A. Operating results The following discussion of our financial condition and results of operations should be read in conjunction with our Consolidated Financial Statements and the notes thereto. The following discussion contains forward-looking statements that involve risks and uncertainties. Our actual results may differ materially from those discussed in the forward-looking statements as a result of various factors, including those set forth in “Item 3. Key Information—D. Risk factors” and “Forward-looking statements.” Factors affecting our results of operations We describe below the year-to-year comparisons of our historical results and the analysis of our financial condition. Our future results could differ materially from our historical results due to a variety of factors, including the following: 79 Table of Contents Discovery and exploitation of reserves Our results of operations depend on our level of success in finding, acquiring (including through bidding rounds) or gaining access to oil and natural gas reserves. While we have geological reports evaluating certain proved, contingent and prospective resources in our blocks, there is no assurance that we will continue to be successful in the exploration, appraisal, development and commercial production of oil and natural gas. The calculation of our geological and petrophysical estimates is complex and imprecise, and it is possible that our future exploration will not result in additional discoveries, and, even if we are able to successfully make such discoveries, there is no certainty that the discoveries will be commercially viable to produce. Our results of operations will be adversely affected in the event that our estimated oil and natural gas asset base does not result in additional reserves that may eventually be commercially developed. In addition, there can be no assurance that we will acquire new exploration blocks or gain access to exploration blocks that contain reserves. Unless we succeed in exploration and development activities, or acquire properties that contain new reserves, our anticipated reserves will continually decrease, which would have a material adverse effect on our business, results of operations and financial condition. Oil and gas revenue and international prices Our revenues are derived from the sale of our oil and natural gas production, as well as of condensate derived from the production of natural gas. The price realized for the oil we produce is generally linked to Brent. The market price of these commodities is subject to significant fluctuation and has historically fluctuated widely in response to relatively minor changes in the global supply and demand for oil and natural gas, market uncertainty, economic conditions, and a variety of additional factors. For example, during the six-year period from March 1, 2020, to February 28, 2026, Brent spot prices ranged from a low of US$19.3 per barrel to a high of US$128.0 per barrel. Additionally, the oil and gas we sell may be subject to certain discounts. For example, in Colombia, the realized oil price is based on Brent, adjusted by a differential linked to either the Vasconia crude reference price, a marker broadly used in the Llanos Basin, or the Oriente crude reference price, a marker broadly used for crude sales in Esmeraldas, Ecuador, for the crude oil of the Putumayo Basin that is transported through Ecuador. In Argentina, the Medanito crude reference price is the marker commonly used in the Neuquén Basin. The reference price is also further adjusted for marketing and quality discounts, considering factors such as API gravity, viscosity, sulphur content, delivery point and transport costs. ​ We seek to partially mitigate our exposure to crude oil price volatility using derivatives by hedging a portion of our production for a limited period going forward. We use a combination of options to manage our production’s exposure to commodity price risk, which considers forecasted production and budget price levels, among other factors. For further information related to Commodity Risk Management Contracts, please see Note 7.1 to our Consolidated Financial Statements. If oil and gas prices had fallen by 10% compared to actual prices during the year, with all other variables held constant, considering the impact of the derivative contracts in place, post-tax profit for the year would have been lower by US$8.2 million (US$24.8 million in 2024). Funding for our capital expenditures relies in part on oil prices remaining close to our estimates or higher levels and other factors to generate sufficient cash flow. Low oil prices affect our revenues, which in turn affect our debt capacity and the covenants in our financing agreements, as well as the amount of cash we can borrow using our oil reserves as collateral, the amount of cash we are able to generate from current operations and the amount of cash we can obtain from prepayment agreements. If we are not able to generate the sales which, together with our current cash resources, are sufficient to fund our capital program, we will not be able to efficiently execute our work program which would cause us to further decrease our work program, which could harm our business outlook, investor confidence and our share price. If oil prices average higher than the base budget price, we have the ability to allocate additional capital to more projects and increase our work and investment program and thereby further increase oil and gas production. 80 Table of Contents Production and operating costs Our production and operating costs consist primarily of expenses associated with the production of oil and gas, the most significant of which are facilities and wells maintenance (including pulling works), labor costs, contractor and consultant fees, chemical analysis, royalties and economic rights in cash, and consumables, among others. Our production costs may vary as a consequence of the increase or decrease of commodity prices and other factors, such as the increase in energy costs that peaked during 2023 and 2024 due to a drought that affected the energy matrix in Colombia as a result of decreased availability of hydroelectric power. We have historically not hedged our costs to protect against fluctuations. However, during the second half of 2025, we entered into a derivative financial instrument to partially mitigate the impact of potential higher electricity costs in Colombia resulting from droughts and reduced hydroelectric generation, particularly in the Llanos 34 Block, where electricity expenses represent a significant portion of our production and operating costs. Availability and reliability of infrastructure Our business depends on the availability and reliability of operating and transportation infrastructure in the areas in which we operate. Prices and availability for equipment and infrastructure, and the maintenance thereof, affect our ability to make the investments necessary to operate our business, and thus our results of operations and financial condition. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Our inability to access needed equipment and infrastructure in a timely manner may hinder our access to oil and natural gas markets and generate significant incremental costs or delays in our oil and natural gas production.” Production levels Our oil and gas production levels are heavily influenced by our drilling results, our acquisitions and oil and natural gas prices. We expect that fluctuations in our financial condition and results of operations will be driven by the rate at which production volumes from our wells decline. As initial reservoir pressures are depleted, oil and gas production from a given well will decline over time. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Unless we replace our oil and natural gas reserves, our reserves and production will decline over time. Our business is dependent on our continued successful identification of productive fields and prospects and the identified locations in which we drill in the future may not yield oil or natural gas in commercial quantities.” Contractual obligations In order to protect our exploration and production rights in our licensed areas, we must make and declare discoveries within certain time periods specified in our various special contracts, E&P contracts and concession agreements. The costs to maintain or operate our licensed areas may fluctuate or increase significantly, and we may not be able to meet our commitments under these agreements on commercially reasonable terms or at all, which may force us to forfeit our interests in such areas. If we do not succeed in renewing these agreements, or in securing new ones, our ability to grow our business may be materially impaired. See “Item 3. Key Information—D. Risk factors—Risks relating to our business—Under the terms of some of our various E&P contracts, exploration permits, exploitation concessions and concession agreements, we are obligated to drill wells, declare any discoveries, and file periodic reports to retain our rights and establish development areas. Failure to meet these obligations may result in the loss of our interests in the undeveloped parts of our blocks or concession areas.” Acquisitions As described above, part of our strategy is to acquire and consolidate assets in Latin America. We intend to continue to selectively acquire companies, producing properties and concessions. As with our historical acquisitions, any future acquisitions could make year-to-year comparisons of our results of operations difficult. We may also incur additional debt, issue equity securities or use other funding sources to fund future acquisitions. We generally incorporate our acquired business into our results of operations at or around the date of closing. 81 Table of Contents In October 2025, we acquired operated working interests in two blocks in the in the Vaca Muerta formation in Argentina. This acquisition provides immediate production, reserves, and long-term growth opportunities. For further information please see “Item 4. Information on the Company—B. Business Overview—Acquisition in Argentina’s Vaca Muerta Formation.” Functional and presentational currency Our Consolidated Financial Statements are presented in US$, which is our presentation currency. Items included in the financial information of each of our entities are measured using the currency of the primary economic environment in which the entity operates, or the functional currency, which is the US$ in each case, except for our Brazil operations, where the functional currency is the real. Geographical segment reporting In the description of our results of operations that follow, our “Other” operations reflect our non-Colombian, non- Argentine, non-Brazilian, non-Ecuadorian and non-Chilean operations, primarily consisting of our corporate head office operations. As of December 31, 2025, we divided our business into four geographical segments—Colombia, Argentina, Brazil and Ecuador—that corresponded to our principal jurisdictions of operation. Activities not falling into these four geographical segments are reported under a separate corporate segment that primarily includes certain corporate administrative costs not attributable to another segment. Description of principal line items The following is a brief description of the principal line items of our consolidated statement of income. Revenue Revenue includes the sale of crude oil, condensate and natural gas net of value-added tax (“VAT”), and discounts related to the sale (such as API and mercury adjustments) and overriding royalties due to the ex-owners of oil and gas properties where the royalty arrangements represent a retained working interest in the property. Revenue from the sale of crude oil and gas is recognized when control of the product is transferred to the customer, which is generally when the product is physically transferred into a pipeline or other delivery mechanism and the customer accepts the product. Consequently, our performance obligations are considered to relate only to the sale of crude oil and gas, with each barrel of crude oil equivalent considered to be a separate performance obligation under the contractual arrangements in place. Commodity risk management contracts are designated and qualify as cash flow hedges. The effective portion of changes in the fair values of these derivative contracts are recognized in Other Reserves within Equity. The gain or loss relating to the ineffective portion, if any, is recognized immediately as gains or losses in the results of the periods in which they occur. The amount accumulated in Other Reserves is reclassified to profit or loss as a reclassification adjustment in the same period or periods during which the hedged cash flows affect profit or loss as part of the Revenue line item in the Consolidated Statement of Income. Production and operating costs Production and operating costs are recognized on the accrual basis of accounting. These costs include wages and salaries incurred to achieve the revenue for the year. Direct and indirect costs of raw materials and consumables, rentals, royalties and economic rights in cash are also included within this account. For a description of our production and operating costs, see “—Factors affecting our results of operations.” 