalties to the ANH based on hydrocarbons produced in the CPO-5 Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the CPO-5 Block E&P contract. The ANH also has an additional economic right equivalent to 23% of production, net of royalties. In accordance with the CPO-5 Block E&P contract, when the accumulated production of each commercial field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
CPO-4-1 Block. On January 18, 2022, the E&P contract was executed between Parex Energy and the ANH as a result of the Permanent Competitive Process launched by ANH in 2019. On April 29, 2022, an amendment to the E&P contract was executed, whereby the ANH approved the assignment of a 50% non-operated working interest to us. As of the date of this annual report, the contract is in phase 1 of the exploration period and our investment commitment consists of drilling one exploratory well for US$2.9 million, at GeoPark’s working interest, before September 19, 2028.
Pursuant to CPO-4-1 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the CPO-4-1 Block. Additionally, we are required to pay a surface and subsoil usage fee to the ANH. We are required to comply with the VEE (economic value for exclusivity) equivalent to the commitments for the exploratory period; however, if we do not perform such commitments, the VEE amount calculated as provided in the CPO-4-1 E&P contract, must be paid to the ANH. The ANH also has an additional economic right equivalent to 1% of production, net of royalties. In accordance with the CPO-4-1 Block E&P contract, when the accumulated production of the area of the contract, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo Basin:
Coati Block E&P contract. We are the operator of and have a 100% working interest in the Coati Block. The Coati Block has an evaluation area, declared in September 2006, in the southern part of the Block for the Temblon wells (Temblon Evaluation Program), which includes the completion and evaluation of the Coati-1 well. Pursuant to the Coati Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Coati Block E&P contract. In accordance with the Coati Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula. As of the date of this annual report, investment commitments in the exploration area consist of 3D seismic and 2D seismic acquisition for US$4.5 million. On November 3, 2022, GeoPark submitted to the ANH a request to withdraw from the exploration period of the Coati E&P contract and transfer the pending commitments to other E&P contracts. We have completed the transfer of the pending commitments in the block and the ANH approval is pending. On October 21, 2024, the relinquishment of the area associated with the exploration period was formalized with the ANH. The evaluation area is currently suspended.
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Mecaya Block E&P contract. We are the operator of and have a 50% working interest in the Mecaya Block. Sierracol Energy is the owner of the remaining 50% working interest in the contract. In December 2010, the former operator declared an evaluation area and presented an evaluation program for the Mecaya-1 well (Mecaya Evaluation Program). As of the date of this annual report, the contract is in unified phases 1 and 2 of the exploration period, and its remaining exploration commitment consists of the acquisition of 52.2 sq. km. of 3D seismic or 1 exploration well for an amount of US$0.6 million, at our working interest. Both the unified phases 1 and 2 and the evaluation program are currently suspended due to force majeure events (relating to prior consultations).
Pursuant to the Mecaya Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Mecaya Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Mecaya Block E&P contract. In accordance with the Mecaya Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Platanillo Block E&P contract. We are the operator of and have a 100% working interest in the Platanillo Block since its acquisition in 2020. The commercial exploitation started on September 11, 2009. Pursuant to the Platanillo Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the Platanillo Block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Platanillo Block E&P contract. In accordance with the Platanillo Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, the Company should deliver to ANH a share of the production net of royalties in accordance with an established formula. During the first nine months of 2025, operations at all wells in the Platanillo Field were suspended, with operations resuming on October 15, 2025.
Putumayo 8 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 8 Block. Sierracol Energy is the owner of the remaining 50% working interest. The contract is in unified phases 1 and 2 of the exploration period. As of the date of this annual report, two of the three committed exploratory wells had been drilled during 2025, and one well remains outstanding to be fulfilled by July 25, 2026. On September 5, 2025, the evaluation program for the Bienparado Sur well was submitted to the ANH for an initial term of one year. In September 2025, the ANH approved the accreditation of the 3D seismic acquired by the partners, and therefore the seismic commitment has been fully satisfied. In addition, the two environmental licensing processes initiated in 2023 have been concluded, and both projects now have duly granted environmental licenses: Bienparado in 2024 and Nyctibius in 2025.
Pursuant to the Putumayo 8 Block E&P contract and applicable law, we are required to pay a royalty to the ANH based on hydrocarbons produced in the block. Additionally, we are required to pay a subsoil use fee to the ANH. The ANH also has the right to receive an additional fee when prices for oil or gas, as the case may be, exceed the prices set forth in the Putumayo 8 Block E&P contract. The ANH also has an additional economic right equivalent to 2% of production, net of royalties. In accordance with the Putumayo 8 Block operation contract, when the accumulated production of each field, including the royalties’ volume, exceeds 5 million barrels and the WTI exceeds a defined base price, we should deliver to ANH a share of the production net of royalties in accordance with an established formula.
Putumayo 9 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 9 Block. Sierracol Energy is the owner of the remaining 50% working interest. As of the date of this annual report, the contract is in phase 1 of the exploration period, which has investment commitments of US$4.4 million at our working interest, corresponding to drilling of two exploration wells and the acquisition of 126.25 sq. km. of 3D seismic. This contract is suspended since June 25, 2019, due to the occurrence of a force majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). In this context, on January 2, 2026, we submitted to the ANH a request for termination of the E&P contract by mutual agreement.
