Gran Tierra Energy Inc.: Form 10-K for the period ended Dec 31, 2024

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. 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. 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. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.

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.

Estimates of oil and natural gas reserves may be inaccurate and our actual revenues may be lower than estimated

We make estimates of oil and natural gas reserves, upon which we base our financial projections and capital expenditure plans. We make these reserve estimates using various assumptions, including assumptions as to oil and natural gas prices, drilling and operating expenses, capital expenditures, taxes and availability of funds. Some of these assumptions are inherently subjective, and the accuracy of our reserve estimates relies in part on the ability of our management team, engineers and other advisors to make accurate assumptions. 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.

The process of estimating oil and natural gas reserves is complex and requires us to use significant decisions and assumptions in the evaluation of available geological, geophysical, engineering and economic data for each property. As a result, our reserves estimates are inherently imprecise. All categories of reserves are continually subject to revisions based on production history, results of additional exploration and development, price changes and other factors. 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. Possible reserves are even less certain and generally require only a 10% or greater probability of being recovered. Estimates of probable and possible reserves are by their nature much more speculative than estimates of proved reserves and are subject to greater uncertainties, and accordingly the likelihood of recovering those reserves is subject to substantially greater risk. Actual future production, oil and natural gas prices, revenues, taxes, exploration and development expenditures, operating expenses and quantities of recoverable oil and natural gas reserves may vary substantially from those we estimate. Such changes could materially reduce our revenues and result in the impairment of our oil and natural gas interests.

Unless we are able to replace our reserves and production, and develop and manage oil and natural gas reserves and production on an economically viable basis, our financial condition and results of operations will be adversely impacted

Our future success depends on our ability to find, develop and acquire additional oil and natural gas reserves that are economically recoverable. Producing oil and natural gas reservoirs generally are characterized by declining production rates that vary depending upon reservoir characteristics and other factors. Our future oil and natural gas reserves and production, and therefore our cash flows and results of operations, are highly dependent on our success in efficiently developing and exploiting our current reserves and economically finding or acquiring additional recoverable reserves. The value of our securities and our ability to raise capital will be adversely impacted if we are not able to replace our reserves that are depleted by production. We may not be able to develop, exploit, find or acquire sufficient additional reserves to replace our current and future production.

Exploration, development and production costs (including operating and transportation costs), marketing costs (including distribution costs) and regulatory compliance costs (including taxes) will substantially impact the net revenues we derive from the oil and natural gas that we produce. These costs are subject to fluctuations and variations in the areas in which we operate, and we may not be able to predict or control these costs. If these costs exceed our expectations, this may adversely affect our results of operations.

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.

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. It is difficult to predict the results and project the costs of implementing an exploratory drilling program due to the inherent uncertainties and costs of drilling in unknown formations and encountering various drilling conditions, such as unexpected formations or pressures, premature decline of reservoirs, the invasion of water into producing formations, tools lost in the hole, and changes in drilling plans and locations as a result of prior exploratory wells or additional seismic data and interpretations thereof. Future oil and natural gas exploration may involve unprofitable efforts, not only from dry wells, but from wells that are productive but do not produce sufficient net revenues to return a profit after drilling, operating and other costs.

Oil and natural gas exploration, development and production operations are subject to the risks and hazards typically associated with such operations, including, but not limited to, fire, explosion, blowouts, cratering, sour gas releases, spills and other environmental hazards. Such risks and hazards could result in substantial damage to oil and natural gas wells, production facilities, other property or the environment, as well as personal injury to our employees, contractors or members of the public. Losses resulting from the occurrence of any of these risks may have a material adverse effect on our business, financial condition, results of operations and prospects.

Although we maintain well control and liability insurance in an amount that we consider prudent and consistent with industry practice, liabilities associated with certain risks could exceed policy limits or not be covered. 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. 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. 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. 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. 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. 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. 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. 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. 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.

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. 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. We also risk losing leases if they are not drilled and brought on to production within the terms of the relevant lease. 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.

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. In addition, drilling of wells adjacent to undrilled freehold leases can trigger an obligation to drill the undrilled lands or pay a royalty on those lands equivalent to what would be expected if a well was operating on those lands, or alternatively we may allow the freehold leases to expire. As such, royalty estimates may significantly change in the future.

Unforeseen title defects

Ownership of some of our properties could be subject to prior undetected claims or interests. We plan to conduct title reviews from time to time according to industry practice prior to the purchase of most of our crude oil and natural gas producing properties or the commencement of drilling wells. 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. 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. 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. 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. 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. 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. Our ability to access land, develop and operate our business may be subject to general social opposition, negative sentiment or litigation which may result in delays or restrictions on the ability to advance through the environmental consultative process.