82 Table of Contents Depreciation Capitalized costs of proved oil and natural gas properties are depreciated on a licensed-area-by-licensed-area basis, using the unit of production method, based on commercial proved and probable reserves as calculated under the Petroleum Resources Management System methodology promulgated by the Society of Petroleum Engineers and the World Petroleum Council (the “PRMS”), which differs from SEC reporting guidelines pursuant to which certain information in the forepart of this annual report is presented. The calculation of the “unit of production” depreciation takes into account estimated future discovery and development costs. Changes in reserves and cost estimates are recognized prospectively. Reserves are converted to equivalent units on the basis of approximate relative energy content. Geological and geophysical expenses Geological and geophysical expenses are recognized on the accrual basis of accounting and consist of geosciences costs, including wages and salaries and share-based compensation not subject to capitalization, geological consultancy costs and costs relating to independent reservoir engineer studies. Administrative expenses Administrative expenses are recognized on the accrual basis of accounting and consist of corporate costs such as director fees and travel expenses, new project evaluations and back-office expenses principally comprised of wages and salaries, share-based compensation, consultant fees and other administrative costs, including certain costs relating to acquisitions. Selling expenses Selling expenses are recognized on the accrual basis of accounting and consist primarily of transportation, storage costs and selling taxes. Write-off of unsuccessful exploration efforts Upon completion of the evaluation phase, the exploratory prospects are either transferred to oil and gas properties or charged to expense in the period in which the determination is made, depending on whether they have discovered reserves or not. If not developed, exploration and evaluation assets are written off after three years, unless it can be clearly demonstrated that the carrying value of the investment is recoverable. During 2025, we recognized write-off of unsuccessful exploration efforts of US$13.4 million (US$14.8 million in 2024). See Note 18 to our Consolidated Financial Statements. Impairment of non-financial assets Assets that are not subject to depreciation and/or amortization are tested annually for impairment. Assets that are subject to depreciation and/or amortization are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is recognized for the amount by which the asset’s carrying amount exceeds its recoverable amount. The recoverable amount is the higher of an asset’s fair value minus costs to sell and value in use. During 2025, we recognized an impairment loss of US$31.0 million in the Perico and Espejo Blocks in Ecuador due to the known selling price of the related net assets in the context of their divestment transaction. No impairment losses were recognized or reversed in 2024. See Notes 18 and 35 to our Consolidated Financial Statements. Financial results Financial results include interest expenses, interest income, bank charges, the amortization of financial assets and liabilities, and foreign exchange gains and losses. 83 Table of Contents Recent accounting pronouncements See Note 2.1.1 to our Consolidated Financial Statements. Results of operations The following discussion is of certain financial and operating data for the periods indicated. You should read this discussion in conjunction with our Consolidated Financial Statements and the accompanying notes. In preparation for continued volatility, we have developed a capital expenditure program for 2026 which is subject to change as a result of market conditions, developments regarding our business, results of operations and financial condition, and other factors. See “Item 4. Information on the Company—B. Business Overview—Our business strategy —2026 work plan and outlook.” ​ 84 Table of Contents Year ended December 31, 2025, compared to year ended December 31, 2024 The following table summarizes certain of our financial and operating data for the years ended December 31, 2025 and 2024. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the year ended December 31, ​ ​ ​ ​ ​ ​ % Change from ​ ​ ​ 2025 ​ ​ 2024 ​ ​ prior year ​ ​ ​ (in thousands of US$, except for percentages) ​ ​ ​ ​ ​ ​ ​ ​ Revenue ​ ​ ​ ​ ​ ​ ​ Sale of crude oil ​ 472,054 ​ 648,670 ​ (27) % Sale of purchased crude oil ​ 419 ​ 7,177 ​ (94) % Sale of gas ​ 6,251 ​ 5,076 ​ 23 % Commodity risk management contracts designated as cash flow hedges ​ 13,794 ​ (85) ​ (16,328) % Revenue ​ 492,518 ​ 660,838 ​ (25) % Production and operating costs ​ (141,059) ​ (164,034) ​ (14) % Geological and geophysical expenses ​ (10,538) ​ (12,595) ​ (16) % Administrative expenses ​ (40,544) ​ (49,534) ​ (18) % Selling expenses ​ (20,909) ​ (14,914) ​ 40 % Depreciation ​ (117,190) ​ (130,659) ​ (10) % Write-off of unsuccessful exploration efforts ​ (13,422) ​ (14,779) ​ (9) % Impairment loss recognized for non-financial assets ​ (30,989) ​ — ​ 100 % Other expenses ​ (7,324) ​ (777) ​ 843 % Operating profit ​ 110,543 ​ 273,546 ​ (60) % Financial expenses ​ (76,324) ​ (51,551) ​ 48 % Financial income ​ 21,718 ​ 8,016 ​ 171 % Foreign exchange gain (loss) ​ (7,286) ​ 12,160 ​ (160) % Profit before income tax ​ 48,651 ​ 242,171 ​ (80) % Income tax expense ​ 1,016 ​ (145,792) ​ (101) % Profit for the year ​ 49,667 ​ 96,379 ​ (48) % ​ ​ ​ ​ ​ ​ ​ ​ Net production volumes ​ ​ ​ ​ ​ ​ ​ Oil (mbbl)(2) ​ 10,100 ​ 12,277 ​ (18) % Gas (mcf)(3) ​ 1,234 ​ 864 ​ 43 % Total net production (mboe) ​ 10,305 ​ 12,421 ​ (17) % Average net production (boepd) ​ 28,233 ​ 33,937 ​ (17) % Average realized sales price ​ ​ ​ ​ ​ ​ ​ Oil (US$ per bbl) ​ 59.1 ​ 66.0 ​ (10) % Gas (US$ per mmcf) ​ 4.2 ​ 5.9 ​ (30) % Average unit costs per boe (US$) ​ ​ ​ ​ ​ ​ ​ Operating cost ​ 15.5 ​ 15.2 ​ 2 % Royalties and economic rights in cash ​ 1.1 ​ 1.1 ​ 3 % Production costs(1) ​ 16.6 ​ 16.3 ​ 2 % Geological and geophysical expenses ​ 1.2 ​ 1.3 ​ (1) % Administrative expenses ​ 4.8 ​ 4.9 ​ (3) % Selling expenses ​ 2.5 ​ 1.5 ​ 67 % (1) Calculated pursuant to FASB ASC 932. (2) We present production figures before deduction of royalties, economic rights and government’s production share, as we believe that net production before royalties, economic rights and government’s production share is more appropriate in light of our foreign operations and the attendant royalty, economic rights and government’s production share regimes. Oil production figures presented on page F-76 are net of royalties, economic rights and government’s production share. (3) Corresponds to production measured after separation but prior to compression, which is the measure we used to monitor business performance. Gas production presented on page F-77 is gas measured at the point of delivery. 85 Table of Contents The following table summarizes certain financial data. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the year ended December 31, ​ ​ 2025 ​ 2024 ​ ​ ​ Colombia ​ ​ Argentina ​ ​ Brazil ​ ​ Ecuador ​ ​ Other ​ ​ Total ​ ​ Colombia ​ ​ Argentina ​ ​ Brazil ​ ​ Ecuador ​ ​ Chile ​ ​ Other ​ ​ Total ​ ​ (in thousands of US$) Revenue ​ 461,418 ​ 5,783 ​ 6,435 ​ 18,463 ​ 419 492,518 619,762 ​ — ​ 2,934 ​ 30,567 ​ 398 ​ 7,177 660,838 Depreciation ​ (110,030) ​ (2,096) ​ (246) ​ (4,818) ​ — (117,190) (121,143) ​ (10) ​ (1,214) ​ (8,290) ​ — ​ (2) (130,659) Impairment and write-off ​ (13,422) ​ — ​ — ​ (30,989) ​ — (44,411) (6,909) ​ — ​ (156) ​ (7,714) ​ — ​ — (14,779) ​ Revenue For the year ended December 31, 2025, crude oil sales, including commodity risk management contracts, remained our principal source of revenue, accounting for 98.6% of our total revenue, followed by gas sales of 1.3% and purchased crude oil sales of 0.1%. The following chart shows the change in oil and natural gas sales from the year ended December 31, 2024, to the year ended December 31, 2025. ​ ​ ​ ​ ​ ​ ​ ​ For the year ended ​ ​ December 31, ​ ​ ​ 2025 ​ ​ 2024 ​ ​ (in thousands of US$) Consolidated ​ ​ ​ ​ Sale of crude oil ​ 472,054 ​ 648,670 Sale of purchased crude oil ​ 419 ​ 7,177 Sale of gas ​ 6,251 ​ 5,076 Commodity risk management contracts designated as cash flow hedges ​ 13,794 ​ (85) Total ​ 492,518 ​ 660,838 ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ (in thousands of US$, except for percentages) ​ By country ​ ​ ​ ​ ​ ​ ​ ​ ​ Colombia ​ 461,418 ​ 619,762 ​ (158,344) ​ (26) % Argentina ​ 5,783 ​ — ​ 5,783 ​ 100 % Brazil ​ 6,435 ​ 2,934 ​ 3,501 ​ 119 % Ecuador ​ 18,463 ​ 30,567 ​ (12,104) ​ (40) % Chile ​ — ​ 398 ​ (398) ​ (100) % Other ​ 419 ​ 7,177 ​ (6,758) ​ (94) % Total ​ 492,518 ​ 660,838 ​ (168,320) ​ (25) % ​ Revenue decreased 25%, from US$660.8 million for the year ended December 31, 2024, to US$492.5 million for the year ended December 31, 2025. This decline was primarily driven by lower sales volumes and lower realized prices during the year. Crude oil sales decreased mainly as a result of a reduction in volumes sold —from 9.8 mmbbl in 2024 to 8.2 mmbbl in 2025— together with lower realized price, resulting in net oil revenue of US$472.1 million for the year ended December 31, 2025, compared to US$648.7 million for the year ended December 31, 2024. This decrease was partially mitigated by the positive effect of the commodity risk management contracts in place during the year. Gas sales increased to US$6.3 million for the year ended December 31, 2025, from US$5.1 million for the year ended December 31, 2024, primarily due to the reactivation of the Manati gas field in Brazil in May 2025, partially offset by the divestment of the Llanos 32 Block in Colombia in March 2025. The US$168.3 million decrease in total net revenue is explained by i) a decrease of US$158.3 million in Colombia (largely due to lower oil deliveries and lower realized prices); ii) an increase of US$5.8 million in Argentina (from the acquisition of working interests in two blocks in the Vaca Muerta formation in October 2025); iii) an increase of US$3.5 million in Brazil (resulting from higher gas deliveries due to the reactivation of the Manati gas field in May 2025, net of lower realized prices); iv) a decrease of US$12.1 million in Ecuador (driven by lower oil deliveries and lower realized 86 Table of Contents prices); v) a decrease of US$0.4 million in Chile (following the divestment of operations in January 2024); and vi) a decrease of US$6.8 million from the trading activities of the holding company, GeoPark Limited. Revenue from our Colombian operations for the year ended December 31, 2025, was US$461.4 million, representing 93.7% of total consolidated sales, compared to US$619.8 million for the year ended December 31, 2024 (93.8% of total consolidated sales). The decrease was primarily driven by a lower average realized price per barrel of crude oil from US$65.8 per barrel in 2024 to US$57.3 per barrel in 2025, mainly reflecting lower reference international prices. In addition, oil deliveries decreased from 9.4 mmbbl in 2024 to 7.8 mmbbl in 2025, mainly impacted by a natural decline in the Llanos 34 Block. These effects were partially offset by commodity risk management gains of $13.8 million recognized during the year. Revenue from our operations in Argentina totaled US$5.8 million, reflecting deliveries from the Loma Jarillosa Este and Puesto Silva Oeste Blocks, which we acquired in October 2025. Revenue from Brazilian operations for the year ended December 31, 2025, was US$6.4 million, representing a 119% increase compared to US$2.9 million for the year ended December 31, 2024. This increase was primarily due to higher gas deliveries (from 0.08 mmboe in 2024 to 0.25 mmboe in 2025), following the reactivation of production at the non-operated Manati gas field in May 2025. The share of total revenue from Brazil rose from 0.4% in 2024 to 1.3% in 2025. Revenue from Ecuador for the year ended December 31, 2025, was US$18.5 million, a 40% decrease from US$30.6 million for the year ended December 31, 2024. This reduction was driven by lower realized oil prices from US$69.8 per barrel in 2024 to US$62.3 per barrel in 2025, mainly reflecting lower reference international prices. In addition, oil deliveries decreased from 0.4 mmbbl in 2024 to 0.3 mmbbl in 2025 in 2025, due to the blocks in Ecuador were divested in December 2025. The contribution of Ecuador to our total revenue was reduced from 4.6% in 2024 to 3.7% in 2025. Revenue from the trading activities performed by our holding company, GeoPark Limited, for the year ended December 31, 2025, was US$0.4 million, compared to US$7.2 million for the year ended December 31, 2024. This represented 0.1% of total revenue in 2025, down from 1.1% in 2024. ​ 87 Table of Contents Production and operating costs The following table summarizes our production and operating costs for the years ended December 31, 2025 and 2024. ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ For the year ended December 31, ​ ​ ​ ​ ​ ​ ​ % Change ​ ​ ​ ​ 2025 ​ ​ 2024 ​ ​ from prior year ​ ​ ​ (in thousands of US$, except for percentages) ​ Consolidated (including Colombia, Argentina, Brazil, Ecuador, Chile and Other) ​ Royalties in cash ​ (6,195) ​ (4,189) ​ 48 % Economic rights in cash ​ (3,079) ​ (6,484) ​ (53) % Staff costs and share-based payments ​ (16,004) ​ (16,344) ​ (2) % Well and facilities maintenance ​ (25,675) ​ (25,631) ​ 0 % Operation and maintenance ​ (8,239) ​ (8,936) ​ (8) % Consumables ​ (31,398) ​ (36,868) ​ (15) % Equipment rental ​ (7,511) ​ (5,716) ​ 31 % Transportation costs ​ (4,095) ​ (5,409) ​ (24) % Field camp ​ (4,822) ​ (6,401) ​ (25) % Safety and insurance costs ​ (4,213) ​ (4,937) ​ (15) % Personnel transportation ​ (2,393) ​ (3,586) ​ (33) % Consultant fees ​ (3,120) ​ (3,893) ​ (20) % Gas plant costs ​ (1,857) ​ (1,753) ​ 6 % Non-operated blocks costs ​ (19,697) ​ (22,305) ​ (12) % Crude oil stock variation ​ 747 ​ (976) ​ (177) % Purchased crude oil ​ (317) ​ (6,274) ​ (95) % Other costs ​ (3,191) ​ (4,332) ​ (26) % Total ​ (141,059) ​ (164,034) ​ (14) % ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ 2025 ​ 2024 ​ ​ ​ Colombia ​ ​ Argentina ​ ​ Brazil ​ Ecuador ​ ​ Other ​ ​ Colombia ​ ​ Brazil ​ ​ Ecuador ​ ​ Chile ​ ​ Other ​ ​ (in thousands of US$) By country ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Royalties in cash ​ (5,131) ​ (699) ​ (365) ​ — ​ — ​ (3,953) ​ (224) ​ — ​ (12) ​ — Economic rights in cash ​ (3,079) ​ — ​ — ​ — ​ — ​ (6,484) ​ — ​ — ​ — ​ — Staff costs and share-based payments ​ (14,509) ​ (1,485) ​ — ​ (10) ​ — ​ (16,337) ​ (2) ​ (5) ​ — ​ — Well and facilities maintenance ​ (22,991) ​ (301) ​ (2,365) ​ (18) ​ — ​ (23,524) ​ (1,764) ​ — ​ (343) ​ — Operation and maintenance ​ (7,278) ​ (794) ​ — ​ (167) ​ — ​ (8,747) ​ — ​ (189) ​ — ​ — Consumables ​ (31,196) ​ (24) ​ — ​ (178) ​ — ​ (36,502) ​ — ​ (318) ​ (48) ​ — Equipment rental ​ (6,829) ​ (79) ​ — ​ (603) ​ — ​ (5,138) ​ — ​ (578) ​ — ​ — Transportation costs ​ (3,783) ​ (141) ​ — ​ (171) ​ — ​ (5,359) ​ — ​ (55) ​ 5 ​ — Field camp ​ (4,538) ​ (260) ​ — ​ (24) ​ — ​ (6,369) ​ — ​ (30) ​ (2) ​ — Safety and insurance costs ​ (3,897) ​ (87) ​ (66) ​ (163) ​ — ​ (4,742) ​ (187) ​ (2) ​ (6) ​ — Personnel transportation ​ (2,312) ​ (64) ​ — ​ (17) ​ — ​ (3,556) ​ — ​ (17) ​ (13) ​ — Consultant fees ​ (3,085) ​ — ​ — ​ (35) ​ — ​ (3,778) ​ (37) ​ — ​ (78) ​ — Gas plant costs ​ (131) ​ — ​ (1,726) ​ — ​ — ​ (138) ​ (1,615) ​ — ​ — ​ — Non-operated blocks costs ​ (13,065) ​ — ​ (90) ​ (6,542) ​ — ​ (14,515) ​ (112) ​ (7,678) ​ — ​ — Crude oil stock variation ​ 601 ​ (7) ​ — ​ 153 ​ — ​ (357) ​ — ​ (619) ​ — ​ — Purchased crude oil ​ — ​ — ​ — ​ — ​ (317) ​ — ​ — ​ — ​ — ​ (6,274) Other costs ​ (2,791) ​ (156) ​ (244) ​ — ​ — ​ (4,135) ​ (199) ​ (58) ​ 60 ​ — Total ​ (124,014) ​ (4,097) ​ (4,856) ​ (7,775) ​ (317) ​ (143,634) ​ (4,140) ​ (9,549) ​ (437) ​ (6,274) ​ Consolidated production and operating costs decreased 14%, from US$164.0 million for the year ended December 31, 2024, to US$141.1 million for the year ended December 31, 2025, primarily due to lower purchased crude oil, lower energy costs compared to the elevated levels experienced in 2024, and cost-efficiency initiatives implemented by the Group during the year, partially offset by operating costs from blocks acquired in Argentina in 2025. 88 Table of Contents Production and operating costs in Colombia decreased by 14%, to US$124.0 million for the year ended December 31, 2025, as compared to US$143.6 million for the year ended December 31, 2024, primarily due to reduced energy, community, and technical consultancy expenses in the Llanos 34 Block, as well as cost-efficiency initiatives implemented by the Group during the year. Production and operating costs in Argentina of US$4.1 million resulted from the takeover of operations at the Loma Jarillosa Este and Puesto Silva Oeste Blocks on October 16, 2025, including ramp-up operating costs associated with the start-up and initial operation of these blocks. Production and operating costs in Brazil increased by 17%, to US$4.9 million for the year ended December 31, 2025, as compared to the year ended December 31, 2024, mainly resulting from facilities maintenance in the Manati gas field. Production and operating costs in Ecuador decreased by 19%, to US$7.8 million for the year ended December 31, 2025, compared to US$9.5 million the year ended December 31, 2024, primarily due to lower activity in the non-operated Perico Block. Purchases of crude oil for the trading operation performed by the holding company, GeoPark Limited, amounted to US$0.3 million and US$6.3 million for the years ended December 31, 2025, and 2024, respectively. Geological and geophysical expenses ​ Geological and geophysical expenses decreased by 16%, from US$12.6 million for the year ended December 31, 2024, to US$10.5 million for the year ended December 31, 2025, primarily as the result of cost-efficiency measures implemented to align the organizational structure with the Group's strategic objectives and operational requirements. Administrative costs ​ Administrative costs decreased by 18%, from US$49.5 million for the year ended December 31, 2024, to US$40.5 million for the year ended December 31, 2025, primarily reflecting lower ongoing corporate and back-office expenses, including the impact of workforce reductions implemented as part of the Group’s cost-efficiency measures during the year. Selling expenses ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ ​ (in thousands of US$, except for percentages) ​ Colombia ​ (18,041) ​ (11,840) ​ (6,201) ​ 52 % Argentina ​ (715) ​ — ​ (715) ​ 100 % Ecuador ​ (2,153) ​ (3,074) ​ 921 ​ (30) % Total ​ (20,909) ​ (14,914) ​ (5,995) ​ 40 % ​ Selling expenses increased by 40%, from US$14.9 million for the year ended December 31, 2024, to US$20.9 million for the year ended December 31, 2025, primarily due to deliveries at different sales points in the CPO-5 and Llanos 123 Blocks in Colombia, including the shift to export delivery locations under a new commercial agreement with BP from August 2025. Sales at the wellhead incur no selling costs but yield lower revenue, while transportation expenses for sales to alternative delivery points are recognized as selling expenses. ​ 89 Table of Contents Depreciation ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ (in thousands of US$, except for percentages) Colombia ​ (110,030) ​ (121,143) ​ 11,113 ​ (9) % Argentina ​ (2,096) ​ (10) ​ (2,086) ​ 20,860 % Brazil ​ (246) ​ (1,214) ​ 968 ​ (80) % Ecuador ​ (4,818) ​ (8,290) ​ 3,472 ​ (42) % Other ​ — ​ (2) ​ 2 ​ (100) % Total ​ (117,190) ​ (130,659) ​ 13,469 ​ (10) % ​ Depreciation charges decreased by 10% from US$130.7 million for the year ended December 31, 2024, to US$117.2 million for the year ended December 31, 2025, primarily due to lower production in Colombia, mainly in the Llanos 34 Block, in addition to the divestment of the Manati gas field in Brazil, and the Perico and the Espejo Blocks in Ecuador. These factors were partially offset by the incorporation of the Loma Jarillosa Este and Puesto Silva Oeste Blocks in Argentina. Operating profit ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ (in thousands of US$, except for percentages) Colombia ​ 155,710 ​ 298,158 ​ (142,448) ​ (48) % Argentina ​ (8,224) ​ (5,052) ​ (3,172) ​ 63 % Brazil ​ 6,147 ​ (7,159) ​ 13,306 ​ (186) % Ecuador ​ (30,542) ​ (1,102) ​ (29,440) ​ 2,672 % Chile ​ — ​ (116) ​ 116 ​ (100) % Other ​ (12,548) ​ (11,183) ​ (1,365) ​ 12 % Total ​ 110,543 ​ 273,546 ​ (163,003) ​ (60) % ​ We recorded an operating profit of US$110.5 million for the year ended December 31, 2025, compared to US$273.5 million for the year ended December 31, 2024, as a result of the reasons described above. In 2025, we recorded write-offs of unsuccessful exploration efforts of US$13.4 million, which corresponded to one exploratory well drilled in the PUT-8 Block in Colombia and other exploration costs incurred in previous years in the Putumayo Basin in Colombia. In 2024, we recorded write-offs of unsuccessful exploration efforts of US$14.8 million, which corresponded to two exploratory wells drilled in the CPO-5 Block in Colombia and two exploratory wells drilled in the Espejo Block in Ecuador. During 2025, we also recognized an impairment loss of US$31.0 million in the Perico and Espejo Blocks due to the known selling price of the related net assets in the context of their divestment transaction. In addition, during 2025 we incurred one-off termination costs of US$7.7 million in connection with cost efficiency measures implemented during the year. Financial results Net financial expense was US$54.6 million for the year ended December 31, 2025, compared to US$43.5 million for the year ended December 31, 