GRAN TIERRA ENERGY INC.

To the Shareholders and Board of Directors of Gran Tierra Energy Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Gran Tierra Energy Inc. and subsidiaries (the Company) as of December 31, 2025 and 2024, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2025, and the related notes (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2025, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated March 4, 2026 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matter

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that: (1) relates to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of a critical audit matter does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

Assessment of the impact of the estimated proved oil and natural gas reserves on the depletion expense and the ceiling test calculations related to the Company’s oil and natural gas properties

As discussed in Note 2 to the consolidated financial statements, the Company depletes its oil and natural gas properties using the unit-of-production method based upon production and estimates of proved reserve quantities. Under such method, capitalized costs are depleted over the estimated proved oil and natural gas reserves. As discussed in Note 8 to the consolidated financial statements, the Company recorded depletion and depreciation expense of $267.9 million for the year ended December 31, 2025, a portion of which related to the Company’s oil and natural gas properties. Additionally, as discussed in Note 2 to the consolidated financial statements, the Company performs a ceiling test calculation each quarter on a country-by-country basis. In performing its quarterly ceiling test, the Company limits the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at 10 percent, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling limitation, the Company will record a ceiling test impairment to the extent of such excess. As discussed in Note 9 to the consolidated financial statements, the Company recorded ceiling test impairment losses of $136.3 million in Canada and Colombia in 2025 related to the Company’s oil and natural gas properties. The estimation of proved oil and natural gas reserves, which are used in the calculations of depletion and the ceiling test, involves the expertise of independent reservoir engineering specialists, who take into consideration assumptions related to forecasted production and forecasted operating, royalty and capital costs (reserve assumptions). The Company engages independent reservoir engineering specialists to estimate the proved oil and natural gas reserves.

We identified the assessment of the impact of estimated proved oil and natural gas reserves on the depletion expense and the ceiling test calculations related to the Company’s oil and natural gas properties as a critical audit matter. Changes in the reserve assumptions could have a significant impact on the depletion expense and the ceiling test calculations. Complex auditor judgment was required in evaluating the Company’s proved oil and natural gas reserves, and the related reserve assumptions, which were an input to the depletion expense and the ceiling test calculations.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls related to the critical audit matter. This included controls related to:

• the depletion expense and the ceiling test calculations

• the estimation of the proved oil and natural gas reserves, including the reserve assumptions.

We recalculated the depletion expense and the ceiling test calculations and analyzed them for compliance with industry and regulatory standards. We evaluated the competence, capabilities and objectivity of the independent reservoir engineering specialists engaged by the Company to estimate the proved oil and natural gas reserves.

We evaluated the methodology used by the independent reservoir engineering specialists to estimate the proved oil and natural gas reserves for compliance with industry and regulatory standards. We compared the Company’s 2025 actual production and operating, royalty and capital costs to those estimates used in the prior year’s estimate of the proved oil and natural gas reserves to assess the Company’s ability to accurately forecast. We assessed the estimates of forecasted production and forecasted operating, royalty and capital costs assumptions used in the estimate of the proved oil and natural gas reserves by comparing them to historical results.

/s/ KPMG LLP

Chartered Professional Accountants

We have served as the Company’s auditor since 2018

Calgary, Canada

March 4, 2026

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

(Thousands of U.S. Dollars, Except Share and Per Share Amounts)

(Thousands of U.S. Dollars)

Consolidated Statements of Shareholders’ Equity

(Thousands of U.S. Dollars)

(1) Reflects our 1-for-10 reverse stock split that became effective May 5, 2023.

Notes to the Consolidated Financial Statements

For the Years Ended December 31, 2025, 2024 and 2023

(Expressed in U.S. Dollars, unless otherwise indicated)

1. Description of Business

Gran Tierra Energy Inc., a Delaware corporation (the “Company” or “Gran Tierra”), is a publicly traded company focused on oil and natural gas exploration and production with assets currently held in Colombia, Ecuador and Canada.

2. Significant Accounting Policies

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles in the United States of America (“GAAP”).

Significant accounting policies are:

Basis of Consolidation

These consolidated financial statements include the accounts of the Company and its controlled subsidiaries. All intercompany accounts and transactions have been eliminated.

Use of Estimates

The preparation of financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and disclosure of contingent assets and liabilities at the date of the consolidated financial statements and the reported amounts of revenues and expenses during the reporting period. Certain estimates and judgments have a material impact where the assumptions underlying these accounting estimates relate to matters that involve significant estimation uncertainty at the time the estimate or judgement is made or are subjective. These estimates and judgments include, but are not limited to:

•estimated proved and probable reserves volumes and the related cash flows are determined by the independent reservoir engineering specialists and used in several of the estimates made by management in preparing these financial statements. Estimates are required to be made in the reserve report, including forecasted production, forecasted operating and royalty costs, capital cost assumptions, and in certain cases forecasted commodity prices;

•depletion, depreciation and accretion (“DD&A”);

•timing of transfers from oil and natural gas properties not subject to depletion to the depletable base;

•impairment of proved oil and natural gas properties as determined using the full cost method of accounting for Company’s oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10;

•asset retirement obligations; and

•fair value measurement associated with the acquired proved and unproved oil and natural gas properties in the business combination, including the discount rate determined by an independent valuator engaged in the Company.

Although management believes these estimates are reasonable, changes in facts and circumstances or discovery of new information may result in revised estimates, and actual results may differ from these estimates.

Some of the Company’s estimates and judgements have a material impact on consolidated financial statements but do not involve significant subjectivity of estimation uncertainty. These estimates and judgements include, but are not limited to:

•fair value of derivatives;

•income taxes;

•stock-based compensation;

•operating and finance leases;

•debt extinguishment and debt modification accounting;

•allocation of relative fair value on acquisition to proved and unproved properties;

•assessment of prepayment agreements; and

•assessment of the likely outcome of legal and other contingencies.

Cash and Cash Equivalents

The Company considers all highly liquid investments with an original maturity of three months or less to be cash equivalents.

Restricted Cash and Cash Equivalents

Restricted cash and cash equivalents are comprised of cash and cash equivalents pledged to secure letters of credit and to settle asset retirement obligations. Letters of credit currently secured by cash relate to work commitment guarantees contained in exploration contracts. Restrictions will lapse when work obligations are satisfied pursuant to the exploration contract or an asset retirement obligation is settled. Cash and claims to cash that are restricted as to withdrawal or use for other than current operations, or are designated for expenditure in the acquisition or construction of long-term assets are excluded from the current asset classification. The long-term portion of restricted cash and cash equivalents is included in other long-term assets on the Company’s balance sheet.

Allowance for Doubtful Accounts

At each reporting date, the Company assesses the expected lifetime credit losses on initial recognition of trade accounts receivable. Credit risk is assessed based on the number of days the receivable has been outstanding and the internal credit assessment of the customer. The expected loss rates are based on payment profiles over a period of 36 months prior to the period-end and the corresponding historical credit losses experienced within this period. Historical loss rates are adjusted to reflect current and forward-looking economic factors of the country where the Company sells oil, natural gas and NGL that affect the ability of the customers to settle the receivables. Trade receivables are written off when there is no reasonable expectation of recovery.

Derivatives

The Company records derivative instruments on its balance sheet at fair value as either an asset or liability with changes in fair value recognized in the consolidated statements of operations as financial instruments gains or losses. While the Company utilizes derivative instruments to manage the price risk attributable to its expected oil, natural gas and NGL production, electricity and foreign exchange risk, it has elected not to designate its derivative instruments as accounting hedges under the accounting guidance.

Inventory

Inventory consists of oil inventory held in tanks and third party pipelines and supplies, and is valued at the lower of cost and net realizable value. The cost of inventory is determined using the weighted average method. Oil inventory include expenditures incurred to produce, upgrade and transport the product to the storage facilities, tanks and third party pipelines and include operating, depletion and depreciation expenses, and royalties.

Income Taxes

Income taxes are recognized using the asset and liability method, whereby deferred tax assets and liabilities are recognized for the future tax consequences attributable to differences between the consolidated financial statements carrying amounts of existing assets and liabilities and their respective tax base, and operating loss and tax credit carryforwards. Deferred tax assets and liabilities are measured using enacted tax rates expected to apply to taxable income in the years in which those temporary differences and carryforwards are expected to be recovered or settled. Valuation allowances are provided if, after considering the available evidence, it is not more likely than not that some or all of the deferred tax assets will be realized.

The tax benefit from an uncertain tax position is recognized when it is more likely than not, based on the technical merits of the position, that the position will be sustained on examination by the taxing authorities. Additionally, the amount of the tax benefit recognized is the largest amount of benefit that has a greater than 50% likelihood of being realized upon ultimate settlement. In evaluating whether a tax position has met the more-likely-than-not recognition threshold, the Company presumes that the position will be examined by the appropriate tax authority that has full knowledge of all relevant information. The Company recognizes potential penalties and interest related to unrecognized tax benefits as a component of income tax expense.