The process of addressing Indigenous and stakeholder claims, regardless of the outcome, can be expensive and time-consuming

and could result in delays which could have a negative effect on our business, financial condition, results of operations and prospects, which negative effect could prove to be material over time.

Restrictions on development activities to protect wildlife

Crude oil and natural gas operations in our operating areas in Canada can be adversely affected by seasonal or permanent restrictions on development activities designed to protect identified wildlife. There is a risk that our activities will be seen to adversely affect protected species, leading to an inability to access planned facility sites or, if already built, some kind of restriction on operations.

Seasonal restrictions may limit our ability to operate in protected areas and can intensify competition for drilling rigs, oilfield equipment, services, supplies and qualified personnel, which may lead to periodic shortages when drilling is allowed. These constraints and the resulting shortages or high costs could delay our operations and materially increase operating and capital costs. Permanent restrictions imposed to protect endangered species could prohibit drilling in certain areas or require the implementation of expensive mitigation measures. The designation of previously unprotected species in areas where we operate as threatened or endangered could cause us to incur increased costs arising from species protection measures or could result in limitations on our exploration and production activities that could have an adverse impact on our ability to develop and produce

our reserves.

Additionally, some of our producing areas in Canada are or will be located in areas that may become inaccessible due to environmental protection requirements. This includes, but is not limited to, protected caribou habitat on a seasonal basis.

Joint Venture partner alignment

We have operated and non operated interests in Colombia and Canada. In the areas where the Company operates as non-operating partner it may have limited control over the day-to-day management or operations of these assets. A third-party mismanagement of an asset may result in significant delays, materially increased costs or liabilities to the Company over which the Company is joint and severally liable. There is no guarantee that the third-party’s environmental standards are aligned with those of the Company. The Company continually engages with its operating partners and closely monitors the operation of its assets, thorough reviews are conducted before entering into joint venture arrangements to ensure that our operational objectives are aligned with potential joint venture partner.

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. 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. When such disruptions occur, they may adversely impact our operations and threaten the economic viability of our projects or our ability to meet our production targets.

Both Colombia and Ecuador may experience future political and economic instability. Colombia has experienced social, economic and security turmoil related to security, guerilla and narcotrafficking. Political changes because of future electoral processes could result in new governments or the adoption of new policies, laws or regulations that might assume a substantially more hostile attitude toward foreign investment, including but not limited to: the imposition of additional taxes as was the case in 2022; nationalization; changes in energy or environmental policies or the personnel administering them; changes in oil and natural gas pricing policies; and royalty changes or increases. In an extreme case, such a change could result in termination of contract rights and expropriation of foreign-owned assets or renegotiation or nullification of existing concessions and contracts. 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 has investment protection treaties in place with the United States and Canada as well as a history of sanctity of contracts.

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. While these pipelines have now been rerouted and are back in service, there remains some risk to our ability to transport oil to market through these systems from future, unforeseen natural events that could again generate outages in the OCP and SOTE pipelines. Such events could include, but are not limited to, earthquakes, volcanic eruptions and additional significant soil erosion.

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. 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. Due to the concentrated nature of our portfolio of properties, a number of our properties could experience any of the same conditions at the same time, resulting in a relatively greater impact on our results of operations than they might have on other companies that have a more diversified portfolio of properties.

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. Further, we operate in remote areas in both South America and Canada and may rely on helicopters, boats or other transportation methods. 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. 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. During the winter months in Canada, heavy snow, ice, or rain may adversely affect our ability to operate. Also, during the spring thaw, which normally starts in late March and continues through June, some areas in Canada may impose transportation restrictions to prevent damage caused by the spring thaw.

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. Improper management of these relationships could lead to a delay or suspension of operations, loss of license or major impact to our reputation in these communities, which could adversely affect our business. We cannot ensure that such issues or disruptions will not be experienced in the future, and we cannot predict their potential impacts, which may include delays or loss of production, standby charges, stranded equipment, or damage to our facilities. We also cannot ensure that we will not experience protests or blockades erected by criminal groups or cultivators of illegal crops, in response to the Colombian government's eradication of such crops, if such crops are grown in proximity to roads required to access our operations. In addition, we must comply with legislative requirements for prior consultation with communities and ethnic groups who are affected by our proposed projects in Colombia and Ecuador. Notwithstanding our compliance with these requirements, we may be sued by such communities through a writ for protection of tutela in the Colombian courts for enhanced consultation, potentially leading to increased costs, operational delays and other impacts. In addition, several areas in Colombia have conducted Popular Consultations and essential referendums on extractive industries. 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 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. Although a Peace Agreement was ratified by the Colombian government in 2016, the result of which was the demobilization and disarmament of the Revolutionary Armed Forces of Colombia (“FARC”), there continue to be examples of violence against pipelines and other infrastructure that has been attributed to former FARC dissident groups and other illegal groups. It is not currently known whether or to what degree violence will continue and whether and to what degree that violence may impact our operations. Notwithstanding the Peace Agreement ratified and the ongoing efforts to implement such Agreements, increased eradication by the Colombian government of illicit crops, as well as the continuing attempts by the Colombian government to reduce or prevent activity of guerrilla dissidents and of farmers, such efforts may not be successful and such activity may continue to disrupt our operations in the future or cause us higher security costs and could adversely impact our financial condition, results of operations or cash flows.