2024. The increase was mainly driven by higher recurring interest expense associated with the Notes due 2030 issued in early 2025, which bear an interest rate of 8.75%. Interest expense and amortization of debt issue costs totaled US$49.3 million in 2025, compared to US$31.1 million in 2024. Net financial expense also included a one-off non-cash charge of US$6.2 million related to the accelerated amortization of deferred issuance costs associated with the Notes due 2027 which were partially repurchased in January 2025, partially offset by a one-off gain of US$10.2 million from the repurchase of Notes due 2030 below par value between June and October 2025. For further information 90 Table of Contents about these transactions, please see “Item 4. Information on the Company—A. History and development of the company—Funding”. Foreign exchange gain (loss) Foreign exchange loss was US$7.3 million for the year ended December 31, 2025, compared to a foreign exchange gain of US$12.2 million for the year ended December 31, 2024. In both years, these results mainly reflected the impact of fluctuations in the Colombian peso on liabilities denominated in local currency, including income tax payable, provisions for asset retirement obligations and other environmental liabilities, as well as lease liabilities. The Colombian Peso revalued by 15% in 2025 and devalued by 15% in 2024. This loss was partially offset by currency risk management gains of US$3.2 million recognized during the year. Profit before income tax ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ ​ (in thousands of US$, except for percentages) ​ Colombia ​ 141,604 ​ 302,277 ​ (160,673) ​ (53) % Argentina ​ (3,982) ​ (4,202) ​ 220 ​ (5) % Brazil ​ 7,202 ​ (9,620) ​ 16,822 ​ (175) % Ecuador ​ (30,815) ​ (1,506) ​ (29,309) ​ 1,946 % Chile ​ — ​ (82) ​ 82 ​ (100) % Other ​ (65,358) ​ (44,696) ​ (20,662) ​ 46 % Total ​ 48,651 ​ 242,171 ​ (193,520) ​ (80) % ​ For the year ended December 31, 2025, we recorded a profit before income tax of US$48.7 million, compared to a profit of US$242.2 million for the year ended December 31, 2024, primarily due to the reasons mentioned above. Income tax expense ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ ​ (in thousands of US$, except for percentages) ​ Colombia ​ (10,327) ​ (141,525) ​ 131,198 ​ (93) % Argentina ​ 10,838 ​ — ​ 10,838 ​ 100 % Brazil ​ (1,287) ​ (246) ​ (1,041) ​ 423 % Ecuador ​ (173) ​ (2,686) ​ 2,513 ​ (94) % Chile ​ — ​ — ​ — ​ — % Other ​ 1,965 ​ (1,335) ​ 3,300 ​ (247) % Total ​ 1,016 ​ (145,792) ​ 146,808 ​ (101) % ​ Our consolidated effective tax rate was (2)% for the year ended December 31, 2025, compared to 60% in 2024, primarily reflecting a lower profit before income tax for the year, the impact of the revaluation of the Colombian peso on the tax bases of property, plant and equipment, the recognition of deferred tax assets related to previously unrecognized tax loss carryforwards in Argentina, which became recoverable as a result of the acquisition in the Vaca Muerta formation, and the reversal of deferred tax liabilities in Spain following the relocation of GeoPark Colombia S.L.U. from Madrid to Bizkaia (Basque Country) in 2025. In 2025 and 2024, the statutory income tax rate in Colombia was 35%, though a tax surcharge is also applicable, impacting companies engaged in the extraction of crude oil like GeoPark. The tax surcharge varies from zero to 15%, depending on different Brent oil prices. The applicable surcharge for 2025 and 2024 was 0% and 10%, respectively. 91 Table of Contents Profit for the year ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ Change from prior year ​ ​ ​ 2025 ​ ​ 2024 ​ ​ ​ ​ ​ % ​ ​ (in thousands of US$, except for percentages) Colombia ​ 131,277 ​ 160,752 ​ (29,475) ​ (18) % Argentina ​ 6,856 ​ (4,202) ​ 11,058 ​ (263) % Brazil ​ 5,915 ​ (9,866) ​ 15,781 ​ (160) % Ecuador ​ (30,988) ​ (4,192) ​ (26,796) ​ 639 % Chile ​ — ​ (82) ​ 82 ​ (100) % Other ​ (63,393) ​ (46,031) ​ (17,362) ​ 38 % Total ​ 49,667 ​ 96,379 ​ (46,712) ​ (48) % ​ For the year ended December 31, 2025, we recorded a net profit of US$49.7 million as a result of the reasons described above, compared to a net profit of US$96.4 million for the year ended December 31, 2024. Year ended December 31, 2024, compared to year ended December 31, 2023 For a discussion of the results of our operations for the year ended December 31, 2024, compared to the year ended December 31, 2023, please refer to “Item 5.—A. Operating Results—Results of Operations for the Year Ended December 31, 2024, compared to the year ended December 31, 2023” in our Annual Report on Form 20-F for the year ended December 31, 2024. B. Liquidity and capital resources Overview Our financial condition and liquidity are and will continue to be influenced by a variety of factors, including changes in oil and natural gas prices and our ability to generate cash flows from our operations, our capital expenditure requirements, the level of our outstanding indebtedness and the interest we have to pay on this indebtedness, and changes in exchange rates which will impact our generation of cash flows from operations when measured in US$. We continually evaluate additional alternatives to further improve our capital structure by increasing our cash balances and/or reducing or refinancing a portion of our indebtedness. These alternatives include various strategic initiatives and potential asset sales as well as potential public or private equity or debt financings. If additional funds are obtained by issuing equity securities, our existing stockholders could be diluted. We can give no assurances that we will be able to sell any of our assets or to obtain additional financing on terms acceptable to us, or at all. Our principal sources of liquidity have historically been contributed shareholder equity, debt financings and cash generated by our operations. We have also in the past entered into offtake and prepayment agreements. For further information on our funding through debt and equity capital markets, see “Item 4. Information on the Company—A. History and Development of the Company—Funding.” We believe that our current operations and 2026 capital expenditures program can be funded from cash flow from existing operations and cash on hand. Should our operating cash flow decline due to unforeseen events, including delivery restrictions or a protracted downturn in oil and gas prices, we would examine measures such as capital expenditure program reductions, oil prepayment agreements, disposition of assets, or issuance of equity, among others. We believe the liquidity and capital resource alternatives available to us will be adequate to fund our operations and provide flexibility until oil prices and industry conditions improve. This includes supporting our capital expenditure program, payment of debt services and dividends and any amount that may ultimately be paid in connection with commitments and contingencies. See “Item 4. Information on the Company—B. Business Overview— Our business strategy.” 