GRAN TIERRA ENERGY INC.

General

Gran Tierra Energy Inc., together with its subsidiaries (“Gran Tierra”, “the Company”, “us”, “our”, or “we”), is a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 46%, our Canadian properties represented 38%, and our Ecuadorian properties represented 16% of our proved reserves NAR at December 31, 2025 and for the year ended December 31, 2025, 70% (2024 - 93%, 2023 -97%) of our revenue was generated in Colombia, 19% of our revenue was generated in Canada (2024 - 3% and 2023 - nil) and 11% (2024 - 4%, 2023 - 3%) of our revenue was generated in Ecuador.

We were incorporated under the laws of the State of Nevada in June 2003 and changed our state of incorporation to the State of Delaware in October 2016.

All dollar ($) amounts referred to in this Annual Report on Form 10-K are United States (U.S.) dollars, unless otherwise indicated.

2025 Operational Highlights

During the year ended December 31, 2025, we drilled 22 gross wells (13 development, two service and seven exploration), 12 in Colombia (eight net), four in Ecuador and six in Canada (three net), and incurred capital expenditures of $256.3 million, of which $149.1 million were incurred in Colombia, $62.3 million in Ecuador and $44.1 million in Canada, with the remainder comprised of administrative assets incurred by the corporate entity.

In Colombia, seven wells were drilled in the Suroriente Block, three in the Chaza Block, one in the Llanos-85 Block and one in the Alea 1848-A Block. In Ecuador, two wells were drilled in the Charapa Block and two in the Iguana Block. In Canada, we drilled six wells; four in the Simonette area and two in the Clearwater area. As at December 31, 2025, of the exploration and development wells drilled, sixteen were producing, two were service wells, one well in the Suroriente Block was in-progress and three wells in the Llanos-85 Block, the Alea 1848-A Block and the Suroriente Block in Colombia were dry.

2026 Outlook

Our Colombian, Canadian and Ecuadorian development expenditures are expected to represent approximately 60%, 30% and 10% of our 2026 capital program.

The table below shows the break-down of our 2026 capital program:

Our base capital program for 2026 is $120 million to $160 million, with over 90% attributed to development activities. Based on the mid-point of the 2026 guidance, approximately 20% of the development activities included in the 2026 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.

We expect cash flows from operations to fully fund our 2026 capital program, assuming average Brent oil prices of $65.00 per boe, WTI oil prices of $61.00 per boe and average AECO natural gas prices of C$3.00 per mcf, together with expected production of 42,000 to 47,000 boepd.

We commenced the execution of our 2026 capital program as planned, and as of February 27, 2026 drilled one well in the Cohembi field in Colombia and three wells in the Simonette area in Canada. Subsequent to December 31, 2025, the entire interest in Simonette was divested.

Business Strategy

We are an exploration and production company focused on hydrocarbon development in proven, under-explored conventional basins which have access to established infrastructure and competitive fiscal regimes. Our mandate is to develop high-value resource opportunities to deliver top-quartile returns. We intend to continue to high-grade our portfolio, with a continued focus on operational excellence, safety, and stakeholder returns. Gran Tierra is focused on continuing to build a diversified portfolio with longevity being paramount. We are constantly high grading our portfolio with the objective to maximize value for stakeholders, through the investments in and divestitures of oil and gas assets. The senior management team has a proven track record in developing technically difficult reservoirs, enhanced oil recovery, and operating in remote locations in demanding jurisdictions. We aim to have a meaningful and sustainable impact through social investments within the communities we operate. Our “Beyond Compliance Policy” focuses on our commitments to environmental, social, and governance excellence.

Capital allocation is anchored in generating sustainable free cash flow and deploying that cash toward meaningful debt reduction.

Oil and Gas Properties - Colombia and Ecuador

As of December 31, 2025, excluding blocks subject to relinquishment, we had interests in 20 blocks in Colombia, five blocks in Ecuador, and were the operator of 24 of these blocks.

Oil and Natural Gas Properties - Canada

As of December 31, 2025, we held interests in 12 areas in Canada of which the entire interest in Simonette was divested subsequent to year-end and as of February 27, 2026 we held interest in 11 areas in Canada and were the operator of 70% across all the areas.

Exploration Blocks & Commitments

The following table provides a summary of our exploration commitments for certain blocks as of December 31, 2025:

*As of December 31, 2025, exploration has been suspended due to licensing restrictions, security issues or social reasons.

** As of December 31, 2025, exploration commitments in the exploration block are not subject to phasing.

Royalties

Colombian royalties are regulated under Colombia Law 756 of 2002, as modified by Law 1530 of 2012. All discoveries made subsequent to the enactment of Law 756 of 2002 have the sliding scale royalty described below. Discoveries made before the enactment of Law 756 of 2002 have a royalty of 20% and in the case of such discoveries under association contracts reverted to the national government, an additional 12% applies for a total royalty of 32%.