Oil and Natural Gas Properties

The Company uses the full cost method of accounting for its investment in oil and natural gas properties as defined by the Securities and Exchange Commission (“SEC”). Under this method, the Company capitalizes all acquisition, exploration, and development costs incurred for the purpose of finding oil and natural gas reserves, including salaries, benefits, and other internal costs directly attributable to these activities. Costs associated with production and general corporate activities, are expensed as incurred. Separate cost centers are maintained for each country in which the Company incurs costs.

The Company computes depletion of oil and natural gas properties on a quarterly basis using the unit-of-production method based upon production and estimates of proved reserve quantities. Capital costs related to properties with proved oil and natural gas reserves are also included in the amortization base for the computation of depletion. The costs of unproved properties are excluded from the amortization base until the properties are evaluated. The cost of exploratory dry wells is transferred to proved properties and thus is subject to amortization immediately upon determination that a well is dry in those countries where proved reserves exist.

The Company performs a ceiling test calculation each quarter in accordance with SEC Regulation S-X Rule 4-10. In performing its quarterly ceiling test, the Company limits, on a country-by-country basis, the capitalized costs of proved oil and natural gas properties, net of accumulated depletion and deferred income taxes, to the estimated future net cash flows from proved oil and natural gas reserves discounted at 10%, net of related tax effects, plus the lower of cost or fair value of unproved properties included in the costs being amortized. If such capitalized costs exceed the ceiling, the Company will record a write-down to the extent of such excess as a non-cash charge to net income or loss. Any such write-down will reduce earnings in the period of occurrence and result in a lower DD&A rate in future periods. A write-down may not be reversed in future periods, even though higher oil and natural gas prices may subsequently increase the ceiling.

The Company calculates future net cash flows by applying the unweighted average of prices in effect on the first-day-of-the month for the preceding 12-month period, adjusted for location and quality differentials. Such prices are utilized except where different prices are fixed and determinable from applicable contracts for the remaining term of those contracts.

Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the depletable base on an ongoing basis as the properties are evaluated, proved reserves are established, or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. This evaluation considers, among other factors, seismic data, plans or requirements to relinquish acreage, drilling results, and activity, remaining time in the commitment period, remaining capital plans, and political, economic, and market conditions. During any period in which factors indicate impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and subject to depletion. For countries where a reserve base has not yet been established, the impairment is charged to net income or loss.

In exploration areas, related seismic costs are capitalized in unproved property and evaluated as part of the total capitalized costs associated with a property. Seismic costs related to development projects are recorded in proved properties and therefore subject to depletion as incurred.

Gains and losses on the sale or other disposition of oil and natural gas properties are not recognized, unless the gain or loss would significantly alter the relationship between capitalized costs and proved oil and natural gas reserves attributable to a country.

Asset Retirement Obligation

The Company records an estimated liability for future costs associated with the abandonment of its oil and natural gas properties, including the costs of reclamation of drilling sites. The Company records the fair value of a liability for a legal obligation to retire an asset in the period in which the liability is incurred with an offsetting increase to the related oil and natural gas properties. The fair value of an asset retirement obligation is measured by reference to the expected future cash outflows required to satisfy the retirement obligation discounted at the Company’s country specific credit-adjusted risk-free interest rate. Accretion expense is recognized over time as the discounted liabilities are accreted to their expected settlement value, while the asset retirement cost is amortized over the estimated productive life of the related assets. The accretion of the asset retirement obligation and amortization of the asset retirement cost is included in DD&A. If estimated future costs of an asset retirement obligation change, an adjustment is recorded to both the asset retirement obligation and oil and natural gas properties. Revisions to the estimated asset retirement obligation can result from changes in retirement cost estimates, revisions to estimated inflation rates, and changes in the estimated timing of abandonment.

Other Capital Assets

Other capital assets, including additions and replacements, are recorded at cost upon acquisition and include furniture, fixtures, leasehold improvement, computer equipment, automobiles and right-of-use assets for operating and finance leases.

Depreciation for furniture and fixtures, computer equipment, and automobiles is provided using the straight-line method over the useful life of the asset. Leasehold improvements and right-of-use assets for operating and finance leases are depreciated on a straight-line basis over the shorter of the estimated useful life and the term of the related lease. The cost of repairs and maintenance is charged to expenses as incurred.

Leases

At the inception of a contract, the Company assesses whether a contract is, or contains, a lease. A contract is, or contains, a lease if the contract conveys the right to control the use of an identified asset for a period of time in exchange for consideration. At the inception of a contract that contains a lease component, the Company allocates the consideration in the contract to each lease and non-lease component on the basis of their relative stand-alone prices. The Company recognizes a right-of-use asset and a lease liability at the lease commencement date. The right-of-use asset is initially measured at cost and subsequently at cost less any accumulated depreciation and impairment losses and adjusted for certain remeasurements of the lease liability.

The lease liability is initially measured at the present value of the lease payments that are not paid at the commencement date, discounted using the interest rate implicit in the lease, or, if that rate cannot be readily determined, the Company’s incremental borrowing rate. Generally, the Company uses its incremental borrowing rate as the discount rate. The lease liability is subsequently increased by the interest cost on the lease liability and decreased by lease payments made. It is remeasured when there is a change in future lease payments arising from a change in an index or rate, a change in the estimate of the amount expected to be payable under a residual value guarantee, or as appropriate, changes in the assessment of whether a purchase or extension option is reasonably certain to be exercised or a termination option is reasonably certain not to be exercised.

The Company has applied judgment to determine the lease term for contracts which include renewal or termination options. The assessment of whether the Company is reasonably certain to exercise such options impacts the lease term, which significantly affects the amount of lease liabilities and right-of-use assets recognized.

Debt extinguishment and debt modification accounting

The Company accounts for debt restructuring or exchange of debt transactions as either a debt extinguishment or a debt modification. For instruments not involving conversion options, the Company recognizes an exchange of debt as an extinguishment if the present value of the cash flows under the terms of the new debt instrument is at least 10 percent different from the present value of the remaining cash flows under the terms of the original instrument. If the exchange of debt is accounted for as a debt extinguishment, the carrying value of the original debt including unamortized deferred financing fees is derecognized from our balance sheet and the new debt is recognized at its fair value less applicable deferred financing fees, with the difference between the net carrying value of the original debt and the fair value of the new debt recognized as a gain or loss in the consolidated statements of operations. If the terms of a debt instrument are changed or modified and the cash flow effect on a present value basis is less than 10 percent, the debt instrument is not considered to be substantially different, the Company accounts for this debt instrument as debt modification. If the exchange of debt is accounted for as a debt modification, the change of the carrying amount of the original debt on the balance sheet is adjusted to the net present value of the revised cash flows with the adjustments treated as a capital cost and amortized as an adjustment of interest expense on our statement of operations.

Revenue from Contracts with Customers

The Company recognizes revenue when it transfers control of the product to a customer. This generally occurs at the time the customer obtains legal title to the product and when it is physically transferred to the delivery point agreed with the customer. Revenue is recognized based on the consideration specified in contracts with customers. Revenue represents the Company's share and is recorded net of royalty payments to governments and other mineral interest owners.

The Company evaluates its arrangements with third parties and partners to determine if the Company acts as a principal or an agent. In making this evaluation, management considers if the Company obtains control of the product delivered, which is indicated by the Company having the primary responsibility for the delivery of the product, having the ability to establish prices, or having inventory risk. If the Company acts in the capacity of an agent rather than as a principal in the transaction, then the revenue is recognized on a net basis, only reflecting the fee realized by the Company from the transaction.

Tariffs, tolls, and fees charged to other entities for the use of pipelines owned by the Company are evaluated by management to determine if these originate from contracts with customers or from incidental arrangements. When determining if the Company acted as a principal or an agent in transactions, management determines if the Company obtains control of the product. As part of this assessment, management considers the criteria for revenue recognition set out in Accounting Standard Codification 606 (“ASC 606”).

Advance payments from customers for the future delivery of crude oil under prepayment arrangements are recognized as contract liabilities and accounted for under ASC 606 when relevant criteria are met. Such arrangements are evaluated for the existence of a significant financing component for which interest expense is measured using a discount rate reflective of the Company’s credit standing. As oil is delivered to the customer, an adjustment is made to the contract liability to adjust the transaction price based on the relevant discount rate.

Stock-based Compensation

The Company records stock-based compensation expense in its consolidated financial statements measured at fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes-Merton or Monte Carlo simulation stock option-pricing models and/or observable share prices. For equity-settled stock-based compensation awards, fair values are determined at the grant date, and the expense, net of estimated forfeitures, is recognized using the accelerated method over the requisite service period. An adjustment is made to compensation expense for any difference between the estimated forfeitures and the actual forfeitures. For cash-settled stock-based compensation awards (performance share units, restricted share units and stock options), the expense is recognized over thethree-year vesting period based on the latest available estimate of the fair value of the awards at each reporting date, and periodic changes are recognized as compensation costs, with a corresponding change to liabilities. The deferred share units are vested immediately and revalued each reporting period based on the latest available estimate of the fair value of the award.

The Company uses historical data to estimate the expected term used in the Black-Scholes-Merton option pricing model, option exercises, and employee departure behavior. Expected volatilities used in the fair value estimate are based on the historical volatility of the Company’s shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant.

