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What changed in GRAN TIERRA ENERGY INC.'s 10-K — 2023 vs 2024

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Paragraph-level year-over-year comparison of GRAN TIERRA ENERGY INC.'s 2023 and 2024 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 2024 report.

+285 added−209 removedSource: 10-K (2025-02-24) vs 10-K (2024-02-20)

Top changes in GRAN TIERRA ENERGY INC.'s 2024 10-K

285 paragraphs added · 209 removed · 178 edited across 6 sections

Item 1A. Risk Factors

Risk Factors — what could go wrong, per management

55 edited+53 added−2 removed82 unchanged
Biggest changeThere 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.
Biggest changeCertain 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.
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.
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.
Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the 25 areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.
Finally, although we strive to operate our business operations to accommodate expected climatic conditions, to the extent there are significant changes in the Earth’s climate, such as more severe or frequent weather conditions in the markets we serve or the areas where our assets reside, we could incur increased expenses, our operations could be materially impacted, and demand for our products could fall.
If the United States imposes sanctions on Colombia or Ecuador in the future, our business may be adversely affected Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States.
If the United States imposes sanctions on Colombia, Ecuador or Canada in the future, our business may be adversely affected Colombia is among several nations whose eligibility to receive foreign aid from the United States is dependent on its progress in stemming the production and transit of illegal drugs, which is subject to an annual review by the President of the United States.
Foreign currency exchange rate volatility may affect our financial results We sell our oil and natural gas production under agreements that are denominated mainly in U.S. dollars. Many of the operational and other expenses we incur, including current and deferred tax assets and liabilities in Colombia, are denominated in Colombian pesos.
Foreign currency exchange rate volatility may affect our financial results We sell our oil and natural gas production under agreements that are denominated mainly in U.S. dollars and Canadian dollars. Many of the operational and other expenses we incur in Colombia, including current and deferred tax assets and liabilities, are denominated in Colombian pesos.
Oil production in Ecuador has recently been impacted by outages experienced by the nation’s two major pipelines (the Sistema de Oleoductos Trans Ecuadoriano (“SOTE”) and the Oleoducto de Crudos Pesados (“OCP”) pipelines) caused by physical damage from significant soil erosion in areas along the Coca river.
Oil production in Ecuador has been impacted by outages experienced by the nation’s two major pipelines (the Sistema de Oleoductos Trans Ecuadoriano (“SOTE”) and the Oleoducto de Crudos Pesados (“OCP”) pipelines) caused by physical damage from significant soil erosion in areas along the Coca river.
As a result of this concentration, we may be disproportionately exposed to the impact of, among other things, regional supply and demand factors including limitations on our ability to most profitably sell or market our oil to a smaller pool of potential buyers, delays or interruptions of production from wells in these areas caused by governmental regulation, community protests, guerrilla activities, processing or transportation capacity constraints, continued authorization by the government to explore and drill in these areas, severe weather events and the availability of drilling rigs and related equipment, facilities, personnel or services.
As a result of this concentration, we may be disproportionately exposed to the impact of, among other things, regional supply and demand factors including limitations on our ability to most profitably sell or market our oil and natural gas to a smaller pool of potential buyers, delays or interruptions of production from wells in these areas caused by governmental regulation, community protests, guerrilla activities, processing or transportation capacity constraints, continued authorization by the government to explore and drill in these areas, severe weather events and the availability of drilling rigs and related equipment, facilities, personnel or services.
Moreover, if any of these events were to materialize, they could lead to losses of 22 sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.
Moreover, if any of these events were to materialize, they could lead to losses of sensitive information, critical infrastructure, personnel or capabilities essential to our operations and could have a material adverse effect on our reputation, financial condition or results of operations.
Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Colombia or Ecuador are beyond our control and may significantly hamper our ability to expand our operations or operate our business at a profit.
Any changes in the oil and gas or investment regulations and policies or a shift in political attitudes in Colombia or Ecuador are beyond our control and may significantly hamper our ability to expand our operations in the region or operate our business at a profit.
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 21 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, and illegal invasions to private property and impacting regions where our operating activities are located.
In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability to conduct business or perform some business processes in a timely manner.
In that event, key information and systems may be unavailable for a number of days or weeks, leading to our inability to conduct business or perform some business processes on a timely manner.
We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance 23 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.
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.
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.
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.
Some of these transport methods may result in increased levels of risk, including the risk of accidents involving serious injury or loss of life, and could lead to operational delays which could affect our ability to add to our reserve base or produce oil and could have a significant impact on our reputation or cash flow.
Some of these transport methods may result in increased levels of risk, including the risk of accidents involving serious injury or loss of life, and could lead to operational delays which could affect our ability to add to our reserve base or produce oil or natural gas and could have a significant impact on our reputation or cash flow.
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 numbers of 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 recent 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 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.
Our ability to obtain needed financing may be impaired by factors such as weak capital markets (both generally and for the oil and gas industry in particular), the location of our oil and natural gas properties, including in Colombia and Ecuador, low or declining prices of oil and natural gas on the commodities markets, and the loss of key management.
Our ability to obtain needed financing may be impaired by factors such as weak capital markets (both generally and for the oil and gas industry in particular), the location of our oil and natural gas properties, including our assets in Colombia, Ecuador and Canada, low or declining prices of oil and natural gas on the commodities markets, and the loss of key management.
The differentials and transportation costs can change over time and have a detrimental impact on realized prices. 18 Future decreases in the prices of oil, 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 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.
Wells that are drilled may not achieve the results expected. Economic factors beyond our control, such as world oil prices, interest rates, inflation, and exchange rates, will also impact the quantity and value of our reserves.
Wells that are drilled may not achieve the results expected. Economic factors beyond our control, such as world oil and natural gas prices, interest rates, inflation, and exchange rates, will also impact the quantity and value of our reserves.
Future oil and 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.
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.
Furthermore, prices which we receive for our oil 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 prices, are established by contracts with purchasers and include the deductions for quality differentials and transportation.
Most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency transactions are translated to U.S. dollars, our reporting currency. An appreciation of local currencies can increase our costs and negatively impact our results from operations.
Our capital and operational expenditures in Canada and most of our administration costs in Canada are incurred in Canadian dollars. As a result, we are exposed to translation risk when local currency transactions are translated to U.S. dollars, our reporting currency. An appreciation of local currencies can increase our costs and negatively impact our results from operations.
We rely on local infrastructure and the availability of transportation for storage and shipment of our products. This infrastructure, including storage and transportation facilities, is less developed than that in North America and may be insufficient for our needs at commercially acceptable terms in the localities in which we operate.
We rely on local infrastructure and the availability of transportation for storage and shipment of our products. The infrastructure in Colombia and Ecuador, including storage and transportation facilities, is less developed than that in North America and may be insufficient for our needs at commercially acceptable terms in the localities in which we operate.
Social disruptions or community disputes in our areas of operations may delay production and result in lost revenue To enjoy the support and trust of local populations and governments, we must demonstrate a commitment to providing local employment, training and business opportunities; a high level of environmental performance; open and transparent communication; and a willingness to discuss and address community issues including community development investments that are carefully selected, not unduly costly and bring lasting social and economic benefits to the community and the area.
Social disruptions or community disputes in Colombia and Ecuador may delay production and result in lost revenue To enjoy the support and trust of local populations and governments in Colombia and Ecuador, we must demonstrate a commitment to providing local employment, training and business opportunities; a high level of environmental performance; open and transparent communication; and a willingness to discuss and address community issues including community development investments that are carefully selected, not unduly costly and bring lasting social and economic benefits to the community and the area.
When producing an estimate of the amount of oil that is recoverable from a particular reservoir, probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
When producing an estimate of the amount of oil or natural gas that is recoverable from a particular reservoir, probable reserves are those additional reserves that are less certain to be recovered than proved reserves but which, together with proved reserves, are as likely as not to be recovered.
The current and forward contract oil price is 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 has been volatile and is expected to remain so.
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.
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 2024 is $210.0 million to $240.0 million for exploration and development activities. We expect to fund our 2024 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 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.
Exploration and production operations are subject to legal, social, security, political and economic uncertainties, including terrorism, social unrest and activism, illegal blockades, strikes by local or national labor groups, interference with private contract rights, extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and natural gas industry, such as restrictions on production, price controls and export controls.
Exploration and production operations are subject to legal, social, security, political and economic uncertainties, including terrorism, social unrest and activism, illegal blockades, strikes by local or national labor groups, interference with private contract rights, extreme fluctuations in currency exchange rates, high rates of inflation, exchange controls, changes in tax rates, tariff and import/export regulations and sanctions by the United States or other countries, changes in laws or policies affecting environmental issues (including land use and water use), workplace safety, foreign investment, foreign trade, investment or taxation, as well as restrictions imposed on the oil and gas industry, such as restrictions on production, price controls and export controls.
For example, on an international level, in December 2015, almost 200 nations, including Colombia, 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 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.
If the amount of capital we are able to raise from financing activities, together with our cash flows from operations, is not sufficient to satisfy our capital needs (even to the extent that we reduce our activities), we may be required to curtail our operations.
If the amount of capital we are able to raise from financing activities, together with our cash flows from operations, is not sufficient to satisfy our capital needs, we may be required to curtail our operations.
All of our revenue is generated outside of Canada and the United States, and if we determine to, or are required to, repatriate earnings from foreign jurisdictions, we could be subject to taxes All of our revenue is generated outside of Canada and the United States.
A substantial portion of our revenue is generated outside of Canada and the United States, and if we determine to, or are required to, repatriate earnings from foreign jurisdictions, we could be subject to taxes A substantial portion of our revenue is generated outside of Canada and the United States.
In addition, shareholders in any of these jurisdictions will not be able to transfer such shares of Common Stock for trading on another market without effecting necessary procedures with our transfer agent or registrar. This could result in time delays and additional cost for shareholders of the Common Stock. Item 1B. Unresolved Staff Comments None.
In addition, shareholders in any of these jurisdictions will not be able to transfer such shares of Common Stock for trading on another market without effecting necessary procedures with our transfer agent or registrar. This could result in time delays and additional cost for shareholders of the Common Stock.
Despite our efforts to mitigate “spoof” and “phishing” emails through policies and education, “spoof” and “phishing” activities remain a serious problem that may damage our information technology infrastructure.
Despite our efforts to mitigate “spoof” and “phishing” emails through policies and education, “spoof” and “phishing” activities remain a serious risk that may result in damage our information technology infrastructure.
Our operations create the risk of significant environmental liabilities to the government or third parties for any unlawful discharge of oil, gas or other pollutants into the air, 24 soil or water or for certain other environmental impacts.
Our operations create the risk of significant environmental liabilities to the government of the jurisdictions in which we operate or third parties for any unlawful discharge of oil, gas or other pollutants into the air, soil or water or for certain other environmental impacts.
Further, we operate in remote areas and may rely on helicopters, boats or other transportation methods.
Further, we operate in remote areas in both South America and Canada and may rely on helicopters, boats or other transportation methods.
Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal fines and penalties.
Compliance with such legislation can require significant expenditures. Failure to comply with these laws and regulations may result in the suspension or termination of operations and subject us to administrative, civil and criminal fines and penalties.
These expectations and standards may continue to evolve. A failure to meet goals or evolving stakeholder expectations of ESG practices and reporting may potentially harm our reputation and impact employee retention, customer relationships, and access to capital.
These expectations and standards may continue to evolve. A failure to meet our publicly disclosed goals or evolving stakeholder expectations of ESG practices and reporting may increase the risk of litigation with respect to such goals or expectations, potentially harm our reputation and impact employee retention, customer relationships, and access to capital.
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 Substantially all of our revenues are derived from the sale of oil.
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.
If we are not able to realize the anticipated benefits expected from our acquisitions within a reasonable time, our business, financial condition and results of operations may be adversely affected.
If we are not able to achieve these objectives and realize the anticipated benefits and synergies expected from the acquisition within a reasonable time, our business, financial condition and operating results may be adversely affected.
Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify and acquire additional suitable producing properties or prospects, to identify and retain responsible service providers and contractors to efficiently drill and complete our wells and to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets. 19 Exploration for oil and natural gas, and development of new formations, is risky Oil and natural gas exploration involves a high degree of operational and financial risk.
Our future reserves will depend not only on our ability to develop and effectively manage then-existing properties, but also on our ability to identify, acquire and successfully integrate additional suitable producing properties or prospects, to identify and retain responsible service providers and contractors to efficiently drill and complete our wells and to find markets for the oil and natural gas we develop and to effectively distribute our production into our markets.
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 (“DEI”) initiatives, and heightened governance standards.
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.
All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to an extensive suite of international conventions and national and regional laws and regulations.
Environmental regulation and risks may adversely affect our business Environmental regulation is stringent and the costs and expenses of regulatory compliance are increasing. All phases of the oil and natural gas business present environmental risks and hazards and are subject to environmental regulation pursuant to an extensive suite of international conventions and national and regional laws and regulations.
Environmental legislation provides 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. The legislation also requires that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. Compliance with such legislation can require significant expenditures.
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.
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 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.
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. In 2023, the Colombian government is undertaking other peace process conversations with illegal groups in the country.
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.
Significant restrictions on GHG emissions could result in decreased demand for the oil that we produce, with a resulting decrease in the value of our reserves. Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and natural gas companies in connection with their GHG emissions.
Increasing attention to the risks of climate change has resulted in an increased possibility of lawsuits brought by public and private entities against oil and natural gas companies in connection with their GHG emissions.
Current GHG emissions legislation has not resulted in material compliance costs; however, emissions, carbon and other regulations impacting climate and climate related matters are constantly evolving. 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 restrictions.
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.
Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations.
Additionally, some of this equipment is specialized and may be difficult to obtain in our areas of operations, which could hamper or delay operations, and could increase the cost of those operations. Further, adverse weather conditions, such as flooding and severe cold weather, may interrupt or curtail our operations, cause supply disruptions, and damage our equipment and facilities.
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 and Ecuador; however, we may eventually expand to other countries.
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. 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.
Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable. Certain acquisitions could adversely affect our financial results We may pursue strategic acquisitions as part of our business strategy from time to time.
Undistributed earnings of foreign subsidiaries are considered to be permanently reinvested and a determination of the amount of unrecognized deferred tax liability on these undistributed earnings is not practicable.
For the year ended December 31, 2023, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 88% of our production and at December 31, 2023, these four fields accounted for 84% of our proved reserves.
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.
These risks are more acute in the early stages of exploration, appraisal and development.
Exploration for oil and natural gas, and development of new formations, is risky Oil and natural gas exploration involves a high degree of operational and financial risk. These risks are more acute in the early stages of exploration, appraisal and development.
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. Environmental regulation and risks may adversely affect our business Environmental regulation is stringent and the costs and expenses of regulatory compliance are increasing.
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.
Security concerns in Colombia or Ecuador may disrupt our operations Oil pipelines have historically been primary targets of terrorist activity in Colombia.
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.
Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per barrel or greater. For the period from January 1 to February 15, 2024, the average price of Brent oil was $79.58 per barrel.
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.
In 2023, El-Niño-induced drought across Colombia, the decrease in power generated from hydroelectricity increased power costs, which resulted in higher operating expenses.
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.
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In either event we could incur significant costs.
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In either event we could incur significant costs. Drilling activities may encounter sour gas A significant portion of the natural gas produced in Alberta originates as sour gas. With the inclusion of wellhead treatment facilities, our infrastructure may, from time to time, encounter concentrations of sour gas.
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GTE mitigates this risk through the maintenance of surplus storage capacity at its facilities (typically 3-days by design) and the optionality of trucking oil to points of sale. 20 We are vulnerable to risks associated with geographically concentrated operations The vast majority of our production comes from four fields located in Colombia.
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If a well encounters a high concentration of sour gas it would have to be shut-in due to the lack of existing sour gas handling infrastructure.
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Sour gas leaks or other exposure to sour gas produced from our properties in Alberta may result in damage to equipment, liability to third parties, adverse effects to humans, animals or the environment, or the shutdown of operations.
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Special equipment and operating procedures are deployed by the industry in Canada for the production of sour gas in accordance with applicable regulatory requirements. Possible shortage of fresh water and surface and groundwater licenses Drilling and completion operations require a large amount of water.
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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.
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This ceiling may take the form of a physical ceiling supported by scientific investigation, or it may be a limitation we choose to accept to abate public concerns despite contradicting scientific evidence of the carrying capacity of the surface water resources.
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Drought and low water levels could impact the year-round availability and associated costs of fresh water for our Canadian operations such as drilling fluid, completions fluid and power or hydrogen plant cooling water.
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Furthermore, there can be no assurance that our Canadian governmental licenses to withdraw water will not be rescinded or that additional conditions will not be added to these licenses. Further, there can be no assurance that we will not have to pay a fee for the use of water in the future or that any such fees will be reasonable.
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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.
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Crown land tenure obligations, interpretations and freehold offset royalty obligations Our Canadian resources are held in leases, mostly owned by Alberta. There is a risk that the Government of Alberta imposes the strictest interpretation of land tenure regulations and terminates a high percentage of leases on expiry.
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The leases have defined terms and conditions upon which they are granted and renewed. The Government of Alberta has the power to unilaterally change the royalty charged or the conditions of renewal. We are at risk of loss of value due to revision in royalty or lease renewal provisions.
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We also risk losing leases if they are not drilled and brought on to production within the terms of the relevant lease.
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We may fail to bring leases on to production because limited capital may be allocated to other higher return priorities or because surface access to a point where wells can be drilled to access a lease may be impaired by surface conditions, such as swamps, steep valleys, or there may be protected species access restrictions.
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Furthermore, on the freehold side, as we develop our land positions in Alberta, we may be required to pay offset royalties to owners of adjacent land without wells.
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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.
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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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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.
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However, title reviews, if conducted, do not guarantee that an unforeseen defect in the chain of title will not arise to defeat a claim by us.
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If any such defect were to arise, our entitlement to the production and reserves associated with such properties could be jeopardized, and could have a material adverse effect on our financial condition, results of operations and our ability to timely execute our business plan. Indigenous peoples have claimed title and rights to portions of Western Canada.
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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.
Added
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.
Added
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.
Added
We are not aware that any claims have been made by Indigenous peoples in respect of our assets in Canada; however, if a claim arose and was successful this could have an adverse effect on our operations. Additionally, opposition may occur from stakeholders, or there may be an expectation of compensation or consideration associated with a project beyond historical levels.

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Item 1C. Cybersecurity

Cybersecurity — threats and controls disclosure

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Biggest changeThis does not guarantee that future incidents or threats will not have a material impact or that we are not currently the subject of an undetected incident or threat that may have such an impact. 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.
Biggest changeAdditional information on cybersecurity risks we face is discussed in “Risk Factors” in Item 1A, which should be read in conjunction with the foregoing information.
Management The Executive Officers and Vice President, Corporate Services are involved in all significant and appropriate cybersecurity decisions on the implementation and design of our IT architecture.
Management The Executive Officers and Executive Vice President, Corporate Services are involved in all significant and appropriate cybersecurity decisions on the implementation and design of our IT architecture.
None of our critical core business activities that impact production, transportation or sales of oil and gas are remotely controlled. 26 Risk Management and Strategy We have implemented a cybersecurity program to assess, identify, mitigate and manage risks from cybersecurity threats that may result in material adverse effects on the confidentiality, integrity, and availability of our information systems.
None of our critical core business activities that impact production, transportation or sales of oil and gas are remotely controlled. Risk Management and Strategy We have implemented a cybersecurity program to assess, identify, mitigate and manage risks from cybersecurity threats that may result in material adverse effects on the confidentiality, integrity, and availability of our information systems.
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 Vice President, Corporate Services also attends certain meetings of the Audit Committee to report information on material risks from cybersecurity threats.
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.
We conduct penetration testing and cybersecurity audits, and require all employees to undertake data protection and cybersecurity training on an annual basis.
We conduct penetration testing and cybersecurity audits, and require all employees to undertake data 32 protection and cybersecurity training on an annual basis.
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 regularly review the measures implemented by the Company to identify and mitigate data protection and cybersecurity risks.
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.
The Director of IT discusses all potential changes to the Company’s controls or detection systems with the Vice President, Corporate Services prior to implementation. The Vice President, Corporate Services is updated by the Director of IT on a regular 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 Director of IT on a periodic basis regarding trends in technology and cybersecurity threats or any potential changes to the Company’s cybersecurity program.
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. The Director of IT has extensive cybersecurity knowledge and skills gained from over 20 years of relevant work experience.
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.
Added
The 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.
Added
This does not guarantee that future incidents or threats will not have a material impact or that we are not currently the subject of an undetected incident or threat that may have such an impact. In particular, sophisticated nation state actors have targeted critical infrastructure, and may continue to do so in the future.

Item 4. Mine Safety Disclosures

Mine Safety Disclosures — required of mining issuers

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Biggest changeEllson has over 24 years of experience in a broad range of international corporate finance and accounting roles. Mr. Ellson is currently a Director of Canary Biofuels and Beyond Renewables (both private companies) and until September 2022 was a Director at PetroTal Corp. (since December 2017). From July 2014 until December 2014 Mr.
Biggest changeEllson 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.
He is credited as the author of various publications and has presented in numerous professional forums. • James Evans, 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 19 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 in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 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 33 in Chad, Africa from August 2011 until July 2014. Glencore E&P (Canada) purchased Caracal in July 2014. Mr.
Guidry is an Alberta-registered professional engineer (P. Eng.) and holds a B.Sc. in petroleum engineering from Texas A&M University. 27 • 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.
Item 4. Mine Safety Disclosures Not applicable. Information About Our Executive Officers Set forth below is information regarding our executive officers as of February 15, 2024: 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 20, 2025: Name Age Position Gary S.
Morin has a Bachelor of Science degree in Geological Engineering from the University of Waterloo in 2001. • Phillip Abraham, Vice President, Legal and Business Development. Mr.
Morin has a Bachelor of Science degree in Geological Engineering from the University of Waterloo in 2001. • Phillip Abraham, Executive Vice President, Legal and Land. Mr.
Guidry 68 President and Chief Executive Officer, Director Ryan Ellson 48 Chief Financial Officer and Executive Vice President, Finance Sebastien Morin 47 Chief Operating Officer Phillip Abraham 53 Vice President, Legal and Business Development James Evans 58 Vice President, Corporate Services • Gary S. Guidry, President and Chief Executive Officer, Director. Mr.
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.

Item 5. Market for Registrant's Common Equity

Market for Common Equity — stock, dividends, buybacks

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Biggest changeAs of February 15, 2024, there were approximately 32 holders of record of shares of our Common Stock and 32,246,501 shares outstanding with $0.001 par value. 28 Dividend Policy We have never declared or paid dividends on the shares of Common Stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future.
Biggest changeDividend Policy We have never declared or paid dividends on the shares of Common Stock and we intend to retain future earnings, if any, to support the development of the business and therefore do not anticipate paying cash dividends for the foreseeable future.
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.
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.
Under the 2023 Program, we are able to purchase at prevailing market prices up to 3,234,914 shares of Common Stock, representing approximately 10% of the public float of common shares as of October 20, 2023.
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.
(2) On October 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE American or alternative trading programs in Canada or the United States commencing November 3, 2023 and ending on November 2, 2024.
(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.
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, 2023 — $ — — 3,234,914 November 1-30, 2023 755,790 $ 6.34 755,790 2,479,124 December 1-31, 2023 286,014 $ 5.87 286,014 2,193,110 Total 1,041,804 $ 6.21 1,041,804 2,193,110 (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, 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.
Added
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.
Added
Performance Graph The information in this Annual Report on Form 10-K appearing under the heading “Performance Graph” is being “furnished” pursuant to Item 201(e) of Regulation S-K under the securities Act and shall not be deemed to be “soliciting material” or “filed” with the SEC or subject to Regulation 14A or 14C, other than as provided in Item 201(e) of Regulation S-K, or to the liabilities of Section 18 of the Exchange Act and shall not be deemed incorporated by reference into any filing under the Securities Act or the Exchange Act except to the extent that we specifically incorporate it by reference into such filing.
Added
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.
Added
This is compared with the cumulative total returns over the same period of the S&P 500 Total Return Index and the S&P O&G E&P Select Index Total Return.
Added
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.
Added
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.
Added
(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

Item 7. Management's Discussion & Analysis

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

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Biggest changeDollars) 2023 % Change 2022 % Change 2021 Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722 Operating expenses 186,864 15 162,385 20 135,722 Transportation expenses 14,546 43 10,197 (12) 11,618 Operating netback (1) 435,547 (19) 538,806 65 326,382 DD&A expenses 215,584 20 180,280 29 139,874 G&A expenses before stock-based compensation 40,124 26 31,908 15 27,867 G&A stock-based compensation expense 5,722 (37) 9,049 8 8,396 Foreign exchange loss 11,822 359 2,578 (87) 20,477 Derivative instruments loss — (100) 26,611 (46) 48,838 Other financial instruments loss (gain) 15 314 (7) (100) 3,369 Interest expense 55,806 20 46,493 (15) 54,381 329,073 11 296,912 (2) 303,202 Other (loss) gain (2,297) (188) 2,598 6,005 (44) Interest income 1,983 348 443 100 — Income before income taxes 106,160 (57) 244,935 959 23,136 Current income tax expense 55,688 (31) 80,566 1,699 4,479 Deferred income tax expense (recovery) 56,759 124 25,340 206 (23,825) Total income tax expense (recovery) 112,447 6 105,906 647 (19,346) 33 Net (loss) income $ (6,287) (105) $ 139,029 227 $ 42,482 Sales Volumes (NAR) Total sales volumes, BOPD 25,947 9 23,696 10 21,598 Brent Price per bbl $ 82.16 (17) $ 99.04 40 $ 70.95 Consolidated Results of Operations per bbl Sales Volumes (NAR) Oil sales $ 67.26 (18) $ 82.25 37 $ 60.09 Operating expenses 19.73 5 18.77 9 17.22 Transportation expenses 1.54 31 1.18 (20) 1.48 Operating netback (1) 45.99 (26) 62.30 51 41.39 DD&A expenses 22.76 9 20.84 17 17.74 G&A expenses before stock-based compensation 4.24 15 3.69 5 3.53 G&A stock-based compensation expense 0.60 (43) 1.05 (2) 1.07 Foreign exchange loss 1.25 317 0.30 (88) 2.60 Derivative instruments loss — (100) 3.08 (50) 6.19 Other financial instruments loss — — — (100) 0.43 Interest expense 5.89 9 5.38 (22) 6.90 34.74 1 34.34 (11) 38.46 Other (loss) gain (0.24) (180) 0.30 3,100 (0.01) Interest income 0.21 320 0.05 100 — Income before income taxes 11.22 (60) 28.31 870 2.92 Current income tax expense 5.88 (37) 9.31 1,533 0.57 Deferred income tax expense (recovery) 5.99 104 2.93 197 (3.02) Total income tax expense (recovery) 11.87 (3) 12.24 600 (2.45) Net (loss) income $ (0.65) (104) $ 16.07 199 $ 5.37 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
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.
The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 45% Colombian statutory tax 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 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 43% for the year ended December 31, 2022, and the 35% Colombian statutory rate was primarily due to $26.6 million of hedging loss, $46.5 million of financing cost mainly related to the senior notes, and $23.1 million of stock-based compensation and G&A cost, which were incurred in jurisdictions where no tax benefit is recognized.
The difference between our effective tax rate of 43% for the year ended December 31, 2022, and the 35% Colombian statutory was primarily due to $26.6 million of hedging loss, $46.5 million of financing cost mainly related to the senior notes, and $23.1 million of stock-based compensation and G&A cost, which were incurred in jurisdictions where no tax benefit is recognized.
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.
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%).
A reconciliation from net income or loss to EBITDA and adjusted EBITDA is as follows: Year Ended Three Months Ended December 31, December 31, September 30, (Thousands of U.S.
A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows: Year Ended Three Months Ended December 31, December 31, September 30, (Thousands of U.S.
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, 2023: 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, 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.
Discussions of items related to the fiscal year ended December 31, 2022 and year-to-year comparisons between the fiscal years ended December 31, 2022 and 2021, 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, 2022.
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.
Therefore, ceiling test estimates are based on historical prices discounted at 10% per year, and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves. For the years ended December 31, 2023, 2022, and 2021, we had no ceiling test impairment losses.
Therefore, ceiling test estimates are based on historical prices discounted at 10% per year, and it should not be assumed that estimates of future net revenues represent the fair market value of our reserves. For the years ended December 31, 2024, 2023 and 2022, we had no ceiling test impairment losses.
In addition, the ultimate 51 financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities.
In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate. 61 We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities.
Information regarding our asset retirement obligation can be found in Note 9 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 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.
Castilla and Vasconia differentials increased to $10.22 and $5.39 from $9.81 and $4.99 per bbl in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a $9.91 per bbl Oriente differential.
Vasconia and Castilla differentials increased to $5.39 and $10.22 per boe in 2023 from $4.99 and $9.81 per boe in 2022, respectively. During the year ended December 31, 2023, we commenced sales in Ecuador which were subject to a $9.91 per boe Oriente differential.
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 bbl when choosing a transportation method.
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.
It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed U.S. GAAP ceiling test calculation.
It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed GAAP ceiling test calculation.
Operating netback, as presented, is defined as oil 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.
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.
As of the end of 2023, Gran Tierra converts gas to power at seven of our facilities located in the Acordionero, Costayaco, Moqueta, Mono Arana, Los Angeles Cohembi and Juglar fields.
As of the end of 2024, Gran Tierra converts gas to power at seven of our facilities located in the Acordionero, Costayaco, Moqueta, Mono Arana, Los Angeles, Cohembi and Juglar fields.
This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses 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.
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.
On a per bbl basis, average realized prices decreased by 18% to $67.26 for the year ended December 31, 2023, compared to $82.25 in 2022, primarily as a result of the decrease in benchmark oil prices and higher Castilla and Vasconia differentials in 2023.
On a per boe basis, average realized prices decreased by 18% to $67.26 for the year ended December 31, 2023, compared to $82.25 in 2022, primarily as a result of the decrease in benchmark oil prices, offset by higher Castilla and Vasconia differentials in 2023.
A reconciliation from oil sales to operating netback is provided in the table above. EBITDA, as presented, is defined as net income or loss adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery.
A reconciliation from oil, natural gas and NGL sales to operating netback is provided in the table above. EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery.
However, the majority of the cash flows associated with proved reserves per the 2023 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 2024 reserve report should be realized prior to the potential elimination of carbon-based energy.
A reconciliation from net income or loss to funds flow from operations and free cash flow is as follows: 32 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: 39 Year Ended Three Months Ended, December 31, December 31, September 30, (Thousands of U.S.
On a per bbl basis, despite significant inflationary pressures operating expenses only increased by only 5% or $0.96 to $19.73 compared to $18.77 in the prior year, primarily as a result of $2.23 per bbl higher lifting costs associated with road and pipeline maintenance, power generation attributed to higher compressed natural gas purchases, diesel tariffs and equipment rental associated with testing exploratory wells, offset by $1.27 per bbl of lower workovers.
On a per boe basis, despite significant inflationary pressures operating expenses increased by only 5% or $0.96 to $19.73 in 2023 compared to $18.77 in 2022, primarily as a result of $2.23 per boe higher lifting costs associated with road and pipeline maintenance, power generation attributed to higher compressed natural gas purchases, diesel tariffs and equipment rental associated with testing exploratory wells, offset by $1.27 per boe of lower workovers.
Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2023 ceiling tests were based on wellhead prices per bbl 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, 2024 ceiling tests were based on wellhead prices per boe as of the first day of each month within that twelve-month period.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 48 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, 2023: (Thousands of U.S.
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.
Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Each non-GAAP financial measure is presented along with the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.
Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.
Our effective tax rate was 106% for the year ended December 31, 2023, compared to 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. These were partially offset by a decrease in valuation allowance and non-deductible stock-based compensation.
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 following table shows the effect of changes in realized price and sales volumes on our oil sales for the years ended December 31, 2023, 2022, and 2021: 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, 2024, 2023, and 2022: Year Ended December 31, (Thousands of U.S.
Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, 31 lease payments, foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, other non-cash gains or losses, and stock-based compensation expense.
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.
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.
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.
Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant. 52
Expected volatilities used in the fair value estimate are based on the historical volatility of our shares. The risk-free rate for periods within the expected term of the stock options is based on the U.S. Treasury yield curve in effect at the time of grant. Business Combination Business combinations are accounted for using the acquisition method.
In total, we converted 2.7 billion standard cubic feet of natural gas into electricity instead of being flared for the 49 year ended December 31, 2023 and have incurred capital expenditures of $28.5 million since 2018. The extent of spending on projects directly linked to reducing the climate impact of our operations.
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.
Expenditures on property, plant and equipment From 2018 to 2023, we incurred $22.9 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 2023, the Acordionero field represented 52% of our production.
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.
Ecuador includes the Charapa, Chanangue and Iguana Blocks. 35 Oil Sales Oil sales for the year ended December 31, 2023, decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023.
Oil, natural gas and NGL sales for the year ended December 31, 2023, decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Vasconia and Castilla differentials partially offset by 9% higher sales volumes and lower transportation discounts in 2023.
Under the 2023 Program, we are able to purchase up to 3,234,914 shares of Common Stock, representing 10% of the public float as of October 20, 2023, at prevailing market prices at the time of purchase. The 2023 Program will continue for one year and expire on November 2, 2024, or earlier if the 10% maximum is reached.
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.
Dollars per bbl Sales Volumes NAR) Brent $ 82.16 $ 99.04 $ 70.95 Quality and transportation discounts (14.90) (16.79) (10.86) Average realized price 67.26 82.25 60.09 Transportation expenses (1.54) (1.18) (1.48) Average realized price, net of transportation expenses 65.72 81.07 58.61 Operating expenses (19.73) (18.77) (17.22) Operating netback (1) $ 45.99 $ 62.30 $ 41.39 (1) Operating netback is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
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.
Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to net income or loss or other measures of financial performance as determined in accordance with GAAP.
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.
Based on the mid-point of the 2024 guidance, the capital budget is forecasted to be approximately 60% directed to development and 40% to exploration activities. Approximately 20% of the development activities included in the 2024 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 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.
Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow less capital expenditures.
Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results.
On a per bbl basis, the DD&A increase in 2023 was due to increased production and higher costs in the depletable base as a result of higher future development costs compared to 2022. DD&A expenses for the year ended December 31, 2022, increased 29% or $3.10 per bbl from 2021.
DD&A expenses for the year ended December 31, 2023, increased 20% or $1.92 per boe from 2022. On a per boe basis, the DD&A increase in 2023 was due to increased production and higher costs in the depletable base as a result of higher future development costs compared to 2022.
The following table shows the percentage of oil volumes we sold in Colombia and Ecuador using each transportation method for each of the three years ended December 31, 2023: Year Ended December 31, 2023 2022 2021 Volume transported through pipelines 2 % — % 12 % Volume sold at wellhead 47 % 47 % 34 % Volume transported via truck to pipelines 51 % 53 % 54 % 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, 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.
Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results.
Free cash flow, as presented, is defined as funds flow from operations less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results.
Dollars) 2023 % Change 2022 % Change 2021 Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109 Credit facility $ 36,364 100 $ — (100) $ 67,500 Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000 45 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 price trends and production levels.
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 per bbl Sales Volumes NAR) 2023 2022 2021 Average Brent price $ 82.16 $ 99.04 $ 70.95 Average realized price, net of transportation expenses for the comparative period $ 81.07 $ 58.61 $ 30.78 (Decrease) increase in benchmark prices (16.88) 28.09 27.74 Decrease (increase) in quality and transportation discounts 1.89 (5.93) 0.12 (Increase) decrease in transportation expense (0.36) 0.30 (0.03) Average realized price, net of transportation expenses for the year $ 65.72 $ 81.07 $ 58.61 Average realized price, net of transportation expenses as a % of Brent 80 % 82 % 83 % 38 Operating Netbacks Year Ended December 31, Consolidated 2023 2022 2021 (Thousands of 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.
As a result of an El-Niño-induced drought, power costs have increased across Colombia, which relies on hydroelectricity for more than two-thirds of its installed power capacity. In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023.
As a result of an El-Niño-induced drought, power costs in 2023 increased across Colombia, which relies on hydroelectricity for more than two-thirds of its installed power capacity.
On a per bbl basis, G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 2% to $4.84 compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 43% decrease in stock-based compensation expense which was a result of lower share price in 2023.
G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million compared to 2022 due to higher G&A expenses before stock-based compensation, partially offset by 37% decrease in stock-based compensation expense which was a result of lower share price in 2023.
At December 31, 2023, we had $24.8 million of 6.25% Senior Notes due 2025, $24.2 million of 7.75% Senior Notes due 2027, and $487.6 million of 9.50% Senior Notes due 2029.
At December 31, 2024, we had $24.8 million of 6.25% Senior Notes due 2025 (the “6.25% Senior Notes”), $24.2 million of 7.75% Senior Notes due 2027 (the “7.75% Senior Notes”), and $737.6 million of 9.50% Senior Notes due 2029 (the “9.50% Senior Notes”).
Dollars) 2023 % Change 2022 % Change 2021 Cash and cash equivalents $ 62,146 (51) $ 126,873 386 $ 26,109 Credit facility $ 36,364 100 $ — (100) $ 67,500 Senior Notes $ 536,619 (7) $ 579,909 (3) $ 600,000 (1) Sales volumes represent production NAR adjusted for inventory changes (2) Non-GAAP measures Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under General Accepted Accounting Principles (“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 (1) Sales volumes represent production NAR adjusted for inventory changes (2) Non-GAAP measures Operating netback, EBITDA, adjusted EBITDA, funds flow from operations, and free cash flow are non-GAAP measures which do not have any standardized meaning prescribed under U.S.
All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split. Overview We are a company focused on oil and gas exploration and production with assets currently in Colombia and Ecuador. Our Colombian properties represented 94% of our proved reserves NAR at December 31, 2023.
All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split. Overview We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador.
Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted 50 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.
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.
The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes will mature on February 15, 2025, unless earlier redeemed or re-purchased.
The 6.25% Senior Notes bear interest at a rate of 6.25% per year, payable semi-annually in arrears on February 15 and August 15 of each year, beginning on August 15, 2018. The 6.25% Senior Notes matured and were settled on February 15, 2025.
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.
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.
Operating expenses for the year ended December 31, 2022, increased by 20% to $162.4 million compared to $135.7 million in 2021.
Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022.
Dollars, unless otherwise noted) Year Ended December 31, 2023 % Change 2022 % Change 2021 SEC Compliant Reserves, NAR (MMBOE) Estimated proved oil and gas reserves 74 12 66 (1) 67 Estimated probable oil and gas reserves 46 28 36 — 36 Estimated possible oil and gas reserves 49 26 39 26 31 Average Consolidated Daily Volumes (BOPD) Working interest (“WI”) production before royalties 32,647 6 30,746 16 26,507 Royalties (6,548) (6) (6,931) 41 (4,919) Production NAR 26,099 10 23,815 10 21,588 (Increase) decrease in inventory (152) (28) (119) (1,290) 10 Sales (1) 25,947 9 23,696 10 21,598 Net (Loss) Income $ (6,287) (105) $ 139,029 227 $ 42,482 Operating Netback Oil sales $ 636,957 (10) $ 711,388 50 $ 473,722 Operating expenses (186,864) 15 (162,385) 20 (135,722) Transportation expenses (14,546) 43 (10,197) (12) (11,618) Operating netback (2) $ 435,547 (19) $ 538,806 65 $ 326,382 G&A Expenses Before Stock-Based Compensation $ 40,124 26 $ 31,908 15 $ 27,867 G&A Stock-Based Compensation $ 5,722 (37) $ 9,049 8 $ 8,396 Adjusted EBITDA (2) $ 399,355 (17) $ 481,882 101 $ 240,134 Net Cash Provided By Operating Activities $ 227,992 (47) $ 427,711 75 $ 244,834 Funds Flow From Operations (2) $ 276,785 (24) $ 366,024 96 $ 186,485 Capital Expenditures $ 218,882 (7) $ 236,604 58 $ 149,879 As at December 31, (Thousands of U.S.
Dollars, unless otherwise noted) Year Ended December 31, 2024 % Change 2023 % Change 2022 SEC Compliant Reserves, NAR (MMBOE) Estimated proved oil and gas reserves 135 82 74 12 66 Estimated probable oil and gas reserves 106 130 46 28 36 Estimated possible oil and gas reserves 75 53 49 26 39 Average Consolidated Daily Volumes (BOEPD) Working interest (“WI”) production before royalties 34,710 6 32,647 6 30,746 Royalties (6,820) 4 (6,548) (6) (6,931) Production NAR 27,890 7 26,099 10 23,815 (Increase) decrease in inventory (454) (199) (152) (28) (119) Sales (1) 27,436 6 25,947 9 23,696 Net Income (Loss) $ 3,216 151 $ (6,287) (105) $ 139,029 Operating Netback 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 (2) $ 401,054 (8) $ 435,547 (19) $ 538,806 G&A Expenses Before Stock-Based Compensation $ 39,912 (1) $ 40,124 26 $ 31,908 G&A Stock-Based Compensation $ 9,707 70 $ 5,722 (37) $ 9,049 Adjusted EBITDA (2) $ 366,758 (8) $ 399,355 (17) $ 481,882 Net Cash Provided By Operating Activities $ 239,321 5 $ 227,992 (47) $ 427,711 Funds Flow From Operations (2) $ 224,941 (19) $ 276,785 (24) $ 366,024 Capital Expenditures $ 234,236 3 $ 226,584 8 $ 210,331 As at December 31, (Thousands of U.S.
Dollars) 2023 2022 2021 Income before income taxes $ 106,160 $ 244,935 $ 23,136 Current income tax expense $ 55,688 $ 80,566 $ 4,479 Deferred income tax expense (recovery) 56,759 25,340 (23,825) Total income tax expense (recovery) $ 112,447 $ 105,906 $ (19,346) Effective tax rate 106 % 43 % (84) % Current income tax expense for the year ended December 31, 2023, was $55.7 million (2022 - $80.6 million; 2021 - $4.5 million).
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).
The Company canceled all previously purchased 6.25% Senior Notes as at December 31, 2023. During the year ended December 31, 2023, we implemented a share re-purchase program (the “2023 Program”) through the facilities of the TSX, the NYSE or alternative trading programs in Canada or the United States, if eligible.
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.
Total G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 26% to $40.1 million compared to 2022 for the same reason mentioned above.
G&A expenses before stock-based compensation, on a per boe basis, for the year ended December 31, 2023, increased by 15% to $4.24 compared to 2022, for the same reason mentioned above.
Cash and Cash Equivalents Held Outside of Canada and the United States At December 31, 2023 , 100% of our cash and cash equivalents were held by subsidiaries outside Canada and the United States. 47 Cash Flows The following table presents our sources and uses of cash and cash equivalents for the periods presented: Year Ended December 31, 2023 2022 2021 Sources of Cash and Cash Equivalents: Net (loss) income $ (6,287) $ 139,029 $ 42,482 Adjustments to reconcile net (loss) income to funds flow from operations DD&A expenses 215,584 180,280 139,874 Deferred tax expense (recovery) 56,759 25,340 (23,825) Stock-based compensation expense 5,722 9,049 8,396 Amortization of debt issuance costs 5,831 3,528 3,809 Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 Other non-cash loss (gain) 2,297 (2,598) 44 Derivative instruments loss — 26,611 48,838 Cash settlement on derivative instruments — (26,611) (58,427) Other financial instruments loss (gain) 15 (7) 3,369 Non-cash lease expenses 4,967 2,818 1,667 Lease payments (3,018) (1,666) (1,621) Funds flow from operations (1) 276,785 366,024 186,485 Changes in non-cash operating working capital — 64,317 59,154 Changes in non-cash investing working capital — 26,273 1,431 Proceeds from exercise of stock options 8 1,300 100 Proceeds from debt, net of issuance costs 48,014 — — Proceeds on disposition of investment, net of transaction costs — — 43,126 Foreign exchange gain on cash and cash equivalents and restricted cash and cash equivalents 5,869 — — 330,676 457,914 290,296 Uses of Cash and Cash Equivalents: Additions to property, plant and equipment (218,882) (236,604) (149,879) Repayment of Senior Notes (60,000) — — Proceeds from debt, net of issuance costs — — (228) Repayment of debt (13,636) (67,803) (122,500) Lease payments (6,527) (2,228) (2,182) Proceeds from other debt, net of issuance costs (13,351) — — Changes in non-cash operating working capital (48,416) — — Changes in non-cash investing working capital (7,702) — — Cash settlement of asset retirement obligation (377) (2,630) (805) Re-purchase of shares of Common Stock (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 — (2,104) (821) (392,996) (355,960) (276,415) Net (decrease) increase in cash and cash equivalents and restricted cash and cash equivalents $ (62,320) $ 101,954 $ 13,881 (1) Funds flow from operations is a non-GAAP measure which does not have any standardized meaning prescribed under GAAP.
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.
Dollars) Year Ended December 31, 2023 % change 2022 % change 2021 G&A expenses before stock-based compensation $ 40,124 26 $ 31,908 15 $ 27,867 G&A stock-based compensation 5,722 (37) 9,049 8 8,396 G&A expenses including stock-based compensation $ 45,846 12 $ 40,957 13 $ 36,263 (U.S.
G&A Expenses (Thousands of U.S. Dollars) Year Ended December 31, 2024 % change 2023 % change 2022 G&A expenses before stock-based compensation $ 39,912 (1) $ 40,124 26 $ 31,908 G&A stock-based compensation 9,707 70 5,722 (37) 9,049 G&A expenses including stock-based compensation $ 49,619 8 $ 45,846 12 $ 40,957 (U.S.
During the year ended December 31, 2023, we re-purchased 1,041,804 shares of Common Stock at a weighted average price of approximately $6.21 per share under the 2023 Program and 1,328,650 shares of Common Stock at a weighted average price of $8.15 per share, under the 2022 share re-purchase program (“2022 Program”), implemented in 2022 with similar terms to that of the 2023 Program.
During the year ended December 31, 2024, the Company re-purchased 487,948 shares of Common Stock at a weighted average price of approximately $6.49 per share under the 2024 Program and 1,662,110 shares at a weighted average price of $7.31 per share under the 2023 Program implemented in 2023 with similar terms to that of 2024 Program.
We will continue to implement projects that focus on environmental protection, conservation and reforestation efforts. Current assets and current liabilities These amounts are short-term in nature, and during the year ended December 31, 2023, management was not aware of any material impacts on these items related to climate change and climate events.
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.
Dollars Per bbl Sales Volumes NAR) G&A expenses before stock-based compensation $ 4.24 15 $ 3.69 5 $ 3.53 G&A stock-based compensation 0.60 (43) 1.05 (2) 1.07 G&A expenses including stock-based compensation $ 4.84 2 $ 4.74 3 $ 4.60 On a per bbl basis, G&A expenses before stock-based compensation for the year ended December 31, 2023, increased by 15% to $4.24 compared to 2022 due to costs attributed to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso against the U.S. dollar.
G&A expenses before stock-based compensation, on a per boe basis for the year ended December 31, 2024, decreased by 6% to $3.97 compared to 2023, for the same reason mentioned above and higher NAR sales during 2024. 50 G&A expenses before stock-based compensation for the year ended December 31, 2023, increased 26% to $40.1 million compared to 2022 due to costs attributed to business development activities, higher salaries related to increased headcount in Ecuador to support ramp-up of operations and the strengthening of the Colombian peso against the U.S. dollar.
Current income tax expense decreased for the year ended December 31, 2023, compared to 2022, primarily due to a decrease in taxable income.
Current income tax expense increased for the year ended December 31, 2024, compared to 2023, primarily due to the additional taxable income generated in Ecuador and Canada.
Our effective tax rate was 43% for the year ended December 31, 2022, compared with (84)% in 2021. The increase in the effective tax rate was primarily due to an increase in valuation allowance, other permanent differences, stock-based compensation costs, and non-deductible third party royalties in Colombia.
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 increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador. 34 Royalties as a percentage of production for the year ended December 31, 2023, decreased compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia.
The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador. 42 Royalties as a percentage of production for the year ended December 31, 2024, were comparable with royalties as a percentage of production for 2023.
We did not experience material credit losses on our accounts receivable during 2023. Share capital The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
Share capital The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.
Dollars) 2023 2022 2021 Oil sales for the comparative year $ 711,388 $ 473,722 $ 237,838 Realized sales price (decrease) increase effect (141,997) 191,664 219,641 Sales volume increase effect 67,566 46,002 16,243 Oil sales for the current year $ 636,957 $ 711,388 $ 473,722 Operating Expenses Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022.
Dollars) 2024 2023 2022 Oil, natural gas and NGL sales for the comparative year $ 636,957 $ 711,388 $ 473,722 Realized sales price (decrease) increase effect (12,147) (141,997) 191,664 Sales volumes (decrease) increase effect (21,916) 67,566 46,002 Oil, natural gas and NGL sales - acquisition 18,955 — — Oil, natural gas and NGL sales for the current year $ 621,849 $ 636,957 $ 711,388 Operating Expenses Operating expenses for the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023.
Dollars) Oil sales $ 636,957 $ 711,388 $ 473,722 Transportation expenses (14,546) (10,197) (11,618) 622,411 701,191 462,104 Operating expenses (186,864) (162,385) (135,722) Operating netback (1) $ 435,547 $ 538,806 $ 326,382 (U.S.
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.
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, 2023: Year Ended December 31, 2023 2022 2021 Change in the U.S. dollar against the Colombian peso weakened by strengthened by strengthened by 21 % 21 % 16 % Change in the U.S. dollar against the Canadian dollar weakened by strengthened by consistent 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, 2023: Year Ended December 31, (Thousands of U.S.
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.
Actual results will differ from these estimates and assumptions. At December 31, 2023, we provided promissory notes totaling $220.1 million (2022 - $111.1 million) to support letters of credit relating to work commitment guarantees in Colombia and Ecuador contained in exploration contracts, the Suroriente Block and other capital or operating requirements.
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.
On a per bbl basis, G&A expenses after stock-based compensation costs for the year ended December 31, 2022, increased by 3% to $4.74 per bbl compared to 2021 for the same reason mentioned above and higher stock-based compensation expense.
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.
Total G&A expenses after stock-based compensation for the year ended December 31, 2023, increased by 12% to $45.8 million, compared to 2022 for the same reason mentioned above.
G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 8% to $49.6 million, compared to 2023 due to higher stock-based compensation attributable to the higher share price in 2024.
The table below shows the break-down of our 2024 capital program: Number of Wells (Gross) Number of Wells (Net) 2024 Capital Budget ($ million) Development - Colombia 13 - 17 12 - 16 130 - 140 Exploration - Colombia and Ecuador 6 - 9 6 - 9 80 - 100 19 - 26 18 - 25 210 - 240 Our base capital program for 2024 is $210 million to $240 million for exploration and development activities.
The table below shows the break-down of our 2025 capital program: Number of Wells (Gross) Number of Wells (Net) 2025 Capital Budget ($ 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.
Dollars) 2023 2022 2021 2023 2022 2023 Net (loss) income $ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527 Adjustments to reconcile net (loss) income to EBITDA and Adjusted EBITDA DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019 Interest expense 55,806 46,493 54,381 17,789 10,750 13,503 Income tax expense (recovery) 112,447 105,906 (19,346) 5,499 5,966 40,333 EBITDA (non-GAAP) $ 377,550 $ 471,708 $ 217,391 $ 83,634 $ 101,772 $ 115,382 Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235 Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676) Foreign exchange loss 11,822 2,578 20,477 3,696 2,092 1,717 Unrealized derivative instruments gain — — (9,589) — — — Other financial instruments loss (gain) 15 (7) 3,369 15 (7) — Other non-cash loss (gain) 2,297 (2,598) 44 3,266 — (354) Stock-based compensation expense 5,722 9,049 8,396 1,974 2,673 1,931 Adjusted EBITDA (non-GAAP) $ 399,355 $ 481,882 $ 240,134 $ 92,964 $ 106,807 $ 119,235 Funds flow from operations, as presented, is defined as net income or loss adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, and other non-cash gains or losses.
Dollars) 2024 2023 2022 2024 2023 2024 Net income (loss) $ 3,216 $ (6,287) $ 139,029 $ (34,210) $ 7,711 $ 1,133 Adjustments to reconcile net income (loss) to EBITDA and Adjusted EBITDA DD&A expenses 230,619 215,584 180,280 63,406 52,635 55,573 Interest expense 80,466 55,806 46,493 23,752 17,789 19,892 Income tax expense 41,389 112,447 105,906 12,299 5,499 20,767 EBITDA (non-GAAP) $ 355,690 $ 377,550 $ 471,708 $ 65,247 $ 83,634 $ 97,365 Non-cash lease expense 5,923 4,967 2,818 1,759 1,479 1,370 Lease payments (5,035) (3,018) (1,666) (1,495) (1,100) (1,171) Foreign exchange (gain) loss (8,808) 11,822 2,578 (496) 3,696 (3,084) Unrealized derivative instruments loss 3,374 — — 3,374 — — Transaction costs 5,907 — — 4,448 — 1,459 Other non-cash loss (gain) — 2,312 (2,605) — 3,281 — Stock-based compensation expense (recovery) 9,707 5,722 9,049 3,331 1,974 (3,145) Adjusted EBITDA (non-GAAP) $ 366,758 $ 399,355 $ 481,882 $ 76,168 $ 92,964 $ 92,794 Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, deferred tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, other financial instruments gains or losses, and other non-cash gains or losses.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 44 2024 Work Program and Capital Expenditures Our Colombian development operation is expected to represent 93% of our production and approximately 60% - 70% of our 2024 capital budget, with the remainder allocated to exploration activities.
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.
The deferred income tax recovery of $23.8 million for the year ended December 31, 2021, was mainly a result of the release of the valuation allowance in Colombia, which was partially offset by excess tax depreciation compared with accounting depreciation and the use of tax losses to offset taxable income in Colombia.
The deferred income tax expense was a recovery of $27.9 million for the year ended December 31, 2024, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy, which were partially offset by tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.
These were partially offset by $13.2 million of non-taxable foreign exchange gain.
These were partially offset by $13.2 million of non-taxable foreign exchange gain. 53 Net Income (Loss) and Funds Flow From Operations (a Non-GAAP Measure) (Thousands of U.S.
G&A expenses before stock-based compensation were $40.1 million in 2023 compared to $31.9 million in 2022, representing a 26% increase • Capital expenditures decreased by $17.7 million or 7% to $218.9 million compared to 2022 due to a more condensed drilling program during 2023 30 (Thousands of U.S.
G&A expenses before stock-based compensation were $39.9 million in 2024 compared to $40.1 million in 2023, representing a 1% decrease • Capital expenditures increased by $7.7 million or 3% to $234.2 million compared to 2023 due to a higher number of wells drilled in 2024 in Colombia, Ecuador and Canada. 37 (Thousands of U.S.
Refer to “Financial and Operational Highlights - Non-GAAP measures” for a definition and reconciliation of this measure. 39 DD&A Expenses Year Ended December 31, 2023 2022 2021 DD&A Expenses, Thousands of U.S. Dollars $ 215,584 $ 180,280 $ 139,874 DD&A Expenses, U.S.
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.
Dollars) 2023 2022 2021 2023 2022 2023 Net (loss) income $ (6,287) $ 139,029 $ 42,482 $ 7,711 $ 33,275 $ 6,527 Adjustments to reconcile net (loss) income to funds flow from operations DD&A expenses 215,584 180,280 139,874 52,635 51,781 55,019 Deferred tax expense (recovery) 56,759 25,340 (23,825) 13,517 (11,528) 13,990 Stock-based compensation expense 5,722 9,049 8,396 1,974 2,673 1,931 Amortization of debt issuance costs 5,831 3,528 3,809 2,437 759 1,594 Non-cash lease expense 4,967 2,818 1,667 1,479 809 1,235 Lease payments (3,018) (1,666) (1,621) (1,100) (532) (676) Unrealized foreign exchange (gain) loss (5,085) 10,251 21,879 2,729 4,113 (266) Unrealized derivative instruments gain — — (9,589) — — — Other financial instruments loss (gain) 15 (7) 3,369 15 (7) — Other non-cash loss (gain) 2,297 (2,598) 44 3,266 — (354) Funds flow from operations (non-GAAP) $ 276,785 $ 366,024 $ 186,485 $ 84,663 $ 81,343 $ 79,000 Capital expenditures $ 218,882 $ 236,604 $ 149,879 $ 39,175 $ 72,887 $ 43,080 Free cash flow (non-GAAP) $ 57,903 $ 129,420 $ 36,606 $ 45,488 $ 8,456 $ 35,920 Consolidated Results of Operations Year Ended December 31, (Thousands of U.S.
Dollars) 2024 2023 2022 2024 2023 2024 Net income (loss) $ 3,216 $ (6,287) $ 139,029 $ (34,210) $ 7,711 $ 1,133 Adjustments to reconcile net income (loss) to funds flow from operations DD&A expenses 230,619 215,584 180,280 63,406 52,635 55,573 Deferred tax (recovery) expense (27,888) 56,759 25,340 4,444 13,517 5,550 Stock-based compensation expense (recovery) 9,707 5,722 9,049 3,331 1,974 (3,145) Amortization of debt issuance costs 12,918 5,831 3,528 3,743 2,437 3,109 Non-cash lease expense 5,923 4,967 2,818 1,759 1,479 1,370 Lease payments (5,035) (3,018) (1,666) (1,495) (1,100) (1,171) Unrealized foreign exchange (gain) loss (7,893) (5,085) 10,251 (223) 2,729 (2,081) Unrealized derivative instruments loss 3,374 — — 3,374 — — Other non-cash loss (gain) — 2,312 (2,605) — 3,281 — Funds flow from operations (non-GAAP) $ 224,941 $ 276,785 $ 366,024 $ 44,129 $ 84,663 $ 60,338 Capital expenditures $ 234,236 $ 226,584 $ 210,331 $ 70,413 $ 35,826 $ 49,779 Free cash flow (non-GAAP) $ (9,295) $ 50,201 $ 155,693 $ (26,284) $ 48,837 $ 10,559 Consolidated Results of Operations Year Ended December 31, (Thousands of U.S.
As of December 31, 2023, we had estimated proved reserves NAR of 74.3 MMBOE, a 13% increase from the prior year, of which 53% were proved developed reserves and 100% were oil. 29 Financial and Operational Highlights Key Highlights • Net loss in 2023 was $6.3 million or $(0.19) per share basic and diluted compared to a net income of $139.0 million or $3.81 per s hare basic and $3.76 per s hare diluted in 2022 • Income before income taxes in 2023 was $106.2 million compared to $244.9 million in 2022 • Adjusted EBITDA (2) for 2023 was $399.4 million compared to $481.9 million in 2022 • In 2023, we re-purchased 1.3 million and 1.0 million shares of Common Stock through the 2022 and 2023 share re-purchase programs, representing about 4% and 3%, respectively, of shares outstanding as of December 31, 2023 • Our total 2023 average production NAR was 26,099 BOPD, an increase from 23,815 BOPD in 2022 as a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador • Our total 2023 oil sales volumes NAR increased by 9% to 25,947 BOPD compared to 23,696 BOPD in 2022 • Oil sales for 2023 decreased by 10% to $637.0 million compared to $711.4 million in 2022, primarily as a result of a 17% decrease in Brent price and higher Castilla and Vasconia differentials, partially offset by 9% increase in sales volumes and lower transportation discounts • Oil sales per bbl for 2023 were $67.26, 18% lower compared to 2022, as a result of a decrease in benchmark oil prices • In 2023, we generated net cash provided by operating activities of $228.0 million, a decrease of 47% from $427.7 million in 2022 • During 2023, the Company generated $57.9 million of free cash flow (2) which was used for debt reduction and share re-purchases • Operating expenses per bbl for 2023 were $19.73, 5% higher compared to 2022, primarily due to higher lifting costs attributed to road and pipeline maintenance, power generation and equipment rental, offset by lower workovers.
We consolidated operating activities for the last two months of 2024 as a result of the i3 Energy acquisition • Net income in 2024 was $3.2 million or $0.10 per share basic and diluted compared to a net loss of $6.3 million or $(0.19) per s hare basic and diluted in 2023 • Income before income taxes in 2024 was $44.6 million compared to $106.2 million in 2023 • Adjusted EBITDA (2) in 2024 was $366.8 million compared to $399.4 million in 2023 • In 2024, we re-purchased 0.5 million and 1.7 million shares of Common Stock through the 2024 and 2023 share re-purchase programs, representing about 1% and 5%, respectively, of shares outstanding as of December 31, 2024 • Our 2024 average production NAR was 27,890 BOEPD, an increase from 26,099 BOEPD in 2023 as a result of two-months of production from the newly acquired Canadian operations, and positive exploration drilling results in Ecuador, partially offset by lower production in the Acordionero field • Our 2024 oil, natural gas and NGL sales volumes NAR increased by 6% to 27,436 BOEPD compared to 25,947 BOEPD in 2023 • Oil, natural gas and natural gas liquids (“NGL”) sales for 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, lower in sales volumes in Colombia, offset by increase in sales volumes in Ecuador, lower differentials, and the addition of natural gas and NGL into the portfolio via the Canadian acquisition in 2024 • In 2024, we generated net cash provided by operating activities of $239.3 million, an increase of 5% from $228.0 million in 2023 • Operating expenses per boe for 2024 were $20.15, 2% higher compared to 2023, primarily due to 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.
We expect our 2024 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on Brent oil prices being $70 per bbl for 2024. Capital Program Capital expenditures during the year ended December 31, 2023 were $218.9 million.
We expect our 2025 capital program to be fully funded by cash flows from operations. Funding this program from cash flows from operations relies in part on average Brent oil prices of $75.00 per boe, WTI oil prices of $71.00 per boe and average AECO gas prices of C$2.50 per mcf for 2025.

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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 changeForeign Currency Risk Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate. Our reporting currency is U.S. dollars and 100% of our revenues are related to the U.S. dollar price of Brent or WTI oil.
Biggest changeOur revenues are from oil sales at Brent or WTI pricing and for gas at AECO pricing and adjusted for quality. Foreign Currency Risk Foreign currency risk is a factor for our company but is ameliorated to a certain degree by the nature of expenditures and revenues in the countries where we operate.
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 $0.3 million U.S. dollars on taxes receivable and payable and loss of approximately $0.4 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 $0.3 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.
Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2023, our credit facility was drawn by $36.4 million (December 31, 2022 - undrawn).
Interest Rate Risk Interest rate risk is the risk that future cash flows will fluctuate as a result of changes in market interest rates. We are exposed to interest rate fluctuations on our credit facility, which bears floating rates of interest. At December 31, 2024, our credit facility remained undrawn (December 31, 2023 - $36.4 million).
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Our principal market risk relates to oil prices. Oil prices are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent pricing and adjusted for quality.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk Commodity Price Risk Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control.
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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.
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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.

Other GTE 10-K year-over-year comparisons