Gran Tierra Energy Inc.: Form 10-Q for the period ended Sep 30, 2025

The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements” as set out in Part I, Item 1 of this Quarterly Report on Form 10-Q, as well as “Management’s Discussion and Analysis of Financial Condition and Results of Operations” and the “Financial Statements and Supplementary Data” included in Part II, Items 7 and 8, respectively, of our 2024 Annual Report on Form 10-K. Please see the cautionary language at the beginning of this Quarterly Report on Form 10-Q regarding the identification of and risks relating to forward-looking statements and the risk factors described in Part II, Item 1A “Risk Factors” of this Quarterly Report on Form 10-Q, as well as Part I, Item 1A “Risk Factors” in our 2024 Annual Report on Form 10-K.

Financial and Operational Highlights

Key Highlights for the third quarter of 2025

• Net loss for the third quarter of 2025 was $20.0 million or $(0.57) per share basic and diluted, compared to a net income of $1.1 million or $0.04 per share basic and diluted for the third quarter of 2024 and a net loss of $12.7 million for the prior quarter.
• Loss before income taxes for the third quarter of 2025 was $31.2 million, compared to income before income taxes of $21.9 million for the third quarter of 2024 and loss before income taxes of $8.1 million for the prior quarter.
• Brent oil price averaged $68.17 per bbl during the third quarter of 2025, a decrease of 13% from the comparable period in 2024, and a 2% increase from the prior quarter. Castilla, Vasconia and Oriente differentials averaged $4.88, $1.88 and $7.20 per bbl during the third quarter of 2025, a decrease of 45%, 63% and 21% from the comparable period of 2024, and an increase of 3% and 10% for Castilla and Vasconia differentials offset by a decrease of 1% for Oriente differential from the prior quarter, respectively.
• Adjusted EBITDA(2) was $69.0 million for the third quarter of 2025, a decrease from $92.8 million in the third quarter of 2024, and a decrease from $77.0 million in the prior quarter.
• Funds flow from operations(2) decreased to $41.7 million compared to $60.3 million in the third quarter of 2024, and decreased from $53.9 million in the prior quarter.
• During the third quarter of 2025, there were no share re-purchases. For the period from November 6, 2024 to October 29, 2025, we re-purchased a total of 1.2 million shares or 3% of the outstanding shares as of September 30, 2025.
• NAR production for the third quarter of 2025 increased by 38% to 35,962 BOEPD, compared to 25,988 BOEPD in the third quarter of 2024 due to the production from Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador, and decreased by 10% from 39,800 BOEPD in the prior quarter as a result of a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 BOEPD.
• NAR sales volumes for the third quarter of 2025 increased by 47% to 37,353 BOEPD, compared to 25,464 BOEPD in the third quarter of 2024 and decreased by 3% from 38,331 BOEPD in the prior quarter.
• Oil, natural gas and NGL sales for the third quarter of 2025 decreased by 1% to $149.3 million, compared to the third quarter of 2024, primarily due to lower oil prices partially offset by an increase in sales volumes. Oil, natural gas and NGL sales were comparable with the prior quarter.
• On per boe basis, operating expenses increased 1% compared to the corresponding period of 2024 and increased 24% from the prior quarter. Operating expenses increased by 48% to $68.4 million when compared to the third quarter of 2024, primarily as a result of new Canadian operations and ramp-up of operations in Ecuador. Operating expenses increased by 22% from $55.9 million in the prior quarter primarily as a result of higher workover activities and lifting costs attributed to inventory fluctuation in Ecuador due to the timing of sales.
• Transportation expenses increased by 10% when compared to the third quarter of 2024 primarily due to 47% higher sales volumes attributed to new Canadian operations and higher sales volumes in Ecuador, partially offset by lower volumes transported in Colombia. Transportation expenses decreased by 4% compared to the prior quarter primarily as a result of lower sales volumes transported from Acordionero field in Colombia.
• Gross profit decreased 70% to $14.7 million compared to $48.8 million in the third quarter of 2024 and 36% from $23.1 million in the prior quarter.
• Operating Netback(2) decreased to $76.6 million compared to $101.4 million in the third quarter of 2024 and $89.0 million in the prior quarter.
• Quality and transportation discounts for the third quarter of 2025 increased to $24.74 per boe compared to $14.10 per boe in the third quarter of 2024, primarily as a result of the change in production mix with the acquisition of Canadian operations, and $23.89 per boe in the prior quarter as a result of higher Castilla and Vasconia differentials.
• General and administrative (“G&A”) expenses before stock-based compensation for the third quarter of 2025 increased to $13.5 million compared to $9.5 million in the third quarter of 2024, due to the addition of the new Canadian operations, and decreased from $14.5 million in the prior quarter due to lower business development costs.
• Capital expenditures for the third quarter of 2025 were $57.3 million compared to $52.9 million in the third quarter of 2024 and $51.2 million in the prior quarter. This increase in capital expenditure activity is in line with the Company’s budgeted capital spend for 2025.
• The temporary excise tax levied on oil sales was introduced by the Colombian government under a state of emergency declared in 2025. The tax applies to the first sale or export of crude oil at a rate of 1% starting from February 2025 and is scheduled to remain in force until December 2025. All temporary taxes enacted under the state of emergency are currently under review by the Constitutional Court, the ruling of which could potentially invalidate these measures