Putumayo 14 Block E&P contract. We are the operator of and have a 100% working interest in the Putumayo 14 Block. On March 10, 2022, we submitted to the ANH a request to withdraw from the PUT-14 E&P contract and transfer
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the pending commitments to the Platanillo and CPO-5 Blocks. Once total investment is reached through such transfers, ANH will proceed with the contract’s termination. As of the date of this annual report, the total investment needed to fulfill the commitments has already been incurred and the ANH approval is pending.
Putumayo 36 Block E&P contract. We are the operator of and have a 50% working interest in the Putumayo 36 Block. Sierracol is the owner of the remaining 50% working interest. The contract is in preliminary phase, which is suspended since April 1, 2020 due to the occurrence of a force majeure event (issuance of the Municipal Agreement which prohibits the execution of hydrocarbons exploration and production activities in Puerto Guzmán Municipality). On September 19, 2025, the partners approved, by vote, a strategy to accredit the commitments associated with Phase 1 of the exploration period (3D seismic acquisition and two exploratory wells), without such approval necessarily implying the termination thereof. A portion of the investment needed to fulfill our working interest commitment has already been incurred through the drilling of two wells in the Llanos 123 Block, leaving a remaining commitment of approximately US$2.0 million. The partner, in turn, must accredit the value corresponding to its own working interest.
Tacacho and Terecay Blocks E&P contracts. We are the operator of and have a 50% working interest in the Tacacho and Terecay Blocks. Sierracol Energy is the owner of the remaining 50% working interest in each E&P contract. The contracts are in phase 1 of the exploration period, which are currently suspended due to the occurrence of force majeure events related with social and public order conditions of the area. The outstanding investment commitments consist of 2D seismic acquisition, processing and interpretation for US$4.1 million at our working interest. On September 21, 2022, we submitted to the ANH requests for termination of the E&P contracts. As of the date of this annual report, the requests are under review by the ANH.
Overriding Royalty Agreements
We are obligated to pay an overriding royalty of 4% and 2.5%, plus a 20% grossing up over the overriding royalty, to the previous owners of the Llanos 34 and the CPO-5 Blocks, respectively, based on the production and sale of hydrocarbons discovered in the blocks. During 2025, the Group has accrued US$18.3 million in relation to these overriding royalty agreements. Furthermore, there are overriding royalty agreements in place from 1.2% to 8.5% of the net production in the Coati, Mecaya, PUT-8, PUT-9, Tacacho and Terecay Blocks. Since they are exploratory blocks with no production during 2025, these agreements had no impact on our results.
Argentina
Overview of Unconventional Concessions
Loma Jarillosa Este Unconventional Concession
The Loma Jarillosa Este unconventional exploitation concession (Concesión de Explotación No Convencional de Hidrocarburos, or “CENCH”) is located in the Province of Neuquén, Argentina, and was granted for a 35-year term until 2057 over an area of approximately 24.5 square kilometers, in accordance with the Federal Hydrocarbons Law. Pluspetrol S.A. originally held 100% of the working interest in the concession and subsequently assigned its entire interest to GeoPark Argentina S.A., which became the operator.
As part of this assignment, GeoPark agreed to a continuing development plan that includes:
(i)A firm commitment for 2025 of US$4.8 million for well interventions and enhancements to the Loma Jarillosa Este facilities. In subsequent years, additional work programs may be submitted and approved as firm commitments.
(ii)During years 2 and 3 of the Continuing Development Plan, the activities will consist of drilling 7 horizontal wells, completion of 9 horizontal wells, and the commissioning of five 5 horizontal wells.
(iii)The entire Development Plan proposed by GeoPark is composed of a total of 29 horizontal wells aiming at maximizing the extraction of unconventional resources from the Cocina and Organico Inferior levels of the Vaca Muerta Formation.
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Puesto Silva Oeste Unconventional Concession
In the Puesto Silva Oeste area, also located in the Province of Neuquén, Pluspetrol S.A. assigned to GeoPark Argentina S.A. its 100% working interest in the existing hydrocarbons exploitation concession. In connection with this assignment, the Province of Neuquén granted a new 35-year unconventional exploitation concession (the “PSO CENCH”), as well as an authorization to transport natural gas from Puesto Silva Oeste to the NEUBA II pipeline. This transportation authorization remains associated with the PSO CENCH.
Under the terms of the assignment, GeoPark Argentina S.A. granted GyP a fully carried 5% participation in the economic rights of the PSO CENCH. This participation entitles GyP to 5% of net production revenues from the concession, without operational responsibility, for the entire duration of the PSO CENCH. The fully carried participation is recoverable in full by GeoPark, through the allocation of up to 100% of GyP’s share of production.
The PSO CENCH includes a Pilot Plan that provides for:
(i)the drilling, completion, and production start-up of one horizontal well with a 2,500-meter lateral section and 42 fracture stages; and
(ii)in the event that after 8 months from the production start-up of the committed well, the production profile recorded is equal to or greater than the estimated levels, the contingent drilling, completion, and production start-up of up to 2 additional wells targeting the Vaca Muerta formation will be triggered as an additional commitment.
The investment commitments under the PSO Pilot Plan shall be executed within a term of 3 years as from the effective date of the CENCH, in line with the proposed work schedule. The investment associated with the proposed Pilot Plan is US14.5 million. Parallel to the Pilot Plan, we shall construct and commission a central processing facility in the area.