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. While blockages have been historically directed at the State, the resulting impact may hinder our ability to mobilize oil, personnel and equipment, resulting in temporary shut-in of production or negatively impacting our assets.

Colombia and Ecuador also both have a history of security problems. Our efforts to ensure the security of our personnel and physical assets may not be successful and there can also be no assurance that we can maintain the safety of our field personnel or our contractors’ field personnel and our Bogota and Quito head office personnel or operations in Colombia and Ecuador or that this violence will not adversely affect our operations in the future and cause significant loss. If these security problems disrupt our operations, our financial condition and results of operations could be adversely affected.

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. The cash generated from operations abroad is generally not available to fund domestic or head office operations unless funds are repatriated. At this time, we do not intend to repatriate further funds, other than to pay head office charges, but if we did, we might have to accrue and pay withholding taxes in certain jurisdictions on the distribution of accumulated earnings. 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, 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. 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. To the extent that we do not generate sufficient cash internally to provide the capital we require to fund our growth strategy and future operations, we will require additional debt or equity financing. This additional financing may not be available or, if available, may not be on terms acceptable to us. Further, high volatility in the capital markets and in our stock price may make it difficult for us to access the capital markets at attractive prices, if at all.

In addition, the anticipated benefits of an acquisition may not be realized fully or at all, or may take longer to realize than we expect. For example, the success of our acquisition of i3 Energy will depend, in significant part, on our ability to successfully integrate i3 Energy and realize the anticipated strategic benefits and synergies from the acquisition. The combination of independent businesses is complex, costly and time consuming, and we have devoted, and will continue to devote, significant management attention and resources to integrating the respective business practices and operations of the companies. Further, the anticipated benefits of the acquisition may not be realized fully or at all, or may take longer to realize than we expect. In connection with our acquisition of i3 Energy, we acquired assets in block 13/23c in the UK North Sea, management has not allocated any value to this block and there is significant uncertainty that any value can be realized upon disposition or relinquishment. Actual operating, technological, strategic and revenue opportunities, if achieved at all, may be less significant than we expect or may take longer to achieve than anticipated. 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.

The threat and impact of cybersecurity incidents may adversely impact our operations and could result in information theft, data corruption, operational disruption, and/or financial loss

We use digital technologies and software programs to interpret seismic data, manage drilling rigs, conduct reservoir modeling and reserves estimation, as well as to process and record financial and operating data. We depend on digital technology, including information systems and related infrastructure as well as cloud application and services, to store, transmit, process and record sensitive information (including trade secrets, employee information and financial and operating data), communicate with our employees and business partners, analyze seismic and drilling information, estimate quantities of oil and gas reserves and for many other activities related to our business. The complexities of the technologies needed to explore for and develop oil and gas in increasingly difficult physical environments, and global competition for oil and gas resources make certain information attractive to thieves. Our business processes depend on the availability, capacity, reliability and security of our information technology infrastructure and our ability to expand and continually update this infrastructure in response to our changing needs and therefore it is critical to our business that our facilities and infrastructure remain secure. While we have implemented strategies to mitigate impacts from these types of events, we cannot guarantee that measures taken to defend against cybersecurity risks and threats will be sufficient for this purpose. The ability of the information technology function to support our business in the event of a security breach or a disaster such as fire or flood and our ability to recover key systems and information from unexpected interruptions cannot be fully tested and there is a risk that, if such an event actually occurs, we may not be able to address immediately the repercussions of the breach or disaster. 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. 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.

Our employees have been and will continue to be targeted by parties using fraudulent “spoof” and “phishing” emails to misappropriate information or to introduce viruses or other malware through “trojan horse” programs to our computers. These emails appear to be legitimate emails but direct recipients to fake websites operated by the sender of the email or request that the recipient send a password or other confidential information through email or download malware. 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.