Stock-based compensation expense is capitalized as part of oil and natural gas properties or expensed as part of G&A or operating expenses, as appropriate.

Foreign Currency Translation

The functional currency of the Company, including its subsidiaries, other than its Canadian subsidiary, is the U.S. dollar. The functional currency of the Canadian subsidiary is the Canadian dollar. Monetary assets and liabilities are translated into the functional currency at the exchange rate in effect at the balance sheet date, and non-monetary items are translated at historical exchange rates. Revenue and expense items are translated in a manner that produces substantially the same reporting currency amounts that would have resulted had the underlying transactions been translated on the dates they occurred.

DD&A expense on assets is translated at the historical exchange rates similar to the assets to which they relate. Gains and losses resulting from foreign currency transactions, which are transactions denominated in a currency other than the entity’s functional currency, are recognized in net income or loss.

The Company’s reporting currency is the U.S. dollar. The assets and liabilities of the Canadian subsidiary are translated to the Company’s reporting currency using the exchange rates at the end of the reporting period. Revenue and expense items are translated at the weighted average exchange rates for the reporting period and shareholders’ equity is translated at historical exchange rates. Foreign exchange gains and loss resulting from translation to reporting currency are recognized in other comprehensive income or loss.

Net Income or Loss per Share

Basic net income or loss per share is calculated by dividing net income or loss attributable to common shareholders by the weighted average number of shares of Common Stock issued and outstanding during each period. Diluted net income or loss per share is calculated by adjusting the weighted average number of shares of Common Stock outstanding for the dilutive effect, if any, of share equivalents. The Company uses the treasury stock method to determine the dilutive effect. This method assumes that all Common Stock equivalents have been exercised at the beginning of the period (or at the time of issuance, if later), and that the funds obtained thereby were used to purchase shares of Common Stock of the Company at the volume-weighted average trading price of shares of Common Stock during the period.

Segment Reporting

The Company’s operations are organized based on the geographical location of each operation. Chief Operational Decision Makers (“CODM”) allocate the Company’s resources and evaluate operation results and profitability using geographical location of each operation. Based on the review of CODM, the Company identified three reportable segments: Colombia, Ecuador and Canada (Note 4).

Business Combinations

Business combinations are accounted for using the acquisition method. Assets acquired and liabilities assumed in a business combination are recognized at their fair values. Any excess of the consideration paid over the fair value of the net assets acquired and liabilities assumed is recognized as a goodwill and any excess of the fair value of the net assets acquired and liabilities assumed over the consideration paid is recognized as bargain purchase gain in the consolidated statements of operations.

Risks and Measurement Uncertainty

The impacts of ongoing conflicts in several parts of the world coupled with volatility in energy markets, increased interest and inflation rates and constrained supply chains have created a higher level of volatility and uncertainty. Management has, to the reasonable extent, incorporated known facts and circumstances into the estimates made; however, the increased levels of uncertainty and volatility make accounting estimates more judgmental, and the actual results could differ materially from estimates.

Recently Adopted Accounting Pronouncements

In December 2023, FASB issued ASU 2023-09, “Improvements to Income Tax Disclosures”. ASU 2023-09 enhances the income tax disclosures to enable investors to better understand entity’s exposure to potential changes in jurisdictional tax legislation and associated risks and opportunities, income tax information that effects cash flow forecasts and potential opportunities to increase future cash flows. This ASU is effective for annual reporting periods beginning after December 15, 2024 and should be applied prospectively, with retrospective application permitted. The Company adopted ASU 2023-09 effective January 1, 2025 on a retrospective basis. The adoption of this guidance did not have a material impact on the Company’s financial position or results of operations. Refer to Note 16 for additional information and the effects of the new guidance.

Recently Issued Accounting Pronouncements

In November 2024 and January 2025, FASB issued ASU 2024-03 and ASU 2025-01 “Income Statement - Reporting Comprehensive Income - Expense Disaggregation Disclosures”. The amendments in ASU 2024-03 require disclosure, in the notes to financial statements, of specified information about certain costs and expenses, such as purchases of inventory, employee compensation, depreciation, intangible asset amortization, depreciation, depletion, and amortization recognized as part of oil-and natural gas-producing activities included in each relevant expense caption on the face of statement of operations. In addition, this ASU requires the presentation of specific expense captions of comprehensive income on the face of the statements of comprehensive income. ASU 2025-01 clarifies the effective date of ASU 2024-03 to be effective for annual reporting periods beginning after December 15, 2026, and interim reporting periods within annual periods beginning after December 15, 2027. The Company is currently assessing the impact of this update will have on its financial statements disclosures.

In July 2025, FASB issued ASU 2025-05 “Financial Instruments—Credit Losses: Amendments to the Measurement of Credit Losses on Certain Financial Assets”. This ASU provides a practical expedient for estimating expected credit losses on certain short-term receivables and contract assets arising from revenue transactions within the scope of ASC 606. Under the practical expedient, all entities may elect to assume that current conditions as of the balance sheet date would not change for the remaining life of the asset when developing reasonable and supportable forecasts. The ASU will be effective for fiscal years, and interim periods within those years, beginning after December 15, 2025, early adoption is permitted for both interim and annual reporting periods. The Company will adopt this ASU effective since January 1, 2026. The implementation of this update is expected to have no material impact on its balance sheet, statement of operations or financial statements disclosures.

3. Business Combination

On October 31, 2024, the Company acquired all of the issued and outstanding common shares of i3 Energy Plc (“i3 Energy”), subsequently renamed as Gran Tierra UK Limited (“Gran Tierra UK”) for $204.5 million, consisting of cash consideration of $161.8 million, cash dividend of $4.0 million, cash settlement of stock options of $2.0 million and 5,808,925 shares of the Company’s Common Stock, the fair value of which was determined to be $36.7 million based on the closing price of the Company’s shares on the acquisition date. The acquisition was accounted for as a business combination using the acquisition method with Gran Tierra being the acquirer, whereby the assets acquired and liabilities assumed were recognized at their fair values as at the i3 Energy acquisition date, and the results of i3 Energy were included with those of Gran Tierra from that date. Fair value estimates were made based on significant unobservable (Level 3) inputs and based on the best information available at the time.

Determining the fair values of the assets and liabilities of i3 Energy and the consideration paid required significant judgment and certain assumptions to be made. The most significant fair value estimates related to the valuation of i3 Energy's proved and unproved oil and natural gas properties. The fair value of proved oil and natural gas properties acquired was based on cash flows associated with estimated acquired proved oil and natural gas reserves and the discount rate. Factors that impact these reserves cash flows include forecasted production, forecasted commodity prices, forecasted operating, royalty and capital costs The following table shows the allocation of the consideration paid based on the fair values of the assets and liabilities acquired.

The most significant fair value estimates related to the valuation of i3 Energy’s proved and unproved oil and natural gas properties. The measurement period for adjustments expired on October 31, 2025. No measurement adjustments were made.

The Company’s consolidated statement of operations for the year ended December 31, 2024, included revenue of $19 million and net loss of $5.1 million from Gran Tierra UK (former i3 Energy).

4. Segment Reporting

The Company is primarily engaged in the exploration and production of oil, natural gas and NGL. The Company reports segmented information based on internal management reporting used by CODM, which are the Company’s Chief Executive Officer, Chief Financial Officer, Chief Operating Officer, Executive Vice Presidents and Vice Presidents across various business functions. CODM allocates resources and assesses performance of each reportable segment based on segmented earnings. The Company determined three reportable segments based on the geographic organization: Colombia, Ecuador and Canada. The "Other" category represents the Company’s corporate activities.

The following tables present information on the Company’s reportable segments and other activities for the years ended December 31, 2025, 2024 and 2023:

5. Taxes Receivable and Payable

The table below shows the break-down of taxes receivable and payable, which are comprised of value added tax (“VAT”) and income tax receivables and payables:

The following table shows the movement of VAT and income tax receivables and payables for the past two years:

(1)VAT is paid on certain goods and services and collected on sales in Colombia at a rate of 19%.

6. Accounts Receivable

7. Inventory

8. Property, Plant and Equipment

(1)The “Other” category includes $65.0 million right-of-use assets for finance leases and operating leases, which had a net book value of $30.8 million as at December 31, 2025 (December 31, 2024 - $70.1 million, which had a net book value of $35.1 million).

During the year ended December 31, 2025, the Company entered into three new finance lease contracts related to power generation equipment andone new operating lease related to motor vehicle and capitalized $20.1 million and $0.1 million of right-of-use assets related to these contracts.

The Company also derecognized finance leases related to power generation and polymer injection equipment following an early termination by reducing net book value of right-of-use asset of $10.5 million and lease liability of $11.2 million.

Depletion and depreciation expense on property, plant and equipment for the year ended December 31, 2025, was $267.9 million (2024 - $223.1 million; 2023 - $209.7 million). A portion of depletion and depreciation expense was recorded as oil inventory in each year.