(1) Sales volumes represent production NAR adjusted for inventory changes.

(2) Non-GAAP measures.

Gross profit is derived from oil, natural gas and NGL sales, net of direct production costs including operating expenses, transportation, and depletion, depreciation, and accretion (“DD&A”). Gross profit does not include general and administrative expenses, interest, taxes, or other non-operating items.

Operating netback, EBITDA, adjusted EBITDA, and funds flow from operations are non-GAAP measures that do not have any standardized meaning prescribed under GAAP. Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as gross profit adjusted for depletion and accretion related to producing assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil sales to operating netback is provided in the table below.

(*) Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $3.0 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024and the prior quarter.

(*) Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $65.0 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.

EBITDA, as presented, is defined as net (loss) income adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, lease payments, foreign exchange gain or loss, stock-based compensation expense or recovery, transaction costs, other loss and unrealized derivative instruments loss or gain. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is useful supplemental information for investors to analyze our performance and our financial results. A reconciliation from net (loss) income to EBITDA and adjusted EBITDA is as follows:

Funds flow from operations, as presented, is defined as net (loss) income adjusted for DD&A expenses, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments loss or gain and other loss. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. A reconciliation from net loss to funds flow from operations is as follows:

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Additional Operational Results

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(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and a reconciliation of this measure.

Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD

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Oil, natural gas and NGL production NAR for the three and nine months ended September 30, 2025, increased by 38% and 47%, to 35,962 BOEPD and 38,099 BOEPD, respectively, compared to the corresponding periods of 2024 due to the production from the Canadian operations acquired on October 31, 2024 and successful exploration well drilling results in Ecuador. Oil, natural gas and NGL production NAR decreased by 10% compared to the prior quarter primarily due to a landslide in Ecuador that required the shut in of all Ecuador production for several weeks and trunk line repairs at the Moqueta field which resulted in the field being shut in for the quarter. Current production from October 1, 2025 to October 29, 2025 is approximately 45,200 boepd.

Royalties as a percentage of production for the three and nine months ended September 30, 2025 decreased by 5% and 4%, respectively, compared to the corresponding periods of 2024 as a result of a decrease in benchmark oil prices due to the price sensitive royalty regime in Colombia and Ecuador, and lower royalties for Canadian operations. Royalties as a percentage of production were comparable to the prior quarter.

The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields. Ecuador includes the Charapa, Chanangue and Iguana Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with all production in Alberta, Canada.