We may be adversely affected by global epidemics or public health crises

Global epidemics and public health crises and fear of such events may adversely impact our operations and the global economy, including the worldwide demand for oil and natural gas. 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. To the extent any global epidemic or public health crisis may adversely affect our business, operations, financial condition and operating results, it may also have the effect of heightening the other risks described herein.

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. 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. For the period from January 1 to February 20, 2025, the average prices of Brent oil, WTI oil and AECO natural gas were $77.24 per barrel, $73.86 per barrel and C$2.04 per mcf, respectively.

If cash flows from operations and cash on hand are not sufficient to fund our capital program, we may be required to seek external financing or to delay or reduce our exploration and development activities, which could impact production, revenues and reserves.

If we require additional capital, we may pursue sources of capital through various financing transactions or arrangements, including joint venturing of projects, debt financing, equity financing or other means. We may not be able to access capital on favorable terms or at all. If we do succeed in raising additional capital, future financings may be dilutive to our shareholders, as we could issue additional shares of Common Stock or other equity to investors. In addition, debt and other mezzanine financing may involve a pledge of assets, require covenants that would restrict our business activities, and may be senior to interests of equity holders. We may incur substantial costs in pursuing future capital financing, including investment banking fees, legal fees and other costs. We may also be required to recognize non-cash expenses in connection with certain securities we may issue, such as convertibles and warrants, which would adversely impact our financial results.

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. Further, if oil or natural gas prices on the commodities markets decrease, then our revenues will likely decrease, and such decreased revenues may increase our requirements for capital. Some of the contractual arrangements governing our exploration activity may require us to commit to certain capital expenditures, and we may lose our contract rights if we do not have the required capital to fulfill these commitments. 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.

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. There has also been pressure on lenders and other financial services companies to limit or curtail financing of companies in the oil and gas industry. Such environmental initiatives aimed at targeting climate changes could ultimately interfere with our access to capital and ability to finance our operations.

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. Furthermore, concerns over climate change have resulted in, and are expected to continue to result in, the adoption of regulatory requirements for climate-related disclosures. As a result, we may continue to face increasing pressure regarding our ESG disclosures and practices, and mandatory reporting obligations could increase our compliance burden and costs. We publish a Sustainability Report, which outlines our progress and ongoing efforts to advance our ESG initiatives. Our disclosures on these matters rely on management’s expectations as of the date the statements are first made, as well as standards for measuring progress that are still in development, and may change or fail to be realized. 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.

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. 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. Because our Consolidated Financial Statements are presented in U.S. dollars, we must translate revenues, expenses and income, as well as assets and liabilities, into U.S. dollars at exchange rates in effect during or at the end of each reporting period. We are also exposed to transaction risk on settlement of payables and receivables denominated in foreign currency.

Legal and Regulatory Risks

We are dependent on obtaining and maintaining permits and licenses from various governmental authorities

Our oil and natural gas exploration and production operations are subject to complex and stringent laws and regulations. In order to conduct our operations in compliance with these laws and regulations, we must obtain and maintain numerous licenses, permits, approvals and certificates, including environmental and other operating permits. We may not be able to obtain, sustain or renew such licenses and permits on a timely basis or at all. We may also have licenses and permits rescinded or may not be able to renew expiring licenses and permits. Failure or delay in obtaining or maintaining regulatory approvals or permits could have a material adverse effect on our ability to develop and explore on our properties, and receipt of drilling permits with onerous conditions could increase our compliance costs. Loss of permits for existing drilling, water injection or other activities necessary for production may result in a decline of our production levels and revenues or damage to the well structure. Regulations and policies relating to these licenses and permits may change, be implemented in a way that we do not currently anticipate or take significantly greater time to obtain. There can be no assurance that future political conditions in Colombia and Ecuador will not result in changes to policies with respect to foreign development and ownership of oil, environmental protection, health and safety or labor relations, which may negatively affect our ability to undertake exploration and development activities in respect of present and future properties, as well as our ability to raise funds to further such activities.

As we are not the operator of all the joint ventures we are currently involved in, we may rely on the operator to obtain all necessary permits and licenses. If we fail to comply with these requirements, we could be prevented from drilling for oil and natural gas, and we could be subject to civil or criminal liability or fines. 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. The new administration has stated that no new bid rounds for exploration blocks will be done until it is decided differently by the government. In addition, in 2023 the government issued a new decree eliminating the obligation of ANH to offer bid rounds for new blocks to Companies. 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. Like other companies with UK North Sea assets, the frequent and adverse changes to the United Kingdom’s oil and gas fiscal regime have caused significant uncertainty that any value can be realized on disposition or relinquishment of UK assets. Management has no intentions to develop UK assets.