Acquisitions and Dispositions

On December 9, 2025, the Company completed the acquisition of 100% working interest (“WI”) of the Perico and Espejo Blocks in the Oriente Basin in Ecuador and their associated Consortiums through its indirect wholly owned subsidiaries. Substantially all of the fair value of the gross assets acquired was concentrated in a single identifiable asset therefore, the acquisition was not considered a business combination and was accounted for as an asset acquisition. The purchase price for the acquisition is comprised of cash consideration of $8.3 million, deferred payment of $3.1 million and $1.1 million of contingent consideration payable upon achieving 2.0 million barrels of cumulative crude oil production from the Perico Block. The deferred payment bears an interest rate of secured overnight finance rate (“SOFR”) plus 3% per annum and is payable at the earlier of the approval of the amended Consortium agreement by Hydrocarbons Committee or December 8, 2026.

The cost of assets was allocated to proved and unproved properties using relative fair values.

On September 8, 2025, the Company, through its wholly owned subsidiary, Gran Tierra UK Limited, a United Kingdom limited company, completed the sale of its wholly owned subsidiary, Gran Tierra North Sea Limited (“GTNSL”) for total consideration of $7.5 million. The disposition of GTNSL did not result in any gain or loss.

On December 17, 2024, the Company entered into agreement for the strategic disposal of 50% working interest (“WI”) in the Simonette Montney Block with an effective date of September 1, 2024 for cash consideration of C$60.2 million (US$43.1 million) which included the purchase price of C$52.0 million (US$37.2 million) and C$8.2 million (US$5.9 million) economic adjustment related to previously drilled wells. No gain has been recognized in the statement of operations because the disposal did not significantly alter the relationship between capital costs and proved reserves of oil and natural gas assets disposed.

Unproved Oil and Natural Gas Properties

At December 31, 2025, unproved oil and natural gas properties consisted of exploration lands held in Colombia and Ecuador and undeveloped lands in Canada. Unproved oil and natural gas properties are not being depleted pending determination of the existence of proved reserves. Gran Tierra will continue to assess the unproved properties over the next several years as proved reserves are established and whether or not future areas will be developed. The Company expects that approximately 100% of costs not subject to depletion at December 31, 2025, will be transferred to the depletable base within the next five years.

The following is a summary of Gran Tierra’s oil and natural gas properties not subject to depletion as at December 31, 2025:

9. Asset impairment

Asset impairment for the year ended December 31, 2025 and 2024, was as follows:

For the year ended December 31, 2025, the Company recorded ceiling test impairment losses of $136.3 million in Canada and Colombia as a result of lower oil and natural gas prices and revised development plans primarily related to natural gas properties in Canada and reduction of capital investment in Colombia. The Company follows the full cost method of accounting for its oil and gas properties. Under this method, the net book value of properties on a country-by-country basis, less related deferred income taxes, may not exceed a calculated “ceiling”. The ceiling is the estimated after-tax future net revenues from proved oil and gas properties, discounted at 10% per year. In calculating discounted future net revenues, oil and natural gas prices are determined using the average price for the 12-month period prior to the ending date of the period covered by the balance sheet, calculated using unweighted arithmetic average of the first-day-of-the-month price for each month within such period. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. Therefore, ceiling test estimates are based on historical prices discounted at 10% per year and it should not be assumed that estimates of future net revenues represent the fair market value of the Company's reserves. In accordance with GAAP, the Company used the unweighted arithmetic average of the first-day-of-the-month prices as follows: Brent price of$69.38 per boe, Edmonton Light price of $63.21 (C$86.73) per boe, Alberta AECO spot price of $1.42 (C$1.95) per MMBtu, Edmonton Propane price of $24.05 (C$32.99) per boe, Edmonton Butane price of $27.64 (C$37.92) per boe and Edmonton Condensate price of $65.38 (C$89.70) per boe for the December 31, 2025 ceiling test calculations (December 31, 2024 - Brent price of $80.42 per boe, Edmonton Light price of $68.11 (C$98.01) per boe, Alberta AECO spot price of $1.01 (C$1.46) per MMBtu, Edmonton Propane price of $21.17 (C$30.46) per boe, Edmonton Butane price of $33.63 (C$48.39) and Edmonton Condensate price of $70.07 (C$100.83) per boe; and December 31, 2023 - Brent price of $82.51 per bbl).

The Company has considered the impact of the evolving worldwide demand for energy and global advancement of alternative sources of energy that are not sourced from fossil fuels in the impairment assessment on oil and natural gas properties. The estimated ceiling amount of the Company’s oil and natural gas properties was based on proved oil and natural gas reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved oil and natural gas reserves per the 2025 reserve report is expected to be realized prior to the potential elimination of carbon-based energy.

At December 31, 2025, a specific adjustment to the discount rate used in the ceiling test to account for the risk of the evolving demand for energy is not permitted as under the full cost accounting the 10% discount rate is prescribed.

10. Accounts Payable and Accrued Liabilities

11. Debt and Debt Issuance Costs

The Company’s debt at December 31, 2025 and 2024, was as follows:

(1)Includes$1.8 million of deferred financing fees related to Canadian and Colombian credit facilities as at December 31, 2025 (December 31, 2024 -nil).

(2) The current portion of the lease obligation has been included inaccounts payable and accrued liabilities on the Company’s balance sheet

and totaled $17.0 million as at December 31, 2025 (December 31, 2024 - $15.3 million).

At December 31, 2025, the Company had $24.2 million of 7.75% Senior Notes due 2027 (the “7.75% Senior Notes”), and $716.3 million of 9.50% Senior Notes due 2029 (the “9.50% Senior Notes”).

The 7.75% Senior Notes bear interest at a rate of 7.75% per annum, payable semi-annually in arrears on May 23 and November 23 of each year, beginning on November 23, 2019. The 7.75% Senior Notes will mature on May 23, 2027, unless earlier redeemed or re-purchased.

The Company may redeem all or a portion of the 7.75% Senior Notes plus accrued and unpaid interest applicable to the date of the redemption.

The 9.50% Senior Notes bear interest at a rate of 9.50% per year, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% Senior Notes will mature on October 15, 2029, unless earlier redeemed or re-purchased.

The principal amount of 9.50% Senior Notes is to be repaid as follows: (i) October 15, 2026,25% of the principal amount; (ii) October 15, 2027,5% of the principal amount; (iii) October 15, 2028,30% of the principal amount; and (iv) October 15, 2029, the remainder of the principal amount.

At any time, prior to October 15, 2026, the Company may redeem 35% of the aggregate principal amount of 9.50% Senior Notes at a redemption price equal to 109.50% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.50% Senior Notes:

(i) prior to October 15, 2026, at a redemption price equal to a 100% principal amount plus an applicable premium, which is the greater of:

•1% of the principal amount of 9.50% Senior Notes, and

•the excess of the present value of the redemption price plus all required interest payments computed using a discount rate equal to the Treasury rate at the redemption date plus 0.5% due to date, excluding accrued but unpaid interest, over the outstanding principal amount of 9.50% Senior Notes.

(ii) On or after October 15, 2026, at the following redemption prices: 2026 -104.750%; 2027 -102.375%; 2028 and thereafter -100%.

If the Company undergoes a change of control, holders may require the Company to repurchase for cash all or any portion of their 9.50% Senior Notes at a change of control repurchase price equal to 101% of the principal amount plus accrued and unpaid interest to, but excluding, the change of control repurchase date.

During the year ended December 31, 2025, the Company paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 15, 2025 for cash consideration of $25.6 million million, including interest payable of $0.8 million.

During the year ended December 31, 2025, the Company purchased in the open market $21.3 million of outstanding 9.50% Senior Notes for cash consideration of $17.2 million, including interest payable of $0.2 million. The purchase resulted in a $2.9 million gain on purchase, which included the write-off of deferred financing fees of $1.4 million. The re-purchase of 9.50% Senior Notes were not cancelled and held by the Company as treasury bonds as at December 31, 2025.

At December 31, 2025, $179.1 million of principal owing on the 9.50% Senior Notes ($173.4 million net of unamortized discount and issuance costs) was contractually due within twelve months of the balance sheet date; however, the Company had both the intent and the ability to refinance the obligation on a long-term basis (see Note 20). As a result, $157.2 million principal owing of 9.50% Senior Notes ($152.1 million net of unamortized discount and issuance costs) has been classified as long-term debt at December 31, 2025, representing the portion of 9.50% Senior Notes exchanged for 9.75% Senior Notes.

Under the terms of the 9.50% Senior Notes agreement, the Company is required to maintain compliance with the following financial covenants:

i. consolidated interest coverage ratio of not less than 2.5; and

ii. consolidated net debt (total debt excluding deferred financing fees debt less cash equivalents) to consolidated adjusted earnings before interest, taxes and DD&A (“EBITDA”) of not more than 3.0.

As at December 31, 2025, the Company was in compliance with all applicable covenants on Senior Notes.

Credit Facility - Canada

As at December 31, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Canada Ltd., had a revolving credit facility with National Bank of Canada dated March 22, 2024 with a borrowing base of C$100.0 million (US$72.9 million) and the available commitment of a C$75.0 million (US$54.7 million) revolving credit facility comprised of a C$60.0 million (US$43.7 million) syndicated facility and a C$15.0 million (US$10.9 million) operating facility. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd. The maturity date of the facility is October 30, 2027.