Commodity prices:

Colombia and Ecuador

Brent - For the three and nine months ended September 30, 2025, Brent decreased 13% and 15% from the comparable periods of 2024, and increased 2% from the prior quarter. For the three months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.88, $1.88 and $7.20 compared to $8.83, $5.07 and $9.15 in the corresponding period of 2024. For the nine months ended September 30, 2025, Castilla, Vasconia and Oriente differentials per boe decreased to $4.98, $1.95 and $7.37 from $8.62, $4.70 and $8.52 in the corresponding period of 2024.

During the third quarter of 2025, 100% of sales from South America were priced against Brent.

Canada

Gran Tierra entered Canada with the acquisition of i3 Energy which closed on October 31, 2024, therefore no comparative data is provided for the corresponding periods of 2024.

WTI - For the three months ended September 30, 2025, WTI increased 2% from the prior quarter. For the three months ended September 30, 2025, 25% of NAR production in Canada was oil, compared with 26% in the prior quarter.

NGLs - For the three months ended September 30, 2025, the weighted average NGL price received was 9% of WTI, consistent with the prior quarter. For the three months ended September 30, 2025, 21% of NAR production in Canada was NGLs, compared to 24% in the prior quarter.

AECO - For the three months ended September 30, 2025, AECO price decreased 63% from the prior quarter. For the three months ended September 30, 2025, 54% of NAR production in Canada was natural gas, compared to 50% in the prior quarter.

Oil, natural gas and NGL sales for the three months ended September 30, 2025, decreased by 1% to $149.3 million compared to the corresponding period of 2024, due to 13% decrease in Brent price and 19% lower sales volumes in Colombia partially offset by 47% increase in sales volumes, attributed to sales from Canadian operations acquired on October 31, 2024 and sales from positive exploration drilling in Ecuador. Oil, natural gas and NGL sales for the nine months ended September 30, 2025, decreased by 2% to $466.8 million compared to the corresponding period of 2024 due to 15% decrease in Brent price and 16% decrease in sales volumes in Colombia, partially offset by a 49% increase in sales volumes attributed to sales from Canadian operations and new exploration wells in Ecuador.

Oil, natural gas and NGL sales were comparable with the prior quarter

During the three months ended September 30, 2025, we retrospectively reclassified transportation expenses against revenue, which were previously recorded separately from revenue, resulting in a decrease of revenue by immaterial impact of $3.1 million and $5.5 million for the three and six months ended June 30, 2025, respectively, and $2.4 million for the three months ended March 31, 2025.

The following table shows the effect of changes in realized price and sale volumes on our oil sales for the three and nine months ended September 30, 2025, compared to the prior quarter and the corresponding periods of 2024:

Gross Profit

(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $47.0 million and $52.8 million, less depreciation of administrative assets of $2.9 million and $2.9 million, respectively. For the nine months ended September 30, 2025 and 2024 of $146.1 million and $160.1 million, less depreciation of administrative assets of $9.2 million and $8.7 million, respectively. For the prior quarter, calculated as DD&A expenses of $50.5 million, less depreciation of administrative assets of $2.6 million.

(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

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(*) Same as DD&A expenses for the three months ended September 30, 2025 and 2024 and the prior quarter.

(*)Calculated as DD&A expenses for the three months ended September 30, 2025 and 2024 of $64.981 million and $55.6 million, less depreciation of administrative assets of $3.1 million and $3.0 million, respectively. For the nine months ended September 30, 2025 and 2024 of $205.8 million and $167.2 million, less depreciation of administrative assets of $9.5 million and $8.9 million, respectively. For the prior quarter, calculated as DD&A expenses of $68.6 million, less depreciation of administrative assets of $2.7 million.

Operating Netback

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(1) Operating netback is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.

Operating expenses for the three months ended September 30, 2025, increased to $68.4 million or by $0.24 per boe to $19.90 compared to the corresponding period of 2024, due to new Canadian operations and ramp-up of operations in Ecuador.

Operating expenses for the nine months ended September 30, 2025, increased to $191.6 million compared to the corresponding period of 2024 for the same reason mentioned above. On a per boe basis, operating expenses decreased by $1.84 to $18.36 compared to the corresponding period of 2024, primarily due higher sales volumes in Ecuador and sales from new Canadian operations.