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 laws and regulations in the countries in which we operate provide for, among other things, restrictions and prohibitions on spills, releases or emissions of various substances used or produced in association with oil and gas operations. These regulations also require that wells and facility sites be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. 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. 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. There is uncertainty around the impact of environmental laws and regulations, including those presently in force and those expected to be proposed in the future. We cannot predict how future environmental laws will be interpreted, administered or enforced, but more stringent laws or regulations or more vigorous enforcement policies could in the future require material expenditures by us for the installation and operation of compliant systems; therefore it is impossible at this time to predict the nature and impact of those requirements on our company however they may have a material adverse impact on our business.

Given the nature of our business, there are inherent risks of oil spills at drilling or operations sites due to operational failure, accidents, sabotage, pipeline failure or tampering or escape of oil due to the transportation of the oil by truck. All of these may lead to significant potential environmental liabilities, such as damages, litigation costs, clean-up costs or penalties, some of which may be material and for which our insurance coverage maybe inadequate or unavailable.

We may be exposed to liabilities under anti-bribery laws and a finding that we violated these laws could have a material adverse effect on our business

We are subject to anti-bribery laws in the United States, Canada, Ecuador and Colombia and will be subject to similar laws in other jurisdictions where we may operate in the future. We may face, directly or indirectly, corrupt demands by officials, tribal or insurgent organizations, international organizations, or private entities. As a result, we face the risk of unauthorized payments or offers of payments by employees, contractors, agents, and partners of ours or our subsidiaries or affiliates, given that these parties are not always subject to our control or direction. It is our policy to prohibit these practices. However, our existing safeguards and any future improvements to those measures may prove to be less than effective or may not be followed, and our employees, contractors, agents, and partners may engage in illegal conduct for which we might be held responsible. A violation of any of these laws, even if prohibited by our policies, may result in criminal or civil sanctions or other penalties (including profit disgorgement) as well as reputational damage and could have a material adverse effect on our business and financial condition.

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. Although Colombia is currently eligible for such aid, it may not remain eligible in the future. A finding by the President that Colombia has failed demonstrably to meet its obligations under international counter-narcotic agreements may result in the imposition of economic and trade sanctions on Colombia which could result in adverse economic consequences in Colombia including potentially threatening our ability to obtain necessary financing to develop our Colombian properties, and could further heighten the political and economic risks associated with our operations there. The United States may in the future impose similar eligibility restrictions on foreign aid provided to Ecuador. The president of the United States declared that Canada, among other countries, is responsible for illegal immigration and drug transit to United States and is in the process of implementing 10% tariffs on energy resources from Canada. Implementation of tariffs could have adverse impact on our profitability from Canadian operations.

Regulations related to emissions and the impact of any changes in climate could adversely impact our business, including demand for our products, our financial condition and results of operations

Governments around the world have become increasingly focused on regulating greenhouse gas (“GHG”) emissions and addressing the impacts of climate change in some manner. GHG emissions legislation is emerging and is subject to change. 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. Although it is not possible at this time to predict how this legislation or any new regulations that may be adopted to address GHG emissions would impact our business, any such future laws and regulations that limit emissions of GHGs could adversely affect demand for the oil and natural gas that we produce. 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. If we are unable to recover a significant amount of our costs related to complying with climate change regulatory requirements imposed on us, it could have a material adverse impact on our business, financial condition and results of operations. Significant restrictions on GHG emissions could result in decreased demand for the oil and natural gas 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. Should we be targeted by any such litigation, we may incur liability, which, to the extent that societal pressures or political or other factors are involved, could be imposed without regard to the Company’s causation of or contribution to the asserted damage, or to other mitigating factors. 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. 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. Any of these financial instruments may be changed by the relevant government and such changes may adversely affect

the profitability of some or all of our business. There is a risk that accounting for GHG releases and the rate of carbon taxation and the level it reaches will be changed from time to time, creating an economic environment of uncertainty. This risk is further complicated by the dependency of Canadian hydrocarbon energy producers on exports to the United Stated and the uncertainty as to how the United Stated will regulate GHG emissions related to domestic and Canadian production.

Carbon taxes and environmental compliance costs

The crude oil and natural gas industry is subject to environmental regulation pursuant to municipal, provincial and federal legislation in Canada. Such legislation may be changed to impose higher standards and potentially more costly obligations. Policies aimed at reducing emissions of carbon dioxide and methane could become a burden on crude oil and natural gas commodities relative to other sources of energy in the marketplace. Furthermore, there is no assurance that any such programs or regulatory amendments, if proposed and enacted, may contain emission reduction targets that we can meet. Financial penalties or charges could be incurred as a result of the failure to meet such targets. As carbon accounting rules and carbon emissions penalties evolve, distributed small-scale use of hydrocarbon-based fuels may become very costly, which may motivate the discontinued use of hydrocarbon-based fuels. This evolution, if it occurs, may severely reduce the hydrocarbon-production market to large consumers that have carbon capture and storage capability.