During 2025, the Company drew C$37.2 million (US$26.1 million) under the revolving credit facility, and C$82.5 million (US$58.8 million) under the operating credit facility, both of which were fully repaid, and as at December 31, 2025, the revolving and operating credit facility remain undrawn.

Credit Facility - Colombia

On April 16, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a $75.0 million reserve-based lending facility (the “RBL Facility”). Any loans incurred under the reserve-based lending facility will mature on April 16, 2028. The availability of borrowings under the RBL Facility is subject to an annual borrowing base determination which will occur on or before May 1 of each year. The RBL Facility will bear interest at a rate per annum equal to, at Company’s option, either (a) a customary base rate (subject to a floor of 1.00%) plus an applicable margin of 4.50% or (b) a term secured overnight finance rate (“SOFR”) reference rate plus an applicable margin of 4.50%. Interest on base rate borrowings is payable quarterly in arrears and interest on term SOFR borrowings accrues in respect of interest periods of three or six months, at the election of the Company, and is payable on the last day of such interest period. The facility also includes a commitment fee of 1.58% per annum on undrawn amounts. On October 23, 2025, the existing RBL facility was amended (“the Amended RBL Facility”) to reduce the borrowing base to $60.0 million and revised certain related terms, including provisions governing borrowings, hedging obligations, and borrowing base redetermination.

Under the terms of the RBL Facility, the Company is required to maintain compliance with the following financial covenants:

i. consolidated net debt to consolidated adjusted EBITDA ratio that may not exceed 3.00 to 1.00, and

ii. consolidated interest coverage ratio that may not be less than 2.50 to 1.00

The Company was in compliance with all applicable covenants related to the RBL facility as of December 31, 2025.

During 2025, the Company drew $34.5 million under the RBL facility, which was fully repaid, and as of December 31, 2025 the RBL facility remained undrawn. Subsequent to December 31, 2025, the RBL facility was terminated by the Company. There were no material early termination penalties incurred, and upon full repayment and satisfaction of the Credit Agreement, the related guarantee and security interests securing its obligations were extinguished and terminated.

Leases

During the year ended December 31, 2025, the Company recordedone new operating lease related to a motor vehicle of $0.1 million andthree new finance leases related to power generation equipment of $20.1 million. The operating lease has a term ofthree years and a discount rate of 10.92%. The finance leases have lease terms ofone year and a weighted average discount rate of 9.60%.

During the year ended December 31, 2024, the Company recorded seven new operating leases related to office leases in Canada and Ecuador, motor vehicles and field equipment totaling $4.9 million andsix new finance leases for power generation and safety equipment totaling $8.1 million. The operating leases have lease terms ranging fromone tofive years and weighted average discount rate of 6.69%. The finance leases have lease terms ranging fromone totwo years and weighted average discount rate of 9.60%.

As of December 31, 2025, the Company’s finance leases had remaining useful lives slightly overone year and the weighted average discount rate of 9.60% and operating leases had remaining useful lives ranging fromone tothree years and the weighted average discount rate of 7.54%.

Interest Expense

The following table presents the total interest expense recognized in the accompanying consolidated statements of operations:

The Company incurred debt issuance costs in connection with the issuance of the 9.50% Senior Notes and its Canadian and Colombian credit facilities. As at December 31, 2025, the balance of unamortized debt issuance costs has been presented as a direct deduction against the carrying amount of debt and is being amortized to interest expense using the effective interest method over the term of the debt.

12. Prepayment agreements

In the fourth quarter of 2025, Gran Tierra executed a prepayment agreement with Trafigura, the Company’s purchaser of crude oil. The prepayment agreement requires Gran Tierra to sell and deliver all production from the Company’s assets in Ecuador for 48 months starting on October 1, 2025 and expiring on September 30, 2029.

The prepayment agreement provides for an advance payment facility of $150 million against future revenues, which was advanced in the fourth quarter of 2025, of this, $34.1 million was recorded as a current liability within accounts payable (Note 10). Amounts drawn on this prepayment agreement are to be repaid through future oil deliveries. Shortfalls in crude oil deliveries in any given repayment period can be delivered during the next repayment period within three calendar months or paid in cash thereafter. The interest cost is based on a SOFR risk-free rate plus a margin of 3.75% per annum. Under the terms of the prepayment agreement, the Company can repay the outstanding balance of the advance payment at any time without penalty. The Company was granted asix-month grace period for repayment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.

The Company is required to maintain compliance with the following financial covenants related to amounts drawn under the prepayment agreement semi-annually, calculated on March 31 and September 30 of each year:

i. Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of the Company up to the final maturity date discounted at 10% over the outstanding principal and the interest payable amount on the prepayment agreement at each reporting period. The net present value of the consolidated future cash flows of the Company is required to be based on 80% of the prevailing ICE Brent forward strip.

ii. Debt Service Coverage Ratio of at least 200%, calculated using the estimated crude oil to be delivered by the Company from any relevant time up to the final maturity date based on 80% of the prevailing ICE Brent forward strip and adjusted for quality differential and transportation discount over the outstanding principal amount under the prepayment agreement.

13. Share Capital

(1)28,612 treasury stock shares held in 2023 were canceled during the year ended December 31, 2024

(2)487,948 treasury stock shares held in 2024 were canceled during the year ended December 31, 2025.

The Company’s authorized share capital consists of 82 million shares of capital stock, of which 57 million was designated as Common Stock, par value $0.001 per share and 25 million as Preferred Stock, par value $0.001 per share.

On May 5, 2023, the Company completed a 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock, without any change to the par value per share. All share and per share numbers have been adjusted to reflect the reverse stock split. The Company’s outstanding options were also proportionately adjusted as a result of the reverse stock split to increase the exercise price and reduce the number of shares issuable upon exercise.

Share Re-purchase Program

During the year ended December 31, 2025, the Company implemented a share re-purchase program (the “2025 Program”) through the facilities of the Toronto Stock Exchange, the NYSE American or alternative trading programs in Canada or the United States, if eligible. Under the 2025 Program, the Company is able to purchase up to 2,925,720 shares of Common Stock, representing 10% of the public float as of October 31, 2025, at prevailing market prices at the time of purchase. The 2025 Program will continue for one year and expire on November 5, 2026, or earlier if the 10% maximum is reached.

During the year ended December 31, 2025, the Company re-purchased 692,804 shares of Common Stock at a weighted average price of $5.00 per share under the 2024 Program implemented in 2024 with similar terms to that of the 2025 Program. The 2024 Program expired on November 5, 2025. As of December 31, 2025, all shares re-purchased under the 2024 Program were cancelled subsequent to re-purchase.

Equity Compensation Awards

The Company has an equity compensation program for its executives, employees, and directors. Executives and employees are given equity compensation grants that vest based on a recipient’s continued employment. In the case of Performance Share Units (“PSUs”), the number of units that vest is dependent upon the achievement of specific key performance measures. Equity based awards consist of 80% of PSUs and 20% of restricted share units (“RSUs”). The Company’s stock-based compensation awards outstanding as at December 31, 2025, include PSUs, RSUs, stock options and deferred share units (“DSUs”) issued to directors.

In accordance with the 2007 Equity Incentive Plan, as amended, the Company’s Board of Directors is authorized to issue options or other rights to acquire shares of the Company’s Common Stock. On June 27, 2012, the shareholdersof Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 2,330,610 shares to 3,980,610 shares. On June 2, 2021, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 3,980,610 shares to 5,480,610 shares. On May 4, 2022, the shareholders of Gran Tierra approved an amendment to the Company’s 2007 Equity Incentive Plan, which increased the Common Stock available for issuance thereunder from 5,480,610 shares to 5,980,610 shares.

The following table provides information about PSU, DSU, RSU and stock option activity for the year ended December 31, 2025:

On May 1, 2024, the Company amended the settlement terms of all outstanding stock option awards. As of this date, all outstanding stock options are to be net settled in cash resulting in a change in classification of stock options from equity to liability. On May 1, 2024, the Company recorded a liability of $4.4 million and an additional stock-based compensation costs of $0.4 million related to the modification of the stock option plan. As at December 31, 2025, the equity compensation award liability on the Company’s balance sheet included $0.6 million of current liability related to the Company’s outstanding stock options.

The fair value of each stock option award was estimated on the modification date using the Black-Scholes-Merton option-pricing model based on the assumptions noted in the following table:

For the year ended December 31, 2025, stock-based compensation expense was $3.2 million (2024 - $9.7 million; 2023 - $5.7 million) and was recorded in G&A expenses.

At December 31, 2025, there was $15.4 million(December 31, 2024 - $21.9 million) of unrecognized compensation cost related to unvested PSUs, RSUs and stock options to be recognized over a weighted average period of 1.6 years. The weighted average remaining contractual term of options vested, or expected to vest, at December 31, 2025, is 1.6 years.

