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What changed in GRAN TIERRA ENERGY INC.'s 10-K — 2024 vs 2025

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Paragraph-level year-over-year comparison of GRAN TIERRA ENERGY INC.'s 2024 and 2025 10-K annual filings, covering the Business, Risk Factors, Legal Proceedings, Cybersecurity, MD&A and Market Risk sections. Every new, removed and edited paragraph is highlighted side-by-side so you can see exactly what management changed in the 2025 report.

+316 added−249 removedSource: 10-K (2026-03-04) vs 10-K (2025-02-24)

Top changes in GRAN TIERRA ENERGY INC.'s 2025 10-K

316 paragraphs added · 249 removed · 204 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

56 edited+22 added−7 removed127 unchanged
Biggest changeThe Company continually engages with its operating partners and closely monitors the operation of its assets, thorough reviews are conducted before entering into joint venture arrangements to ensure that our operational objectives are aligned with potential joint venture partner. 24 Our business is subject to local legal, social, security, political and economic factors that are beyond our control, which could impair or delay our ability to expand our operations or operate profitably All of our proved reserves and production are currently located in Colombia, Ecuador and Canada; however, we may eventually expand to other countries.
Biggest changeOur business is subject to local legal, social, security, political and economic factors that are beyond our control, which could impair or delay our ability to expand our operations or operate profitably All of our proved reserves and production are currently located in Colombia, Ecuador and Canada; however, we have recently entered into an exploration, development and production sharing agreement with SOCAR and may eventually expand our operations into Azerbaijan and other countries.
Current and forward contract oil natural gas prices are based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels, geopolitical unrest, world health events and other factors, all of which are beyond our control. Historically, the market for oil and natural gas has been volatile and is expected to remain so.
Current and forward contract oil and natural gas prices are based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels, geopolitical unrest, world health events and other factors, all of which are beyond our control. Historically, the market for oil and natural gas has been volatile and is expected to remain so.
The market price for shares of our Common Stock may be influenced by many factors, some of which are beyond our control, including those described above and the following: • strategic actions or announcements by us of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments; • general economic and stock market conditions; 31 • volatility in commodity prices; • risks related to our business and our industry, including those discussed above; • changes in conditions or trends in our industry, markets or customers; • geopolitical events or terrorist acts; • trading volume of our Common Stock; • future sales of shares of our Common Stock or other securities by us, members of our management team or our existing shareholders; and • investor perceptions of the investment opportunity associated with our industry or securities relative to other investment alternatives.
The market price for shares of our Common Stock may be influenced by many factors, some of which are beyond our control, including those described above and the following: • strategic actions or announcements by us of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments; • general economic and stock market conditions; • volatility in commodity prices; • risks related to our business and our industry, including those discussed above; • changes in conditions or trends in our industry, markets or customers; • geopolitical events or terrorist acts; • trading volume of our Common Stock; • future sales of shares of our Common Stock or other securities by us, members of our management team or our existing shareholders; and • investor perceptions of the investment opportunity associated with our industry or securities relative to other investment alternatives.
The extent to which our business, results of operations and financial 27 condition will be affected by such events depend on future developments, many of which are outside of our control, such as the duration, severity, and sustained geographic spread of the virus, and the impact and effectiveness of governmental actions to contain and treat outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties.
The extent to which our business, results of operations and financial condition will be affected by such events depend on future developments, many of which are outside of our control, such as the duration, severity, and sustained geographic spread of the virus, and the impact and effectiveness of governmental actions to contain and treat outbreaks, including government policies and restrictions; vaccine hesitancy, vaccine mandates, and voluntary or mandatory quarantines; and the global response surrounding such uncertainties.
Notwithstanding the Peace Agreement ratified and the ongoing efforts to implement such Agreements, increased eradication by the Colombian government of illicit crops, as well as the continuing attempts by the Colombian government to reduce or prevent activity of guerrilla dissidents and of farmers, such efforts may not be successful and such activity may continue to disrupt our operations in the future or cause us higher security costs and could adversely impact our financial condition, results of operations or cash flows.
Notwithstanding the Peace Agreement ratified and the ongoing efforts to implement such agreements, increased eradication by the Colombian government of illicit crops, as well as the continuing attempts by the Colombian government to reduce or prevent activity of guerrilla dissidents and of farmers, such efforts may not be successful and such activity may continue to disrupt our operations 26 in the future or cause us higher security costs and could adversely impact our financial condition, results of operations or cash flows.
Environmental laws and regulations in the countries in which we operate provide for, among other things, restrictions and prohibitions on spills, releases or 29 emissions of various substances used or produced in association with oil and gas operations. These regulations also require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.
Environmental laws and regulations in the countries in which we operate provide for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances used or produced in association with oil and gas operations. These regulations also require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities.
Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase operating and capital costs.
Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These 24 constraints and the resulting shortages or high costs could delay our operations and materially increase operating and capital costs.
We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance our ESG initiatives. Our disclosures on these matters rely on management’s expectations as of the date the statements are first made, as 28 well as standards for measuring progress that are still in development, and may change or fail to be realized.
We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance our ESG initiatives. Our disclosures on these matters rely on management’s expectations as of the date the statements are first made, as well as standards for measuring progress that are still in development, and may change or fail to be realized.
During the winter months in Canada, heavy snow, ice, or rain may 25 adversely affect our ability to operate. Also, during the spring thaw, which normally starts in late March and continues through June, some areas in Canada may impose transportation restrictions to prevent damage caused by the spring thaw.
During the winter months in Canada, heavy snow, ice, or rain may adversely affect our ability to operate. Also, during the spring thaw, which normally starts in late March and continues through June, some areas in Canada may impose transportation restrictions to prevent damage caused by the spring thaw.
Finally, new projects or the expansion of existing projects may be dependent on securing licenses for additional water withdrawal, and there can be no assurance that these licenses will be granted on favorable terms, or at all, or that such additional water will in fact be available to divert under such licenses.
Finally, new projects or the expansion of existing projects may be 23 dependent on securing licenses for additional water withdrawal, and there can be no assurance that these licenses will be granted on favorable terms, or at all, or that such additional water will in fact be available to divert under such licenses.
The surface water resources of some of the regions in Canada where we aspire to operate may be insufficient for the full commercial-scale development of the region at a pace matching the industry's ambitions. Thus, limitations on water access may present a ceiling on the allowed pace of development.
The surface water resources of some of the regions in Canada where we operate and aspire to operate may be insufficient for the full commercial-scale development of the region at a pace matching the industry's ambitions. Thus, limitations on water access may present a ceiling on the allowed pace of development.
The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.
The value of our securities and our 22 ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.
Future oil and natural gas exploration may involve unprofitable 22 efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.
The complexities of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, and global competition for oil and gas resources make certain information attractive to thieves.
The complexities of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, and global competition for oil and gas resources make certain 27 information attractive to thieves.
Further, if oil or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital.
Further, if oil or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased 28 revenues may increase our requirements for capital.
There can be no assurance that future political conditions in Colombia and Ecuador will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities.
There can be no assurance that future political conditions in Colombia, Ecuador, Canada and Azerbaijan will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities.
For example, on an international level, in December 2015, almost 200 nations, including Canada, Colombia and, by ratification in July 2017, Ecuador, agreed to an international climate change agreement in Paris, France (the “Paris Agreement”), that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets.
For example, on an international level, in December 2015, almost 200 nations, including Canada, Colombia and, by ratification in January 2017, Azerbaijan, and by ratification in July 2017, Ecuador, agreed to an international climate change agreement in Paris, France (the “Paris Agreement”), that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets.
In the areas where the Company operates as non-operating partner it may have limited control over the day-to-day management or operations of these assets. A third-party mismanagement of an asset may result in significant delays, materially increased costs or liabilities to the Company over which the Company is joint and severally liable.
In the areas where the Company operates as non-operating partner it may have limited control over the day-to-day management or operations of these assets. A third-party mismanagement of an asset may result in significant delays, materially increased costs or liabilities to the Company over which the Company is jointly and severally liable.
While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting our assets. Colombia and Ecuador also both have a history of security problems.
While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting our assets. Colombia and Ecuador also both have a history of security incidents.
Colombia and Ecuador have experienced social turmoil related to changes in economic policy, which have resulted in illegal road blockades throughout the countries, and illegal invasions to private property and impacting regions where our operating activities are located.
Colombia and Ecuador have experienced social turmoil related to changes in economic policy, which have resulted in illegal road blockades throughout the countries, illegal invasions of private property and impact to regions where our operating activities are located.
Public and investor sentiment towards climate change, fossil fuels and other Environmental, Social and Governance (“ESG”) matters could adversely affect our cost of capital and the price of our common stock Certain members of the investment community (including investment fund managers, sovereign wealth, pension and endowment funds, and individual investors) have promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves, including divestment actions by several prominent New York State and New York public employee pension funds.
Public and investor sentiment towards climate change, fossil fuels and other sustainability and human capital matters could adversely affect our cost of capital and the price of our common stock Certain members of the investment community (including investment fund managers, sovereign wealth, pension and endowment funds, and individual investors) have promoted the divestment of fossil fuel equities and pressured lenders to cease or limit funding to companies engaged in the extraction of fossil fuel reserves, including divestment actions by several prominent New York State and New York public employee pension funds.
We may be exposed to liabilities under anti-bribery laws and a finding that we violated these laws could have a material adverse effect on our business We are subject to anti-bribery laws in the United States, Canada, Ecuador and Colombia and will be subject to similar laws in other jurisdictions where we may operate in the future.
We may be exposed to liabilities under anti-bribery laws and a finding that we violated these laws could have a material adverse effect on our business 30 We are subject to anti-bribery laws in the United States, Canada, Ecuador and Colombia and will be subject to similar laws in other jurisdictions where we may operate in the future, such as Azerbaijan.
This risk is further complicated by the dependency of Canadian hydrocarbon energy producers on exports to the United Stated and the uncertainty as to how the United Stated will regulate GHG emissions related to domestic and Canadian production.
This risk is further complicated by the dependency of Canadian hydrocarbon energy producers on exports to the United States and continuing uncertainty as to how the United States will regulate GHG emissions related to domestic and Canadian production.
Some members of the investment community have increased their focus on ESG practices and disclosures by public companies, including practices and disclosures related to climate change and sustainability, diversity, equity and inclusion initiatives, and heightened governance standards, while others have criticized companies for such practices and modified their investments as a result of the same initiatives.
Some members of the investment community have increased their focus on ESG practices and disclosures by public companies, including practices and disclosures related to climate change and sustainability, human capital initiatives, and heightened governance standards, while others have criticized companies for such practices and modified their investments as a result of the same initiatives.
In addition, drilling of wells adjacent to undrilled freehold leases can trigger an obligation to drill the undrilled lands or pay a royalty on those lands equivalent to what would be expected if a well was operating on those lands, or alternatively we may allow the freehold leases to expire.
In addition, drilling of wells adjacent to undrilled freehold leases can trigger an obligation to drill the undrilled lands or pay a royalty on those lands equivalent to what would be expected if a well was operating on those lands, or alternatively we may allow the freehold leases to expire. As such, royalty estimates may significantly change in the future.
Requirements relating to the federal implementation of the United Nations Declaration of Rights for Indigenous Peoples, including the concept of free, prior and informed consent before adopting measures or approving projects that may affect Indigenous peoples, have the potential to adversely affect our ability to obtain permits, leases, licenses and other approvals in Canada, or to meet the terms and conditions of those approvals.
The federal implementation of the United Nations Declaration of Rights for Indigenous Peoples, which includes the concept of free, prior and informed consent before adopting measures or approving projects that may affect Indigenous peoples, has the potential to adversely affect our ability to obtain permits, leases, licenses and other approvals in Canada, or to meet the terms and conditions of those approvals.
Risks Related to our Financial Condition Our business requires significant capital expenditures, and we may not have the resources necessary to fund these expenditures Our base capital program for 2025 is $240.0 million to $280.0 million for exploration and development activities. We expect to fund our 2025 capital program through cash flows from operations.
Risks Related to our Financial Condition Our business requires significant capital expenditures, and we may not have the resources necessary to fund these expenditures Our base capital program for 2026 is $120.0 million to $160.0 million for exploration and development activities. We expect to fund our 2026 capital program through cash flows from operations.
It is not possible at this time to predict whether proposed legislation or regulations will be adopted, and any such future laws and regulations could result in additional compliance costs or additional operating 30 restrictions.
It is not possible at this time to predict whether updates to this legislation or regulations will be adopted, if at all, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions.
The differentials and transportation costs can change over time and have a detrimental impact on realized prices. 21 Future decreases in the prices of oil or natural gas, sustained low prices, periods of extended pricing volatility, and increasing borrowing costs may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable or requiring temporary suspension of fields), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.
Future decreases in the prices of oil or natural gas, sustained low prices, periods of extended pricing volatility, and increasing borrowing costs may have a material adverse effect on our financial condition, the future results of our operations (including rendering existing projects unprofitable or requiring temporary suspension of fields), financing available to us, and quantities of reserves recoverable on an economic basis, as well as the market price for our securities.
The referendums were organized by opponents of the mining or oil and natural gas industries. It remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government.
The referendums were organized by opponents of the mining or oil and natural gas industries. It remains unclear to what extent such results can impact the exercise of mineral rights conferred by the national government, specifically in 2026, a general elections year in Colombia.
The United States may in the future impose similar eligibility restrictions on foreign aid provided to Ecuador. The president of the United States declared that Canada, among other countries, is responsible for illegal immigration and drug transit to United States and is in the process of implementing 10% tariffs on energy resources from Canada.
The United States may in the future impose similar eligibility restrictions on foreign aid provided to Ecuador. The President of the United States declared that Canada, among other countries, is responsible for illegal immigration and drug transit to the United States and has implemented 10% tariffs on energy resources from Canada that do not comply with the Canada-United States-Mexico Agreement.
We are not aware of any claims that have been made in respect of our property and assets in Western Canada; however, if a claim arose and was successful, this could have an adverse effect on our operations. Indigenous rights and stakeholder opposition in Canada Indigenous peoples have established and claimed Indigenous rights and title in portions of Western Canada.
We are not aware of any claims that have been made in respect of our property and assets in Western Canada; however, if a claim arose and was successful, this could have an adverse effect on our operations.
Implementation of tariffs could have adverse impact on our profitability from Canadian operations.
Tariffs could have an adverse impact on our profitability from Canadian operations.
Funding this program from cash flows from operations relies in part on average Brent oil prices of $75 per barrel, WTI oil prices of $71 per barrel and gas prices of C$2.50 per mcf or greater.
Funding this program from cash flows from operations relies in part on average Brent oil prices of $65 per barrel, WTI oil prices of $61.00 per barrel and gas prices of C$3.00 per mcf or greater.
While these pipelines have now been rerouted and are back in service, there remains some risk to our ability to transport oil to market through these systems from future, unforeseen natural events that could again generate outages in the OCP and SOTE pipelines. Such events could include, but are not limited to, earthquakes, volcanic eruptions and additional significant soil erosion.
While these pipelines have now been rerouted and are back in service, there remains some risk to our ability to transport oil to market through these systems from future, unforeseen natural events that could again generate outages in the OCP and SOTE pipelines.
Because our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenues, expenses and income, as well as assets and liabilities, into U.S. dollars at exchange rates in effect during or at the end of each reporting period. We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency.
Because our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenues, expenses and income, as well as assets and liabilities, into U.S. dollars at exchange rates in effect during or at the end of each reporting period.
Furthermore, prices which we receive for our oil and natural gas sales, while based on international oil prices, are established by contracts with purchasers and include the deductions for quality differentials and transportation.
Furthermore, prices which we receive for our oil and natural gas sales, while based on international oil and natural gas prices, are established by contracts with purchasers and include the deductions for quality differentials and transportation. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.
The market price of our Common Stock may be volatile The market price for shares of our Common Stock has experienced and may continue to experience volatility. For example, during 2024, the market price for shares of our Common Stock ranged from a low of $4.72 per share to a high of $10.40 per share.
The market price of our Common Stock may be volatile The market price for shares of our Common Stock has experienced and may continue to experience volatility. For example, during 2025, the market price for shares of our Common Stock ranged from a low of $3.09 per share to a high of $8.19 per share.
We may also discover liabilities or deficiencies associated with any acquisitions that were not identified in advance, which may result in unanticipated costs. Additionally, integration efforts associated with our acquisitions may require significant capital and operating expense. We intend to pay for future acquisitions using cash, stock, notes, debt, assumption of indebtedness or any combination of the foregoing.
Additionally, integration efforts associated with our acquisitions may require significant capital and operating expense. We intend to pay for future acquisitions using cash, stock, notes, debt, assumption of indebtedness or any combination of the foregoing.
We plan to conduct title reviews from time to time according to industry practice prior to the purchase of most of our crude oil and natural gas producing properties or the commencement of drilling wells.
Unforeseen title defects Ownership of some of our properties in Canada could be subject to prior undetected claims or interests. We plan to conduct title reviews from time to time according to industry practice prior to the purchase of most of our crude oil and natural gas producing properties or the commencement of drilling wells.
Legal and Regulatory Risks We are dependent on obtaining and maintaining permits and licenses from various governmental authorities Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations.
We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency. 29 Legal and Regulatory Risks We are dependent on obtaining and maintaining permits and licenses from various governmental authorities Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations.
Claims of Indigenous peoples and protests and demonstrations pertaining to Indigenous rights and title may disrupt or delay third-party operations or new development on our Canadian properties.
Indigenous rights and stakeholder opposition in Canada Indigenous peoples have established and claimed Aboriginal rights and title in portions of Western Canada, including Alberta. Claims of Indigenous peoples and protests and demonstrations pertaining to Aboriginal rights and title may disrupt or delay third-party operations or new development on our Canadian properties.
If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected.
If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected. Azerbaijan has also experienced geopolitical tensions and armed conflict Armenia.
For the period from January 1 to February 20, 2025, the average prices of Brent oil, WTI oil and AECO natural gas were $77.24 per barrel, $73.86 per barrel and C$2.04 per mcf, respectively.
For the period from January 1 to February 27, 2026, the average prices of Brent oil, WTI oil and AECO natural gas were $67.00 per barrel, $62.34 per barrel and C$1.99 per mcf, respectively.
Item 1A. Risk Factors Risks Related to our Business Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could cause temporary suspension of production and reduce our value We generate revenue through the production and sale of oil, natural gas and NGLs.
Refer also to the other information set forth in this Form 10-K, including in the MD&A and Financial Statements sections. 21 Risks Related to our Business Prices and markets for oil and natural gas are unpredictable and tend to fluctuate significantly, which could cause temporary suspension of production and reduce our value We generate revenue through the production and sale of oil, natural gas and NGLs.
Any of these financial instruments may be changed by the relevant government and such changes may adversely affect the profitability of some or all of our business. There is a risk that accounting for GHG releases and the rate of carbon taxation and the level it reaches will be changed from time to time, creating an economic environment of uncertainty.
There is a risk that accounting for GHG releases and the 31 effective rate of carbon taxation and the level it reaches over specified time horizons will be changed from time to time, creating an economic environment of uncertainty.
This evolution, if it occurs, may severely reduce the hydrocarbon-production market to large consumers that have carbon capture and storage capability.
As carbon accounting rules and carbon emissions penalties evolve, distributed small-scale use of hydrocarbon-based fuels may become very costly, which may motivate the discontinued use of hydrocarbon-based fuels. This evolution, if it occurs, may severely reduce the hydrocarbon-production market to large consumers that have carbon capture and storage capability.
The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government. In addition, in 2023 the government issued a new decree eliminating the obligation of ANH to offer bid rounds for new blocks to Companies.
In Colombia, the ANH is delegated by the Ministry of Mining and Energy to offer and award new blocks through exploration and production (“E&P”) and technical evaluation agreement contract terms. The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government.
Policies aimed at reducing emissions of carbon dioxide and methane could become a burden on crude oil and natural gas commodities relative to other sources of energy in the marketplace. Furthermore, there is no assurance that any such programs or regulatory amendments, if proposed and enacted, may contain emission reduction targets that we can meet.
Policies aimed at reducing emissions of GHGs, including carbon dioxide and methane, could become a burden on crude oil and natural gas commodities relative to other sources of energy in the marketplace.
As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines.
As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses.
We are vulnerable to risks associated with geographically concentrated operations The vast majority of our production comes from four fields located in Colombia. For the year ended December 31, 2024, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 79% of our production and at December 31, 2024, these four fields accounted for 42% of our proved reserves.
For the year ended December 31, 2025, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 49% of our production and at December 31, 2025, these four fields accounted for 51% of our proved reserves.
Under new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and operations. In connection with our acquisition of i3 Energy, we acquired an entity that owns and operates block 13/23c in the UK North Sea.
In addition, in 2023 the government issued a new decree eliminating the obligation of ANH to offer bid rounds for new blocks to Companies. Under the new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and operations.
In 2024, the Colombian government commenced peace process conversations with illegal groups in the country, but it is not clear if these discussions will resolve the disruptions. Security concerns in Colombia or Ecuador may disrupt our operations Oil pipelines have historically been primary targets of terrorist activity in Colombia.
Security concerns in Colombia, Ecuador or Azerbaijan may disrupt our operations Oil pipelines have historically been primary targets of terrorist activity in Colombia.
Certain acquisitions could adversely affect our financial results 26 We may pursue strategic acquisitions, such as our recent acquisition of i3 Energy, as part of our business strategy from time to time. There is no assurance that we will be able to find suitable acquisition candidates or be able to complete acquisitions on favorable terms, if at all.
Certain acquisitions could adversely affect our financial results We may pursue strategic acquisitions, such as our recent acquisition of the Perico and Espejo Blocks in Ecuador, as part of our business strategy from time to time.
In 2024, El-Niño-induced drought experienced across Colombia resulted in a decrease in power generated from hydroelectricity which increased power costs and resulted in higher operating expenses. Reduction, elimination or expiration of government subsidies The profitability of our business depends on government-imposed financial instruments such as carbon taxes and carbon tax credits.
Reduction, elimination or expiration of government subsidies The profitability of our business depends on government-imposed levies, such as carbon taxes and output-based pricing systems, government-recognized financial instruments such as carbon tax or pricing system credits, and the liquidity and pricing conditions in which such financial instruments may be traded, to the extent they are tradeable.
There is no guarantee that the third-party’s environmental standards are aligned with those of the Company.
There is no guarantee that the third-party’s environmental standards are aligned with those of the Company. The Company continually engages with its operating partners and closely monitors the operation of its assets. Thorough reviews are conducted before entering into joint venture arrangements to ensure that our operational objectives are aligned with potential joint venture partner.
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As such, royalty estimates may significantly change in the future. 23 Unforeseen title defects Ownership of some of our properties could be subject to prior undetected claims or interests.
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Item 1A. Risk Factors The following section summarizes the material factors that make an investment in our securities speculative or risky.
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For example, the success of our acquisition of i3 Energy will depend, in significant part, on our ability to successfully integrate i3 Energy and realize the anticipated strategic benefits and synergies from the acquisition.
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When any one or more of the following risks materialize from time to time, our business, reputation, financial condition, cash flows, and results of operations can be materially and adversely affected, and the trading price of our common stock could decline.
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The combination of independent businesses is complex, costly and time consuming, and we have devoted, and will continue to devote, significant management attention and resources to integrating the respective business practices and operations of the companies. Further, the anticipated benefits of the acquisition may not be realized fully or at all, or may take longer to realize than we expect.
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These risk factors do not identify all risks that we face; our operations can also be affected by factors that are not presently known to us or that we currently consider to be immaterial to our operations, or by various risks that are generally applicable to most companies.
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In connection with our acquisition of i3 Energy, we acquired assets in block 13/23c in the UK North Sea, management has not allocated any value to this block and there is significant uncertainty that any value can be realized upon disposition or relinquishment.
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Due to risks and uncertainties, known and unknown, our past financial results may not be a reliable indicator of future performance, and historical trends should not be used to anticipate results or trends in future periods .
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Revocation or suspension of our environmental and operating permits could have a material adverse effect on our business, financial condition and results of operations. In Colombia, the ANH is delegated by the Ministry of Mining and Energy to offer and award new blocks through exploration and production (“E&P”) and technical evaluation agreement contract terms.
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Some of the factors, events, and contingencies discussed below may have occurred in the past, and the disclosures below are not representations as to whether or not the factors, events, or contingencies have occurred in the past, but are provided because future occurrences of such factors, events, or contingencies could have a material adverse effect on our business.
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Like other companies with UK North Sea assets, the frequent and adverse changes to the United Kingdom’s oil and gas fiscal regime have caused significant uncertainty that any value can be realized on disposition or relinquishment of UK assets. Management has no intentions to develop UK assets.
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We also make estimates of the volumes of contingent resources and prospective resources. The same uncertainties inherent in estimating quantities of reserves apply to estimating quantities of contingent resources. The uncertainty in estimating prospective resources is even greater. Actual results may vary significantly from these estimates and such variances could be material.
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Financial penalties or charges could be incurred as a result of the failure to meet such targets. As carbon accounting rules and carbon emissions penalties evolve, distributed small-scale use of hydrocarbon-based fuels may become very costly, which may motivate the discontinued use of hydrocarbon-based fuels.
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In addition, there are contingencies that prevent contingent resources from being classified as reserves. With respect to contingent resources, there is uncertainty that it will be commercially viable to produce any portion of the resources. With respect to prospective resources, there is no certainty that any portion of the resources will be discovered.
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If discovered, there is no certainty that it will be commercially viable to produce any portion of the prospective resources.
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In Ecuador, we have entered into investment agreements with the Ecuadorian government in respect of three of our five Blocks and are in the process of finalizing an additional investment agreement in connection with a recently acquired Perico Block.
Added
These agreements are intended to provide certain legal and fiscal stability protections, including stabilization of the applicable tax regime and access to international arbitration mechanisms. While these agreements are designed to mitigate political and regulatory risk, they do not eliminate the possibility of adverse governmental action.
Added
Such events could include, but are not limited to, earthquakes, volcanic eruptions and additional significant soil erosion. 25 We are vulnerable to risks associated with geographically concentrated operations Approximately half of our production comes from four fields located in Colombia.
Added
While our operations in Azerbaijan are expected to be conducted in cooperation with State Oil Company of Azerbaijan Republic (“SOCAR”), there can be no assurance that regional instability, security incidents, changes in governmental policy or international sanctions affecting the region will not disrupt our operations or adversely affect our financial condition, results of operations or cash flows.
Added
There is no assurance that we will be able to find suitable acquisition candidates or be able to complete acquisitions on favorable terms, if at all. We may also discover liabilities or deficiencies associated with any acquisitions that were not identified in advance, which may result in unanticipated costs.
Added
Anti-greenwashing rules introduce risk into making certain environmental-related disclosures On June 20, 2024, Bill C-59 received royal assent from the federal government of Canada (“Royal Assent”), thereby enacting certain changes to the Competition Act (Canada) (the “Competition Act”) to address “greenwashing”, meaning false, misleading, or deceptive environmental claims made for the purpose of promoting a product or a business or business activity.
Added
Under these rules, certain environmental claims that companies commonly make, including those related to sustainability and forward-looking environmental-related goals, may be problematic. How the new rules will be interpreted and applied is currently unclear.
Added
In June 2025, new private rights of action came into effect, meaning that any person is able to bring a complaint directly to the Competition Tribunal under the Competition Act for an alleged violation of the greenwashing provisions.
Added
In November 2025, the federal government of Canada introduced further amendments to the Competition Act as part of Bill C-15 which will remove the private right of action related to greenwashing claims about a business or business activity. The Competition Bureau will still be able to bring such claims. Bill C-15 has not yet received Royal Assent.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeThe Director of IT has extensive cybersecurity knowledge and skills gained from over 20 years of relevant work experience. The Director of IT discusses all potential changes to the Company’s controls or detection systems with the Executive Vice President, Corporate Services prior to implementation.
Biggest changeThe Senior Manager of IT has extensive cybersecurity knowledge and skills gained from over 25 years of relevant work experience. The Senior Manager of IT discusses all potential changes to the Company’s controls or detection systems with the Executive Vice President, Corporate Services prior to implementation.
Item 1C. Cybersecurity Governance Board of Directors The Board of Directors (“the Board”) has delegated the primary responsibility to oversee risks from cybersecurity threats to the Audit Committee. The Board and Audit Committee periodically review the measures implemented by the Company to identify and mitigate data protection and cybersecurity risks.
Item 1C. Cybersecurity 32 Governance Board of Directors The Board of Directors (“the Board”) has delegated the primary responsibility to oversee risks from cybersecurity threats to the Audit Committee. The Board and Audit Committee periodically review the measures implemented by the Company to identify and mitigate data protection and cybersecurity risks.
All incidents are reported to the Executive Officers (including the President and Chief Executive Officer, Chief Financial Officer and the Chief Operating Officer) who assess the severity and what measures and procedures are necessary.
All incidents are reported to the Executive Officers (including the President and Chief Executive Officer, Executive Vice President and Chief Financial Officer and the Chief Operating Officer) who assess the severity and what measures and procedures are necessary.
Additional information on cybersecurity risks we face is discussed in “Risk Factors” in Item 1A, which should be read in conjunction with the foregoing information.
Additional information on cybersecurity risks we face is discussed in “Risk Factors” in Item 1A, which should be read in conjunction with the foregoing information. 33
We conduct penetration testing and cybersecurity audits, and require all employees to undertake data 32 protection and cybersecurity training on an annual basis.
We conduct penetration testing and cybersecurity audits, and require all employees to undertake data protection and cybersecurity training on an annual basis.
The Director of IT is informed about and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents through a number of experienced direction systems and third party cybersecurity providers. The Executive Vice President, Corporate Services also attends certain meetings of the Audit Committee to report information on material risks from cybersecurity threats.
The Senior Manager of IT is informed about and monitors the prevention, detection, mitigation, and remediation of cybersecurity incidents through a number of experienced direction systems and third party cybersecurity providers. The Executive Vice President, Corporate Services also attends certain meetings of the Audit Committee to report information on material risks from cybersecurity threats.
Executive Vice President, Corporate Services, along with support from the Director of IT, is responsible for the assessment and management of risks from cybersecurity threats and oversees the implementation of IT processes, which includes cybersecurity, into the core business of the Company.
Executive Vice President, Corporate Services, along with support from the Senior Manager of IT, is responsible for the assessment and management of risks from cybersecurity threats and oversees the implementation of IT processes, which includes cybersecurity, into the core business of the Company.
The Executive Vice President, Corporate Services is updated by the Director of IT on a periodic basis regarding trends in technology and cybersecurity threats or any potential changes to the Company’s cybersecurity program.
The Executive Vice President, Corporate Services is updated by the Senior Manager of IT on a periodic basis regarding trends in technology and cybersecurity threats or any potential changes to the Company’s cybersecurity program.
The Board and Audit Committee are updated on a quarterly basis by Vice President, Corporate Services on the Company’s internal information technology (“IT”) security testing, any unauthorized attempts to access the Company’s network, any significant developments in cyber security risks and threats, and updates on the Company’s policies and procedures for protecting the Company’s data.
The Board and Audit Committee are updated on a biannual basis or as required by Executive Vice President, Corporate Services on the Company’s internal information technology (“IT”) security testing, any unauthorized attempts to access the Company’s network, any significant developments in cyber security risks and threats, and updates on the Company’s policies and procedures for protecting the Company’s data.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

12 edited+0 added−1 removed12 unchanged
Biggest changeEllson has completed the Leadership for Senior Executives program at Harvard Business School and the General Management Program at the Wharton School of the University of Pennsylvania. • Sebastien Morin, Chief Operating Officer. Mr. Morin was appointed as Gran Tierra’s Chief Operations Officer on November 6, 2023. Mr.
Biggest changeEllson is a Chartered Professional Accountant and holds a Bachelor of Commerce and a Masters of Professional Accounting from the University of Saskatchewan. Mr. Ellson has completed the Leadership for Senior Executives program at Harvard Business School and the General Management Program at the Wharton School of the University of Pennsylvania. • Sebastien Morin, Chief Operating Officer. Mr.
Morin worked at Imperial Oil (Esso) and ExxonMobil, where he achieved more senior technical and managerial positions in upstream and downstream including roles in drilling and completions, reservoir development, production, customer service and distribution, mostly onshore but also with experience offshore in the Gulf of Mexico. Mr.
Morin worked at Imperial Oil (Esso) and ExxonMobil, where he achieved more senior technical and managerial positions in upstream and downstream including roles in drilling and completions, reservoir development, production, customer service and distribution, mostly onshore but also with experience offshore in the Gulf 34 of Mexico. Mr.
He is credited as the author of various publications and has presented in numerous professional forums. • James Evans, Executive Vice President, Corporate Services . Mr. Evans has been Gran Tierra’s Vice President, Corporate Services, since May 2015. Mr. Evans has over 30 years of experience including working the last 19 years in the international oil and gas industry.
He is credited as the author of various publications and has presented in numerous professional forums. • James Evans, Executive Vice President, Corporate Services . Mr. Evans has been Gran Tierra’s Vice President, Corporate Services, since May 2015. Mr. Evans has over 30 years of experience including working the last 20 years in the international oil and gas industry.
Ellson was Head of Finance for Glencore E&P (Canada) Inc. and prior thereto Vice President, Finance at Caracal Energy Inc.(“Caracal”), a London Stock Exchange (“LSE”) listed company with operations 33 in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 2014. Mr.
From July 2014 until December 2014 Mr. Ellson was Head of Finance for Glencore E&P (Canada) Inc. and prior thereto Vice President, Finance at Caracal Energy Inc. (“Caracal”), a London Stock Exchange (“LSE”) listed company with operations in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 2014. Mr.
His legal experience includes positions at prominent law firms and is broadly based with a focus on international energy law. Mr. Abraham’s corporate experience extends to a variety of leadership positions with Cenovus Energy, Encana Corporation and Nexen Inc.
His legal experience includes positions at prominent law firms and is broadly based with a focus on international oil and gas law. Mr. Abraham’s corporate experience extends to a variety of leadership positions with Cenovus Energy, Encana Corporation and Nexen Inc.
Abraham has been with Gran Tierra in a variety of roles since January 2016 and, in addition to his current role as Vice President, Legal and Business Development, is also Gran Tierra’s Corporate Secretary. He is a lawyer with over 25 years of corporate and legal experience.
Abraham has been with Gran Tierra in a variety of roles since January 2016 and, in addition to his current role as Executive Vice President, Legal and Land, is also Gran Tierra’s Corporate Secretary. He is a lawyer with over 25 years of corporate and legal experience.
Item 4. Mine Safety Disclosures Not applicable. Information About Our Executive Officers Set forth below is information regarding our executive officers as of February 20, 2025: Name Age Position Gary S.
Item 4. Mine Safety Disclosures Not applicable. Information About Our Executive Officers Set forth below is information regarding our executive officers as of February 27, 2026: Name Age Position Gary S.
Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University. • Ryan Ellson, Chief Financial Officer and Executive Vice President, Finance. Mr. Ellson has been Gran Tierra’s Chief Financial Officer since May 2015. Mr.
Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University. • Ryan Ellson, Chief Financial Officer and Executive Vice President, Finance. Mr. Ellson has been Gran Tierra’s Chief Financial Officer since May 2015. Mr. Ellson has 25 years of experience in a broad range of international corporate finance and accounting roles.
Guidry 69 President and Chief Executive Officer, Director Ryan Ellson 49 Chief Financial Officer and Executive Vice President, Finance Sebastien Morin 48 Chief Operating Officer Phillip Abraham 54 Executive Vice President, Legal and Land James Evans 59 Executive Vice President, Corporate Services • Gary S. Guidry, President and Chief Executive Officer, Director. Mr.
Guidry 70 President and Chief Executive Officer, Director Ryan Ellson 50 Chief Financial Officer and Executive Vice President, Finance Sebastien Morin 49 Chief Operating Officer Phillip Abraham 55 Executive Vice President, Legal and Land James Evans 60 Executive Vice President, Corporate Services • Gary S. Guidry, President and Chief Executive Officer, Director. Mr.
Morin has more than 20 years of experience in the oil and gas industry in various management positions. Prior to his appointment as Chief Operating Officer of the Company, Mr.
Morin was appointed as Gran Tierra’s Chief Operations Officer on November 6, 2023. Mr. Morin has more than 25 years of experience in the oil and gas industry in various management positions. Prior to his appointment as Chief Operating Officer of the Company, Mr.
Guidry currently sits on the board of Africa Oil Corp. (since April 2008) where he also serves as a member of the Audit Committee. Mr. Guidry was on the board of PetroTal Corp. from December 2017 until September 2022. From September 2010 to October 2011, Mr.
Guidry was on the board of Africa Oil Corp. from April 2008 until February 2025, PetroTal Corp. from December 2017 until September 2022. From September 2010 to October 2011, Mr.
Ellson has over 24 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of Beyond Renewables (private company) and previously was a Director of Canaary Biofuels (until October 2024) and Director at PetroTal Corp. (until September 2022). From July 2014 until December 2014 Mr.
Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is currently a Director of Beyond Renewables (private company) and previously was a Director of Canary Biofuels (until October 2024) and Director at PetroTal Corp. (until September 2022). Mr.
Removed
Ellson has held management and executive positions with companies operating in Chad, Egypt, India and Canada. Mr. Ellson is a Chartered Professional Accountant and holds a Bachelor of Commerce and a Masters of Professional Accounting from the University of Saskatchewan. Mr.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

8 edited+0 added−2 removed3 unchanged
Biggest change(2) On November 4, 2024, we implemented a share re-purchase program (the “2024 Program”) through the facilities of the TSX, the NYSE American or alternative trading programs in Canada or the United States commencing November 6, 2024 and ending on November 5, 2025.
Biggest change(2) On November 3, 2025, we implemented a share re-purchase program (the “2025 Program”) through the facilities of the TSX, the NYSE American or alternative trading programs in Canada or the United States commencing November 6, 2025 and ending on November 5, 2026. 35 Under the 2025 Program, we are able to purchase at prevailing market prices up to 2,925,720 shares of Common Stock, representing approximately 10% of the public float of common shares as of October 31, 2025.
Payment of future dividends, if any, would be at the discretion of our Board of Directors after taking into account various 34 factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
Payment of future dividends, if any, would be at the discretion of our Board of Directors after taking into account various factors, including current financial condition, the tax impact of repatriating cash, operating results and current and anticipated cash needs.
The graph assumes that, on December 31, 2019, $100 was invested in our shares and $100 was invested in each of the other two indices, with dividends reinvested on the ex-dividend date without payment of any commissions.
The graph assumes that, on December 31, 2020, $100 was invested in our shares and $100 was invested in each of the other two indices, with dividends reinvested on the ex-dividend date without payment of any commissions.
The performance shown in the graph represents past performance and should not considered an indication of future performance. 35 12/31/2019 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 Gran Tierra Energy Inc.
The performance shown in the graph represents past performance and should not considered an indication of future performance. 12/31/2020 12/31/2021 12/31/2022 12/31/2023 12/31/2024 12/31/2025 Gran Tierra Energy Inc.
The performance graph below shows the cumulative total shareholder return on our shares of the period starting on December 31, 2019, and ending on December 31, 2024, which was the end of our fiscal 2023 year.
The performance graph below shows the cumulative total shareholder return on our shares of the period starting on December 31, 2020, and ending on December 31, 2025, which was the end of our fiscal 2025 year.
Issuer Purchases of Equity Securities (a) Total Number of Shares Purchased (b) Average Price Paid per Share (1) (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2) October 1-31, 2024 — $ — — 3,545,872 November 1-30, 2024 298,450 $ 6.31 298,450 3,247,422 December 1-31, 2024 189,498 $ 6.76 189,498 3,057,924 Total 487,948 $ 6.49 487,948 3,057,924 (1) Including commission fees paid to the broker to re-purchase the shares of Common Stock.
Issuer Purchases of Equity Securities (a) Total Number of Shares Purchased (b) Average Price Paid per Share (1) (c) Total Number of Shares Purchased as Part of Publicly Announced Plans or Programs (d) Maximum Number of Shares that May Yet be Purchased Under the Plans or Programs (2) October 1-31, 2025 — $ — — 2,365,120 November 1-30, 2025 — $ — — 2,925,720 December 1-31, 2025 — $ — — 2,925,720 Total — $ — — 2,925,720 (1) Including commission fees paid to the broker to re-purchase the shares of Common Stock.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Shares of our Common Stock trade on the NYSE American, the TSX and on the LSE under the symbol “GTE”.
Item 5. Market for Registrant's Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities Shares of our Common Stock trade on the NYSE American, the TSX and the LSE under the symbol “GTE”. As of February 27, 2026, there were 54 holders of record of shares of our Common Stock and 35,298,774 shares outstanding with $0.001 par value.
(GTE) $ 100.0 $ 28.2 $ 59.0 $ 76.7 $ 43.7 $ 56.0 S&P 500 Total Return (SPXT) $ 100.0 $ 118.4 $ 152.4 $ 124.8 $ 157.6 $ 197.0 S&P O&G E&P Select Index Total Return (SPSIOPTR) $ 100.0 $ 63.4 $ 106.3 $ 154.9 $ 160.8 $ 159.7
(GTE) $ 100.0 $ 209.2 $ 272.1 $ 155.0 $ 198.7 $ 116.5 S&P 500 Total Return (SPXT) $ 100.0 $ 128.7 $ 105.4 $ 133.1 $ 166.4 $ 196.2 S&P O&G E&P Select Index Total Return (SPSIOPTR) $ 100.0 $ 167.6 $ 244.2 $ 253.6 $ 251.8 $ 247.0
Removed
As of February 20, 2025, there were approximately 32 holders of record of shares of our Common Stock and 35,888,773 shares outstanding with $0.001 par value.
Removed
Under the 2024 Program, we are able to purchase at prevailing market prices up to 3,545,872 shares of Common Stock, representing approximately 10% of the public float of common shares as of October 31, 2024.

Item 7. Management's Discussion & Analysis

Management's Discussion & Analysis (MD&A) — revenue / margin commentary

113 edited+90 added−35 removed45 unchanged
Biggest changeDollars) 2024 % Change 2023 % Change 2022 Oil, natural gas and NGL sales $ 621,849 (2) $ 636,957 (10) $ 711,388 Operating expenses 202,331 8 186,864 15 162,385 Transportation expenses 18,464 27 14,546 43 10,197 Operating netback (1) 401,054 (8) 435,547 (19) 538,806 DD&A expenses 230,619 7 215,584 20 180,280 G&A expenses before stock-based compensation 39,912 (1) 40,124 26 31,908 G&A stock-based compensation expense 9,707 70 5,722 (37) 9,049 Severance expenses 1,519 100 — — — Transaction costs 5,907 100 — — — Foreign exchange (gain) loss (8,808) (175) 11,822 359 2,578 Derivative instruments loss 2,271 100 — (100) 26,611 Other financial instruments loss (gain) — (100) 15 314 (7) Interest expense 80,466 44 55,806 20 46,493 361,593 10 329,073 11 296,912 Other gain (loss) 1,478 164 (2,297) (188) 2,598 Interest income 3,666 85 1,983 348 443 Income before income taxes 44,605 (58) 106,160 (57) 244,935 Current income tax expense 69,277 24 55,688 (31) 80,566 Deferred income tax (recovery) expense (27,888) (149) 56,759 124 25,340 Total income tax expense 41,389 (63) 112,447 6 105,906 40 Net income (loss) $ 3,216 151 $ (6,287) (105) $ 139,029 Sales Volumes (NAR) Total sales volumes, BOEPD 27,436 6 25,947 9 23,696 Brent Price per boe $ 79.86 (3) $ 82.16 (17) $ 99.04 WTI Price per boe $ 69.62 100 $ — — $ — AECO Price per GJ C$ 1.56 100 C$ — — C$ — Consolidated Results of Operations per boe Sales Volumes (NAR) Oil, natural gas and NGL sales $ 61.93 (8) $ 67.26 (18) $ 82.25 Operating expenses 20.15 2 19.73 5 18.77 Transportation expenses 1.84 19 1.54 31 1.18 Operating netback (1) 39.94 (13) 45.99 (26) 62.30 DD&A expenses 22.97 1 22.76 9 20.84 G&A expenses before stock-based compensation 3.97 (6) 4.24 15 3.69 G&A stock-based compensation expense 0.97 62 0.60 (43) 1.05 Severance expenses 0.15 100 — — — Transaction costs 0.59 100 — — — Foreign exchange (gain) loss (0.88) (170) 1.25 317 0.30 Derivative instruments loss 0.23 100 — (100) 3.08 Other financial instruments loss — — — — — Interest expense 8.01 36 5.89 9 5.38 36.01 4 34.74 1 34.34 Other gain (loss) 0.15 163 (0.24) (180) 0.30 Interest income 0.37 76 0.21 320 0.05 Income before income taxes 4.45 (60) 11.22 (60) 28.31 Current income tax expense 6.90 17 5.88 (37) 9.31 Deferred income tax (recovery) expense (2.78) (146) 5.99 104 2.93 Total income tax expense 4.12 (65) 11.87 (3) 12.24 Net income (loss) $ 0.33 151 $ (0.65) (104) $ 16.07 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Biggest changeDollars) 2025 % Change 2024 % Change 2023 Oil, natural gas and NGL sales $ 596,713 (4) $ 621,849 (2) $ 636,957 Operating expenses 248,748 23 202,331 8 186,864 Transportation expenses 17,024 (8) 18,464 27 14,546 Operating netback (1) 330,941 (17) 401,054 (8) 435,547 Export tax 3,287 100 — — — DD&A expenses 278,353 21 230,619 7 215,584 Asset impairment 136,261 100 — — — G&A expenses before stock-based compensation 56,873 37 41,431 3 40,124 G&A stock-based compensation expense 3,214 (67) 9,707 70 5,722 Transaction costs — (100) 5,907 100 — Foreign exchange loss (gain) 8,734 199 (8,808) (175) 11,822 Derivative instruments (gain) loss (18,925) (933) 2,271 100 — Other financial instruments loss — — — (100) 15 Interest expense 101,309 26 80,466 44 55,806 569,106 57 361,593 10 329,073 Other gain (loss) 4,203 184 1,478 164 (2,297) Interest income 1,090 (70) 3,666 85 1,983 (Loss) income before income taxes (232,872) (622) 44,605 (58) 106,160 Current income tax expense 15,859 (77) 69,277 24 55,688 42 Deferred income tax (recovery) expense (55,612) (99) (27,888) (149) 56,759 Total income tax (recovery) expense (39,753) (196) 41,389 (63) 112,447 Net (loss) income $ (193,119) (6,105) $ 3,216 151 $ (6,287) Sales Volumes (NAR) Total sales volumes, BOEPD 37,664 37 27,436 6 25,947 Brent Price per boe $ 68.19 (15) $ 79.86 (3) $ 82.16 WTI Price per boe $ 64.87 (7) $ 69.62 100 $ — AECO Price per GJ C$ 1.59 2 C$ 1.56 100 C$ — Consolidated Results of Operations per boe Sales Volumes (NAR) Oil, natural gas and NGL sales $ 43.41 (30) $ 61.93 (8) $ 67.26 Operating expenses 18.09 (10) 20.15 2 19.73 Transportation expenses 1.24 (33) 1.84 19 1.54 Operating netback (1) 24.08 (40) 39.94 (13) 45.99 Export tax 0.24 100 — — — DD&A expenses 20.25 (12) 22.97 1 22.76 Asset impairment 9.91 100 — — — G&A expenses before stock-based compensation 4.14 — 4.13 (3) 4.24 G&A stock-based compensation expense 0.23 (76) 0.97 62 0.60 Transaction costs — (100) 0.59 100 — Foreign exchange loss (gain) 0.64 173 (0.88) (170) 1.25 Derivative instruments (gain) loss (1.38) (700) 0.23 100 — Interest expense 7.37 (8) 8.01 36 5.89 41.40 15 36.02 4 34.74 Other gain (loss) 0.31 107 0.15 163 (0.24) Interest income 0.08 (78) 0.37 76 0.21 (Loss) income before income taxes (16.93) (481) 4.44 (60) 11.22 Current income tax expense 1.15 (83) 6.90 17 5.88 Deferred income tax (recovery) expense (4.05) (46) (2.78) (146) 5.99 Total income tax (recovery) expense (2.90) (170) 4.12 (65) 11.87 Net (loss) income $ (14.03) (4,484) $ 0.32 149 $ (0.65) (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
The increase in production was a result of two months of production from the 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.
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.
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 (40%).
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%.
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.
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 40 this financial measure is a useful supplemental information for investors to analyze our performance and financial results.
Dollars per boe $ 24.15 $ 25.50 $ 9.97 $ — $ 22.97 49 Year Ended December 31, 2023 Colombia Ecuador Canada Corporate Total DD&A Expenses, Thousands of U.S. Dollars $ 207,346 $ 8,018 $ — $ 220 $ 215,584 DD&A Expenses, U.S.
Dollars per boe $ 24.15 $ 25.50 $ 9.97 $ — $ 22.97 Year Ended December 31, 2023 Colombia Ecuador Canada Corporate Total DD&A Expenses, Thousands of U.S. Dollars $ 207,346 $ 8,018 $ — $ 220 $ 215,584 DD&A Expenses, U.S.
Asset Impairment 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.
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.
Discussions of items related to the fiscal year ended December 31, 2023 and year-to-year comparisons between the fiscal years ended December 31, 2023 and 2022, 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, 2023.
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.
Information regarding our asset retirement obligation can be found in Note 12 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.
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.
Current assets and current liabilities These amounts are short-term in nature, and during the year ended December 31, 2024, 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 2024.
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.
Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2024 ceiling tests were based on wellhead prices per boe as of the first day of each month within that twelve-month period.
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.
Oil, Natural Gas and NGL Sales 43 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 increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024.
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 46 an increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024.
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, 2024, 2023, and 2022: Year Ended December 31, (Thousands of U.S.
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.
On a per boe basis, average realized prices 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 natural gas and liquids to the portfolio in 2024 through the i3 Energy acquisition.
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.
A reconciliation from net income (loss) to funds flow from operations and free cash flow is as follows: 39 Year Ended Three Months Ended, December 31, December 31, September 30, (Thousands of U.S.
A reconciliation from net income (loss) to funds flow from operations and free cash flow is as follows: 41 Year Ended Three Months Ended, December 31, December 31, September 30, (Thousands of U.S.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses 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.
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.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 58 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, 2024: (Thousands of U.S.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 66 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.
However, the majority of the cash flows associated with proved reserves per the 2024 reserve report should be realized prior to the potential elimination of carbon-based energy.
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.
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.
“Risk Factors” in this Annual Report on Form 10-K. 36 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.
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.
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.
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, 2024: Year Ended December 31, 2024 2023 2022 Volume transported through pipelines 13 % 2 % — % Volume sold at wellhead 43 % 47 % 47 % Volume transported via truck to pipelines 44 % 51 % 53 % 100 % 100 % 100 % Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher 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, 2025 2024 2023 Volume transported through pipelines 46 % 13 % 2 % Volume sold at wellhead 25 % 43 % 47 % Volume transported via truck to pipelines 29 % 44 % 51 % 100 % 100 % 100 % Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses.
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, 2024: Impairment 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.
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.
These were partially offset by a 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments. 52 During the year ended December 31, 2024, the company strategically revised its 2022 tax return to use its tax receivable balance to offset current tax liabilities, rather than applying net operating loss carryforwards.
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.
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.
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.
Foreign Exchange (Gains) Losses For the years ended December 31, 2024, 2023 and 2022, we had an $8.8 million gain, $11.8 million loss and $2.6 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.
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.
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2024, increased by 2% to $4.94 compared to 2023 due to 62% increase in stock-based compensation attributable to higher share price in 2024.
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.
The difference between our effective tax rate of 93% for the year ended December 31, 2024, and the 45% Colombian statutory tax rate was primarily due to an increase in impact of foreign taxes, valuation allowance, non-deductible royalties in Colombia, other permanent differences and non-deductible stock-based compensation.
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.
On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 compared to $19.73 in the prior year, 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 as a result of production ramp-up in 2024.
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.
Expenditures on property, plant and equipment From 2018 to 2024, 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 2024, the Acordionero field represented 43% of our production.
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.
Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, 38 lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, transaction costs, other financial instruments gains or losses, other non-cash gains or losses, and stock-based compensation 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.
Dollars per boe Sales Volumes NAR) Average realized price $ 21.14 $ — $ — Transportation expenses (0.75) — — Average realized price, net of transportation expenses 20.39 — — Operating expenses (10.76) — — Operating netback (1) $ 9.63 $ — $ — Year Ended December 31, Total Company 2024 2023 2022 (Thousands of U.S.
Dollars per boe Sales Volumes NAR) Average realized price $ 21.71 $ 21.14 $ — Transportation expenses (0.24) (0.75) — Average realized price, net of transportation expenses 21.47 20.39 — Operating expenses (10.99) (10.76) — Operating netback (1) $ 10.48 $ 9.63 $ — Year Ended December 31, Total Company 2025 2024 2023 (Thousands of U.S.
Under the 2024 Program, we are able to purchase up to 3,545,872 shares of Common Stock, representing 10% of the public float as of October 31, 2024, at prevailing market prices at the time of purchase. The 2024 Program will continue for one year and expire on November 5, 2025, or earlier if the 10% maximum is reached.
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.
NaturAmazonas is projected to sequester approximately 8.7 million tonnes of CO2, equivalent to approximately 19 years of our 2024 Scope 1 and Scope 2 emissions 1 .
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 .
During the year ended December 31, 2024, we implemented a share re-purchase program (the “2024 Program”) through the facilities of the TSX, the NYSE or alternative trading programs in Canada or the United States, if eligible.
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.
These were partially offset by an increase in valuation allowance. Our effective tax rate was 106% for the year ended December 31, 2023, compared with 43% in 2022. The increase in the effective tax rate was primarily due to an increase in non-deductible foreign exchange adjustments, impact of foreign taxes and other permanent differences.
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.
Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback (1) per boe when choosing a transportation method.
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.
In total, we converted 2.8 billion standard cubic feet of natural gas into electricity instead of being flared for the 59 year ended December 31, 2024 and have incurred capital expenditures of $33.4 million since 2018. The extent of spending on projects directly linked to reducing the climate impact of our operations.
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.
Dollars per boe Sales Volumes NAR) 47 Brent $ 79.86 $ 82.16 $ 99.04 Quality and transportation discounts (17.93) (14.90) (16.79) Average realized price 61.93 67.26 82.25 Transportation expenses (1.84) (1.54) (1.18) Average realized price, net of transportation expenses 60.09 65.72 81.07 Operating expenses (20.15) (19.73) (18.77) Operating netback (1) $ 39.94 $ 45.99 $ 62.30 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Dollars per boe Sales Volumes NAR) Brent $ 68.19 $ 79.86 $ 82.16 Quality and transportation discounts (24.78) (17.93) (14.90) Average realized price 43.41 61.93 67.26 Transportation expenses (1.24) (1.84) (1.54) Average realized price, net of transportation expenses 42.17 60.09 65.72 Operating expenses (18.09) (20.15) (19.73) Operating netback (1) $ 24.08 $ 39.94 $ 45.99 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Dollars) 2024 % Change 2023 % Change 2022 Cash and cash equivalents $ 103,379 66 $ 62,146 (51) $ 126,873 Credit facility $ — (100) $ 36,364 100 $ — Senior Notes $ 786,619 47 $ 536,619 (7) $ 579,909 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.
Dollars) 2025 % Change 2024 % Change 2023 Cash and cash equivalents $ 82,931 (20) $ 103,379 66 $ 62,146 Credit facility $ — — $ — (100) $ 36,364 Senior Notes $ 740,541 (6) $ 786,619 47 $ 536,619 61 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.
Actual results will differ from these estimates and assumptions.
Actual results could differ from these estimates and assumptions.
Dollars per boe Sales Volumes NAR) Brent $ 79.86 $ 82.16 $ — Quality and transportation discounts (11.06) (8.58) — Average realized price 68.80 73.58 — Transportation expenses (3.75) (3.37) — Average realized price, net of transportation expenses 65.05 70.21 — Operating expenses (33.69) (36.46) — Operating netback (1) $ 31.36 $ 33.75 $ — Year Ended December 31, Canada 2024 2023 2022 (Thousands of U.S.
Dollars per boe Sales Volumes NAR) Brent $ 68.19 $ 79.86 $ 82.16 52 Quality and transportation discounts (6.66) (11.06) (8.58) Average realized price 61.53 68.80 73.58 Transportation expenses (3.18) (3.75) (3.37) Average realized price, net of transportation expenses 58.35 65.05 70.21 Operating expenses (23.85) (33.69) (36.46) Operating netback (1) $ 34.50 $ 31.36 $ 33.75 Year Ended December 31, Canada 2025 2024 2023 (Thousands of U.S.
Operating netback, as presented, is defined as oil, natural gas and NGL sales less operating and transportation expenses. 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.
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.
At December 31, 2024, we had provided letters of credit and other credit support totali ng $244.5 million ( December 31, 2023 - $220.1 million) as security relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block, and other capital or operating requirements as well as for transmission capacity in Canada.
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 7.75% Senior Notes bear interest at a rate of 7.75% per year, 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 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.
We have planted over 1.9 million trees and conserved, preserved, or reforested more than 5,300 hectares of land through all of our environmental efforts to date. 1 2024 emissions are based on full year emissions from Colombia and Ecuador, plus post-transaction date emissions in Canada (November & December).
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.
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. 45 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, 2024: Year Ended December 31, (U.S.
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.
Dollars) Oil, natural gas and NGL sales $ 27,412 $ 15,660 $ — Transportation expenses (1,495) (717) — 25,917 14,943 — Operating expenses (13,425) (7,761) — Operating netback (1) $ 12,492 $ 7,182 $ — (U.S.
Dollars) Oil, natural gas and NGL sales $ 62,609 $ 27,412 $ 15,660 Transportation expenses (3,236) (1,495) (717) 59,373 25,917 14,943 Operating expenses (24,270) (13,425) (7,761) Operating netback (1) $ 35,103 $ 12,492 $ 7,182 (U.S.
Our Colombian properties represented 47%, our Canadian properties represented 46% and our Ecuadorian properties represented 7% of our proved reserves NAR at December 31, 2024, and for the year ended December 31, 2024, 93% of our revenue was 36 generated in Colombia (2023 - 97% and 2022 -100%), 3% of our revenue was generated in Canada (2023 and 2022 - nil) and 4% (2023 - 3%, 2022 - nil) of our revenue was generated in 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.
Dollars per boe Sales Volumes NAR) Brent $ 79.86 $ 82.16 $ 99.04 Quality and transportation discounts (14.06) (15.05) (16.79) Average realized price 65.80 67.11 82.25 46 Transportation expenses (1.86) (1.49) (1.18) Average realized price, net of transportation expenses 63.94 65.62 81.07 Operating expenses (20.50) (19.35) (18.77) Operating netback (1) $ 43.44 $ 46.27 $ 62.30 Year Ended December 31, Ecuador 2024 2023 2022 (Thousands of U.S.
Dollars per boe Sales Volumes NAR) Brent $ 68.19 $ 79.86 $ 82.16 Quality and transportation discounts (11.65) (14.06) (15.05) Average realized price 56.54 65.80 67.11 Transportation expenses (1.69) (1.86) (1.49) Average realized price, net of transportation expenses 54.85 63.94 65.62 Operating expenses (22.42) (20.50) (19.35) Operating netback (1) $ 32.43 $ 43.44 $ 46.27 Year Ended December 31, Ecuador 2025 2024 2023 (Thousands of U.S.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 54 2025 Work Program and Capital Expenditures Our Colombian, Canadian and Ecuadorian development operations are expected to represent approximately 52 %, 37% and 11% of our 2025 production.
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.
Based on the mid-point of the 2025 guidance, the capital budget is forecasted to be approximately 75%directed to development activities and 25% directed to exploration activities. Approximately 30% of the development activities included in the 2025 capital program are expected to be directed to facilities to support future production growth and enhance recovery factors.
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.
Dollars) Oil, natural gas and NGL sales $ 18,955 $ — $ — Transportation expenses (672) — — 18,283 — — Operating expenses (9,649) — — Operating netback (1) $ 8,634 $ — $ — (U.S.
Dollars) Oil, natural gas and NGL sales $ 115,693 $ 18,955 $ — Transportation expenses (1,283) (672) — 114,410 18,283 — Operating expenses (58,576) (9,649) — Operating netback (1) $ 55,834 $ 8,634 $ — (U.S.
Dollars per boe Sales Volumes NAR) 2024 2023 2022 Average Brent price $ 79.86 $ 82.16 $ 99.04 Average realized price, net of transportation expenses for the comparative period $ 65.72 $ 81.07 $ 58.61 (Decrease) increase in benchmark prices (2.30) (16.88) 28.09 (Increase) decrease in quality and transportation discounts (3.03) 1.89 (5.93) (Increase) decrease in transportation expense (0.30) (0.36) 0.30 Average realized price, net of transportation expenses for the year $ 60.09 $ 65.72 $ 81.07 Average realized price, net of transportation expenses as a % of Brent 75 % 80 % 82 % Operating Netbacks Year Ended December 31, Colombia 2024 2023 2022 (Thousands of U.S.
Dollars per boe Sales Volumes NAR) 2025 2024 2023 Average Brent price $ 68.19 $ 79.86 $ 82.16 Average realized price, net of transportation expenses for the comparative period $ 60.09 $ 65.72 $ 81.07 Decrease in benchmark prices (11.67) (2.30) (16.88) (Increase) decrease in quality and transportation discounts (6.85) (3.03) 1.89 Decrease (increase) in transportation expense 0.60 (0.30) (0.36) Average realized price, net of transportation expenses for the year $ 42.17 $ 60.09 $ 65.72 Average realized price, net of transportation expenses as a % of Brent 62 % 75 % 80 % Gross Profit Colombia Year Ended December 31, (Thousands of U.S.
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 impairment is charged to earnings.
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.
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.
Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted 68 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.
Reserve estimates are evaluated at least annually by independent reservoir engineering specialists. 60 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.
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.
Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOEPD compared to 23,815 BOEPD in 2022.
Oil production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023.
Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022.
Operating expenses for the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023.
In calculating discounted future net revenues, oil and natural gas prices are determined 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. That average price is then held constant, except for changes which are fixed and determinable by existing contracts.
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.
In accordance with GAAP, we used unweighted arithmetic average of the first-day-of-the-month prices as follows; Brent Crude $80.42 p er boe, Edmonton Light Crude of C$98.01 per boe, Alberta AECO spot price of C$1.46 per MMBtu Edmonton Propane C$30.46 per boe, Edmonton Butane C$48.39 per boe and Edmonton Condensate C$100.83 per boe for the December 31, 2024 ceiling test calculations (December 31, 2023, and 2022 Brent Crude - $82.51 and $97.98 per boe, respectively).
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).
Cash and Cash Equivalents Held Outside of Canada and the United States At December 31, 2024 , 100% of our cash and cash equivalents was held in Canada and the United States. 57 Cash Flows The following table presents our sources and uses of cash and cash equivalents for the periods presented: Year Ended December 31, 2024 2023 2022 Sources of Cash and Cash Equivalents: Net income (loss) $ 3,216 $ (6,287) $ 139,029 Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 230,619 215,584 180,280 Deferred tax (recovery) expense (27,888) 56,759 25,340 Stock-based compensation expense 9,707 5,722 9,049 Amortization of debt issuance costs 12,918 5,831 3,528 Unrealized foreign exchange (gain) loss (7,893) (5,085) 10,251 Other non-cash loss (gain) — 2,312 (2,605) Derivative instruments loss 2,271 — 26,611 Cash settlement on derivative instruments 1,103 — (26,611) Other financial instruments loss (gain) — — — Non-cash lease expenses 5,923 4,967 2,818 Lease payments (5,035) (3,018) (1,666) Funds flow from operations (1) 224,941 276,785 366,024 Proceeds from issuance of Senior Notes, net of issuance costs 221,474 — — Changes in non-cash operating working capital 16,078 — 64,317 Proceeds from exercise of stock options 373 8 1,300 Proceeds from debt, net of issuance costs — 48,014 — Proceeds on disposition of investment, net of transaction costs 44,382 — — Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents — 5,869 — 507,248 330,676 431,641 Uses of Cash and Cash Equivalents: Additions to property, plant and equipment (234,236) (226,584) (210,331) Cash paid for business combinations, net of cash acquired (162,651) — — Repayment of Senior Notes — (60,000) — Senior Notes issuance costs — (13,351) — Repayment of debt (36,364) (13,636) (67,803) Lease payments (13,300) (6,527) (2,228) Changes in non-cash operating working capital — (48,416) — Cash settlement of asset retirement obligation (1,698) (377) (2,630) Re-purchase of shares of Common Stock (15,309) (17,300) (27,317) Re-purchase of Senior Notes — (6,805) (17,274) Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents (3,391) — (2,104) (466,949) (392,996) (329,687) Net increase (decrease) in cash and cash equivalents and restricted cash and cash equivalents $ 40,299 $ (62,320) $ 101,954 (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
Cash Flows The following table presents our sources and uses of cash and cash equivalents for the periods presented: 65 Year Ended December 31, 2025 2024 2023 Sources of Cash and Cash Equivalents: Net (loss) income $ (193,119) $ 3,216 $ (6,287) Adjustments to reconcile net (loss) income to funds flow from operations DD&A expenses 278,353 230,619 215,584 Asset impairment 136,261 — — Deferred tax (recovery) expense (55,612) (27,888) 56,759 Stock-based compensation expense 3,214 9,707 5,722 Amortization of debt issuance costs 16,943 12,918 5,831 Unrealized foreign exchange loss (gain) 1,040 (7,893) (5,085) Non-cash interest expense 2,025 — — Other non-cash (gain) loss (2,558) — 2,312 Unrealized derivative instruments (gain) loss (8,633) 3,374 — Non-cash lease expenses 5,821 5,923 4,967 Lease payments (5,973) (5,035) (3,018) Funds flow from operations (1) 177,762 224,941 276,785 Proceeds from issuance of Senior Notes, net of issuance costs — 221,474 — Changes in non-cash operating working capital 141,872 16,078 — Proceeds from exercise of stock options 51 373 8 Proceeds from debt, net of issuance costs 116,548 — 48,014 Proceeds on disposition of property, plant and equipment 7,876 44,382 — Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents 387 — 5,869 444,496 507,248 330,676 Uses of Cash and Cash Equivalents: Additions to property, plant and equipment (275,869) (234,236) (226,584) Cash paid for business combinations, net of cash acquired — (162,651) — Cash paid for property acquisitions (4,471) — — Repayment of Senior Notes (24,828) — (60,000) Senior Notes issuance costs — — (13,351) Repayment of debt (119,945) (36,364) (13,636) Lease payments (11,182) (13,300) (6,527) Changes in non-cash operating working capital — — (48,416) Cash settlement of asset retirement obligation (6,385) (1,698) (377) Re-purchase of shares of Common Stock (3,466) (15,309) (17,300) Re-purchase of Senior Notes (17,021) — (6,805) Foreign exchange loss on cash and cash equivalents and restricted cash and cash equivalents — (3,391) — (463,167) (466,949) (392,996) Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents $ (18,671) $ 40,299 $ (62,320) (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
The deferred income tax expense of $56.8 million and $25.3 million for the years ended December 31, 2023 and 2022, respectively, were primarily a result of 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.
Dollars) 2024 2023 2022 Income before income taxes $ 44,605 $ 106,160 $ 244,935 Current income tax expense $ 69,277 $ 55,688 $ 80,566 Deferred income tax (recovery) expense (27,888) 56,759 25,340 Total income tax expense $ 41,389 $ 112,447 $ 105,906 Effective tax rate 93 % 106 % 43 % Current income tax expense for the year ended December 31, 2024, was $69.3 million (2023 - $55.7 million; 2022 - $80.6 million).
Dollars) 2025 2024 2023 (Loss) income before income taxes $ (232,872) $ 44,605 $ 106,160 Current income tax expense $ 15,859 $ 69,277 $ 55,688 Deferred income tax (recovery) expense (55,612) (27,888) 56,759 Total income tax (recovery) expense $ (39,753) $ 41,389 $ 112,447 Effective tax rate 17 % 93 % 106 % Current income tax expense for the year ended December 31, 2025, was $15.9 million (2024 - $69.3 million; 2023 - $55.7 million).
The 2023 Program expired on November 2, 2024. As of December 31, 2024, all shares re-purchased under the 2024 Program were held as treasury shares and all shares re-purchased under the 2023 Program were cancelled subsequent to re-purchase.
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.
Dollars) Oil, natural gas and NGL sales $ 621,849 $ 636,957 $ 711,388 Transportation expenses (18,464) (14,546) (10,197) 603,385 622,411 701,191 Operating expenses (202,331) (186,864) (162,385) Operating netback (1) $ 401,054 $ 435,547 $ 538,806 (U.S.
Dollars) Oil, natural gas and NGL sales $ 596,713 $ 621,849 $ 636,957 Transportation expenses (17,024) (18,464) (14,546) 579,689 603,385 622,411 Operating expenses (248,748) (202,331) (186,864) Operating netback (1) $ 330,941 $ 401,054 $ 435,547 (U.S.
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2023, increased by 2% to $4.84 per boe compared to 2022 due to higher NAR sales in 2023.
G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2025, decreased by 14% to $4.37 compared to 2024 due to a 37% increase in sales volumes.
The table below shows the break-down of our 2025 capital program: Number of Wells (Gross) Number of Wells (Net) 2025 Capital Budget ($ million) Development - Colombia 4 - 6 2 - 3 105 - 120 Development - Ecuador 2 2 35 - 45 Development - Canada 4 - 6 2 - 3 35 - 45 Exploration, Colombia and Ecuador 6 - 8 6 - 8 65 - 70 16 - 22 12 - 16 240 - 280 Our base capital program for 2025 is $240 million to $280 million for exploration and development activities.
The table below shows the break-down of our 2026 capital program: Number of Wells (Gross) Number of Wells (Net) 2026 Capital Budget ($ million) Development - Colombia 4 - 5 2 - 3 70 - 90 Development - Canada 4 - 5 2 - 3 35 - 45 Development - Ecuador — — 15 - 25 8 - 10 4 - 6 120 - 160 Our base capital program for 2026 is $120 million to $160 million with over 90% attributed to development activities.
We are headquartered in Calgary, Alberta, Canada. As of December 31, 2024, we had estimated proved reserves NAR of 135.0 MMBOE, an 82% increase from the prior year, of which 50% were proved developed reserves and 62% were oil.
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.
Ecuador includes the Charapa and Chanangue Blocks. Canada includes several areas in the Western Canadian Sedimentary Basin with all production in Alberta, Canada.
Canada includes several areas in the Western Canadian Sedimentary Basin with the majority of production in Alberta, Canada.
Royalties as a percentage of production for the year ended December 31, 2023, decreased 3% compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador. The Midas Block includes the Acordionero field, the Suroriente Block includes the Cohembi field, and the Chaza Block includes the Costayaco and Moqueta fields.
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.
Dollars) Oil, natural gas and NGL sales $ 575,482 $ 621,297 $ 711,388 Transportation expenses (16,297) (13,829) (10,197) 559,185 607,468 701,191 Operating expenses (179,257) (179,103) (162,385) Operating netback (1) $ 379,928 $ 428,365 $ 538,806 (U.S.
Dollars) Oil, natural gas and NGL sales $ 418,411 $ 575,482 $ 621,297 Transportation expenses (12,505) (16,297) (13,829) 405,906 559,185 607,468 Operating expenses (165,902) (179,257) (179,103) Operating netback (1) $ 240,004 $ 379,928 $ 428,365 (U.S.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 41 Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD Year Ended December 31, Average Daily Volumes (BOEPD) - Colombia 2024 2023 2022 WI production before royalties 29,389 31,590 30,592 Royalties (5,545) (6,161) (6,870) Production NAR 23,844 25,429 23,722 Decrease (increase) in inventory 53 (65) (26) Sales 23,897 25,364 23,696 Royalties, % of working interest production before royalties 19 % 20 % 22 % Year Ended December 31, Average Daily Volumes (BOEPD) - Ecuador 2024 2023 2022 WI production before royalties 2,477 1,057 154 Royalties (881) (387) (61) Production NAR 1,596 670 93 Increase in inventory (507) (87) (93) Sales 1,089 583 — Royalties, % of working interest production before royalties 36 % 37 % 40 % Year Ended December 31, Average Daily Volumes (BOEPD) - Canada 2024 2023 2022 WI production before royalties 2,844 — — Royalties (394) — — Production NAR 2,450 — — Increase in inventory — — — Sales 2,450 — — Royalties, % of working interest production before royalties 14 % — % — % Year Ended December 31, Average Daily Volumes (BOEPD) - Total Company 2024 2023 2022 WI production before royalties 34,710 32,647 30,746 Royalties (6,820) (6,548) (6,931) Production NAR 27,890 26,099 23,815 (Increase) decrease in inventory (454) (152) (119) Sales 27,436 25,947 23,696 Royalties, % of working interest production before royalties 20 % 20 % 23 % Oil, natural gas and NGL production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023.
Oil, Natural Gas and NGL Production and Sales Volumes, BOEPD Year Ended December 31, Average Daily Volumes (BOEPD) - Colombia 2025 2024 2023 WI production before royalties 24,169 29,389 31,590 Royalties (3,685) (5,545) (6,161) Production NAR 20,484 23,844 25,429 (Increase) decrease in inventory (210) 53 (65) Sales 20,274 23,897 25,364 Royalties, % of working interest production before royalties 15 % 19 % 20 % 43 Year Ended December 31, Average Daily Volumes (BOEPD) - Ecuador 2025 2024 2023 WI production before royalties 4,854 2,477 1,057 Royalties (1,497) (881) (387) Production NAR 3,357 1,596 670 Increase in inventory (569) (507) (87) Sales 2,788 1,089 583 Royalties, % of working interest production before royalties 31 % 36 % 37 % Year Ended December 31, Average Daily Volumes (BOEPD) - Canada 2025 2024 2023 WI production before royalties 16,685 2,844 — Royalties (2,083) (394) — Production NAR 14,602 2,450 — Increase in inventory — — — Sales 14,602 2,450 — Royalties, % of working interest production before royalties 12 % 14 % — % Year Ended December 31, Average Daily Volumes (BOEPD) - Total Company 2025 2024 2023 WI production before royalties 45,709 34,710 32,647 Royalties (7,266) (6,820) (6,548) Production NAR 38,443 27,890 26,099 Increase in inventory (779) (454) (152) Sales 37,664 27,436 25,947 Royalties, % of working interest production before royalties 16 % 20 % 20 % 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.
For the years ended December 31, 2024, 2023 and 2022, we had no ceiling test impairment losses.
For the year ended December 31, 2025 we had $136.3 million ceiling test impairment losses, none for December 31, 2024 and 2023.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. b 48 DD&A Expenses Year Ended December 31, 2024 Colombia Ecuador Canada Corporate Total DD&A Expenses, Thousands of U.S. Dollars $ 211,239 $ 10,162 $ 8,941 $ 277 $ 230,619 DD&A Expenses, U.S.
Refer to note 2 “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 53 54 DD&A Expenses Year Ended December 31, 2025 Colombia Ecuador Canada Corporate Total DD&A Expenses, Thousands of U.S. Dollars $ 199,381 $ 29,903 $ 48,599 $ 470 $ 278,353 DD&A Expenses, U.S.
G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 8% to $49.6 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 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. 56 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.
We used an average Brent Crude price of $80.42 p er boe, Edmonton Light Crude of C$98.01 per boe, Alberta AECO spot price of C$1.46 per MMBtu Edmonton Propane C$30.46 per boe, Edmonton Butane C$48.39 per boe and Edmonton Condensate C$100.83 per boe for the December 31, 2024 ceiling test calculations (December 31, 2023, and 2022 Brent Crude - $82.51 and $97.98 per boe, respectively).
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).
In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023. 44 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.
Transportation Expenses 47 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 difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory rate was primarily due to an increase in non-deductible foreign exchange adjustments, other permanent differences, the impact of foreign taxes, non-deductible royalties in Colombia and non-deductible stock-based compensation. These were partially offset by a decrease 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.
Our effective tax rate was 93% for the year ended December 31, 2024, compared to 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.
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.
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. 51 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, 2024: Year Ended December 31, 2024 2023 2022 Change in the U.S. dollar against the Colombian peso strengthened by weakened by strengthened by 15 % 21 % 21 % Change in the U.S. dollar against the Canadian dollar strengthened by weakened by strengthened by 9 % 2 % 7 % 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, 2024: Year Ended December 31, (Thousands of U.S.
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, 2025 2024 2023 Change in the U.S. dollar against the Colombian peso weakened by strengthened by weakened by 15 % 15 % 21 % Change in the U.S. dollar against the Canadian dollar weakened by strengthened by weakened by 5 % 9 % 2 % 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: 57 Year Ended December 31, (Thousands of 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.
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.

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Item 7A. Quantitative and Qualitative Disclosures About Market Risk

Market Risk — interest-rate, FX, commodity exposure

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Biggest changeInterest 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 credit facility, which bears floating rates of interest. At December 31, 2024, our credit facility remained undrawn (December 31, 2023 - $36.4 million).
Biggest changeInterest 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 credit facility, which bears floating rates of interest. At December 31, 2025, our Canadian and Colombian credit facilities remained undrawn (December 31, 2024 - undrawn).
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.
In Canada, we receive 100% of our revenue in Canadian dollars and majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.
A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately $0.3 million U.S. dollars on accounts payable, gain of approximately $0.1 million U.S. dollars on taxes receivable and payable and loss of approximately $0.2 million U.S. dollars on deferred tax assets and liabilities.
A one percent strengthening in Colombian peso against the U.S. dollar results in foreign exchange loss of approximately $0.4 million U.S. dollars on accounts payable, gain of approximately $0.2 million U.S. dollars on taxes receivable and payable and gain of approximately $0.1 million U.S. dollars on deferred tax assets and liabilities.
A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes.
A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any investments for trading purposes. 70
Our reporting currency is U.S. dollars and 97% 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.
Our reporting currency is U.S. dollars and 81% 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, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of income and VAT and G&A expenses in all locations are in local currency.
In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of our operating costs, income taxes, VAT, and G&A expenses in all locations are in local currency.

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