Risks Related to Ownership of our Common Stock

Shares of our Common Stock are listed on the NYSE American, the Toronto Stock Exchange (“TSX”) and the London Stock Exchange (“LSE”) and investors seeking to take advantage of price differences between such markets may create unexpected volatility in market prices

Shares of our Common Stock are listed on the NYSE American, the TSX and the LSE. While the shares of Common Stock are traded on such markets, the price and volume levels could fluctuate significantly on any market independently of the price or trading volume on other markets. Investors could seek to sell or purchase shares of Common Stock to take advantage of any price differences between the NYSE American, the TSX and the LSE through a practice referred to as arbitrage. Any arbitrage activity could create unexpected volatility in the price of the shares of Common Stock on any of these exchanges or the volume of shares of Common Stock available for trading on any of these markets. 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.

The market price of our Common Stock may be volatile

The market price for shares of our Common Stock has experienced and may continue to experience volatility. For example, during 2024, the market price for shares of our Common Stock ranged from a low of $4.72 per share to a high of $10.40 per share. The market price for shares of our Common Stock may be influenced by many factors, some of which are beyond our control, including those described above and the following:

• strategic actions or announcements by us of significant contracts, acquisitions, joint marketing relationships, joint ventures or capital commitments;
• general economic and stock market conditions;
• volatility in commodity prices;
• risks related to our business and our industry, including those discussed above;
• changes in conditions or trends in our industry, markets or customers;
• geopolitical events or terrorist acts;
• trading volume of our Common Stock;
• future sales of shares of our Common Stock or other securities by us, members of our management team or our existing shareholders; and
• investor perceptions of the investment opportunity associated with our industry or securities relative to other investment alternatives.

These market and industry factors may materially reduce the market price for shares of our Common Stock, regardless of our operating performance.

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 Board and Audit Committee are updated on a quarterly basis by Vice President, Corporate Services on the Company’s internal information technology (“IT”) security testing, any unauthorized attempts to access the Company’s network, any significant developments in cyber security risks and threats, and updates on the Company’s policies and procedures for protecting the Company’s data. We also have processes by which certain cybersecurity incidents are escalated within the Company and, where appropriate, reported in a timely manner to the Board and Audit Committee. All incidents are reported to the Executive Officers (including the President and Chief Executive Officer, Chief Financial Officer and the Chief Operating Officer) who assess the severity and what measures and procedures are necessary.

As part of the Company’s enterprise risk management, the Board of the Company receives, reviews and assesses reports from the Board’s committees and from management relating to enterprise-level risks. The Audit Committee reports its cybersecurity risk assessments to the full Board at each regularly scheduled Board meeting.

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. 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. 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. The Executive Vice President, Corporate Services is updated by the Director of IT on a periodic basis regarding trends in technology and cybersecurity threats or any potential changes to the Company’s cybersecurity program. The 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. 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. As part of this program, we have processes in place that include a variety of controls, systems, and technologies designed to prevent or mitigate data loss, theft, misuse, or other cybersecurity incidents affecting the data we collect, process, store, and transmit as part of our business. We conduct penetration testing and cybersecurity audits, and require all employees to undertake data protection and cybersecurity training on an annual basis. We also use systems and processes designed to oversee and identify risks associated with our use of third-party service providers, including with respect to the occurrence of a cybersecurity incident at a third-party service provider or that otherwise implicates a third-party technology or system we use. We contract cybersecurity specialists to review and implement controls and structural mechanisms in order to enhance our cybersecurity program, and protect against and detect cybersecurity threats.

To our knowledge, we have not experienced any risks from cybersecurity threats or incidents through the date of this annual report that have materially affected or are reasonably likely to materially affect the Company, its business strategy, results of operation or financial condition. 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.

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.

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

This report, and in particular this Management’s Discussion and Analysis of Financial Condition and Results of Operations, contains forward-looking statements within the meaning of Section 27A of the Securities Act and Section 21E of the Exchange Act. Please see the cautionary language at the very beginning of this Annual Report on Form 10-K regarding the identification of and risks relating to forward-looking statements, as well as Part I, Item 1A. “Risk Factors” in this Annual Report on Form 10-K.