PSUs

PSUs entitle the holder to receive, at the option of the Company, either the underlying number of shares of the Company’s Common Stock upon vesting of such units or a cash payment equal to the value of the underlying shares. PSUs will cliff vest after three years, subject to the grantee’s continued employment. Upon vesting, the underlying number of Common Shares or the cash payment equivalent to their value may range fromnil to 200% of the number of PSU’s vested, based on the Company’s performance with respect to the applicable performance targets. As at December 31, 2025,1.6 million (December 31, 2024 -1.1 million) of PSUs had vested and will settle in cash. The performance targets for the PSUs outstanding as at December 31, 2025, were as follows:

i.50% of the award is subject to targets relating to the total shareholder return (“TSR”) of the Company against a group of peer companies;

ii.25% of the award is made up of the following financial targets:

•In 2023, the compliance with financial covenants and $20.0 million free cash flow

•In 2024, the compliance with financial covenants

•In 2025, the compliance with $20.0 million cash flow; and

iii.25% of the award is subject to targets relating to the execution of corporate strategy.

The compensation cost of PSUs is subject to adjustment based upon the attainability of these performance targets. No settlement will occur with respect to the portion of the PSU award subject to each performance target for results below the applicable minimum threshold for that target. In excess of the target number granted, PSUs will vest and be settled if performance exceeds the targeted performance goals. The Company currently intends to settle the PSUs in cash.

DSUs

DSUs entitle the holder to receive either the underlying number of shares of the Company’s Common Stock upon vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. Once a DSU is vested, it is immediately settled. During the year ended December 31, 2025, DSUs were granted to directors and will be settled at such time the grantee ceases to be a member of the Board of Directors. The Company currently intends to settle the DSUs in cash.

RSUs

RSUs entitle the holder to receive either the underlying number of shares of the Company’s Common Stock upon vesting of such units or, at the option of the Company, a cash payment equal to the value of the underlying shares. Under the 2007 Equity Incentive Plan, RSUs will vest one-third each year over athree-year period.

Stock Options

Each stock option permits the holder to purchaseone share of Common Stock at the stated exercise price. The exercise price equals the market price of a share of Common Stock at the time of grant and vest over three years. The term of the stock options granted isfive years orthree months after the grantee’s end of service to the Company, whichever occurs first.

For the year ended December 31, 2025,19,385 stock options were exercised, and$0.1 million cash proceeds were received (2024 -66,825 stock options were exercised, and$0.4 million cash proceeds were received and 2023 -1,839 stock options were exercised, and $8.0 thousand cash proceeds were received).

At December 31, 2025 and 2024, the weighted average remaining contractual term for outstanding stock options was 1.2 and 1.6 years, respectively, and forexercisable stock options was 1.1 and 1.2 years, respectively.

The fair value of each stock option award is estimated on the date of grant using the Black-Scholes Merton option-pricing model based on assumptions noted in the following table:

There wereno stock options granted during the year ended December 31, 2025. The weighted average grant date fair value for options granted in the year ended December 31, 2024 was $4.29 (2023 - $5.57) per option. The weighted average grant date fair value for options vested in the year ended December 31, 2025 was$0.86 (2024 - $2.02; 2023 - $4.77) per option. The total fair value of stock options vested during the year ended December 31, 2025 was$0.2 million (2024 - $0.8 million; 2023 - $2.3 million).

Weighted Average Shares Outstanding

For the year ended December 31, 2025 the weighted average number of common shares outstanding was 35,435,782 (2024 -32,042,897, 2023 -33,469,828) and all options were excluded from the diluted (loss) earnings per share calculation as the options were anti-dilutive(2024 - all; 2023 -1,825,299).

14. Asset Retirement Obligation

Changes in the carrying amounts of the asset retirement obligation associated with the Company’s oil and natural gas properties were as follows:

(1) Current portion of asset retirement obligation is included in accounts payable and accrued liabilities on the Company’s balance sheet (refer to Note 10).

Revisions in estimated liabilities relate primarily to changes in estimates of asset retirement costs and include, but are not limited to, revisions of estimated inflation rates, changes in property lives and the expected timing of settling asset retirement obligations. At December 31, 2025, the fair value of assets that were legally restricted for purposes of settling asset retirement obligations was $9.7 million (December 31, 2024 - $8.0 million). These assets were accounted for as restricted cash and cash equivalents on the Company’s balance sheet (Note 19).

15. Revenue

During the year ended December 31, 2025, the Company’s production was sold primarily to one major customer, representing 69% of total Company’s sales volumes (2024 - one, representing 91% of total Company’s sales volumes, and 2023 - one, representing 98% of total sales volumes) reported in each of the reportable segments.

As at December 31, 2025, accounts receivable included $14.8 million (at December 31, 2024 - $13.4 million and 2023 -nil) of accrued sales revenue related to December production.

16. Taxes

The income tax expense and recovery reported differs from the amount computed by applying the statutory rate to (loss) income before income taxes for the following reasons:

(1) The tax rate is the statutory rate in the United States.

ASU 2023-09, issued by the Financial Accounting Standards Board, enhances income tax disclosure requirements under ASC 740 with the objective of improving transparency and decision-usefulness for investors. The update primarily requires expanded disaggregation of the effective tax rate reconciliation, including specific categories such as foreign taxes, state and local taxes, and tax credits, as well as additional information about income taxes paid (net of refunds) disaggregated by federal, state, and foreign jurisdictions, disclosing both reporting currency amounts and percentages. The standard does not change the recognition or measurement of income taxes; rather, it focuses on providing more detailed and consistent disclosures in the notes to the financial statements, thereby increasing comparability across reporting entities. In applying the new guidance, the Company elected to present its income tax expense reconciliation using the U.S. federal statutory rate as the primary reference rate, rather than the statutory rates of other jurisdictions, such as Colombia, Canada, or Ecuador, as these foreign jurisdictions are becoming more significant. Management believes that maintaining a single reference rate will enhance consistency and comparability of the effective tax rate reconciliation across reporting periods.

In general, it is the Company’s practice and intention to reinvest the earnings of our non-U.S. subsidiaries in such subsidiaries’ operations. As of December 31, 2025, the Company has not made a provision for U.S. or additional foreign withholding taxes on the investments in foreign subsidiaries that are indefinitely reinvested. Generally, such amounts become subject to taxation upon the remittance of dividends and under certain other circumstances.

On December 31, 2022, the Colombian Government enacted a tax reform that took effect on January 1, 2023, introducing significant changes to the income tax regime for oil companies. One of the key changes was the introduction of a surcharge on the existing 35% tax rate. This surcharge is calculated by comparing the average inflation-adjusted Brent price for the taxation year to the monthly inflation-adjusted Brent prices over the previous 120 months. If the Brent price for the taxation year exceeds the 30th percentile of this historical range, a 5% surtax applies. The surtax increases to 10% when the price surpasses the 45th percentile and to 15% when it exceeds the 60th percentile. For 2025, the calculation of current and deferred income tax has been based on a nil surtax, resulting in the regular tax rate of 35%, while for 2024 the calculation of current and deferred income tax has been based on a 10% surtax, resulting in a total tax rate of 45%.

In 2025, the One Big Beautiful Bill Act (OBBBA) was enacted, effective January 1, 2025, which maintains the federal corporate income tax rate at 21 %, modifies the interest deduction under §163(j) by calculating the limitation based on EBITDA rather than EBIT, allowing a higher deduction by excluding depreciation and amortization, makes adjustments to Subpart F provisions, including changes to the look‑through rules and downward attribution, and preserves the existing rules on Net Operating Losses and the maximum deduction of 80 % of taxable income.

The OECD Pillar Two GloBE Rules establish a 16% global minimum tax for multinational groups with consolidated revenues of at least EUR 750 million in two of the four preceding fiscal years. Several jurisdictions where the Company operates including Canada, Switzerland, and the United Kingdom enacted Pillar Two–aligned legislation effective since January 1, 2024. Based on management’s preliminary assessment, no material impact is expected on the Company’s 2024 or 2025 consolidated financial statements. The United States has not adopted Pillar Two legislation. Instead, in January 2026, the U.S. reached a “side‑by‑side” agreement with OECD/G7 members, under which U.S.-headquartered groups are exempt from the IIR and UTPR, and remain subject only to U.S. minimum tax rules. The Company will continue monitoring legislative and administrative developments.

The table below presents the components of the deferred tax liabilities and assets as at December 31, 2025 and 2024:

At December 31, 2025, the Company has not recognized the benefit of unused non-capital loss carryforwards of $86.6 million (2024 - $114.4 million, 2023 - $58.8 million) for federal purposes in the United States, which expire from 2037 to 2045.

At December 31, 2025, the Company has not recognized the benefit of unused non-capital loss carryforwards of $0.1 million (2024 - $3.3 million, 2023 - $16.5 million), out of a total of $156.7 million for federal purposes in Colombia. The Company’s remaining Colombian tax losses are entitled to a carryforward period of 12 years.

As at December 31, 2025, the Company has not recognized the benefit of unused non-capital loss carryforwards of $15.8 million (2024 -nil, 2023 -nil), for federal purposes in Ecuador. The Company’s remaining Ecuadorian tax losses are entitled to a carryforward period of 5 years.

At December 31, 2025, the Company has not recognized the benefit of the total unused non-capital loss carryforwards of $6.3 million (2024 - $14.2 million, 2023 -nil) for federal purposes in United Kingdom.