Compared to the prior quarter, operating expenses increased from $55.9 million or by $3.89 from $16.01 per boe due to higher workover activities and lifting costs associated with inventory fluctuation in Ecuador due to the timing of sales.

Transportation expenses

We have options to sell our oil through multiple pipelines and various trucking routes. Each option has varying effects on realized sales price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each option for the three and nine months ended September 30, 2025 and 2024, and the prior quarter:

Volumes transported through pipeline or via truck receive a higher realized price but incur higher transportation expenses. Conversely, volumes sold at the wellhead have the opposite effect of a lower realized price, offset by lower transportation expenses.

Transportation expenses for the three months ended September 30, 2025, increased by 10% to $4.3 million or by $0.42 to $1.25 per boe, compared to the corresponding period of 2024, due to the new Canadian operations, higher sales volumes transported in Ecuador partially offset by lower sales volumes transported in Colombia.

Transportation expenses for the nine months ended September 30, 2025, decreased by 6% to $13.3 million or by $0.74 to $1.28 per boe, compared to the corresponding period of 2024, due to lower sales volumes transported in Colombia partially offset by sales volumes from a new Canada operations and the higher sales volumes transported in Ecuador.

Transportation expenses decreased by 4% or $0.04 per boe from $4.5 million or $1.29 per boe in the prior quarter due to lower sales volumes transported from Acordionero field in Colombia.

DD&A Expenses

DD&A expenses for the three and nine months ended September 30, 2025, increased by 17% and 23% due to higher costs in the depletable base for Ecuador and the new Canadian operations, compared to the corresponding periods of 2024.

On a per boe basis, DD&A expenses for the three and nine months ended September 30, 2025 decreased by $4.81 and $4.14 due to higher NAR sales volumes primarily attributed to the new Canadian operations.

DD&A expenses decreased by 5% from $68.6 million when compared to the prior quarter due to lower production rates. On a per boe basis, DD&A expenses decreased by $0.77 due to higher production in Ecuador.

G&A Expenses

G&A expenses before stock-based compensation on a per boe basis for the three months ended September 30, 2025 decreased by $0.14 or 3% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 42% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations and higher business development and consulting cost related to optimization projects.

G&A expenses before stock-based compensation on a per boe basis for the nine months ended September 30, 2025, decreased by $0.62 or 14% compared to the corresponding period of 2024 due to higher sales volumes mainly driven by the addition of the new Canadian operations. Total G&A expenses before stock-based compensation increased by 28% compared to the corresponding period of 2024, primarily due to the addition of the new Canadian operations.

Compared to the prior quarter, G&A expenses before stock-based compensation decreased by 7% or $0.24 per boe due to lower business development cost.

G&A expenses after stock-based compensation for the three and nine months ended September 30, 2025, increased by 114% and 7% or $1.25 and decreased $1.52 per boe compared to the corresponding periods of 2024, due to higher stock-based compensation attributed to a higher share price during the current periods and the addition of the new Canadian operations.

Compared to the prior quarter, G&A expenses after stock-based compensation decreased by 9% or $0.34 per boe due to a recovery from a lower share price.

Foreign Exchange Gains and Losses

For the three and nine months ended September 30, 2025, we had a $0.3 million loss and $7.8 million loss on foreign exchange compared to a $3.1 million gain and $8.3 million gain on foreign exchange in the corresponding periods of 2024 and a $3.7 million loss on foreign exchange in the prior quarter. Accounts payable, taxes receivable and payable and deferred income taxes are considered monetary items and require translation from local currencies to U.S. dollar functional currency at each balance sheet date. This translation was the primary source of the foreign exchange gains and losses in the periods.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the three and nine months ended September 30, 2025 and 2024 and the prior quarter:

Income Tax Expense

Current income tax expense was $14.5 million for the nine months ended September 30, 2025, compared to $61.4 million in the corresponding period of 2024, primarily due to lower taxable income.