The Agencia Nacional de Hidrocarburos (National Hydrocarbons Agency) (“ANH”) contracts have royalties that are based on a sliding scale described in Law 756 of 2002. These royalties work on an individual oil field basis starting with a base royalty rate of 8% for gross production of less than 5,000 BOEPD, increasing in a linear fashion from 8% to 20% for gross production between 5,000 and 125,000 BOEPD and is fixed at 20% for gross production between 125,000 and 400,000 BOEPD. For gross production between 400,000 and 600,000 BOEPD the rate increases in a linear fashion from 20% to 25%. For gross production in excess of 600,000 BOEPD the royalty rate is fixed at 25%. The Santana and Nancy-Burdine-Maxine Blocks have fixed rates for existing production of 32% and 20%, respectively. New discoveries and incremental production are subject to sliding scale royalties duly approved by the ANH. In addition to the sliding scale royalty, there are additional x-factor economic rights of 1% for Llanos-22, Putumayo-4, Putumayo-7, Putumayo-21 and VMM-24; 2% for Llanos-85; 3% for VMM-2, 5% for Putumayo-1; 12% for Putumayo-31; 31% for Llanos-1 and Llanos-70.

For natural gas fields, the royalty is based on an individual natural gas field basis starting with a base royalty rate of 6.4% for gross production of less than 28.5 MMcf of natural gas per day. The royalty increases in a linear fashion from 6.4% to 16% for gross production between 28.5 MMcf of natural gas per day and 712.5 MMcf of natural gas per day and is stable at 16% for gross production between 712.5 to 2,280 MMcf of natural gas per day, and then increases in a linear fashion from 16% to 20% for gross production between 2,280 to 3,420 MMcf of natural gas per day. For gross production in excess of 3,420 MMcf of natural gas per day the royalty rate is fixed at 20%.

Additional high price rights (“HPR”) are applicable for exploration and production contracts signed under the new ANH oil regulatory regime in 2004 and onwards when cumulative gross production from an exploitation area is greater than 5 MMbbls of oil and WTI reference price exceeds the trigger price defined in the contract. The HPR is calculated using the associated production multiplied by the Q factor, which is calculated as follows:

Q factor = (WTI price - Base Price(1))/WTI Price *S(2)

(1)Base Price is determined annually by the ANH, based on a formula defined in the contract. For 2025 and 2024, the base price was set as follows:

At December 31, 2025, HPR was applicable to our production from the Costayaco and Moqueta exploitation areas in the Chaza Block, the Acordionero Exploitation Area in the Midas Block, and the Llanos-22 Block.

(2)S percentageof HPR participation is 30% flat for Chaza and Midas Blocks. For Llanos-22, the percentage is variable compared to WTI price as per below:

In addition to these government royalties and rights, our original interests in the Guayuyaco and Chaza Blocks acquired on our entry into Colombia in 2006 are subject to a third party royalty. The additional interests in Guayuyaco and Chaza that we acquired on the acquisition of Solana in 2008 are not subject to this third party royalty. The overriding royalty rights start with a 2% rate on working interest production less government royalties. For new commercial fields discovered within 10 years of the agreement date and after a prescribed threshold is reached, Crosby Capital, LLC (“Crosby”) reserves the right to convert the overriding royalty rights to a net profit interest (“NPI”). This NPI ranges from 7.5% to 10% of working interest production less sliding scale government royalties, as described above, and operating and overhead costs. No adjustment is made for the HPR. On certain pre-existing fields, Crosby does not have the right to convert its overriding royalty rights to an NPI. In addition, there are conditional overriding royalty rights that apply only to the pre-existing fields. Currently, we are subject to a 10% NPI on 50% of our working interest production from the Costayaco and Moqueta fields in the Chaza Block and 35% of our working interest production from the Juanambu field in the Guayuyaco Block and overriding royalties on our working interest production from the Guayuyaco field in the Guayuyaco Block.

The Putumayo-7 and Putumayo-1 Blocks are also subject to a third party royalty in addition to the government royalties and rights. Pursuant to the terms of the agreement by which the interests in the Putumayo-7 Block were acquired, a 10% royalty on production from the Putumayo-7 Block is payable to a third party. The terms of the royalty allow for transportation costs, marketing and handling fees, government royalties (including royalties payable to the ANH pursuant to Section 39 of the contract for the Putumayo-7 Block - the “Rights Due to High Prices”) and taxes, other than taxes measured by the income of any party, value-added tax (“VAT”) or any equivalent, to be paid in cash or kind to the Government of Colombia (or any federal, state, regional or local government agency) and ANH, and a 1% ‘X’ factor payment to be deducted from production revenue prior to the royalty being paid to a third party. Pursuant to the terms of the agreement by which the interests in the Putumayo-1 Block were acquired, a 3% royalty on production from the Putumayo-1 Block is payable to a third party. The terms of the royalty do not allow for any costs, royalties, and taxes to be deducted from production revenue.