17. Commitments and Contingencies

Purchase Obligations, Firm Agreements and Leases

As at December 31, 2025, future minimum payments under non-cancelable agreements with remaining terms in excess of one year were as follows:

(1) Including maintenance and operating costs.

Gran Tierra has operating leases for office spaces and motor vehicles and finance leases for power generation and enhanced oil recovery facilities, storage tanks, and compressors.

Indemnities

Corporate indemnities have been provided by the Company to directors and officers for various items including, but not limited to, all costs to settle suits or actions due to their association with the Company and its subsidiaries and/or affiliates, subject to certain restrictions. The Company has purchased directors’ and officers’ liability insurance to mitigate the cost of any potential future suits or actions. The maximum amount of any potential future payment cannot be reasonably estimated. The Company may provide indemnifications in the normal course of business that are often standard contractual terms to counterparties in certain transactions such as purchase and sale agreements. The terms of these indemnifications will vary based upon the contract, the nature of which prevents the Company from making a reasonable estimate of the maximum potential amounts that may be required to be paid.

Letters of Credit

As at December 31, 2025, the Company had provided letters of credit and other credit support totaling $209.0 million, of which $61.3 million was related to capital commitments in the Suroriente Block, with the remaining as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts and other capital or operating requirements, as well as for transmission capacity in Canada(December 31, 2024 - $244.5 million).

Contingencies

Gran Tierra has several lawsuits and claims pending. The outcome of the lawsuits and disputes cannot be predicted with certainty; Gran Tierra believes the resolution of these matters would not have a material adverse effect on the Company’s consolidated financial position, results of operations, or cash flows. Gran Tierra records costs as they are incurred or become probable and determinable.

18. Financial Instruments, Fair Value Measurement, Credit Risk and Foreign Exchange Risk

Financial Instruments

Financial instruments are initially recorded at fair value, defined as the price that would be received to sell an asset or paid to market participants to settle liability at the measurement date. For financial instruments carried at fair value, GAAP establishes a fair value hierarchy that prioritizes the inputs to valuation techniques used to measure fair value. This hierarchy consists of three broad levels:

•Level 1 - Inputs representing quoted market prices in active markets for identical assets and liabilities

•Level 2 - Inputs other than quoted prices included within Level 1 that are observable for the assets and liabilities, either directly or indirectly

•Level 3 - Unobservable inputs for assets and liabilities

The Company’s financial instruments recognized on the balance sheet consist of cash and cash equivalents, accounts receivable, derivatives, other long-term assets, accounts payable and accrued liabilities, current portion of long-term debt, long-term debt and other long-term liabilities. The Company’s valuation techniques to measure the fair values of assets and liabilities are described in the subsequent disclosures.

Fair Value Measurement

The following table presents the Company’s fair value measurements of its financial instruments as of December 31, 2025 and 2024:

(1)The long-term restricted cash is included in other long-term assets on the Company’s consolidated balance sheet

The fair values of cash and cash equivalents, current restricted cash and cash equivalents, accounts receivable, accounts payable and accrued liabilities and credit facility approximate their carrying amounts due to the short-term maturity of these instruments.

Financial instruments recorded at amortized costs at December 31, 2025, include Senior Notes (Note 11).

The Senior Notes are publicly traded on Singapore Exchange and the fair value is determined using the Senior Notes trading prices at the end of each reporting period. At December 31, 2025, the carrying amounts of the 7.75% Senior Notes and 9.50% Senior Notes were $24.0 million and $673.8 million, respectively, which represents the aggregate principal amounts less unamortized debt issuance costs and discounts.

Derivative asset and derivative liability

The fair value of derivatives is estimated based on various factors, including quoted market prices in active markets and quotes from third parties. The Company also performs an internal valuation to ensure the reasonableness of third party quotes. In consideration of counterparty credit risk, the Company assessed the possibility of whether the counterparty to the derivative would default by failing to make any contractually required payments. Additionally, the Company considers that it has the ability to meet its potential repayment obligations associated with the derivative transactions.

The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2025:

Restricted cash - long-term

The fair value of long-term restricted cash and cash equivalents approximate its carrying value because interest rates are variable and reflective of market rates.

Commodity Price Risk

The Company may at times utilize commodity price derivatives to manage the variability in cash flows associated with the forecasted sale of its oil production, reduce commodity price risk and provide a base level of cash flow in order to assure it can execute at least a portion of its capital spending. As at December 31, 2025, the Company had outstanding commodity price derivative positions in Canada and Colombia as follows:

Subsequent to the year ended December 31, 2025, the Company entered into the following commodity price derivative positions:

Foreign Exchange Risk

The Company is exposed to foreign exchange risk in relation to its Colombian and Canadian operations predominantly in operating and transportation costs, G&A expenses and revenue for Canadian operations. To mitigate exposure to fluctuations in foreign exchange, the Company may enter into foreign currency exchange derivatives. During the year ended December 31, 2025, the Company settled $80 million nominal USD$ (COP$323,600 million) in outstanding foreign currency derivatives for a gain of $6.1 million (COP$$30,800 million) and as at December 31, 2025 had no outstanding foreign currency exchange derivative positions.

Unrealized foreign exchange gains and losses primarily result from fluctuations of the U.S. dollar to the Colombian peso and Canadian dollar due to Gran Tierra’s accounts payable, tax and deferred tax assets and liabilities which are monetary assets and liabilities mainly denominated in the local currencies. As a result, foreign exchange gains and losses must be calculated on conversion to the U.S. dollar functional currency. A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately $0.4 million of U.S. dollars on accounts payable, gain of approximately $0.2 million of U.S. dollars on taxes receivable and payable and gain of approximately $0.1 million of U.S. dollars on deferred tax assets and liabilities. This effect was calculated based on the Company’s December 31, 2025 balances of accounts payable, deferred tax assets, and taxes payable. The translation of assets and liabilities of Canadian operations from Canadian dollar functional currency does not impact consolidated statements of operations foreign exchange gains and losses.

For the year ended December 31, 2025,70% of the Company’s oil, natural gas and NGL sales were generated in Colombia,11% of oil, natural gas and NGL sales generated in Ecuador and 19% of oil, natural gas and NGL in Canada. For the year ended December 31, 2024,93% of the Company’s oil, natural gas and NGL sales were generated in Colombia,4% of oil, natural gas and NGL sales generated in Ecuador and 3% of oil, natural gas and NGL in Canada for the two months of operations (2023 -97% of the Company's oil sales were generated in Colombia with the remainder in Ecuador). In Colombia and Ecuador, the Company receives 100% of its revenues in U.S. dollars and the majority of the capital expenditures are in U.S. dollars or are based on U.S. dollar prices. In Canada,100% of oil, natural gas and NGL revenue is received in Canadian dollars and capital expenditures are primarily based on Canadian dollar prices. The majority of Company’s operating costs, income taxes, VAT and G&A expenses in all countries are in local currencies.

Credit Risk

Credit risk arises from the potential that the Company may incur a loss if counterparty to a financial instrument fails to meet its obligation in accordance with agreed terms. The Company’s financial instruments that are exposed to concentrations of credit risk consist primarily of cash and cash equivalents and accounts receivable. The carrying value of cash and cash equivalents and accounts receivable reflects management’s assessment of credit risk.

At December 31, 2025, cash and cash equivalents and restricted cash and cash equivalents included balances in bank accounts, term deposits and certificates of deposit, placed with financial institutions with investment grade credit ratings.

Most of the Company’s accounts receivable relate to sales to customers in the oil and natural gas industry and are exposed to typical industry credit risks. The concentration of revenues in a single industry affects the Company’s overall exposure to credit risk because customers may be similarly affected by changes in economic and other conditions. The Company manages this credit risk by entering into sales contracts with only credit worthy entities and reviewing its exposure to individual entities on a regular basis. Additionally, the Company reduces the credit risk exposure by managing its accounts receivable which are paid on a weekly basis in Colombia and Ecuador and on a monthly basis in Canada. For the year ended December 31, 2025, the Company had one customer (2024 - one and 2023 - one) which accounted for over 69% of sales.

To reduce the concentration of exposure to any individual counterparty, the Company utilizes a group of investment-grade rated financial institutions for its derivative transactions. The Company monitors counterparty creditworthiness on an ongoing basis; however, it cannot predict sudden changes in counterparties’ creditworthiness. In addition, even if such changes are not sudden, the Company may be limited in its ability to mitigate an increase in counterparty credit risk. Should one of these counterparties not perform, the Company may not realize the benefit of some of its derivative instruments.

19. Supplemental Cash Flow Information

The following table provides a reconciliation of cash, cash equivalents and restricted cash and cash equivalents with the Company’s consolidated balance sheet that sum to the total of such amounts shown in the consolidated statements of cash flows:

(1) The current portion of restricted cash and cash equivalents is included in other current assets and long-term portion of restricted cash and cash equivalents is included in other long-term assets on the Company's balance sheet.