92 Table of Contents Capital expenditures In the past, we have funded our capital expenditures with proceeds from equity offerings, credit facilities, debt issuances and pre-sale agreements, as well as through cash generated from our operations. We expect to incur substantial expenses and capital expenditures as we develop our oil and natural gas prospects and acquire additional assets. See “Item 4. Information on the Company –B. Business Overview— Our business strategy”. In the year ended December 31, 2025, we had total capital expenditures related to the purchase of property, plant and equipment of US$98.4 million (US$96.7 million, US$1.4 million, US$0.1 million and US$0.2 million, in Colombia, Argentina, Brazil and Ecuador, respectively). In the year ended December 31, 2024, we had total capital expenditures related to the purchase of property, plant and equipment of US$191.3 million (US$167.0 million and US$24.1 million in Colombia and Ecuador, respectively). Cash flows The following table sets forth our cash flows for the periods indicated: ​ ​ ​ ​ ​ ​ ​ ​ ​ ​ Year ended December 31, ​ ​ ​ 2025 ​ ​ 2024 ​ ​ 2023 ​ ​ (in thousands of US$) Cash flows from (used in) ​ ​ ​ ​ ​ ​ Operating activities ​ 14,705 ​ 471,031 ​ 300,938 Investing activities ​ (155,495) ​ (226,855) ​ (198,590) Financing activities ​ (36,122) ​ (99,240) ​ (98,721) Net (decrease) increase in cash and cash equivalents ​ (176,912) ​ 144,936 ​ 3,627 ​ Cash flows from operating activities For the year ended December 31, 2025, cash flows from operating activities were US$14.7 million compared to US$471.0 million for the year ended December 31, 2024. This variation was mainly from the repayment in 2025 of most of the oil sales prepayment of US$152 million drawn from the offtake and prepayment agreement with Vitol in November 2024, in addition to higher income tax for the year 2024 paid in 2025 and lower revenues reflecting lower deliveries and oil and gas prices in 2025. For the year ended December 31, 2024, cash flows from operating activities were US$471.0 million, a 57% increase from US$300.9 million for the year ended December 31, 2023, mainly resulting from an oil sales prepayment of US$152 million drawn from the offtake and prepayment agreement with Vitol in November 2024, as well as lower income tax paid, which was driven by: i) a decrease in the accrual of income taxes for the year 2023 to be paid in 2024 (due to lower taxable results in 2023, as compared to 2022), and ii) a reduction of the rates of self-withholding taxes and withholding taxes from clients applicable to companies engaged in the extraction of crude oil like GeoPark. Those effects were partially offset by lower operating results from operations. Cash flows used in investing activities For the year ended December 31, 2025, cash flows used in investing activities were US$155.5 million, a 31% decrease from US$226.9 million for the year ended December 31, 2024. This decrease primarily reflected lower capital expenditures in Colombia and Ecuador, the reimbursement of the US$38 million advance payment made in 2024 for the Unconsummated transaction in Argentina (Vaca Muerta), and the proceeds from divestments executed during the year. These effects were partially offset by the payment of US$115.5 million for the Acquisition in Argentina’s Vaca Muerta Formation. ​ 93 Table of Contents For the year ended December 31, 2024, cash flows used in investing activities were US$226.9 million, a 14% increase from US$198.6 million for the year ended December 31, 2023. This variation is primarily explained by the advance payment of US$38 million for the Unconsumated transaction in Argentina (Vaca Muerta) in May 2024. Cash flows used in financing activities Cash flows used in financing activities were US$36.1 million for the year ended December 31, 2025, compared to US$99.2 million used in financing activities for the year ended December 31, 2024. This decrease primarily reflected the absence of significant repurchase of own common shares in 2025 compared to 2024, lower dividends distributed and lower lease payments during the year, as well as the impact of liability management transactions carried out in 2025, which included the issuance of US$550.0 million aggregate principal amount of Notes due 2030, bearing an interest rate of 8.75%, the repurchase of US$405.3 million aggregate principal amount of Notes due 2027, which bore an interest rate of 5.5%, both in early 2025, and the repurchase of US$108.3 million aggregate principal amount of Notes due 2030 between June and October 2025. While these transactions reduced near-term refinancing risk and improved liquidity, they also resulted in higher recurring interest expense due to the higher coupon on the Notes due 2030. Cash flows used in financing activities were US$99.2 million for the year ended December 31, 2024, compared to US$98.7 million used in financing activities for the year ended December 31, 2023. This variation was mainly related to higher repurchase of own common shares, partially offset by proceeds from a short-term financial loan granted in Argentina and lower lease payments. Indebtedness As of December 31, 2025, and 2024, we had total outstanding indebtedness of US$553.5 million and US$514.3 million, respectively, as set forth in the table below. ​ ​ ​ ​ ​ ​ ​ ​ As of December 31, ​ ​ ​ 2025 ​ ​ 2024 ​ ​ (in thousands of US$) Notes due 2030 ​ 454,305 ​ — Notes due 2027 ​ 96,242 ​ 504,535 Local debt in Colombia ​ 3,000 ​ — Local debt in Argentina ​ — ​ 9,798 Total ​ 553,547 ​ 514,333 ​ Our outstanding indebtedness as of December 31, 2025 is described below. Notes due 2030 General In January 2025, we issued US$550.0 million aggregate principal amount of 8.75% senior notes due 2030 (the “Notes due 2030”). We used the net proceeds of the offering to repurchase a portion of our Notes due 2027 for a nominal amount of US$405.3 million through a concurrent tender offer, to partially repay the prepayment drawn from the offtake and prepayment agreement with Vitol, and the remainder for general corporate purposes, including capital expenditures. This transaction improved our financial profile by extending our debt maturities. Ranking The Notes due 2030 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U., GeoPark Colombia S.A.S and GeoPark Argentina S.A. (the “Guarantors”). The Notes due 2030 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantors (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of 94 Table of Contents payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantors; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantors and their respective subsidiaries to the extent of the value of the collateral securing such obligations. Optional redemption We may, at our option, redeem all or part of the Notes due 2030, at the redemption prices, expressed as percentages of principal amount, set forth below, plus accrued and unpaid interest thereon (including additional amounts), if any, to the applicable redemption date, if redeemed during the 12-month period beginning on January 31 of the years indicated below: ​ ​ ​ ​ Year ​ ​ Percentage 2027 ​ 104.375 % 2028 ​ 102.188 % 2029 and after ​ 100.000 % Change of control Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2030, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2030 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2030 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption. Covenants The indenture governing the Notes due 2030 includes incurrence test covenants that provide, among other things, that the Net Debt to Adjusted EBITDA ratio should not exceed 3.5 times and the Adjusted EBITDA to Interest ratio should exceed 2.5 times. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes due 2030. Incurrence covenants as opposed to maintenance covenants must be tested before incurring additional debt or performing certain corporate actions including but not limited to dividend payments, restricted payments and others. Events of default Events of default under the indentures governing the Notes due 2030 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2030; cross payment default relating to debt with a principal amount of US$50.0 million or more, and cross-acceleration default following a judgment for US$50.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of default would permit or require the principal of and accrued interest on the Notes due 2030 to become or to be declared due and payable. Notes due 2027 General In January 2020, we issued US$350.0 million aggregate principal amount of 5.5% senior notes due 2027 (the “Notes due 2027”). In April 2021, we reopened our Notes due 2027, issuing an additional US$150.0 million principal amount. Final maturity will be January 17, 2027. On January 31, 2025, we repurchased a portion of our Notes due 2027 for a nominal amount of US$405.3 million through a concurrent tender offer. 95 Table of Contents Ranking The Notes due 2027 constitute senior unsubordinated obligations of GeoPark Limited and are guaranteed by GeoPark Colombia, S.L.U. (the “Guarantor”). The Notes due 2027 rank equally in right of payment with all existing and future senior obligations of GeoPark Limited and the Guarantor (except those obligations preferred by operation of law, including without limitation labor and tax claims); rank senior in right of payment to all existing and future subordinated indebtedness of GeoPark Limited and the Guarantor; and rank effectively junior to any secured obligations of GeoPark Limited, the Guarantor and their respective subsidiaries to the extent of the value of the collateral securing such obligations. Optional redemption We had the option to redeem all or part of the Notes due 2027 at their principal amount plus accrued and unpaid interest thereon (including additional amounts), if any, beginning on January 17, 2026; however, we did not exercise this option. Change of control Upon the occurrence of certain events constituting a change of control, we are required to make an offer to repurchase all outstanding Notes due 2027, at a purchase price equal to 101% of the principal amount thereof plus any accrued and unpaid interest (including any additional amounts payable in respect thereof) thereon to the date of purchase. If holders of not less than 90% in aggregate principal amount of the outstanding Notes due 2027 validly tender and do not withdraw such notes and we repurchase all such notes, we may redeem the Notes due 2027 that remain outstanding following such purchase at a price in cash equal to 101% of the principal amount thereof plus accrued and unpaid interest to but excluding the date of such redemption. Covenants The Notes due 2027 contain customary covenants, which include, among others, limitations on the incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), incurrence of liens, guarantees of additional indebtedness, the ability of certain subsidiaries to pay dividends, asset sales, transactions with affiliates, engaging in certain businesses and merger or consolidation with or into another company. In the event the Notes due 2027 receive investment-grade ratings from at least two of the following rating agencies, Standard & Poor’s, Moody’s and Fitch, and no default has occurred or is continuing under the indentures governing the Notes due 2027, certain of these restrictions, including, among others, the limitations on incurrence of debt and disqualified or preferred stock, restricted payments (including restrictions on our ability to pay dividends), the ability of certain subsidiaries to pay dividends, asset sales and certain transactions with affiliates will no longer be applicable. The indenture governing our Notes includes certain tests that must be satisfied before incurring additional debt, as well as other matters, and which provide among other things, that the net debt to Adjusted EBITDA ratio should not exceed 3.25 and the Adjusted EBITDA to interest ratio should exceed 2.5. Failure to comply with the incurrence test covenants does not trigger an event of default. However, this situation may limit our capacity to incur additional indebtedness, as specified in the indenture governing the Notes, other than certain categories of permitted debt. We must test incurrence covenants before incurring additional debt or performing certain corporate actions including but not limited to making dividend payments, restricted payments and others (in each case with certain specific exceptions). Events of default Events of default under the indentures governing the Notes due 2027 include: the nonpayment of principal when due; default in the payment of interest, which continues for a period of 30 days; failure to make an offer to purchase and thereafter accept tendered notes following the occurrence of a change of control or as required by certain covenants in the indentures governing the Notes due 2027; cross payment default relating to debt with a principal amount of US$40.0 million or more, and cross-acceleration default following a judgment for US$40.0 million or more; bankruptcy and insolvency events; and invalidity or denial or disaffirmation of a guarantee of the notes. The occurrence of an event of 96 Table of Contents default would permit or require the principal of and accrued interest on the Notes due 2027 to become or to be declared due and payable. Local debt in Colombia 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. Off-balance sheet arrangements We did not have any off-balance sheet arrangements as of December 31, 2025, or as of December 31, 2024. C. Research and development, patents and licenses, etc. See “Item 4. Information on the Company—B. Business Overview” and “Item 4. Information on the Company—B. Business Overview—Title to properties.” D. Trend information For a discussion of Trend information, see “—A. Operating Results—Factors affecting our results of operations” and “Item 4. Information on the Company—B. Business Overview— Our business strategy.” E. Critical accounting policies and estimates Not applicable. ​ 97 Table of Contents