Brazil
Overview of concession agreements
Oil and gas activities in Brazil are governed primarily by the Brazilian Petroleum Law and regulated by the National Agency of Petroleum, Natural Gas and Biofuels (“ANP”). Under this framework, exploration and production activities are conducted pursuant to concession agreements, which generally provide for an exploration phase followed, upon a declaration of commercial viability, by a development and production phase. Concession agreements are subject to ANP oversight and require compliance with applicable technical, operational, environmental and financial obligations.
BCAM-40 Concession Agreement.
The BCAM 40 Concession Agreement, which included the Manati gas field, was the only producing asset in Brazil in which we held an interest. In December 2025, we divested our 10% non-operated working interest in the BCAM 40 Concession Agreement, and as a result, we no longer have any producing assets in Brazil.
Exploration blocks.
We currently hold operated interests in four exploratory blocks awarded in the ANP’s First Open Acreage Bid Round, located in the Potiguar Basin (Block POT-T-834) and the Recôncavo Basin (Blocks REC-T-58, REC-T-67 and REC-T-77). These blocks are at an early exploration stage and are subject to limited minimum work commitments. As of December 31, 2025, the estimated remaining exploration commitments to be executed before August 2026 amounted to approximately US$0.5 million.
Title to properties
In each of the countries in which we operate, the state is the exclusive owner of all hydrocarbon resources located in such country and has full authority to determine the rights, royalties or compensation to be paid by private investors for
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the exploration or production of any hydrocarbon reserves. In Colombia, Argentina and Brazil, local governments grant such rights through E&P contracts, exploration permits, exploitation concessions and concession agreements, respectively. See “Item 3. Key Information—D. Risk factors—Risks relating to the countries in which we operate— Oil and natural gas companies in Colombia, Argentina and Brazil operate and have a working and/or economic interest over, yet do not own any of the oil and natural gas reserves in such countries.” Other than as specified in this annual report, we believe that we have satisfactory rights to exploit or benefit economically from the oil and gas reserves in the blocks in which we have an interest in accordance with standards generally accepted in the international oil and gas industry. Our E&P contracts, exploration permits, exploitation concessions and concession agreements are subject to customary royalty and other interests, liens under operating agreements and other burdens, restrictions and encumbrances customary in the oil and gas industry that we believe do not materially interfere with the use of or affect the carrying value of our interests. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—We are not, and may not be in the future, the sole owner or operator of all of our licensed areas and do not, and may not in the future, hold all of the working interests in certain of our licensed areas. Therefore, we may not be able to control the timing of exploration or development efforts, associated costs, or the rate of production of any non-operated and, to an extent, any non-wholly owned, assets.”
Our customers
In Colombia, we allocate our sales on a competitive basis to industry leading participants including traders and other producers. In 2025, the oil and gas production was sold to three clients that concentrated 96% of the Colombian subsidiaries’ revenue. During 2024 and 2025, we executed offtake and prepayment agreements with Vitol, Trafigura and BP to sell production from our producing blocks in the Llanos Basin, mainly Llanos 34, Llanos 123 and CPO-5. We managed the counterparty credit risk associated to sales contracts by limiting payment terms offered to minimize the exposure, such as the offtake and prepayment agreements with Vitol, Trafigura and BP. For further information, please see Note 3 to our Consolidated Financial Statements.
In Argentina, our crude oil production is transported by truck and sold to local refineries, offtakers and/or third-party operators. Our initial crude’s sale and evacuation was implemented by two short-term complementary agreements entered with Pluspetrol. Under a sales agency agreement, Pluspetrol acted as our sales agent to market all crude produced from the Loma Jarillosa Este and Puesto Silva Oeste Blocks in the domestic market, coordinating lifting, invoicing, and collections on our behalf during the contractual term, renewable quarterly. And any unsold daily production volumes were purchased directly by Pluspetrol under a Crude Sale Agreement delivered at the Centenario treatment plant.
In Brazil, all our gas produced in the Manati field was sold to Petrobras. In Ecuador, 100% of our sales were exported on a competitive basis to industry leading participants including traders and other producers.
Seasonality
Although there is some historical seasonality to the prices that we receive for our production, the impact of such seasonality has not been material. Seasonality has also not played a significant role in our ability to conduct our operations, including drilling and completion activities.
Our competition
The oil and gas industry is competitive, and we may encounter strong competition from other independent operators and from major state-owned oil companies in acquiring and developing licenses in the countries where we operate or plan to operate.
Many of these competitors have financial and technical resources and personnel substantially larger than ours. As a result, our competitors may be able to pay more for desirable oil and natural gas assets, or to evaluate, bid for and purchase a greater number of licenses than our financial or personnel resources will permit. Furthermore, these companies may also be better able to withstand the financial pressures of unsuccessful wells, sustained periods of volatility in financial and commodities markets and generally adverse global and industry-wide economic conditions, and may be better able to absorb the burdens resulting from changes in relevant laws and regulations, which may adversely affect our competitive position. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Competition in the oil and
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natural gas industry is intense, which makes it difficult for us to attract capital, acquire properties and prospects, market oil and natural gas and secure trained personnel.”