Net changes in assets and liabilities from operating activities were as follows:

Net changes in working capital from investing activities were as follows:

The following table provides additional supplemental cash flow disclosures:

20. Subsequent Events

Subsequent to December 31, 2025, the Company completed the exchange of its existing$628.7 million 9.50% Senior Notes for a new$503.6 million 9.75% Senior Notes. The exchange consideration for the Senior Notes exchanged prior to the early participation deadline of February 11, 2026, included an early participation premium of $50 for each $1,000 aggregate principal amount and cash consideration of$125.0 million. Approximately 86.13% of the aggregate principal amount exchanged was tendered prior to the early participation deadline. The 9.75% Senior Notes will mature on April 15, 2031, unless earlier redeemed or re-purchased.

The principal amount of 9.75% Senior Notes is to be repaid as follows: (i) October 15, 2029 -15% of the principal amount; (ii) October 15, 2030 -15% of the principal amount; (iii) April 15, 2031 - the remainder of the principal amount.

At any time, prior to April 15, 2028, the Company may redeem up to 35% of the aggregate principal amount of 9.75% Senior Notes at a redemption price equal to 109.5% of the principal amount. Additionally, the Company may redeem all or a portion of the 9.75% Senior Notes on or after April 15, 2028 at the following redemption prices: 2028 -104.875%; 2029 -102.438%; 2030 and thereafter -100%.

Subsequent to December 31, 2025, the Company amended its existing prepayment agreement with Trafigura, entering into a new oil prepayment agreement that covers both its Ecuadorian and Colombian oil production. The amended agreement allows for a total prepayment facility of up to $350.0 million, consisting of:

•$150.0 million, fully drawn as of December 31, 2025,

•$175.0 million immediately available, of which $158.5 million was drawn subsequent to December 31, 2025, and

•an additional $25.0 million, at Trafigura’s absolute discretion

Pursuant to the amended and restated prepayment agreement, proceeds from the new advance are required to be used exclusively to finance the repurchase or exchange of Senior Notes and to pay fees and expenses associated with the amended agreement. In addition, the agreement revised the asset coverage ratio covenant calculation by increasing the ICE Brent pricing assumption from 80% to 90%.

This new agreement amends and restates the existing prepayment arrangement and will include Gran Tierra Operations Colombia GMBH as a seller of oil production from Colombian assets, provide a new prepayment advance and replace the old accordion facility with a new uncommitted advance option.

Subsequent to December 31, 2025, the Company, through its wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into an exploration, development and production sharing agreement (“PSA”) with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to the Company and a 35% participating interest to SOCAR. The PSA provides for afive-year exploration phase and, in the event of a commercial crude oil discovery, a 25-year development phase, with minimum work commitments during the exploration period to be completed within 36 months. These commitments include, among others, the acquisition of 250 square kilometers of 3D seismic data, the drilling oftwo exploration wells, and the conduct of geological and environmental impact studies. The Company has the right to relinquish the entire contract area during the exploration phase upon fulfillment of its exploration commitments, subject to 90 days’ prior notice to SOCAR.

Subsequent to December 31, 2025, the Company entered into the agreement to dispose the entire WI and associated title rights in the Simonette Montney Block in Canada effective January 1, 2026 for total cash consideration of C$62.5 million (US$45.6 million). The consideration comprised C$50.0 million (US$36.4 million) attributable to the sale of crude oil and natural gas rights and C$12.5 million (US$9.1 million) related to the sale of tangible assets and seismic data.

Supplementary Data (Unaudited)

1. Oil and Natural Gas Producing Activities

In accordance with Financial Accounting Standards Board (FASB) Accounting Standards Codification Topic 932, “Extractive Activities—Oil and Gas”, and regulations of the U.S. Securities and Exchange Commission (SEC), the Company is making certain supplemental disclosures about its oil and natural gas exploration and production operations.

A. Estimated Proved Net After Royalty (“NAR”) Reserves

The following table sets forth Gran Tierra’s estimated proved NAR reserves and total net proved developed and undeveloped reserves as of December 31, 2023, 2024, and 2025, and the changes in total net proved reserves during the three-year period ended December 31, 2025.

The net proved reserves represent management’s best estimate of proved oil and natural gas reserves after royalties. Reserve estimates for each property are prepared internally each year and 100% of the reserves at December 31, 2025, have been evaluated by independent reservoir engineering specialist, McDaniel & Associates Consultants Ltd.

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, and demonstrate reasonable certainty that they are recoverable from known reservoirs under economic and operating conditions that existed at year end. The determination of oil and natural gas reserves is complex and requires significant judgment. Assumptions used to estimate reserve information may significantly increase or decrease such reserves in future periods. The estimates of reserves are subject to continuing changes and, therefore, an accurate determination of reserves may not be possible for many years because of the time needed for development, drilling, testing, and studies of reservoirs.

(1) NGL includes immaterial volume of Condensate

Changes in proved reserves during the years ended December 31, 2025, 2024 and 2023 shown in the table above primarily resulted from the following significant factors:

Acquisitions. Added 2.7 MMbbl of proved crude oil related to the purchase of the Perico and Espejo Blocks in Ecuador (2024 - added 10.1 MMbbl of proved crude oil,184.8 MMMcf of proved natural gas and 21.8 MMbbl of proved NGLs for the Canadian operations acquired through the acquisition of i3 Energy on October 31, 2024) .

Extensions and Discoveries. Added 7.3 MMbbl of proved crude oil,6.1 MMMcf of proved natural gas and 0.3 MMbbl of proved NGL reserves during the year ended December 31, 2025. The additions of proved crude oil were comprised of 1.5 MMbbl extensions in Canada related to successful drilling efforts in the Simonette and Clearwater area and 5.8 MMbbl of discoveries in Ecuador related to a 0.8 MMbbl discovery in the Chanangue Block, a 4.0 MMbbl discovery in the Charapa Block and a 1.0 MMbbl discovery in the Iguana Block (2024 -8.6 MMbbl extensions in the Acordionero and Costayaco fields in Colombia and discoveries in the Charapa and Chanangue Blocks in Ecuador; 2023 -17.8 MMbbl, reserve extensions in the Acordionero and Costayaco fields in Colombia and the Charapa and Chanangue Blocks in Ecuador and a discovery in the Alea-1848 Block).

Technical and Economic Revisions. Deducted 4.4 MMbbl of proved crude oil,49.6 MMMcf of proved natural gas and 7.3 MMbbl of proved NGL reserves during the year ended December 31, 2025. In Colombia, we reduced 5.4 MMbbl of proved crude oil reserves primarily due to base performance in the Moqueta and Costayaco fields, as well as the removal of Proved locations in Cumplidor, Chuira, and Mono Arana field. In Ecuador, we added 1.2 MMbbl due to production type curve increases. In Canada we deducted natural gas and NGL volumes due to reclassifying certain drilling locations from NAR reserves to contingent resources to better align development timing with prevailing commodity price assumptions and expected activity levels (2024 - reduced 0.4 MMbbl primarily due to the underperformance of Acordionero Forelimb and Costayaco South area drills relative to previous expectations and production type curve decreases in Ecuador; 2023 -0.7 MMbbl, related to positive technical revisions based on increased drilling and continued waterflood performance in the Acordionero and Costayaco fields as well as production type curve increases in the Ecuador Blocks).

Dispositions. Disposed of 3.3 MMMcf of proved natural gas and 0.5 MMbbl of proved NGL reserves during the year ended December 31, 2025 in the Retlaw area in Southern Alberta and Elmworth area in Wapiti.

B. Capitalized Costs

Capitalized costs for Gran Tierra’s oil and natural gas producing activities consisted of the following at the end of each of the years in the two-year period ended December 31, 2025:

C. Costs Incurred

The following table presents costs incurred for Gran Tierra’s oil and natural gas property acquisitions and exploration and development for the respective years:

D. Results of Operations for Oil and Natural Gas Producing Activities

E. Standardized Measure of Discounted Future Net Cash Flows and Changes

The following disclosure is based on estimates of net proved reserves and the period during which they are expected to be produced. Future cash inflows are computed by applying the twelve month period unweighted arithmetic average of the price as of the first day of each month within that twelve month period, unless prices are defined by contractual arrangements, excluding escalations based on future conditions to Gran Tierra’s after royalty share of estimated annual future production from proved oil, natural gas and NGL reserves.

Future development and production costs to be incurred in producing and further developing the proved reserves are based on year end cost indicators. Future income taxes are computed by applying year end statutory tax rates. These rates reflect allowable deductions and tax credits, and are applied to the estimated pre-tax future net cash flows. Discounted future net cash flows are calculated using 10% mid-year discount factors. The calculations assume the continuation of existing economic, operating and contractual conditions. However, such prescribed assumptions have not proved to be the case in the past. Other assumptions could give rise to substantially different results.

The Company believes this information does not in any way reflect the current economic value of its oil and gas producing properties or the present value of their estimated future cash flows as:

•no economic value is attributed to probable and possible reserves;

•use of a 10% prescribed discount rate; and

•prices change constantly from the twelve-month period unweighted arithmetic average of the price as of the first day of each month within that twelve-month period.

The standardized measure of discounted future net cash flows from Gran Tierra’s estimated proved oil and gas reserves is as follows:

Changes in the Standardized Measure of Discounted Future Net Cash Flows

The following table summarizes changes in the standardized measure of discounted future net cash flows for Gran Tierra’s proved oil and natural gas reserves: