Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations
This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Please see the cautionary language at the very beginning of this Annual Report on Form 10-K regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A. “Risk Factors” in this Annual Report on Form 10-K.
The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements and Supplementary Data” as set out in Part II, Item 8 of this Annual Report on Form 10-K. This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2025, and year-to-year comparisons between the fiscal years ended December 31, 2025, and 2024, respectively. Discussions of items related to the fiscal year ended December 31, 2024 and year-to-year comparisons between the fiscal years ended December 31, 2024 and 2023, respectively, that are not included in this Annual Report on Form 10-K can be found in “Management’s Discussion and Analysis of Financial Condition and Results of Operations” in Part II, Item 7 of the Company’s Annual Report on Form 10-K for the fiscal year ended December 31, 2024. On May 5, 2023, the Company completed 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. All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split.
Overview
We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 46%, our Canadian properties represented 38%, and our Ecuadorian properties represented 16% of our proved reserves NAR at December 31, 2025, and for the year ended December 31, 2025, 70% of our revenue was generated in Colombia (2024 - 93%; 2023 -97%), 19% of our revenue was generated in Canada (2024 - 3%; 2023 - nil) and 11% (2024 - 4%; 2023 - 3%) of our revenue was generated in Ecuador. We are headquartered in Calgary, Alberta, Canada.
As of December 31, 2025, we had estimated proved reserves NAR of 111.6 MMBOE, a 17% decrease from the prior year, of which 57% were proved developed reserves and 71% were oil.
Financial and Operational Highlights
Key Highlights
• Net loss in 2025 was $193.1 million or $5.45 per share basic and diluted, which included a non-cash ceiling test impairment in Colombia and Ecuador of $136.3 million, compared to net income of $3.2 million or $0.10 per s hare basic and diluted in 2024
• Loss before income taxes in 2025 was $232.9 million compared to income before income taxes of $44.6 million in 2024
• Adjusted EBITDA (2) in 2025 was $283.7 million compared to $366.8 million in 2024
• In 2025, we re-purchased 0.7 million shares of Common Stock through the 2024 share re-purchase program, representing about 2% of shares outstanding as of December 31, 2025
• Our 2025 average production NAR was 38,443 BOEPD, an increase from 27,890 BOEPD in 2024 as a result of positive exploration drilling results in Ecuador, full year production from the Canadian operations, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions and trunk line repairs at the Moqueta field which resulted in the field being shut-in during the third quarter of 2025
• Our 2025 oil, natural gas and NGL sales volumes NAR increased by 37% to 37,664 BOEPD compared to 27,436 BOEPD in 2024
• Oil, natural gas and NGL sales for 2025 decreased by 4% to $596.7 million compared to $621.8 million in 2024, primarily as a result of a 15% decrease in Brent price, lower sales volumes in Colombia, offset by higher sales volumes in Ecuador, lower differentials, and a full year of sales from Canadian operations
• In 2025, we generated net cash provided by operating activities of $313.2 million, an increase of 31% from $239.3 million in 2024
• Operating expenses per boe for 2025 were $18.09, 10% or $2.06 per boe lower compared to 2024, primarily due to higher NAR sales volumes. Total operating expenses were $248.7 million in 2025, compared to $202.3 million in 2024, representing an 23% increase as a result of higher operating costs in Ecuador driven by a production ramp-up in 2025, and the full year of Canadian operations
• Quality and transportation discounts per boe in South America decreased in 2025 to $11.04 when compared to $13.93 in 2024 due to lower Castilla, Vasconia and Oriente differentials as a result of higher demand for heavy oil.
• Quality and transportation discounts for oil per boe in Canada increased in 2025 to $7.90 when compared to $4.49 in 2024, primarily as a result of higher pipeline tariffs related to new wells coming on stream in Simonette and Clearwater areas
• Transportation expenses for 2025 decreased by 8% or by $0.60 per boe to $17.0 million or $1.24 per boe compared to $18.5 million or $1.84 per boe in 2024 due to the full year of Canadian operations which had lower transportation costs per boe, and a shift to lower-cost delivery points in Colombia
• Gross profit decreased by 64% to $66.4 million compared to $182.6 million in 2024 primarily as a result of higher operating and depletion and accretion costs driven by a full year of Canadian operations in 2025
• Operating netback (2) decreased to $330.9 million compared to $401.1 million in 2024
• G&A expenses before stock-based compensation increased by 37% to $56.9 million in 2025 compared to $41.4 million in 2024 as a result of the full year of G&A expenses from Canadian operations, higher business development costs, and consulting costs attributed to optimization projects
• Capital expenditures increased by $8.2 million or 3% to $256.3 million compared to $248.1 million in 2024
• During the fourth quarter of 2025, we completed the acquisition for 100% working interest of Perico and Espejo Blocks in the Oriente Basin in Ecuador for cash consideration of $8.3 million, deferred payment of $3.1 million and $1.1 million contingent consideration payable upon achieving 2.0 million barrels of crude oil production in the Perico Block
• In February 2025, the Colombian government introduced a temporary 1% excise tax on the first sale or export of crude oil pursuant to a declared state of internal emergency, effective through December 31, 2025. On October 16, 2025, the Colombian Constitutional Court upheld the validity of the emergency tax measures, including the excise tax on hydrocarbons, subject to a cap on total collections. The Court confirmed that the tax remains payable during its effective period and that any amounts collected in excess of the authorized budget must be refunded to taxpayers on a proportional basis following reporting by the Colombian tax authority. The determination of whether excess collections exist is expected to occur after the end of the tax period, once the tax authority completes its reporting of total collections. Accordingly, while we were required to comply with the tax through December 31, 2025, any potential refund would be assessed thereafter and cannot be determined at this time.
(Thousands of U.S. Dollars, unless otherwise noted)
Year Ended December 31,
% Change
% Change
SEC Compliant Reserves, NAR (MMBOE)
Estimated proved oil and gas reserves
Estimated probable oil and gas reserves
Estimated possible oil and gas reserves
Average Consolidated Daily Volumes (BOEPD)
Working interest (“WI”) production before royalties
Royalties
Production NAR
Increase in inventory
Sales (1)
Net (Loss) Income
Operating Netback
Gross Profit
Depletion and Accretion
Operating netback (2)
G&A Expenses Before Stock-Based Compensation
G&A Stock-Based Compensation
Adjusted EBITDA (2)
Net Cash Provided By Operating Activities
Funds Flow From Operations (2)
Capital Expenditures
As at December 31,
(Thousands of U.S. Dollars)
% Change
% Change
Cash and cash equivalents
Credit facility
Senior Notes
(1) Sales volumes represent production NAR adjusted for inventory changes
(2) Non-GAAP measures
Gross profit is derived from oil, gas and NGL sales, less operating and transportation expenses, and depletion and accretion related to producing assets. Gross profit does not include depreciation of administrative assets, asset impairment, general and administrative expenses, interest, taxes or other non-operating items.
Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under U.S. General Accepted Accounting Principles (“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 gross profit to operating netback is provided in the table below.
Year Ended
Three Months Ended
Colombia
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Gross Profit (Loss)
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)
Operating netback (non-GAAP)
(*) Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $199.4 million, $211.2 million and $207.3 million, less depreciation of administrative assets of $13.1 million, $11.9 million and $6.5 million, respectively. For the three months ended December 31, 2025 and 2024, calculated as DD&A expenses of $53.3 million and $51.1 million, less depreciation of administrative assets of $3.9 million and $3.3 million, respectively. For the prior quarter, calculated as DD&A expenses of $47.0 million, less depreciation of administrative assets of $2.9 million.
Year Ended
Three Months Ended
Ecuador
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Gross Profit (Loss)
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)
Operating netback (non-GAAP)
(*) Calculated as DD&A expenses for the year ended December 31, 2025, of $29.9 million, less depreciation of administrative assets of $0.3 million and the same as DD&A expenses for the years ended December 31, 2024 and 2023. For the three months ended December 31, 2025 of $5.5 million less depreciation of administrative assets of $0.3 million and the same as DD&A expenses for the three months ended December 31, 2024, and the prior quarter.
Year Ended
Three Months Ended
Canada
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Gross Profit (Loss)
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)
Operating netback (non-GAAP)
(*) Same as DD&A expenses for the year ended December 31, 2025 and 2024, three months ended December 31, 2025 and 2024 and the prior quarter.
Year Ended
Three Months Ended
Total Consolidated
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Gross Profit
Adjustments to reconcile gross profit to operating netback
Depletion and accretion (*)
Operating netback (non-GAAP)
(*) Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $278.4 million, $230.6 million and $215.6 million, less depreciation of administrative assets of $13.8 million, $12.2 million and $6.8 million, respectively. For the three months ended December 31, 2025 and 2024 of $72.5 million and $63.4 million, less depreciation of administrative assets of $4.3 million and $3.3 million, respectively. For the prior quarter, calculated as DD&A expenses of $65.0 million, less depreciation of administrative assets of $3.1 million.
EBITDA, as presented, is defined as net income (loss) 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 asset impairment, non-cash lease expense, lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, transaction costs, other non-cash gains or losses, and stock-based compensation expense. 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 a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:
Year Ended
Three Months Ended
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Net (loss) income
Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA
DD&A expenses
Interest expense
Income tax (recovery) expense
EBITDA (non-GAAP)
Asset impairment
Non-cash lease expense
Lease payments
Foreign exchange loss (gain)
Unrealized derivative instruments (gain) loss
Transaction costs
Other non-cash (gain) loss
Stock-based compensation expense
Adjusted EBITDA (non-GAAP)
Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, and other non-cash gains or losses. 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. Free cash flow, as presented, is defined as funds flow from operations less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income () to funds flow from operations and free cash flow is as follows:
Year Ended
Three Months Ended,
December 31,
December 31,
September 30,
(Thousands of U.S. Dollars)
Net income (loss)
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses
Asset impairment
Deferred tax (recovery) expense
Stock-based compensation expense
Amortization of debt issuance costs
Non-cash interest
Non-cash lease expense
Lease payments
Unrealized foreign exchange loss (gain)
Unrealized derivative instruments (gain) loss
Other non-cash (gain) loss
Funds flow from operations (non-GAAP)
Capital expenditures
Free cash flow (non-GAAP)
Consolidated Results of Operations
Year Ended December 31,
(Thousands of U.S. Dollars)
% Change
% Change
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Operating netback (1)
Export tax
DD&A expenses
Asset impairment
G&A expenses before stock-based compensation
G&A stock-based compensation expense
Transaction costs
Foreign exchange loss (gain)
Derivative instruments (gain) loss
Other financial instruments loss
Interest expense
Other gain (loss)
Interest income
(Loss) income before income taxes
Current income tax expense
Deferred income tax (recovery) expense
Total income tax (recovery) expense
Net (loss) income
Sales Volumes (NAR)
Total sales volumes, BOEPD
Brent Price per boe
WTI Price per boe
AECO Price per GJ
Consolidated Results of Operations per boe Sales Volumes (NAR)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Operating netback (1)
Export tax
DD&A expenses
Asset impairment
G&A expenses before stock-based compensation
G&A stock-based compensation expense
Transaction costs
Foreign exchange loss (gain)
Derivative instruments (gain) loss
Interest expense
Other gain (loss)
Interest income
(Loss) income before income taxes
Current income tax expense
Deferred income tax (recovery) expense
Total income tax (recovery) expense
Net (loss) income
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD
Year Ended December 31,
Average Daily Volumes (BOEPD) - Colombia
WI production before royalties
Royalties
Production NAR
(Increase) decrease in inventory
Sales
Royalties, % of working interest production before royalties
Year Ended December 31,
Average Daily Volumes (BOEPD) - Ecuador
WI production before royalties
Royalties
Production NAR
Increase in inventory
Sales
Royalties, % of working interest production before royalties
Year Ended December 31,
Average Daily Volumes (BOEPD) - Canada
WI production before royalties
Royalties
Production NAR
Increase in inventory
Sales
Royalties, % of working interest production before royalties
Year Ended December 31,
Average Daily Volumes (BOEPD) - Total Company
WI production before royalties
Royalties
Production NAR
Increase in inventory
Sales
Royalties, % of working interest production before royalties
Oil, natural gas and NGL production NAR for the year ended December 31, 2025, increased by 38% to 38,443 BOEPD compared to 27,890 BOEPD in 2024. The increase in production was a result of positive exploration well drilling in Ecuador, full-year production from the Canadian operations acquired on October 31, 2024, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions, and trunk line repairs in the Moqueta field which resulted in the field being shut-in during the third quarter.
Oil production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023. The increase in production was a result of two months production from Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador, partially offset by lower production in the Acordionero field caused by downtime related to workovers.
Royalties as a percentage of production for the year ended December 31, 2025, decreased 4% compared to 2024 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia, Ecuador, and Canada. Royalties as a percentage of production for the year ended December 31, 2024, were comparable to 2023.
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, Iguana, Chanangue and Perico Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada.
Commodity prices:
Colombia and Ecuador
Brent - For the year ended December 31, 2025, Brent price decreased by 15% compared to 2024 as a result of excess global oil supply and the gradual unwinding of the previously curtailed OPEC production volumes while Castilla, Vasconia and Oriente
differentials decreased to $5.36, $2.31 and $7.63 compared to $8.54, $4.78 and $8.75 in 2024 primarily as a result of decreased supply of heavier crude oil.
For the year ended December 31, 2024, Brent price decreased by 17% compared to 2023 and Castilla, Vasconia and Oriente differentials decreased to $8.54, $4.78 and $8.75 from $10.22, $5.39 and $9.91 in 2023.
During the years ended December 31, 2025, 2024 and 2023, 100% of sales from South America were oil, priced against Brent.
Canada
We entered Canada with the acquisition of i3 Energy which closed on October 31, 2024, and as a result, we only have two months of comparative data available for the corresponding period of 2024, and no comparative data available for 2023.
WTI - For the year ended December 31, 2025, WTI decreased 7% compared to the two month period of operations in 2024. For the year ended December 31, 2025, 25% of NAR production in Canada was oil, compared with 21% during the two month period of 2024.
NGLs - For the year ended December 31, 2025, the weighted average NGL price received was 11% of WTI, consistent with the two month period of 2024. For the year ended December 31, 2025, 24% of NAR production in Canada was NGLs, compared to 27% during the two month period of 2024.
AECO - For the year ended December 31, 2025, AECO price increased 2% compared to the two month period of 2024 averaging $1.56 per mcf. For the year ended December 31, 2025, 51% of NAR production in Canada was natural gas, compared to 52% during the two month period of 2024.
Oil, Natural Gas and NGL Sales
Oil, natural gas and NGL sales for the year ended December 31, 2025, decreased by 4% to $596.7 million compared to $621.8 million in 2024, primarily as a result of a 15% decrease in Brent price, a 15% decrease in sales volumes in Colombia, offset by higher sales volumes in Ecuador, lower differentials, and the full year of sales from Canadian operations of $115.7 million in 2025 compared to the two month period in 2024 of $19.0 million.
On a per boe basis, the average realized price for Colombia decreased by 14% to $56.54 for the year ended December 31, 2025, compared to $65.80 in 2024, primarily as a result of 15% decrease in Brent price.
On a per boe basis, the average realized price for Ecuador decreased by 11% to $61.53 for the year ended December 31, 2025, compared to $68.80 in 2024, primarily as a result of 15% decrease in Brent price and lower differentials.
On a per boe basis, the average realized price for Canada increased by 3% to $21.71 for the year ended December 31, 2025, compared to $21.14 in 2024, primarily as a result of royalties adjustments during the year, partially offset by the decrease in benchmark oil and gas prices.
On a consolidated basis, the average realized price decreased by 30% to $43.41 per boe for the year ended December 31, 2025, compared to $61.93 in 2024, r eflecting the structural impact of adding Canadian operations which carry wider benchmark differentials and transportation costs.
Oil, natural gas and NGL sales for the year ended December 31, 2024, decreased by 2% to $621.8 million compared to $637.0 million in 2023, primarily as a result of a 3% decrease in Brent price and 6% decrease in sales volumes in Colombia, offset by
an increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024.
On a per boe basis, the average realized price decreased by 8% to $61.93 for the year ended December 31, 2024, compared to $67.26 in 2023, primarily as a result of the decrease in benchmark oil prices and the addition of two months of natural gas and liquids to the portfolio in 2024 through the i3 Energy acquisition.
The following table shows the effect of changes in realized price and sales volumes on our oil, natural gas and NGL sales for the years ended December 31, 2025, 2024, and 2023:
Year Ended December 31,
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales for the comparative year
Realized sales price decrease effect
Sales volumes (decrease) increase effect
Oil, natural gas and NGL sales change - Canada operations
Oil, natural gas and NGL sales for the current year
Operating Expenses
Operating expenses for the year ended December 31, 2025, increased by 23% to $248.7 million compared to $202.3 million in 2024 due to higher operating costs in Ecuador as a result of production ramp-up in 2025 and the full year of Canadian operations compared to only two months in the corresponding period of 2024. On a per boe basis, operating expenses decreased by 10% or by $2.06 ($1.43 lower workovers and $0.63 lower power generation) to $18.09 compared to $20.15 in the prior year as a result of higher NAR sales in Ecuador and Canada in 2025.
Operating expenses for the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023. On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 in 2024 compared to $19.73 in 2023, primarily as a result of $0.48 higher workovers, removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador.
Transportation Expenses
We have options to sell our oil, natural gas and NGL through multiple pipelines and, in Colombia, trucking routes. Each transportation route has varying effects on realized 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 transportation method for each of the last three years ending December 31, 2025:
Year Ended December 31,
Volume transported through pipelines
Volume sold at wellhead
Volume transported via truck to pipelines
Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense as transportation costs are netted against the sales price. Volumes sold in Ecuador and Canada are transported via pipeline and trucks. We focus on maximizing operating netback (1) per boe when choosing a transportation method.
Transportation expenses for the year ended December 31, 2025, decreased b y 8% to $17.0 million or by $0.60 to $1.24 per boe compared to $18.5 million or $1.84 per boe in 2024, as a result of full year of operations in Canada which had lower transportation costs per boe, and a shift to lower-cost delivery points in Colombia.
Transportation expenses for the year ended December 31, 2024, increased b y 27% to $18.5 million or by $0.30 to $1.84 per boe compared to $14.5 million or $1.54 per boe in 2023, as a result of higher sales volumes transported in Ecuador, two months of transporting sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024.
The following table shows the variance in our average realized price net of transportation expenses in Colombia, Ecuador and Canada for each of the three years ended December 31, 2025:
Colombia
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price
Average realized price, net of transportation expenses for the comparative period
Decrease in benchmark prices
Decrease in quality and transportation discounts
Decrease (increase) in transportation expense
Average realized price, net of transportation expenses for the year
Average realized price, net of transportation expenses as a % of Brent
Ecuador
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price
Average realized price, net of transportation expenses for the comparative period
Decrease in benchmark prices
Decrease (increase) in quality and transportation discounts
Decrease (increase) in transportation expense
Average realized price, net of transportation expenses for the year
Average realized price, net of transportation expenses as a % of Brent
Canada
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Average WTI price
Average realized price, net of transportation expenses for the comparative period
Decrease in benchmark prices
Decrease in quality and transportation discounts
Decrease in transportation expense
Average realized price, net of transportation expenses for the year
Average realized price, net of transportation expenses as a % of WTI
Total Company
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Average Brent price
Average realized price, net of transportation expenses for the comparative period
Decrease in benchmark prices
(Increase) decrease in quality and transportation discounts
Decrease (increase) in transportation expense
Average realized price, net of transportation expenses for the year
Average realized price, net of transportation expenses as a % of Brent
Gross Profit
Colombia
Year Ended December 31,
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion (*)
Gross profit
(*) Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $199.4 million, $211.2 million and $207.3 million, less depreciation of administrative assets of $13.1 million, $11.9 million and $6.5 million, respectively.
Colombia
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion
Gross profit
Ecuador
Year Ended December 31,
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion (*)
Gross profit (loss)
(*) Calculated as DD&A expenses for the year ended December 31, 2025, of $29.9 million, less depreciation of administrative assets of $0.3 million. and the same as DD&A expenses for the years ended December 31, 2024 and 2023.
Ecuador
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion
Gross profit (loss)
Canada
Year Ended December 31,
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion (*)
Gross profit (loss)
(*) Same as DD&A expenses for the years ended December 31, 2025 and 2024.
Canada
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion
Gross profit (loss)
Total Company
Year Ended December 31,
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion (*)
Gross profit
(*) Calculated as DD&A expenses for the year ended December 31, 2025, 2024 and 2023 of $278.4 million, $230.6 million and $215.6 million, less depreciation of administrative assets of $13.8 million, $12.2 million and $6.8 million, respectively.
Total Company
Year Ended December 31,
(U.S. Dollars per boe Sales Volumes NAR)
Oil, natural gas and NGL sales
Operating expenses
Transportation expenses
Depletion and accretion
Gross profit
Operating Netbacks
Year Ended December 31,
Colombia
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Transportation expenses
Operating expenses
Operating netback (1)
(U.S. Dollars per boe Sales Volumes NAR)
Brent
Quality and transportation discounts
Average realized price
Transportation expenses
Average realized price, net of transportation expenses
Operating expenses
Operating netback (1)
Year Ended December 31,
Ecuador
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Transportation expenses
Operating expenses
Operating netback (1)
(U.S. Dollars per boe Sales Volumes NAR)
Brent
Quality and transportation discounts
Average realized price
Transportation expenses
Average realized price, net of transportation expenses
Operating expenses
Operating netback (1)
Year Ended December 31,
Canada
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Transportation expenses
Operating expenses
Operating netback (1)
(U.S. Dollars per boe Sales Volumes NAR)
Average realized price
Transportation expenses
Average realized price, net of transportation expenses
Operating expenses
Operating netback (1)
Year Ended December 31,
Total Company
(Thousands of U.S. Dollars)
Oil, natural gas and NGL sales
Transportation expenses
Operating expenses
Operating netback (1)
(U.S. Dollars per boe Sales Volumes NAR)
Brent
Quality and transportation discounts
Average realized price
Transportation expenses
Average realized price, net of transportation expenses
Operating expenses
Operating netback (1)
(1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
DD&A Expenses
Year Ended December 31, 2025
Colombia
Ecuador
Canada
Corporate
Total
DD&A Expenses, Thousands of U.S. Dollars
DD&A Expenses, U.S. Dollars per boe
Year Ended December 31, 2024
Colombia
Ecuador
Canada
Corporate
Total
DD&A Expenses, Thousands of U.S. Dollars
DD&A Expenses, U.S. Dollars per boe
Year Ended December 31, 2023
Colombia
Ecuador
Canada
Corporate
Total
DD&A Expenses, Thousands of U.S. Dollars
DD&A Expenses, U.S. Dollars per boe
DD&A expenses for the year ended December 31, 2025, increased by 21% from 2024 due to higher production in Ecuador and full year of DD&A from Canadian operations. On a per boe basis, the DD&A decreased by $2.72 due to a higher mix of Canadian NAR sales which have a lower depletion rate.
DD&A expenses for the year ended December 31, 2024, increased by 7% or $0.21 per boe from 2023. On a per boe basis, the DD&A increase in 2024 was due to increased production relative to reserve additions in Ecuador, two months of DD&A expense from Canadian operations, and higher costs in the depletable base as a result of higher future development costs compared to 2023.
Asset Impairment
As at December 31,
(Thousands of U.S. Dollars)
Impairment of oil and gas properties - Canada
Impairment of oil and gas properties - Colombia
For the year ended December 31, 2025, we 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. We follow the full cost method of accounting for our 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 our reserves. In accordance with GAAP, we used unweighted arithmetic average of the first-day-of-the-month prices as follows: Brent price of $69.38 p er 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).
G&A Expenses
(Thousands of U.S. Dollars)
Year Ended December 31,
% change
% change
G&A expenses before stock-based compensation
G&A stock-based compensation
G&A expenses including stock-based compensation
(U.S. Dollars Per boe Sales Volumes NAR)
G&A expenses before stock-based compensation
G&A stock-based compensation
G&A expenses including stock-based compensation
G&A expenses before stock-based compensation for the year ended December 31, 2025 increased 37% compared to 2024, as a result of a full year of G&A from 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 year ended December 31, 2025, was comparable with 2024.
G&A expenses before stock-based compensation for the year ended December 31, 2024, increased 3% to $41.4 million as a result of higher severance costs and the addition of two months of G&A from Canadian operations acquired through the i3 acquisition, partially offset by lower business development, legal and consulting costs compared to 2023.
G&A expenses before stock-based compensation, on a per boe basis, for the year ended December 31, 2024, decreased by 3% to $4.13 compared to 2023, as a result of higher NAR sales volumes during 2024.
G&A expenses after stock-based compensation for the year ended December 31, 2025, increased by 17% to $60.1 million, compared to 2024 for the same reason mentioned above, partially offset by lower stock-based compensation attributable to the lower share price in 2025.
G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 12% to $51.1 million compared to 2023 due to higher stock-based compensation attributable to the higher share price in 2024.
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2025, decreased by 14% to $4.37 compared to 2024 due to a 37% increase in sales volumes.
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2024, increased by 5% to $5.10 per boe compared to 2023 due to a 62% increase in stock-based compensation attributable to higher share price in 2024.
Foreign Exchange Losses (Gains)
For the years ended December 31, 2025, 2024 and 2023, we had an $8.7 million loss, $8.8 million gain and $11.8 million loss on foreign exchange, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.
The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the last three years ended December 31, 2025:
Year Ended December 31,
Change in the U.S. dollar against the Colombian peso
weakened by
strengthened by
weakened by
Change in the U.S. dollar against the Canadian dollar
weakened by
strengthened by
weakened by
Financial Instruments Gains or Losses
The following table presents the nature of our financial instruments gains or losses for each of the three years ended December 31, 2025:
Year Ended December 31,
(Thousands of U.S. Dollars)
Commodity price derivative (gain) loss
Foreign currency derivative gain
Electricity price derivative loss
Derivative instruments (gain) loss
Income Tax Expense and Recovery
Year Ended December 31,
(Thousands of U.S. Dollars)
(Loss) income before income taxes
Current income tax expense
Deferred income tax (recovery) expense
Total income tax (recovery) expense
Effective tax rate
Current income tax expense for the year ended December 31, 2025, was $15.9 million (2024 - $69.3 million; 2023 - $55.7 million). Current income tax expense decreased for the year ended December 31, 2025, compared to 2024, primarily due to the lower taxable income generated in Colombia.
The deferred income tax expense was a recovery of $55.6 million for the year ended December 31, 2025, primarily as a result of the recognition of additional tax losses from Colombia.
The deferred income tax expense was a recovery of $27.9 million for the year ended December 31, 2024, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy, which were partially offset by tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia. The deferred income tax expense of $56.8 million for the year ended December 31, 2023 was primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.
Our effective tax rate was 17% for the year ended December 31, 2025, compared to 93% in 2024. The decrease in the effective tax rate was primarily due to a decrease in valuation allowance and impact of foreign taxes, partially offset by an increase in non-deductible foreign exchange adjustments and other permanent differences.
Our effective tax rate was 93% for the year ended December 31, 2024, compared with 106% in 2023. The decrease in the effective tax rate was primarily due to a decrease in non-deductible foreign exchange adjustments, 2022 true-up related to tax planning strategy, other permanent differences and impact of foreign taxes. These were partially offset by an increase in valuation allowance.
The difference between our effective tax rate of 17% for the year ended December 31, 2025, and the 21% US statutory tax rate was primarily due to non-deductible foreign exchange adjustments and other permanent differences partially offset by the impact of foreign taxes.
The difference between our effective tax rate of 93% for the year ended December 31, 2024, and the 21% US statutory rate was primarily due to the impact of foreign taxes, valuation allowance, non-deductible royalties in Colombia, other permanent differences and non-deductible stock-based compensation. These were partially offset by a 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments.
During the year ended December 31, 2024, we strategically revised our 2022 tax return to use our tax receivable balance to offset current tax liabilities, rather than applying net operating loss carryforwards. This decision was driven by the expectation of higher future income tax rates and increased profitability. As a result, there was an increase in current tax expense of approximately $27.8 million which was offset by long-term tax receivable, ensuring no impact on cash flows. This approach preserved the Company’s net operating loss carryforward for future periods, providing greater tax benefits and flexibility in recovering tax receivables, while strengthening our equity position.
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 21% US statutory was primarily due to the impact of foreign taxes, non-deductible foreign exchange adjustments, other permanent differences, non-deductible royalties in Colombia and non-deductible stock-based compensation.
Net Income (Loss) and Funds Flow From Operations (a Non-GAAP Measure)
(Thousands of U.S. Dollars)
Fourth quarter 2025 compared with third quarter 2025
% change
Fourth quarter 2025 compared with fourth quarter 2024
% change
Year ended December 31, 2025 compared with year ended December 31, 2024
% change
Net (loss) income for the comparative period
Increase (decrease) due to:
Sales volumes
Prices
Sales from acquisition
Expenses:
Cash operating expenses
Transportation
Export tax
Cash G&A, excluding stock-based compensation expense
Interest, net of amortization of debt issuance costs
Non-cash interest
Realized foreign exchange gain (loss)
Transaction costs
Settlement of financial instruments
Other gain (loss)
Current taxes
Net lease payments
Interest income
Net change in funds flow from operations (1) from comparative period
Expenses:
Depletion, depreciation and accretion
Asset impairment
Deferred tax
Amortization of debt issuance costs
Net lease payments
Stock-based compensation
Non-cash interest
Other non-cash loss
Financial instruments gain, net of financial instruments settlements
Unrealized foreign exchange (loss) gain
Net change in net (loss) income
Net loss for the current period
(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
2026 Work Program and Capital Expenditures
Our Colombian, Canadian and Ecuadorian development expenditures are expected to represent approximately 50% , 35% and 15% of our 2026 capital program.
The table below shows the break-down of our 2026 capital program:
Number of Wells
(Gross)
Number of Wells
(Net)
2026 Capital Budget
($ million)
Development - Colombia
Development - Canada
Development - Ecuador
Our base capital program for 2026 is $120 million to $160 million with over 90% attributed to development activities. Based on the mid-point of the 2026 guidance, approximately 20% of the development activities included in the 2026 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
We expect cash flows from operations to fully fund our 2026 capital program, assuming average Brent oil prices of $65.00 per boe, WTI oil prices of $61.00 per boe and average AECO natural gas prices of C$3.00 per mcf, together with expected production of 42,000 to 47,000 boepd.
We commenced the execution of our 2026 capital program as planned, and as of February 27, 2026, we drilled one well in the Cohembi field in Colombia and three wells in the Simonette area in Canada. Subsequent to December 31, 2025, the entire interest in Simonette was divested.
Capital Program
Capital expenditures during the year ended December 31, 2025 were $256.3 million.
(Millions of U.S. Dollars)
Colombia
Ecuador
Canada
Total
Exploration:
Drilling and Completions
Civil Works
Other
Total Exploration
Development:
Drilling and Completions
Facilities
Civil Works
Other
Total Development
Total Company
During the year ended December 31, 2025, we spud the following wells in Colombia, Ecuador and Canada:
Number of Wells
Gross
Net
Colombia
Exploration
Productive
Dry
Development
Productive
Dry
Service
In-progress
Ecuador
Exploration
Productive
In-progress
Canada
Development
Productive
Service
Total
In 2025, we drilled eight development, one service and three exploration wells in Colombia, four exploration wells in Ecuador, and five development and one service well in Canada. Of the wells drilled in Colombia, seven were drilled in the Suroriente Block, three in the Chaza Block, one in the Llanos-85 Block and one in the Alea 1848-A Block. In Ecuador, two wells were drilled in the Charapa Block and two in the Iguana Block. In Canada, we drilled six wells, four of which were in our Simonette acreage and two in our Clearwater acreage. As at December 31, 2025, of the exploration and development wells drilled, sixteen were producing, two were service, three were dry, and one well was in-progress.
Liquidity and Capital Resources
As at December 31,
(Thousands of U.S. Dollars)
% Change
% Change
Cash and cash equivalents
Credit facility
Senior Notes
We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to maintain current operations and execute the capital program for the next 12 months and beyond, given current oil and natural gas price trends and production levels. 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 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, be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.
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, we 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 remained undrawn.
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 (the “RBL facility”). Any loans incurred under the reserve-based lending 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 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 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 the Company are in excess of $20.0 million.
Under the terms of the RBL 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
We were in compliance with all applicable covenants related to the RBL facility as of December 31, 2025.
During 2025, we drew $34.5 million under the facility, which was fully repaid, and as of December 31, 2025, the RBL facility remained undrawn. Subsequent to year end, we terminated the RBL Facility. 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.
Senior Notes
At December 31, 2025, we 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 9.50% Senior Notes bear interest at a rate of 9.50% per annum, payable semi-annually in arrears on April 15 and October 15 of each year, beginning on April 15, 2024. The 9.50% 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 of 40%.
Under the terms of 9.50% Senior Notes agreement, we are 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.
During the year ended December 31, 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.
During the year ended December 31, 2025, we 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, which included the write-off of deferred financing fees of $1.4 million.
We were in compliance with all applicable covenants related to Senior Notes as of December 31, 2025.
Subsequent to December 31, 2025, we completed an exchange of 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 early participation deadline of February 11, 2026, included 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, we 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, we 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%.
As of February 27, 2026, we had outstanding aggregate principal amounts of $24.2 million of our 7.50% Senior Notes due 2027, $87.6 million of our 9.50% Senior Notes due 2029 and $503.6 million of our 9.75% Senior Notes due 2031.
Prepayment agreements
In the fourth quarter of 2025, we executed a prepayment agreement with Trafigura, our purchaser of crude oil. The prepayment agreement requires Gran Tierra to sell and deliver all production from our 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 up to $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. 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, we can repay the outstanding balance of the advance payment at any time without penalty. We were granted a six-month grace period for repayment of the principal amount drawn under the prepayment agreement with first re-payment starting April 2026.
Under the terms of the prepayment agreement, we are required to maintain compliance with the following financial covenants:
i. Asset Coverage Ratio of at least 150%, calculated using the net present value of the consolidated future cash flows of our 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.
Subsequent to December 31, 2025, we amended the existing prepayment agreement to include both Ecuadorian and Colombian oil production and ability to upsize the prepayment amount to $350 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
• $25.0 million additional, 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 will amend and restate 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.
Production sharing agreement (“PSA”)
Subsequent to December 31, 2025, we, through our wholly owned subsidiary, Gran Tierra Energy (Azerbaijan) GmbH, entered into an exploration, development and PSA with the State Oil Company of Azerbaijan Republic (“SOCAR”), providing for a 65% participating interest to us and a 35% participating interest to SOCAR. The PSA provides for a five-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 of two exploration wells, and the conduct of geological and environmental impact studies. We have 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.
Disposition of Simonette area
Subsequent to December 31, 2025, we entered into the agreement to dispose of 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.
Share Repurchase Program, NCIB
During the year ended December 31, 2025, we implemented a share re-purchase program (the “2025 Program”) through the facilities of the TSX, the NYSE or alternative trading programs in Canada or the United States, if eligible. Under the 2025 Program, we are 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, we re-purchased 692,804 shares at a weighted average price of $5.00 per share under the 2024 Program implemented in 2024 with similar terms to that of 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 and no shares were repurchased under 2025 Program.
Acquisitions and Dispositions
On December 9, 2025, we 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 was 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 the earlier of the approval of the amended Consortium agreement by Hydrocarbons Committee or December 8, 2026. We are expecting to reach 2.0 million barrels of cumulative production from the Perico Block in approximately 3 years.
During the year ended December 31, 2025, we, through our wholly owned subsidiary, Gran Tierra UK Limited, a United Kingdom limited company, completed the sale agreement for its wholly owned subsidiary, Gran Tierra North Sea Limited (“GTNSL”) to NEO Energy for total consideration of $7.5 million. GTNSL held a 100% equity interest in United Kingdom Continental Shelf licence P2358, which includes the Serenity discovery. The transaction was subject to customary closing conditions, including regulatory approval from the North Sea Transition Authority, all of which were satisfied prior to closing. We applied the deferred income tax asset associated with GTNSL, with a carrying value of $7.5 million, against the total consideration received, resulting in no gain or loss recognized on the sale.
Cash and Cash Equivalents Held Outside of Canada and the United States
At December 31, 2025 , 100% of our cash and cash equivalents was held in Canada and the United States.
Cash Flows
The following table presents our sources and uses of cash and cash equivalents for the periods presented:
Year Ended December 31,
Sources of Cash and Cash Equivalents:
Net (loss) income
Adjustments to reconcile net (loss) income to funds flow from operations
DD&A expenses
Asset impairment
Deferred tax (recovery) expense
Stock-based compensation expense
Amortization of debt issuance costs
Unrealized foreign exchange loss (gain)
Non-cash interest expense
Other non-cash (gain) loss
Unrealized derivative instruments (gain) loss
Non-cash lease expenses
Lease payments
Funds flow from operations (1)
Proceeds from issuance of Senior Notes, net of issuance costs
Changes in non-cash operating working capital
Proceeds from exercise of stock options
Proceeds from debt, net of issuance costs
Proceeds on disposition of property, plant and equipment
Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents
Uses of Cash and Cash Equivalents:
Additions to property, plant and equipment
Cash paid for business combinations, net of cash acquired
Cash paid for property acquisitions
Repayment of Senior Notes
Senior Notes issuance costs
Repayment of debt
Lease payments
Changes in non-cash operating working capital
Cash settlement of asset retirement obligation
Re-purchase of shares of Common Stock
Re-purchase of Senior Notes
Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents
Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents
(1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP. Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure.
Contractual Obligations
The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2025:
(Thousands of U.S. Dollars)
Total
2031 and beyond
7.75% Senior Notes
9.50% Senior Notes
Total debt
Interest and commitment fee payments (1)
Oil transportation services
Drilling and Completions
Operating leases
Finance leases
Software and Telecommunication
Total
(1) Commitment fee payments were calculated by assuming that our borrowing base on credit facilities would be available until October 2027 and April 2028 maturity dates and interest and principal payments on our 7.75% and 9.50% Senior Notes were calculated under assumption that Senior Notes would be held until their maturity dates of May 2027 and October 2029, respectively. Actual results could differ from these estimates and assumptions.
As at December 31, 2025, we had provided letters of credit and other credit support totali ng $209.0 million, of which $61.3 million was related to capital commitments in the Suroriente Block, and 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).
The above table does not reflect estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties and other long-term liabilities, as we cannot determine with accuracy the timing of such payments. Information regarding our asset retirement obligation can be found in Note 14 to the Consolidated Financial Statements, Asset Retirement Obligation, in Item 8 “Financial Statements and Supplementary Data.”
As is customary in the oil and gas industry, we may at times have commitments in place to reserve or earn certain acreage positions or wells. If we do not meet such commitments, the acreage positions or wells may be lost, and associated penalties may be payable.
Climate Change
We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 2025:
Impairment
In our impairment evaluation of unproved properties, we have 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 ceiling test impairment assessment on oil and gas properties. The estimated ceiling amount of our oil and gas properties was based on proved 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 reserves per the 2025 reserve report should be realized prior to the potential elimination of carbon-based energy.
Expenditures on property, plant and equipment
From 2018 to 2025, we incurred $23.2 million on gas-to-power facilities in the Acordionero field to reduce emissions principally by the recovery and use of natural gas in the field for power generation and reduction of diesel use for power generation. In 2025, the Acordionero field represented 29% of our oil and natural gas production. As of the end of 2025, Gran Tierra was converting gas to power at eight of our facilities located in the Acordionero, Costayaco, Moqueta, Mono Arana, Los
Angeles, Cohembi fields in Colombia, and Charapa and Chanangue Blocks in Ecuador. In total, we converted 2.6 billion standard cubic feet of natural gas into electricity instead of being flared for the year ended December 31, 2025 and have incurred capital expenditures of $45.5 million since 2018. The extent of spending on projects is directly linked to reducing the climate impact of our operations.
Established in 2017, NaturAmazonas addresses the root causes of deforestation and develops nature-based solutions for reversing the process while increasing the well-being of nearby communities. We are an industry leader in reforestation and conservation in Colombia. It has created an effective model for creating change at scale by engaging communities in protecting their environment and securing partnerships with public and private institutions, as well as stakeholders in long-term reforestation and conservation efforts. NaturAmazonas is projected to sequester approximately 8.7 million tonnes of CO2, equivalent to approximately 14 years of our 2025 Scope 1 and Scope 2 emissions 1 . We have planted over 1.9 million trees and conserved, preserved, or reforested more than 5,600 hectares of land through all of our environmental efforts to date.
1 2025 emissions are based on full year emissions from Colombia, Canada and Ecuador operations.
Current assets and current liabilities
These amounts are short-term in nature, and during the year ended December 31, 2025, management was not aware of any material impacts on these items related to climate change and climate events. We did not experience material credit losses on our accounts receivable during 2025.
Share capital
The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
Critical Accounting Policies and Estimates
The preparation of financial statements under GAAP requires management to make estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities as well as the revenues and expenses reported and disclosure of contingent liabilities. Changes in these estimates related to judgments and assumptions will occur as a result of changes in facts and circumstances or discovery of new information, and, accordingly, actual results could differ from the amounts estimated.
On a regular basis, we evaluate our estimates, judgments, and assumptions. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.
Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. The areas of accounting and the associated critical estimates and assumptions made are discussed below.
Full Cost Method of Accounting and the impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to Oil and Gas Properties.
We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8 “Financial Statements and Supplementary Data.”
Our estimates of proved oil and natural gas reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production, and the amount and timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.
We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impact oil and natural gas prices and costs change.
Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted
industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent reservoir engineering specialists.
While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas and the applicable discount rate that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling test calculation dictates that a 10% discount factor be used and future net revenues are calculated using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs but reflect adjustments for gravity, quality, local conditions, gathering and transportation fees, and distance from market. Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2025 ceiling tests were based on wellhead prices per boe as of the first day of each month within that twelve-month period.
Because the ceiling test calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Historical oil and gas prices for any particular 12-month period can be either higher or lower than our price forecast. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.
Our Reserves Committee oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reservoir engineering specialists to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reservoir engineering specialists, their independence.
For the year ended December 31, 2025 we had $136.3 million ceiling test impairment losses, none for December 31, 2024 and 2023. We used an average Brent price of $69.38 p er 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).
It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed GAAP ceiling test calculation. These factors include, but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.
Unproved Properties
Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering 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. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, seismic evaluations, the assignment of proved reserves, availability of capital and other factors. For countries where a reserve base has not yet been established, the is charged to earnings.
Asset Retirement Obligations (“ARO”)
We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.
We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, inflation factors, credit-adjusted risk-free discount rates and changes in legal, regulatory, environmental and political environments. Because costs typically extend many years into the future, estimating future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.
It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.