We may also be affected by competition for drilling rigs and the availability of related equipment. Higher commodity prices generally increase the demand for drilling rigs, supplies, services, equipment and crews, and can lead to shortages of, and increasing costs for, drilling equipment, services and personnel. Shortages of, or increasing costs for, experienced drilling crews and equipment and services could restrict our ability to drill wells and conduct our operations.
Health, safety and environmental matters
General
We are genuinely committed to ensuring that everyone returns home safely and to preventing environmental impacts derived from our operations. Our actions are guided by compliance with applicable laws, industry best practices, and international standards related to environmental, health, and safety performance. We work hand in hand with our suppliers and contractors to transfer best health, safety and environmental practices throughout our value chain, reinforcing our shared responsibility for safety and environmental protection. This commitment is reflected in binding contractual agreements, regular performance evaluations, compliance reviews, and continuous capacity building to strengthen our health, safety, and environmental culture across all operations.
Our Health and Safety Management Plan focus on strengthening leadership at all organizational levels and fostering safe and informed decision-making. Through the implementation of systematic health and safety management tools, we reinforce risk awareness and operational discipline. The updated Work Permit System provides greater clarity in roles, responsibilities, and authorities across operations, contributing to a stronger safety culture. We have also enhanced contractor management throughout their entire lifecycle, ensuring alignment with our corporate standards of excellence. In our administrative environments, we promote a robust health and safety culture and implement initiatives that foster comprehensive well-being, integrating physical, mental, and social health.
We have an environmental management and feasibility strategy that allows us to guarantee the development of plans and actions that ensure respect and protection of the environment in the territories where we operate.
Across all countries where we operate, we ensure compliance with applicable health, safety and environmental requirements. All our operations have the necessary environmental licenses and permits as required by local legislation, based on environmental studies with citizen participation to define management measures and impact mitigation strategies.
Our Environmental Management System (EMS), certified under the ISO standard: 14001:2015 for our operations in Colombia, defines programs for the integral management of water resources; solid and liquid waste management; atmospheric emissions and energy; biodiversity and ecosystem services and training and awareness regarding the protection of the environment for employees and suppliers. In addition, it defines the roles and responsibilities of management regarding the performance of our environmental issues.
Our corporate environmental commitment is mainly based on the management of the following topics:
Integral water management
Our integral water management program is based on the following water principles and objectives: (i) considering water-related risks and opportunities during the planning and execution of our projects, (ii) ensuring sustainable water management by reducing, reusing and optimizing water consumption in our operations, and (iii) innovating, and implementing best practices to ensure zero wastewater discharges into surface water bodies.
We are committed to eliminate any natural surface waterbody withdrawal in all our permanent operations (fields under development) during 2025, as well as continuing to maintain zero direct discharges into surface water sources.
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In 2024, we conducted our first comprehensive water footprint assessment in all our operated blocks in Colombia and Ecuador, following the NTC-ISO 14046:2017 methodology and verified by Colombia’s Standards Institute (ICONTEC). The evaluation covered both direct and indirect water use and assessed impacts on water availability and quality, establishing a corporate baseline to guide future goals and actions for sustainable water management across our operations. In 2025, for the second consecutive year, we carried out the verification of our corporate water footprint assessment for the previous year, reaffirming our commitment to responsible and sustainable water resource management, as well as to the continuous improvement of water use efficiency in our operations.
During 2025, in Colombia, we maintained our commitment to avoiding the use natural surface water sources in our permanent operations, and we did not carry out any type of wastewater discharge into surface waterbodies, to avoid any potential conflict with the other users of this resource due to its quality or quantity
As a contribution to the water-shed in which we capture the water required for the operations in the Llanos 34 Block in Colombia, we completed the construction of the sewerage system and the water waste treatment plant for a local town over 1,300 residents, enhancing the quality of life of its inhabitants and improving the water quality of the river receiving the discharge.
Biodiversity
Through our biodiversity management, we articulate our efforts to avoid, mitigate and eliminate any impact that may represent a material risk to the biodiversity of the environment where we operate, applying the mitigation hierarchy to protect nature and use it sustainably. We recognize the importance of biodiversity in the areas of our interest since the planning stage of our projects. We are committed to avoiding operations in legally protected areas and taking into account biodiversity value and ecosystem services as a driver to design, plan and execute our projects. We are also taking a no-deforestation and no-net-loss approach to biodiversity. The following action lines guide our decision making related to biodiversity; i) green infrastructure, sustainable use and connectivity, ii) conservation of species of wild flora and fauna, iii) strengthening protected areas in the countries we operate, and iv) biodiversity knowledge management.
In addition, we compensate for our residual impact on biodiversity and, we participate and promote programs related to the rehabilitation, restoration, and conservation of high value ecosystems through strategic alliances for the conservation of biodiversity, strengthening social and cultural connections with nature, and promoting knowledge of the natural wealth of the countries we operate in.
Some of the projects related to biodiversity that contribute to the reduction of biodiversity loss, the promotion of conservation of the environment and the stability of ecosystems during 2025, included:
● 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.
● In 2025, 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 Group’s largest operations in terms of production.
● In 2025, we registered as TNFD adopters and we will gradually begin adopting and reporting in alignment with these recommendations to identify and manage impacts and dependencies, risks and opportunities on nature related risks.
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● 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% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2025;
● 40-60% GHG emissions intensity reduction of Scope 1 and 2 emissions by 2030; and
● net zero Scope 1 and 2 emissions by or before 2050.
All our abovementioned goals are defined against a 2020 baseline.
These goals take into account the execution of some operational and environmental projects. The following projects represent our most relevant achievements in Colombia during 2025:
● 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
● use of previously flared gas, gradually decreasing routine flaring.
Medium-term actions include additional energy efficiency measures, small-scale renewable projects, further energy diversification alternatives, management of methane emissions, potential participation in carbon markets, reforestation and afforestation initiatives, among others.
As of the date of this annual report, we have other ongoing environmental initiatives related to climate adaptation, such as, in Colombia, we continue the execution of an agreement with the Institute of Hydrology, Meteorology and Environmental Studies (IDEAM) for the strengthening and modernization of the hydrometeorological monitoring network of the Orinoquía, in the hydrographic zone of the Meta River, which will contribute to improve water management, comprehensive risk management and climate change adaptation.
Integral waste management and circular economy
Regarding the proper management of solid waste generated by our activities, we focus our management on the principles of reduce, reuse, recycle and recover. In this way we ensure the mitigation of environmental impacts, while complying with applicable regulations. In 2025, we continued strengthening our circular economy strategic plan and the roadmap for its implementation. As part of this plan, we are carrying out more than 8 circular initiatives as part of the three (3) circularity models that we have prioritized: i) water management, ii) waste management, and iii) use of gas.
In 2024, we were recognized by the ACP with the Sustainability Facts award in the implementation of circular models category, for the results of the circular economy strategic plan through which we promote the efficient management of
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resource consumption, the maintenance of the value of products and materials, and the minimization of waste generation in our operations.
Spill Management
In 2025, we had zero recordable hydrocarbon spills (>=1Bbl uncontained) in our operations.
Our HS Plan
Our Health and Safety Management System (HSMS) remain certified under the ISO 45001:2018 standard, encompassing all our operations in Colombia. With the expansion of our operations into Argentina, we have extended the implementation of our HSMS to this new operation, reaffirming our corporate commitment to excellence in health and safety performance throughout the region.
Our Health and Safety Management Plan is designed to implement realistic, practical, and globally recognized programs that strengthen leadership, operational discipline, and risk awareness across the organization. Guided by international standards (IOGP / IPIECA / IADC / ARPEL) and our SPEED philosophy, we aim to foster shared ownership of health and safety, embedding it into every level of decision-making and every aspect of our operations.
In 2025, our strategy focused on four key areas that form the foundation of our health and safety (“HS”) management:
● Leadership and Governance: Strengthening leadership at all levels through the Safety First communication strategy and promoting safe, informed decision-making across all teams.
● People Management: Enhancing technical and HS competencies through targeted training programs and fostering a culture of care that integrates physical, mental, and social well-being.
● Operation Management: Reinforcing operational discipline through the updated Work Permit System, clearer definition of roles and responsibilities, and the consistent use of HS management tools that strengthen risk control.
● Contractors Management: Strengthening contractor engagement throughout the entire process, from selection to performance evaluation, ensuring alignment with our corporate HS standards and shared commitment to safety excellence.
Our HS Policy
Our Health and Safety Policy seeks to meet or exceed all applicable regulations in the countries where we operate. We believe that oil and gas can be produced safely and responsibly, safeguarding people’s well-being and protecting the environment. Within our SPEED philosophy, a dedicated and highly trained team leads the implementation of best HS practices, ensuring compliance with the standards established by our board of directors and providing continuous training and support to all employees and contractors.
Since 2024, health and safety performance has become a recurring topic of review for the board’s Sustainability Committee (SPEED Committee), reinforcing the integration of HS into our corporate governance and comprehensive sustainability management.
Our health and safety practices and outcomes
We continuously improve and update management tools to strengthen our health and safety policy. Our programs are designed to identify, evaluate, and control risks that could affect the health and safety of employees, contractors, and visitors. Among our core programs are: Proactive Observation Program (POP), Authority to stop an activity (ADA), Safety
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Operational Standard (SOS), Management of Change (MOC), Incident Reporting and Investigation System (IRIS), Road Transportation Safety (RTS), and the business continuity master plan (PMCN).
In 2025, we achieved significant milestones that demonstrate our commitment to continuous improvement and operational excellence:
● Zero recordable vehicular incidents and zero recordable oil spills across all operations.
● Zero recordable incidents affecting people in our Ecuadorian operations, which remained active throughout the year.
● Achievement of our Total Recordable Injury Rate (TRIR) and Motor Vehicle Crash (MVC) targets.
● Strategic reviews and retrospective meetings held with contractor management teams, including quarterly sessions with Drilling & Completion, ALS, O&M, and Facilities groups.
● Maintenance of our ISO 45001 certification, ensuring alignment with the highest international standards for health and safety.
As of December 31, 2025, and for the preceding twelve months, our HS performance indicators were as follows:
● People injury (per 1,000,000 hours worked, including employees and contractors):
● Lost time injury rate (LTIR) of 0.43.
● Total recordable incident rate (TRIR) of 0.57.
● Zero fatal incidents.
● Vehicle incidents (per 1,000,000 kilometers traveled):
● Recordable Vehicular Incident Rate (MVC): 0.00
Certain Bermuda law considerations
We have been designated by the Bermuda Monetary Authority as a non-resident for Bermuda exchange control purposes. This designation allows us to engage in transactions in currencies other than the Bermuda dollar, and there are no restrictions on our ability to transfer funds (other than funds denominated in Bermuda dollars) in and out of Bermuda or to pay dividends to United States residents who are holders of our common shares.
Insurance
We maintain insurance coverage of types and amounts that we believe to be customary and reasonable for companies of our size and with similar operations in the oil and gas industry. However, as is customary in the industry, we do not insure fully against all risks associated with our business, either because such insurance is not available or because premium costs are considered prohibitive.
Currently, our insurance program includes, among other things, construction, fire, vehicle, technical, umbrella liability, cyber security, director’s and officer’s liability and employer’s liability coverage. Our insurance includes various limits and deductibles or retentions, which must be met prior to or in conjunction with recovery. A loss not fully covered by insurance could have a materially adverse effect on our business, financial condition and results of operations. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Oil and gas operations contain a high degree of risk, and we may not be fully insured against all risks we face in our business.”
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Industry and regulatory framework
Colombia
Regulation of the oil and gas industry
The ANH administers Colombia’s upstream acreage and awards areas primarily through exploration and production contracts (“E&P contracts”) and technical evaluation agreements (“TEAs”). The contractual framework has been updated through successive ANH agreements; E&P contracts entered into in recent years are governed principally by Agreement 002 of 2017 (as compiled by Agreement 009 of 2021), while earlier contracts remain subject to the regulations in effect at the time they were executed. In September 2023, the ANH issued Agreement 06 of 2023 to promote exploration by, among other measures, allowing extensions of exploration and evaluation periods in exchange for additional exploration commitments.
Regulatory framework
Regulation of exploration and production activities
Under Colombian law, the state is the exclusive owner of all hydrocarbon resources located in Colombia and has full authority to determine the rights, royalties or compensation to be paid by private investors for the exploration or production of any hydrocarbon reserves. The Ministry of Mines and Energy is responsible for national energy policy, and the ANH administers the granting and oversight of upstream contractual rights. The Petroleum Code (Decree Law 1056 of 1953) and related regulations establish general requirements applicable to hydrocarbon activities, which are implemented in practice through E&P contracts and TEAs.
E&P contractors are generally required to pay royalties (in kind or in cash as instructed by the ANH) and, depending on the applicable contract, additional economic rights in favor of the ANH (including the participating interest in production commonly referred to as the ‘X factor’), as well as other contractual economic provisions. Contractors may also undertake community-related obligations in the area of influence of the projects (Proyectos en Beneficio de las Comunidades, “PBC”)
In connection with the ANH’s Ronda Colombia 2021, the ANH introduced additional bid parameters, including an ‘Exclusivity Economic Value’ (EEV) concept linked to exploration commitments. We did not participate in that round; however, we subsequently received a 50% non-operated working interest in the CPO4-1 E&P contract through a transfer from Parex.
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.
The main taxes currently in effect are the income tax (35%, plus a surtax for companies developing crude oil extractive activities from 2023 onwards, ranging between 0% and 15%, depending on the Brent crude oil price level), capital gains tax (15%), sales or value added tax (19%), and the tax on financial transactions (0.4%).
Additional regional taxes also apply with some special rules for the companies belonging to the oil and gas industry. Colombia has entered into a number of international tax treaties to avoid double taxation and prevent tax evasion in matters of income tax and net asset tax.
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Decree 2080 of 2000 (amended by Decree 4800 of 2010), or the international investment regime, regulates foreign capital investment in Colombia. Resolution 1/2018 of the board of the Colombian Central Bank, or the Exchange Statute, and its amendments contain provisions governing exchange operations. Articles 94 to 97 of Resolution 1 provide for a special exchange regime for the oil industry that removes the obligation of repayment to the foreign exchange market currency from foreign currency sales made by foreign oil companies.
Such companies may not acquire foreign currency in the exchange market under any circumstances and must reinstate in the foreign exchange market the capital required in order to meet expenses in Colombian legal currency. Companies can avoid participating in this special oil and gas exchange regime, however, by informing the Colombian Central Bank and Ministry of Mines and Energy, in which case they will be subject to the general exchange regime of Resolution 1 and may not be able to access the special exchange regime for a period of 10 years.
Tax regulations implemented in 2025 and subsequent events in 2026
On February 14, 2025, Colombia’s Ministry of Finance issued Decree No. 0175 of 2025 in connection with the state of internal commotion declared in certain regions, introducing (i) a 1% special tax on the first sale or export of crude oil and coal (based on sale value for domestic transactions and FOB value for exports) and (ii) a temporary increase of the stamp tax rate from 0% to 1% on certain public instruments and private documents recording obligations above approximately COP 298 million (approximatellyIn 2024, Argentina enacted Law No. 27,742 (the ‘Ley de Bases’), US$ 0.07 million), with these measures applying through December 31, 2025.
In December 2025, the Government declared a nationwide State of Economic and Social Emergency and adopted additional fiscal measures, including a temporary tax on sale or export of hydrocarbons and restrictions affecting the deductibility of royalty payments; however, on January 29, 2026, the Constitutional Court ordered the provisional suspension and, as a consequence, ordered that the additional fiscal measures would not produce effects as of that date pending a final ruling.
More recently, in February 2026, the Government declared a new regional State of Economic, Social and Ecological Emergency for 30 days and subsequently adopted a temporary net worth tax for legal entities for tax year 2026, applicable to entities with net worth above a specified threshold as of March 1, 2026. While the general rate is 0.5%, for companies in the mining-energy sector (including oil and gas) such as us, the applicable rate is 1.6%. The tax is payable in two equal installments (50% due on April 1, 2026 and 50% due on May 4, 2026).
Environmental
Hydrocarbon operations are subject to national comprehensive environmental regulations issued by the Ministry of Environment and Sustainable Development. The permits required for exploration and exploitation activities are granted and followed by ANLA which is an independent entity. Colombian environmental legislation is very robust, and oil and gas is one of the most regulated sectors including seismic programs, exploration, production, transportation of hydrocarbons, decommissioning, restoration and remediation stages.
Decree 1076 of 2015 and further modifications, compile the country’s environmental legal framework prioritizing the recognition of sensitive areas, the country’s biodiversity, the mitigation hierarchy of impacts, the implementation of the best practices of environmental management, the liquid effluent disposal thresholds, the minimum offset measures requirements, among others, in order to achieve the development of the activity with an adequate care of the environment.
Argentina
Regulatory framework
Hydrocarbon activities in Argentina are primarily governed by the Federal Hydrocarbons Law No. 17,319, as amended, which establishes a concession-based system for the exploration and exploitation of oil and gas resources. Following constitutional and legislative reforms, jurisdiction over onshore hydrocarbon resources is vested in the provincial states, which grant exploration permits and exploitation concessions within their territories.
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In 2024, Argentina enacted Law No. 27,742 (the ‘Ley de Bases’), which introduced, among other measures, the Incentive Regime for Large Investments (‘RIGI’). In February 2026, Argentina issued a regulation extending the RIGI incentive regime to onshore upstream oil and gas. We are evaluating its potential applicability to our development plans in the Loma Jarillosa Este and Puesto Silva Oeste Blocks, subject to meeting eligibility requirements and regulatory interpretation by the authorities.
Hydrocarbon Income Maximization and Exports
Argentina has historically implemented policies prioritizing domestic hydrocarbon supply, including export restrictions and price controls. Recent regulatory changes have shifted this approach toward promoting investment and maximizing income from hydrocarbon exploitation. Exports of crude oil and hydrocarbon products are generally permitted, subject to regulatory notification and the absence of objections by the Energy Secretariat based on supply security considerations.
Hydrocarbon Exploitation Concessions Terms
Argentina law provides for different types of hydrocarbons exploitation concessions: (i) 25-years conventional concessions; (ii) 35-years unconventional hydrocarbon concessions and (iii) 30-years offshore concessions.
With regards to royalties, while historically a fixed or standardized royalty was foreseen for all concessions, an important modification was introduced by Section IV of the Ley de Bases in the selection procedures, since, although the competitive scheme is maintained, the bidding among the interested parties will be based on the royalty offered. In this scheme, the State will set a reference price based on international markets, and its real value will be estimated by adjusting the values in accordance with the U.S. Consumer Price Index. In this way, the bidder will have to quote a base royalty of 15% with an adjustment (which may be positive or negative) and this will compose the royalty offered for the whole course of the concession. The novelty is that the royalty offered will be maintained if the reference price does not change by more or less than 50% with respect to the price in force at the time of award. If the reference price increases by more than 50%, the concessionaire will pay double the royalty offered for the duration of such increase and, vice versa, will pay half if the reference price decreases by more than 50%.
The payment of an extension bonus to the government is also provided for a maximum amount equal to 2% of the remaining proven reserves at the end of effective term of the concession valued at the average basin price applicable to the respective hydrocarbons during the immediate past 2 years.
Regulation of transportation activities
Exploitation concessionaires have the exclusive right to obtain a transportation concession for the transport of oil and gas from the provincial states or the federal government, depending on the applicable jurisdiction. Such transportation concessions include storage, ports, pipelines and other fixed facilities necessary for the transportation of oil, gas and by-products.
Transportation facilities with surplus capacity must transport third parties’ hydrocarbons on an open-access basis, for a fee which is the same for all users on similar terms.
Crude oil and natural gas transportation in Argentina is carried out primarily through a limited number of common carrier pipeline systems, which continue to operate today. In order to promote the expansion of transportation capacity, regulations adopted in 2019 allow shippers to reserve capacity in new or expanded pipelines through freely negotiated capacity reservation agreements.
Taxation
Exploitation concessionaires are subject to the general federal and provincial tax regime. For our Argentine operations, the most relevant federal taxes include corporate income tax at a 35% rate (based on our applicable taxable income threshold), value-added tax (21%), and the tax on debits and credits in bank accounts, which generally applies
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to debits and credits in Argentine bank accounts (typically 0.6% on debits and 0.6% on credits, with certain transactions subject to higher or reduced rates and with limited creditability against income tax in specific cases). Provincial taxes generally include turnover tax (rates vary by jurisdiction and activity) and stamp tax.
Since May 2020, export duties are exempted as long as the international Brent crude oil price is equal to or lower than US$45 per bbl, progressively increasing as the reference price rises up to 8%, a ceiling to be recognized when Brent is equal to or higher than US$60 per bbl (as per DNU No. 488/20). During 2025, the rate remained at 8%.
Argentine resident individuals and undivided estates, foreign individuals and undivided estates, and foreign entities are subject to a 0.5% personal assets tax on the value of shares issued by Argentine entities held as of December 31 of each year, which is assessed on the Argentine issuer as a substitute taxpayer and calculated based on the proportional net worth value derived from the issuer’s financial statements; the issuer is generally entitled to seek reimbursement from the relevant shareholders, including through dividend withholding or enforcement against the shares.
Tax Benefits of Negotiable Obligations (“ONs”)
Negotiable Obligations (“ONs”) in Argentina are governed by Law 23,576, which provides several tax advantages for issuers and subscribers.
For issuers, the key benefits include:
● 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: Argentine resident individuals are generally exempt from Argentine income tax and capital gains on interests. The turnover tax generally does not apply to individuals unless they habitually engage in a taxable activity, subject to the applicable provincial regulations. In addition, certain provinces may provide specific exemptions for yields on ONs for individuals.
● 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 comply with the applicable requirements and conditions established by the Argentine Central Bank (BCRA) to access the official foreign exchange market (MULC) for payments abroad, including dividend distributions, repayment of intercompany loans, and external debt servicing. Certain transactions, such as payments for imports, may be conducted through the MULC but are subject to regulatory conditions and, in some cases, delays.
Despite these restrictions, companies can transfer funds abroad through alternative mechanisms permitted under the current regulatory framework. These include financing structures, capital contributions, and transactions conducted at
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financial market exchange rates. Additionally, companies operating under certain promotional regimes, particularly in the hydrocarbon sector, may access preferential foreign exchange conditions, allowing for improved financial planning and operational efficiency. However, differences between the official exchange rate and financial market exchange rates may result in additional costs.
The current Argentine government has publicly expressed its intention to gradually ease foreign exchange restrictions as part of broader economic stabilization efforts. Future regulatory changes could modify access to foreign currency and the conditions under which companies operate in the exchange market, potentially increasing flexibility in capital flows over time.
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.
Brazil
Regulatory framework
Oil and gas activities in Brazil are governed primarily by the Brazilian Federal Constitution and the Brazilian Petroleum Law, which allow private and state-owned companies to engage in the exploration and production of hydrocarbons under a concession-based regime. The sector is regulated and supervised by the National Agency of Petroleum, Natural Gas and Biofuels (“ANP”), which is responsible for awarding concession rights, overseeing compliance with concession agreements and enforcing applicable technical, operational and environmental regulations.
Exploration and production activities are carried out pursuant to concession agreements granted by the ANP through competitive processes. Such concession agreements establish the rights and obligations of concessionaires, including exploration and production terms, requirements for the return of areas, guarantees to secure performance, and conditions for the transfer or assignment of participation interests, which are generally subject to ANP approval.
Taxation and government take
Concessionaires in Brazil are subject to a government take primarily comprised of royalties and, in certain cases, a special participation fee applicable to fields with higher production levels or profitability. Royalties generally range between 5% and 10% of production, calculated based on reference prices established by the ANP. The special participation fee, when applicable, may reach up to 40% of net revenues, depending on production volumes, field characteristics and location.
In addition to government take, oil and gas activities are subject to direct federal taxes, including corporate income tax, currently levied at a combined rate of approximately 34% (comprising a 25% corporate income tax and a 9% social contribution on net profit), calculated on taxable income.
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Upstream operations are also subject to indirect taxes, which may represent a significant cost component. These include the state value-added tax (ICMS), generally levied at rates ranging from 17% to 20% on local transactions, as well as federal social contribution taxes on gross revenues (PIS and COFINS), which under the non-cumulative regime are levied at a combined nominal rate of 9.25%, subject to the availability of tax credits depending on the nature of the activity and expenditures.
Tax incentives
In 2018, GeoPark Brazil was granted a tax incentive by the Superintendence for the Development of the Northeast (“SUDENE”), which provided for a 75% reduction in corporate income tax and related surcharges on qualifying profits derived from exploration activities in the SUDENE operating area. This incentive was granted for a ten-year period, subject to compliance with certain investment, operational, labor and environmental requirements.
Ecuador
Regulatory and tax framework
Hydrocarbon operations in Ecuador are conducted under service contracts or production-sharing contracts regulated by the Ministry of Energy and supervised by Agency for Regulation and Control of Hydrocarbons (“ARCH”). The State retains ownership of hydrocarbons and receives its economic participation through its share of production and applicable taxes. Contractors are subject to a 25% corporate income tax (reduced to 20% for the Espejo Consortium under an investment agreement), 15% employee profit-sharing, 15% VAT (non-creditable), and a 5% tax on foreign currency outflows, among other levies.
C. Organizational structure
We are an exempted company incorporated pursuant to the laws of Bermuda. We operate and own our assets directly and indirectly through a number of subsidiaries. See an illustration of our corporate structure in Note 19 (“Subsidiary undertakings”) to our Consolidated Financial Statements.
D. Property, plant and equipment
See “—B. Business Overview—Title to properties.”