The deferred tax for the nine months ended September 30, 2025, was a recovery of $17.6 million mainly due to an increase in deductible temporary differences arising from tax losses generated during the period. These were partially offset by higher tax depreciation relative to accounting depreciation.

For the nine months ended September 30, 2024, the deferred income tax was a recovery of $32.3 million, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy.

For the nine months ended September 30, 2025, the difference between the effective tax rate of negative 6% and the 35% statutory tax rate was primarily due to permanent differences and valuation allowance. This was partially offset by an increase in the impact of foreign taxes.

For the nine months ended September 30, 2024, the difference between the effective tax rate of 44% and the 50% Colombian tax rate was primarily due to a lower impact of foreign taxes, 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments. These were partially offset by an increase in valuation allowance, other permanent differences, non-deductible stock-based compensation and non-deductible royalties in Colombia.

Net (Loss) Income and Funds Flow from Operations (a Non-GAAP Measure)

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(1) Funds flow from operations is a non-GAAP measure that does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in "Financial and Operational Highlights" for a definition and reconciliation of this measure.

Capital expenditures during the three months ended September 30, 2025, were $57.3 million.

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During the three months ended September 30, 2025, we drilled the following wells:

During the three months ended September 30, 2025, we spud one exploration well in Ecuador and one in Colombia. As of September 30, 2025, the exploration well drilled in Ecuador was in-progress and in Colombia was a dry well. We also spud one development well in Canada which was in-progress as of September 30, 2025.

Liquidity and Capital Resources

We believe that our capital resources, including cash on hand, cash generated from operations and available borrowings under our credit facilities and prepayment structure, will provide us with sufficient liquidity to meet our strategic objectives and planned capital program for the next 12 months, including the repayment of 25% of the principal amount of 9.50% Senior Notes due October 15, 2026, given the current oil price trends and production levels. Beyond the next 12 months, the Company may require the support of its lenders to renew existing lending arrangements and may also access to capital markets to pursue financing, including for the re-purchase of common stock or the repayment of debt in the future. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us with the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital to be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.

On October 24, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, entered into crude oil sale and purchase agreement where we will receive an advance of up to $150.0 million related to Ecuador production. An additional advance of $50.0 million is available to the Company, at the sole discretion of the lender and subject to completion of certain conditions.

Credit Facility - Canada

We, through our wholly owned subsidiary Gran Tierra Canada Ltd., have a revolving credit facility with National Bank of Canada dated March 22, 2024 with a borrowing base of C$100.0 million (US$71.8 million as of September 30, 2025) and the available commitment of a C$50.0 million (US$35.9 million as of September 30, 2025) revolving credit facility comprised of C$35.0 million (US$25.1 million as of September 30, 2025) syndicated facility and C$15.0 million (US$10.8 million as of September 30, 2025) of 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. As of September 30, 2025, the outstanding balance under the facility was US$19.9 million (C$30.0 million) and the weighted-average interest rate on borrowings for the three and nine months ended September 30, 2025 was 6.64% and 6.48%, respectively. On July 22, 2025, the borrowing base was redetermined by National Bank of Canada at C$100.0 million, of which available commitment is C$50.0 million.

On October 30, 2025, the existing revolving credit facility was amended to increase available commitment amount from C$50.0 million (US$35.9 million as of September 30, 2025) to C$75.0 million (US$53.9 million as of September 30, 2025) and extend the term to a two-year maturing October 30, 2027. The borrowing base was maintained at C$100.0 million.

Credit Facility - Colombia

On April 16, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy Colombia GmbH, a Swiss limited liability company, entered into a $75.0 million reserve-based lending facility. Any loans incurred under the new facility will mature on April 16, 2028 and will bear interest at a rate per annum equal to, at our 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 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.

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 Amended RBL Facility, we are required to repay any amounts outstanding in excess of $20.0 million upon funding the oil prepayment agreement and the lender may initiate a redetermination of the borrowing base if advances requested by us are in excess of $20.0 million.

As of September 30, 2025 the outstanding balance under the RBL Facility was $24.5 million. For the three and nine months ended September 30, 2025, the weighted-average interest rate on borrowings was 9.05% and 8.79%, respectively.

Under the terms of the facility, we are 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

Senior Notes

At September 30, 2025, we had $24.2 million aggregate principal amount of outstanding 7.75% Senior Notes due 2027, and $735.8 million aggregate principal amount of outstanding 9.50% Senior Notes due 2029.

During the nine months ended September 30, 2025, we paid at maturity the remaining principal of $24.8 million of 6.25% Senior Notes due in February 2025 for cash consideration of $25.6 million, including interest payable of $0.8 million.

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.

We were in compliance with all applicable covenants related to credit facilities and Senior Notes as of September 30, 2025.

Share Repurchase Program, NCIB

During the three and nine months ended September 30, 2025, we re-purchased nil and 692,804 shares under the 2024 Program at a weighted average price of nil and $5.00 per share (three and nine months ended September 30, 2024 - 371,130 and 1,662,110 shares under the 2023 program at a weighted average price of $9.37 and $7.31 per share). Under the 2024 Program, we were able to re-purchase at prevailing market prices up to 3,545,872 shares of Common Stock, representing approximately 10% of the public float as of October 31, 2024. We cancelled 487,948 held as treasury shares as at December 31, 2024 and cancelled 10,000 shares re-purchased during the nine months ended September 30, 2025. During the period from November 6, 2024 to October 29, 2025, we have re-purchased 1,180,752 shares under the 2024 Program.

Acquisitions and Dispositions

On September 8, 2025, we, through our wholly owned subsidiary, Gran Tierra UK Limited, a United Kingdom limited company, closed the sale agreement for its wholly owned subsidiary, Gran Tierra North Sea Limited (“GTNSL”) to NEO Energy for total consideration of $7.5 million. The deferred income tax asset balance of $7.5 million has been applied against total consideration and resulted in zero gain or loss on sale.

On July 31, 2025, we, through our indirect wholly owned subsidiaries, Gran Tierra Energy Ecuador 1 GmbH and Gran Tierra Energy Ecuador 2 GmbH, have entered into definitive agreements to acquire all of GeoPark Ecuador S.A.’s and Frontera Energy Colombia Corp Sucursal Ecuador’s interests in the Perico and Espejo Blocks (the “Blocks”) and their associated Consortiums (the “Consortiums”).

The aggregate purchase price for the Blocks and Consortiums is $15.5 million, subject to customary working capital adjustments as of the effective date of January 1, 2025. The agreement includes an additional contingent consideration of $1.5 million, payable upon the Perico Block achieving cumulative gross production of two million barrels starting from January 1, 2025. The acquisitions are expected to close upon satisfaction of customary closing conditions, including the receipt of regulatory approvals for closing and operations takeover from the Ministry of Energy of Ecuador. Closing is anticipated no earlier than the fourth quarter of 2025.

Cash Flows

The following table presents our primary sources and uses of cash and cash equivalents and restricted cash and cash equivalents for the presented:

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(1) Adjusted EBITDA and funds flow from operations are non-GAAP measures which do not have any standardized meaning prescribed under GAAP. Refer to note 2 “Non-GAAP measures” in “Financial and Operational Highlights” for a definition and reconciliation of this measure.

One of the primary sources of variability in our cash flows from operating activities is the fluctuation in oil prices. Sales volume changes, costs related to operations and debt transactions also impact cash flows. Our cash flows from operating activities are also impacted by foreign currency exchange rate changes. During the three months ended September 30, 2025, funds flow from operations decreased by 31% compared to the corresponding period of 2024, due to a decrease in Brent price, higher operating expenses and higher transportation cost partially offset by higher sales volumes, lower differentials and lower current income tax expense. Funds flow from operations for the nine months ended September 30, 2025, decreased by 17% compared to the corresponding period of 2024, primarily due to decrease in Brent price, higher operating expenses, higher interest expense partially offset by higher sales volumes, lower differentials and lower current income tax expense.

Critical Accounting Policies and Estimates

Our critical accounting policies and estimates are disclosed in Item 7 of our 2024 Annual Report on Form 10-K and have not changed materially since the filing of that document.

Commodity Price Risk

Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent or Edmonton Light pricing and for gas at AECO pricing and adjusted for quality. As at September 30, 2025, the Company had 1,782 and 562 weighted average bopd crude volumes hedged up to December 31, 2026, in Colombia and Canada, respectively, as well as 22,500 weighted average GJ/day natural gas volumes hedged for Q4 2025 and 10,000 weighted average GJ/day natural gas volumes hedged for second and third quarters of 2026. The Company entered into an additional 10,000 weighted average GJ/day natural gas derivative from January 01, 2026 up to October 31, 2026 as well as 2,500 weighted average bopd crude volumes from January 01, 2026 up to December 31, 2026, subsequent to the quarter-end, to manage the variability of cash flows associated with the forecasted sale of our production, reduce commodity price risk and provide a base level of cash flow in order to assure we can execute at least a portion of our capital spending.

Foreign Currency Risk

Foreign currency risk is a factor for our Company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 82% of our revenues are related to the U.S. dollar price of Brent with the remainder related to Canadian dollar price of WTI oil or AECO gas. In Colombia and Ecuador, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures is in U.S. dollars or is based on U.S. dollar prices. The majority of income and value added taxes and G&A expenses in all locations are in local currency. In Canada, we receive 100% of our revenue in Canadian dollar and majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar reporting currency.

During the three months ended September 30, 2025, the Company crystallized $80 million nominal USD$ (COP$323,600 million) in outstanding foreign currency derivatives for a gain of $6 million (COP$30,800 million) and as at September 30, 2025 had no outstanding foreign currency derivative positions.

Interest Rate Risk

Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our Canadian revolving credit facility and Colombian reserve-based lending (“RBL”) facility, which bear floating rates of interest. As of September 30, 2025 our outstanding balance under the revolving credit facility was US$19.9 million (C$30.0 million) and $24.5 million under the RBL facility (December 31, 2024 - nil).

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our disclosure controls and procedures are designed to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized, and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule l3a-15(b) of the Exchange Act. Based on this evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra’s disclosure controls and procedures were effective as of September 30, 2025.

Changes in Internal Control over Financial Reporting

There were no changes in our internal control over financial reporting (as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act) during the quarter ended September 30, 2025, that have materially affected or are reasonably likely to materially affect our internal control over financial reporting.

On October 31, 2024, the Company completed the acquisition of i3 Energy Plc (“i3 Energy”), a publicly traded oil and gas company that was listed on the TSX venture exchange. i3 Energy’s operations have been included in the consolidated financial statements of Gran Tierra since October 31, 2024. However, Gran Tierra has not yet completed its assessment of the disclosure controls and procedures, and internal controls over financial reporting previously used by i3 Energy, and integrate them with those of Gran Tierra. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of i3 Energy (as permitted by applicable securities laws in U.S.). Gran Tierra has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by October 31, 2025. During the nine months ended September 30, 2025, the assets previously held by i3 Energy, contributed $87.3 million (representing 19%) of total Company’s oil, natural gas and NGL revenue and as at September 30, 2025, there were $291.7 million of total assets associated with acquired entity.

There are numerous factors that affect our business and results of operations, many of which are beyond our control. In addition to information set forth in this Quarterly Report on Form 10-Q, including in Part I, Item 2 “Management’s Discussion and Analysis of Financial Condition and Results of Operations”, you should carefully read and consider the factors set out in Part I, Item 1A “Risk Factors” in our Annual Report on Form 10-K for the year ended December 31, 2024. These risk factors could materially affect our business, financial condition and results of operations. The unprecedented nature of ongoing conflicts in several parts of the world, along with volatility in the worldwide economy and oil and gas industry may make it more difficult to identify all the risks to our business, results of operations and financial condition and the ultimate impact of identified risks.