We currently hold Participation Sharing Contracts (“PSC”) for the five Blocks (Charapa, Chanangue, Iguana, Perico and Espejo) in the Oriente Basin in Ecuador. Unlike traditional PSCs, these contracts do not include cost oil or royalties. Instead, the entire production is placed into a profit-sharing pool that is split between the Company and the government based on a percentage derived from a biddable price component and a production component. The biddable price component is a sliding scale that is based on the Oriente oil price ranging from $30 per boe to $120 per boe, with the Company’s production share varying between 40% and 87.5%, respectively. The Company’s share in production would only drop below 50% if the Oriente oil prices exceed $100 per boe. The production component is a tier-based mechanic increasing from 0% to 6% based on the PSC’s daily production. Additionally, sales of crude oil are subject to Amazon Fund royalty equal to 4% of the sale price. For the year ended December 31, 2025, the share of production retained by the government of Ecuador was recorded as royalties in-kind and Amazon Fund royalties were paid in cash and recorded as a reduction of revenue.

The royalty calculation in Canada is a significant factor in the profitability of Canadian oil and natural gas production. Oil and natural gas crown royalties are determined by provincial and territorial government regulation and are generally calculated as a percentage of the value of the gross production, net of allowed deductions. The royalty rate is dependent in part on prescribed reference prices, well productivity, geographical locations, recovery methods, as well as type and quality of the hydrocarbon produced. For pre-payout oil and natural gas projects, the regulations prescribe lower royalty rates for oil and natural gas projects until allowable incentive programs have been depleted and capital costs have been recovered. The calculation for wells post payout is based on a percentage of production net of allowed deductions and varies with commodity price.

The Alberta royalty regime governs the compensation oil and natural gas producers pay to the provincial government for extracting resources, ensuring revenues for the province while promoting industry investment and competitiveness. For conventional oil and natural gas, royalties are calculated using a sliding scale that considers commodity prices, production volumes, and well characteristics such as depth and density. Higher prices and production levels result in higher royalty rates, while lower production or market prices trigger reduced rates. Conventional oil royalties can range from 0% to 40%, while natural gas royalties are similarly adjusted based on productivity, price, and natural gas composition. Newly drilled wells benefit from an initial flat 5% royalty rate until they reach a specified payout or until they reach a specified production cap, enabling quicker cost recovery. The Modernized Royalty Framework, introduced in 2017, applies to wells drilled on or after January 1, 2017. Under this system, producers initially pay a flat 5% royalty rate until cumulative revenues equal standardized well drilling and completion costs, known as the "C* cost allowance." Once these costs are recovered, royalties increase on a sliding scale based on commodity prices and production levels, ensuring the system adjusts to economic conditions while maintaining a stable revenue stream for the province. To further encourage resource development, Alberta’s regime includes targeted incentives, such as royalty reductions for enhanced oil recovery projects and credits for deep drilling, particularly in natural gas exploration. These measures balance the province’s economic interests with the need to attract ongoing investment and maintain competitiveness in the energy sector. All of the Company’s Canadian production is in Alberta and all wells drilled in 2025 were in Alberta.

Administrative Facilities

Our principal executive office is located in Calgary, Alberta, Canada. Our principle Calgary office lease will expire on November 30, 2028. Our office leases in Colombia and Ecuador will expire on February 28, 2031, and May 31, 2029, respectively.

Estimated Reserves

Our 2025 reserves were evaluated independently by McDaniel & Associates (“McDaniel”). McDaniel was established in 1955 as an independent Canadian consulting firm and has been providing oil and natural gas reserves evaluation services to the world’s petroleum industry for the past 70 years. They have internationally recognized expertise in reserves evaluations, resource assessments, geological studies, and acquisition and disposition advisory services. McDaniel’s office is located in Calgary, Canada. The technical person primarily responsible for the preparation of our reserves estimates at McDaniel meets the requirements regarding qualifications, independence, objectivity, and confidentiality set forth in the Standards Pertaining to the Estimating and Auditing of Oil and Natural Gas Reserves Information promulgated by the Society of Petroleum Engineers.

The primary internal technical person in charge of overseeing the preparation of our reserve estimates is the Chief Operating Officer. He has a Bachelor of Geological Engineering, graduating from University of Waterloo and is responsible for our engineering activities, including reserves reporting, asset evaluation, reservoir management, and field development. He has over 20 years of experience in the oil and natural gas industry with extensive experience in reservoir management, production, and operations.

All of our reserves are evaluated by an independent reservoir engineering firm, at least annually. We have developed internal controls over estimation and evaluation of reserves. Our internal controls over reserve estimates include an independent internal review of assumptions used for reserve estimates and presentation of the results of this internal review to our reserves committee. Calculations and data are reviewed at several levels of the Company to ensure consistent and appropriate standards and procedures. Our policies are applied to all staff involved in generating and reporting reserve estimates including geological, engineering and finance personnel.

The process of estimating oil and natural gas reserves is complex and requires significant judgment, as discussed in Item 1A “Risk Factors”. The reserve estimation process requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering, and economic data for each property. Therefore, the accuracy of the reserve estimates is dependent on the quality of the data, the accuracy of the assumptions based on the data, and the interpretations and judgment related to the data.

Proved reserves are reserves 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 under existing economic conditions, operating methods, and government regulations prior to the time at which contracts providing the right to operate expires, unless evidence indicates that renewal is reasonably certain. The term “reasonable certainty” implies a high degree of confidence that the quantities of oil or natural gas actually recovered will equal or exceed the estimate. To achieve reasonable certainty, we and the independent reserve engineers employed technologies that have been demonstrated to yield results with consistency and repeatability. Estimates of proved reserves are generated through the integration of relevant geological, engineering, and production data, utilizing technologies that have been demonstrated in the field to yield repeatable and consistent results as defined by the SEC regulations. Data used in these integrated assessments included information obtained directly from the subsurface through wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, such as seismic data. The tools used to interpret the data included proprietary and commercially available seismic processing software and commercially available reservoir modeling and simulation software. Reservoir parameters from analogous reservoirs were used to increase the quality of and confidence in the reserves estimates when available. The method or combination of methods used to estimate the reserves of each reservoir was based on the unique circumstances of each reservoir and the dataset available at the time of the estimate. Probable reserves are reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered. Estimates of probable reserves which may potentially be recoverable through additional drilling or recovery techniques are by nature more uncertain than estimates of proved reserves and accordingly are subject to substantially greater risk of not actually being realized by us. The probable reserves that have been assigned as of December 31, 2025, were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for proved reserves, as well as the areas of a reservoir adjacent to proved reserves where data control or interpretations of available data are less certain. Possible reserves are reserves that are less certain to be recovered than probable reserves. Estimates of possible reserves are also inherently imprecise. Estimates of probable and possible reserves are also continually subject to revisions based on production history, results of additional exploration and development, price changes, and other factors. The possible reserves that have been assigned as of December 31, 2025, were based on both the greater percentage of recovery of the hydrocarbons in place than assumed for probable reserves as well as to areas of a reservoir adjacent to probable reserves where data control or interpretations of available data are less certain.

The following table sets forth our estimated reserves NAR located in Colombia, Ecuador and Canada as of December 31, 2025:

(1) Estimates of probable and possible reserves are more uncertain than proved reserves, but have not been adjusted for risk due to that uncertainty. Accordingly, estimates of probable and possible reserves are not comparable and have not been, or should not be, summed arithmetically with each other or with estimates of proved reserves.

Product Prices Used in Reserves Estimates

The product prices that were used to determine the future gross revenue for each property reflect adjustments to the benchmark prices for gravity, quality, local conditions and/or distance from market. The average realized prices for reserves in the report are based on unweighted arithmetic average price, as of the first-day-of-the-month, for the 12-month period ended December 31, 2025:

These prices should not be interpreted as a prediction of future prices. We do not represent that this data is the fair value of our oil and natural gas properties or a fair estimate of the present value of cash flows to be obtained from their development and production.

Proved Undeveloped Reserves

As at December 31, 2025, we had total proved undeveloped reserves NAR of 48.3 MMBOE (December 31, 2024 - 66.9 MMBOE), which were 42% in Colombia, 29% in Canada and 29% in Ecuador (December 31, 2024 – 44% in Colombia, 44% in Canada with the remainder in Ecuador). Approximately 20%, 8%, and 9% for a total of 37% of proved undeveloped reserves are located in our Acordionero, Costayaco fields and Suroriente Block, respectively, in Colombia, 12% located in the Chanangue Block in Ecuador and 15% in the Simonette area in Canada. None of our proved undeveloped reserves at December 31, 2025, have remained undeveloped for five years or more since initial disclosure as proved reserves, and we have adopted a development plan which indicates that the proved undeveloped reserves are scheduled to be drilled within five years of initial disclosure as proved reserves.

Changes in proved undeveloped reserves during the year ended December 31, 2025 are shown in the table below:

Changes in proved undeveloped reserves during the year ended December 31, 2025, shown in the table above primarily resulted from the following significant factors:

Acquisitions

In 2025, we acquired 1.6 MMBOE of proved undeveloped reserves in the Perico Block in Ecuador.

Converted to Proved Producing

In 2025, we converted 4.7 MMBOE, or 7% of 2024 proved undeveloped reserves to developed status (2.0 MMBOE in the Cohembi field in Colombia, 1.6 MMBOE in the Costayaco field in Colombia, 0.4 MMBOE in Ecuador and 0.7 MMBOE in the Simonette area in Canada). In 2025, the conversion of proved producing volumes was a result of capital expenditures of $53.7 million associated with drilling four wells in the Suroriente Block, three wells in the Chaza Block, one well in Ecuador and three wells in Canada.

Technical and Economic Revisions

During the year ended December 31, 2025, there was an overall negative revision of 21.9 MMBOE proved undeveloped reserves, of which 5.6 MMBOE were deducted in Colombia primarily due to the removal of undeveloped drilling locations in minor properties, 16.9 MMBOE deducted in Canada resulted from the reclassification of certain drilling locations from reserves to contingent resources to better align development timing with prevailing commodity price assumptions and expected activity levels and 0.6 MMBOE added in Ecuador, associated with production type curve improvements in the Charapa Block.

Extensions and Discoveries

We added 6.3 MMBOE to proved undeveloped reserves during the year ended December 31, 2025, of which 2.0 MMBOE were in Canada and 4.3 MMBOE in Ecuador. In Canada, we had extensions in the Simonette and Clearwater areas. In Ecuador, we had discoveries of 0.5 MMBOE in the Iguana Block,0.6 MMBOE in the Chanangue Block and 3.3 MMBOE in the Charapa Block.

Production, Revenue and Price History

Certain information concerning production, prices, revenues, and operating expenses for the years ended December 31, 2025, 2024, and 2023, is set forth in Item 7 “Management's Discussion and Analysis of Financial Condition and Results of Operations” and in the “Supplementary Data (Unaudited)” provided following our Financial Statements in Item 8, which information is incorporated by reference here.

The following table presents NAR oil, natural gas and NGL production, average sales prices, and operating expenses per boe of NAR oil production from our major fields (Acordionero, Costayaco, Moqueta, Cohembi) located in Colombia and total for all our properties for the three years ended December 31, 2025, 2024, and 2023, respectively:

(1) 100% of product sales were oil.

(2) Includes natural gas production from Canada operations of 16,486,076 Mcf (2,747,679 boe) for the year ended December 31, 2025 2,781,141 Mcf (463,524 boe) for the year ended December 31, 2024, and the de minimis natural gas production from non-core properties from Colombia of 9,682 Mcf (1,614 boe) for the year ended December 31, 2023.

(3) Operating expenses include operating and transportation expenses.

We prepared the estimate of a standardized measure of proved reserves in accordance with the Financial Accounting Standards Board (“FASB”) Accounting Standards Codification 932, “Extractive Activities – Oil and Gas.”

Drilling Activities

The following table summarizes the results of our exploration and development drilling activity for the past three years. Wells labeled as “In Progress” for a year were in progress as of December 31, 2025, 2024, or 2023. This information should not be considered indicative of future performance, nor should it be assumed that there was any correlation between the number of productive wells drilled and the oil and natural gas reserves generated thereby or the costs to Gran Tierra of productive wells compared to the costs of dry holes.

Well Statistics

The following table sets forth our productive wells as of December 31, 2025:

(1) Includes 87 gross and 82 net water injector wells and 95 gross and 94 net wells with multiple completions.

(2) Includes 274 gross and 78 net water injector wells.

(3) Includes five gross and net wells with multiple completions.

Developed and Undeveloped Acreage

At December 31, 2025, our gross acreage was located 47% in Colombia, 46% in Canada and 7% in Ecuador and the following table sets forth our developed and undeveloped oil and natural gas lease and mineral acreage as of that date:

(1) Excludes our interest in one Block with a total of 0.1 million net acres for which government approval of relinquishment or sale was pending at December 31, 2025.

(2) As of December 31, 2025, the exploration phase for 0.3 million gross and net undeveloped acres expires within the next three years, with an option to extend the exploration phase for 50% of the expired area.

(3)During the year ended December 31, 2025, the production in Ecuador was under the evaluation permits of exploration phase, and therefore the entire acreage for Ecuador is reported as undeveloped.

Marketing and Major Customers

Colombia represents approximately 53% of our production, with oil reserves and production mainly located in the Middle Magdalena Valley (“MMV”) and Putumayo Basin. In MMV, our largest field is the Acordionero field, where we produce approximately 17.9° API oil, which represented 29% of the total Company’s production for the year ended December 31, 2025. Putumayo production is approximately 27° API for the Chaza Block and 18° API for the Suroriente Block, representing 14% and 7%, respectively, of the total Company’s production for the year ended December 31, 2025.

We have sales agreements for our production from MMV and the Putumayo Basin with one international marketer for selling crude oil for export purposes expiring on September 30, 2029. The volume of crude oil contemplated in this sales agreement does not include the volume of oil corresponding to royalties taken in-kind and, since October 2022, does include volumes relating to HPR royalties. The loss of any individual sales customer will not have a material adverse impact on our Company as customers can be substituted or we could market the crude directly ourselves.

All of our Putumayo production is sold at the wellhead. In order to capture the best market value and optimize our netback, our marketing strategy is to sell a blend “Chaza Heavy” of the entire Putumayo production with an average quality between 23 and 25° API. Production from the Acordionero field in MMV is trucked and sold at various terminals or pipeline inlets and various distances from the Acordionero field, depending on our marketing strategy to optimize the value.

In Ecuador, Chanangue Block produces between 18° and 21° API oil, Charapa Block produces between 24 and 26° API oil, Iguana Block produces approximately 28° API oil and Perico Block, acquired in December 2025, produces approximately 26° API. We have a sales agreement covering our entire Ecuadorian production with a single international marketer, under which the product is sold at the port of shipment, and which is set to expire on September 30, 2029. For the year ended December 31, 2025, Ecuador contributed 11% of the total Company’s production.

For our Canadian operations, marketing activities are focused on maximizing the value of production from our core assets, including the Simonette, Central Alberta, Wapiti, and Clearwater regions. Our Canadian oil production is approximately 40° API. Our strategy prioritizes minimizing production curtailments, maximizing realized commodity prices, and managing credit risk exposure across our customer base. Our production, consisting of crude oil, natural gas, and NGLs, is primarily sold to marketers and aggregators. Prices realized are based on prevailing regional market indices, influenced by supply-demand fundamentals, transportation infrastructure, and competing energy sources. Our Canadian sales were 37% of the total Company’s production for the year ended December 31, 2025.

To manage commodity price risks, we employ financial hedging instruments to stabilize future cash flows, protect against price volatility, and support operational planning.

We expect to fulfill our delivery commitments primarily with production from our proved developed reserves. Longer-term delivery obligations will be satisfied through production from proved undeveloped reserves. For long-term transportation and processing agreements, we anticipate utilizing future resource developments that are not yet classified as proved reserves.

Production from our reserves is not subject to priorities, curtailments, or regulatory price limitations that could impact quantities delivered to customers.

We receive revenues for our Colombian and Ecuadorian oil sales in U.S. dollars and for our Canadian oil, natural gas and NGL sales in Canadian dollars. Oil prices for sales of our crude oil are defined by agreements with the purchasers of the oil. They are based generally on an average price for crude oil, natural gas and NGLs, referenced to ICE Brent, WTI, Mixed Sweet Blend (“MSW”) and AECO natural gas, with adjustments for differences in quality, specified fees, transportation fees, and transportation tax. Pipeline tariffs are denominated in U.S. dollars for Colombia and Ecuador and Canadian dollars for Canada, while trucking costs are in Colombian Pesos in Colombia and U.S. dollars in Ecuador. 100% of transportation in Canada is performed via pipelines.

Competition

The oil and natural gas industry is highly competitive. We face competition from both local and multinational companies. This competition impacts our ability to acquire properties, contract drilling and other oil field equipment, and secure trained personnel. Many competitors, such as Colombian and Ecuadorian national oil companies and independent oil and natural gas companies in Canada, have greater financial resources. Our larger or more integrated competitors may be able to absorb the burden of existing, and any changes to, federal, state and local laws and regulations more easily than we can, which could adversely affect our competitive position. Our ability to acquire additional properties and to discover reserves in the future will depend on our ability to evaluate and select suitable properties and consummate transactions in a highly competitive environment. There is substantial competition for land contracts, prospects, and resources in the oil and gas industry, and we compete to develop and produce those reserves cost-effectively. The oil and natural gas industry also competes with other industries focused on providing alternative forms of energy to consumers. Competitive forces can lead to cost increases or result in an oversupply of oil, natural gas or NGLs. In addition, we compete to monetize our oil production: for transportation capacity and infrastructure to deliver our products, maintain a skilled workforce, and obtain quality services and materials.

Geographic Information

We have three reportable segments based on the geographic organization: Colombia, Ecuador and Canada. Long-lived assets are Property, Plant and Equipment, which include all oil, natural gas and NGL assets, furniture and fixtures, automobiles, computer equipment, and capitalized leases. No long-lived assets are held in our country of domicile, which is the United States of America. Assets held by our corporate head office in Calgary, Alberta, Canada, were not significant as of December 31, 2025, and 2024 and were included in the “Other” category which represents the Company’s corporate activities. Because all of our exploration and development operations are in Colombia, Ecuador and Canada, we face many risks associated with these operations. See Item 1A “Risk Factors” for risks associated with our foreign operations.

Regulation

The oil and gas industry in Colombia, Ecuador and Canada is heavily regulated. Rights and obligations relating to exploration, development, and production activities are explicit for each project; economics are governed by a royalty and tax regime. Various government approvals are required for property acquisitions and transfers, including, but not limited to, meeting financial and technical qualification criteria in order to be certified as an oil and gas company in the country. Oil and gas concessions are typically granted for fixed terms with an opportunity for extension. In Alberta, the Alberta Energy Regulator (“AER”) is the single regulator of oil and gas development in Alberta and, through its numerous Directives, oversees all aspects of the regulatory process, including operations related to exploration, construction and development, abandonment, reclamation, and remediation activities. The AER oversees compliance with the Oil and Gas Conservation Act, Public Lands Act, Mines and Minerals Act, Water Act and the Environmental Protection and Enhancement Act by oil and gas operators. The AER operates in conjunction with Alberta Environment and Parks to ensure the province's environmental, social and economic targets are met. Alberta Environment and Parks is also responsible for climate change-related regulations such as the Alberta Technology Innovation and Emissions Reduction program.

Colombia Administration

We operate in Colombia through Colombian branches of the following entities: Gran Tierra Energy Colombia GmbH and Gran Tierra Operations Colombia GmbH. These entities are currently qualified as operators of oil and gas properties by the ANH. The entities operate under a special regime for hydrocarbon companies in Colombia that entitle them to collect proceeds from oil sales abroad in U.S. dollars and import such into Colombia for payments in local currency.

In Colombia, the ANH is the administrator of the hydrocarbons in the country, as delegated by the Ministry of Mining and Energy, and therefore is responsible for the administration of Colombian oil and natural gas contracts and management of all of the nation’s exploration and exploitation lands. Ecopetrol, the Colombian national oil company, is a public company listed in the Colombian and United States stock markets, owned in majority by the state with the main purpose of exploring and producing hydrocarbons similar to any other integrated oil company. In addition, Ecopetrol is a major purchaser and marketer of oil in Colombia and directly or through its subsidiaries operates most of the oil pipeline transportation and refining infrastructure in the country. Ecopetrol Group also owns a majority stake in the Colombian energy transmission sector. Companies can also have joint exploration and exploitation contracts with Ecopetrol.

The ANH uses various forms of contracts, which provide full risk/reward benefits for the contractor. Under the terms of these contracts, the operator retains the right to produce all reserves, production, and income from any new exploration and evaluation block, subject to existing royalty and tax regulations. Each contract contains an exploration and a production period. The exploration period contains a number of exploration phases, and each phase has an associated work commitment. The production period usually lasts 24 years from the declaration of a commercial hydrocarbon discovery. Such contracts may be terminated at election of the ANH on the failure of the contract holder to comply with certain material terms of the contract, such as failure to perform committed exploration operations or investments in accordance with the contract. Ecopetrol uses various forms of contracts, which contain exploration and development phases. Duration of contracts can be life of field or up to a specific date and the terms of such contracts vary depending on the type of contract. Under the Ecopetrol contract, the partner retains its working interest rights to produce all reserves, production and income from any new exploration and evaluation block, subject to existing royalty and tax regulations during the duration of such contract.

When operating under the ANH contract, the contractor is the owner of the hydrocarbons extracted from the contract area during the performance of operations, except for royalty volumes which are collected by the ANH (or its designee). The contractor can market the hydrocarbons in any manner whatsoever, subject to a limitation in the case of natural emergencies where the law specifies the manner of sale. Under the Ecopetrol contract, each party owns its working interest of the hydrocarbons extracted.

The contracts in place with ANH and Ecopetrol are agreements among both parties duly protected by regulation and, therefore, cannot be unilaterally adjusted at election of the Government. Contracts include the instances for remediation, arbitration and other protection measures. In addition, investment protection treaties and Colombian regulation protect the sanctity of the existing contract.

Ecuador Administration

We operate three Blocks in Ecuador through the Ecuadorian branch of Gran Tierra Energy Colombia, GmbH (“GTEC”) and two newly acquired consortium Blocks through Ecuadorian Branches Gran Tierra Energy 1 GmbH (51%) and Gran Tierra Energy 2 GmbH (49%).

In Ecuador, the Ministry of Environment and Energy (“MEE”) is the entity responsible for executing exploration and production oil and natural gas contracts. The technical regulator of such contracts and other hydrocarbon matters is the Agency for Regulation and Control of Energy and Non-Renewable Natural Resources.

Hydrocarbons Law provides four contract types: service, association, production and sharing and marginal blocks. MEE has currently in force service and production sharing contracts for the exploration and/or exploitation of hydrocarbons (“PSC’s”). GTEC currently holds three PSC’s which provide for full risk for the contractor and production sharing with MEE. PSC’s are divided into a four-year exploration period (which may be extended for two years on certain grounds such as delays on licensing procedures) and up to 20 years of production. Each period has minimum associated work commitments. In the second quarter of 2021, we received a two-year extension of the exploration period for all three Participation Contracts, under the aforementioned provision. The production period begins with the approval of a development plan for one of several commercial hydrocarbon discoveries. Such contracts may be terminated at the election of the MEE on the failure of the contract holder to comply with certain material terms of the contract, such as failure to perform committed exploration or production activities in accordance with the contract.

When operating under a PSC, the contractor holds title to its share of the hydrocarbon once it is distributed by the parties at a specific point called the auditing point. Until such point, the contractor is responsible and shall pay transportation costs. Afterwards, contractor and MEE pay transportation costs separately in accordance with their shares. Marketing costs are paid entirely by the contractor for its production share. At the auditing point, risks and titles are passed to the contractor for its production share, and MEE becomes responsible as well for its volumes. During 2025, we completed all exploration commitments under our existing three contracts, submitted future development plans for Chanangue and Iguana Blocks with Ecuadorian government and successfully received the approval for both Blocks. In 2025 we acquired 100% working interests in the Perico and Espejo Blocks and currently are the operator in all five Blocks in Ecuador.

Canada Administration

We operate in Canada through the Canadian subsidiary Gran Tierra Canada Ltd. registered in Alberta. In Canada, oil and natural gas mineral rights may be held by individuals, corporations or governments that have jurisdiction over the area in which such mineral rights are located. Generally, parties holding these mineral rights grant licenses or leases to third parties to facilitate the exploration and development of these mineral rights. The terms of these leases and licenses are generally established to require timely development. Notwithstanding the ownership of mineral rights, the government of the jurisdiction in which the mineral rights are located generally retains authority over the drilling and operation of oil and natural gas wells.

Environmental Compliance

Our activities are subject to laws and regulations governing environmental compliance quality, waste and pollution control in the countries where we maintain operations. Our activities with respect to exploration, drilling, production facilities, including the operation and construction of pipelines, plants and other facilities for transporting, processing, treating or storing oil and other products, are subject to stringent environmental regulation by regional and federal authorities in Colombia, Ecuador and Canada. Such regulations relate to mandatory environmental impact studies, the discharge of pollutants into air and water, water use and management, the management of non-hazardous and hazardous waste, including its transportation, storage and disposal permitting for the construction of facilities, recycling requirements and reclamation standards, and the protection of certain plants and animal species as well as cultural resources and areas inhabited by indigenous people, among others. Risks are inherent in oil and gas exploration, development and production operations. These risks include blowouts, fires and spills. Significant costs and liabilities may be incurred in connection with environmental compliance issues. Licenses and permits required for our exploration and production activities may not be obtainable on reasonable terms or on a timely basis, which could result in delays and have an adverse effect on our operations. Spills and releases of petroleum products into the environment can result in remediation costs and liability for damages. The costs of remedying such conditions may be significant, and remediation obligations could adversely affect our financial condition, results of operations and prospects. Moreover, violations of environmental laws and regulations can result in the issuance of administrative, civil or criminal fines and penalties, as well as orders or injunctions prohibiting some or all of our operations in affected areas. In addition, indigenous groups or other local organizations could oppose our operations in their communities, potentially resulting in delays which could adversely affect new developments. Governmental or judicial actions may influence the interpretation and enforcement of environmental laws and regulations and may thereby increase licensing and compliance costs. We do not expect that the cost of compliance with regional and federal provisions, which have been enacted regulating the discharge of materials into the environment, or otherwise relating to the protection of the environment or natural resources, will be material to us.

We have implemented a company wide web-based reporting system which allows us to track incidents and respective corrective actions and associated costs. We have a Corporate Health, Safety, and Environmental Management Policy and Plan as well as a Corporate Environmental Management Plan (“EMP”). The EMP is based on the environmental performance standards of the World Bank International Finance Corporation and reflects best industry practices. We have an Environmental Management System which is ISO14001:2015 certified representing compliance with internationally recognized industry best practice, as well as the environmental risk management program and robust waste management procedures. Air, soil and water testing occurs regularly and environmental contingency plans have been prepared for all sites and transportation of oil. We have a regular quarterly reporting system, reporting to executive management as well as the Health Safety and Environment Committee of the Board of Directors. We have a schedule of internal and external audits and routine checking of practices and procedures and conduct emergency response exercises.

Human Capital Management

At February 27, 2026, we had 406 full-time employees (December 31, 2024 - 431): 137 located in Canada (133 staff in Calgary and four field personnel), 217 in Colombia (156 staff in Bogota and 61 field personnel), 52 in Ecuador (21 staff in Quito and 31 field personnel). None of our employees are represented by labor unions, and we consider our employee relations to be good.

Health and Safety

We have implemented safety management systems, procedures, and tools to protect our employees and contractors. As part of our Health and Safety Management System, we identify potential risks associated with the workplace and develop measures to mitigate possible hazards. We support our employees with general safety training and implement specific programs for those working in all our operations, such as equipment and machinery safety, chemical management, and electrical safety.

Workplace Practices and Policies

Gran Tierra is an equal opportunity employer committed to equality and sourcing local employees, contractors, and suppliers. We have a program to increase gender and diversity representation, including guidelines to prevent gender discrimination in selection and recruitment by contractors, incentives to promote the recruitment of women throughout the supply chain, training to increase the competitiveness of female employees and candidates, and guarantees of fair working conditions including schedules and salaries.

We are committed to enabling employees and contractors to grow within their roles to advance by offering coaching and mentoring programs. An example of this is our Te Enseña (Learn with Gran Tierra) program. It involves independent training sessions across several departments, where participants improve internal knowledge and further develop their skill sets. We also offer employee-led virtual training sessions that promote individual growth and create a space for employees to learn from their peers. These programs have fostered interdepartmental connections between employees and contractors providing the ability to work remotely.

Compensation

We believe that all employees deserve competitive compensation and standard short and long-term incentives that enable employees to share in the success of the Company.

Engagement

We believe that open, honest, and transparent communication among the team members, managers, and senior management promotes company engagement and offers a strong understanding of our business’s big picture. We regularly encourage employees to learn about the organization’s strategic objectives and understand the company’s decisions and how those decisions impact them specifically. We undertake quarterly reviews to inform our team about the Company’s performance and future goals. We believe these key strategies have led to strategic alignment across the organization.

Available Information

We file or furnish annual, quarterly and current reports, proxy statements and other documents with the SEC. We make available free of charge, through our website at www.grantierra.com, our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K, and all amendments to those reports as soon as reasonably practicable after such material is electronically filed or furnished with the SEC. Our Code of Business Conduct and Ethics, Corporate Governance Guidelines, Audit Committee Charter, Compensation Committee Charter, Nominating and Corporate Governance Committee Charter, Reserve Committee Charter, and other Company policies and guidelines are also posted to the governance section of our website. Our website address is provided solely for informational purposes. Information on our website is not incorporated into this Annual Report or otherwise made part of this Annual Report. We intend to use our website as a means for distributing information to the public for purposes of compliance with Regulation Fair Disclosure.

In addition, the SEC maintains a website (www.sec.gov) that contains reports, proxy and information statements, and other information regarding issuers that file electronically with the SEC, including us.