The following discussion of our financial condition and results of operations should be read in conjunction with the “Financial Statements and Supplementary Data” as set out in Part II, Item 8 of this Annual Report on Form 10-K. This Management’s Discussion and Analysis of Financial Condition and Results of Operations generally discusses items related to the fiscal year ended December 31, 2024, and year-to-year comparisons between the fiscal years ended December 31, 2024, and 2023, respectively. 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. On May 5, 2023, the Company completed 1-for-10 reverse stock split of the Company’s Common Stock. As a result of the reverse stock split, every ten of the Company’s issued shares of Common Stock were automatically combined into one issued share of Common Stock. All share and per share data included in this Annual Report on Form 10-K have been retroactively adjusted to reflect the reverse stock split.

Overview

We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 47%, our Canadian properties represented 46% and our Ecuadorian properties represented 7% of our proved reserves NAR at December 31, 2024, and for the year ended December 31, 2024, 93% of our revenue was generated in Colombia (2023 - 97% and 2022 -100%), 3% of our revenue was generated in Canada (2023 and 2022 - nil) and 4% (2023 - 3%, 2022 - nil) of our revenue was generated in Ecuador. We are headquartered in Calgary, Alberta, Canada.

As of December 31, 2024, we had estimated proved reserves NAR of 135.0 MMBOE, an 82% increase from the prior year, of which 50% were proved developed reserves and 62% were oil.

Financial and Operational Highlights

Key Highlights

• On October 31, 2024, we acquired oil and natural gas reserves and production operations in Canada through the acquisition of all of the issued and outstanding common shares of i3 Energy, subsequently renamed Gran Tierra UK Limited (“Gran Tierra UK”), for $204.5 million. 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 share 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. Total operating expenses were $202.3 million in 2024, compared to $186.9 million in 2023, representing an 8% increase as a result of two months of Canadian production
• Quality and transportation discounts per boe increased in 2024 to $17.93 when compared to $14.90 in 2023 primarily due to higher differentials
• Transportation expenses per boe for 2024 increased by 19% to $1.84 compared to $1.54 in 2023, due to higher sales volumes transported in Ecuador, two months transportation of sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024
• General and administrative (“G&A”) expenses before stock-based compensation per boe for 2024 decreased by 6% to $3.97 compared to $4.24 in 2023 due to lower business development, consulting and legal expenses during 2024. 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.

(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. General Accepted Accounting Principles (“GAAP”). Management views these measures as financial performance measures. Investors are cautioned that these measures should not be construed as alternatives to oil sales, net income (loss) or other measures of financial performance as determined in accordance with GAAP. Our method of calculating these measures may differ from other companies and, accordingly, may not be comparable to similar measures used by other companies. Disclosure of each non-GAAP financial measure is preceded by the corresponding GAAP measure so as not to imply that more emphasis should be placed on the non-GAAP measure.

Operating netback, as presented, is defined as 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. 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. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for non-cash lease expense, 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. Management uses this supplemental measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income and believes that this financial measure is a useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to EBITDA and adjusted EBITDA is as follows:

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. Management uses this financial measure to analyze performance and income generated by our principal business activities prior to the consideration of how non-cash items affect that income, and believes that this financial measure is also useful supplemental information for investors to analyze performance and our financial results. Free cash flow, as presented, is defined as funds flow from operations less capital expenditures. Management uses this financial measure to analyze cash flow generated by our principal business activities after capital requirements and believes that this financial measure is also useful supplemental information for investors to analyze our performance and financial results. A reconciliation from net income (loss) to funds flow from operations and free cash flow is as follows:

Consolidated Results of Operations

40

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

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

Oil, natural gas and NGL production NAR for the year ended December 31, 2024, increased by 7% to 27,890 BOEPD compared to 26,099 BOEPD in 2023. The increase in production was a result of two months of production from the Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador, partially offset by lower production in the Acordionero field caused by downtime related to workovers.

Oil production NAR for the year ended December 31, 2023, increased by 10% to 26,099 BOEPD compared to 23,815 BOEPD in 2022. The increase in production was a result of successful drilling and workover campaigns in all major fields, and increased production in Ecuador.

Royalties as a percentage of production for the year ended December 31, 2024, were comparable with royalties as a percentage of production for 2023. Royalties as a percentage of production for the year ended December 31, 2023, decreased 3% compared to 2022 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in Colombia and Ecuador.

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

Oil, Natural Gas and NGL Sales

Oil, natural gas and NGL sales for the year ended December 31, 2024, decreased by 2% to $621.8 million compared to $637.0 million in 2023, primarily as a result of a 3% decrease in Brent price and 6% decrease in sales volumes in Colombia, offset by increase in sales volumes in Ecuador, lower differentials, and two months of sales from Canadian operations of $19.0 million in 2024. Vasconia, Castilla and Oriente differentials decreased to $4.78, $8.54 and $8.75 per boe in 2024 from $5.39, $10.22 and $9.91 per boe in 2023, respectively.

On a per boe basis, average realized prices decreased by 8% to $61.93 for the year ended December 31, 2024, compared to $67.26 in 2023, primarily as a result of the decrease in benchmark oil prices and the addition of natural gas and liquids to the portfolio in 2024 through the i3 Energy acquisition.

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. 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.

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.

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:

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. On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 compared to $19.73 in the prior year, primarily as a result of $0.48 higher workovers, removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador as a result of production ramp-up in 2024.

Operating expenses for the year ended December 31, 2023, increased by 15% to $186.9 million compared to $162.4 million in 2022. 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. 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. In addition, operating costs increased as a result of the depreciation of U.S. dollar against the Colombian peso in 2023.

Transportation Expenses

We have options to sell our oil, natural gas and NGL through multiple pipelines and, in Colombia, trucking routes. Each transportation route has varying effects on realized price and transportation expenses. The following table shows the percentage of oil, natural gas and NGL volumes we sold in Canada, Colombia and Ecuador using each transportation method for each of the last three years ending December 31, 2024:

Colombian volumes transported through pipelines or via trucks receive a higher realized price but incur higher transportation expenses. Volumes sold at the wellhead have the opposite effect of lower realized price, offset by lower transportation expense. Volumes sold in Ecuador are transported via pipeline. We focus on maximizing operating netback (1) per boe when choosing a transportation method.

Transportation expenses for the year ended December 31, 2024, increased by 27% to $18.5 million or by $0.30 to $1.84 per boe compared to $14.5 million or $1.54 per boe in 2023, as a result of higher sales volumes transported in Ecuador, two months of transporting sales volumes in Canada through pipelines, and an increase in trucking tariffs for Acordionero volumes in 2024.

The following table shows the variance in our average realized price net of transportation expenses in Colombia, Ecuador and Canada for each of the three years ended December 31, 2024:

Operating Netbacks

46

47

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

b

DD&A Expenses

49

DD&A expenses for the year ended December 31, 2024, increased by 7% or $0.21 per boe from 2023 due to higher production in Ecuador, the addition of DD&A expense from Canadian operations acquired in the i3 Energy acquisition, and higher costs in the depletable base as a result of higher future development costs compared to 2023.

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.

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. In calculating discounted future net revenues, oil and natural gas prices are determined using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. That average price is then held constant, except for changes which are fixed and determinable by existing contracts. 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 accordance with GAAP, we used unweighted arithmetic average of the first-day-of-the-month prices as follows; Brent Crude $80.42 per boe, Edmonton Light Crude of C$98.01 per boe, Alberta AECO spot price of C$1.46 per MMBtu Edmonton Propane C$30.46 per boe, Edmonton Butane C$48.39 per boe and Edmonton Condensate C$100.83 per boe for the December 31, 2024 ceiling test calculations (December 31, 2023, and 2022 Brent Crude - $82.51 and $97.98 per boe, respectively).

G&A Expenses

G&A expenses before stock-based compensation for the year ended December 31, 2024 decreased 1% as a result of lower business development, legal and consulting costs compared to 2023, offset by the addition of two months of G&A from the newly acquired Canadian operations.

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.

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.

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.

G&A expenses after stock-based compensation for the year ended December 31, 2024, increased by 8% to $49.6 million, compared to 2023 due to higher stock-based compensation attributable to the higher share price in 2024.

G&A expenses after stock-based compensation for the year ended December 31, 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.

G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2024, increased by 2% to $4.94 compared to 2023 due to 62% increase in stock-based compensation attributable to higher share price in 2024.

G&A expenses after stock-based compensation, on a per boe basis, for the year ended December 31, 2023, increased by 2% to $4.84 per boe compared to 2022 due to higher NAR sales in 2023.

Foreign Exchange (Gains) Losses

For the years ended December 31, 2024, 2023 and 2022, we had an $8.8 million gain, $11.8 million loss and $2.6 million loss on foreign exchange, respectively. The main sources of foreign exchange gains and losses are the revaluation of taxes receivable and payable, deferred tax assets and liabilities and accounts payable. Under GAAP, income taxes, deferred taxes and accounts payable are considered monetary assets and liabilities and require translation from local currency to the U.S. dollar functional currency at each balance sheet date.

The following table presents the change in the U.S. dollar against the Colombian peso and Canadian dollar for the last three years ended December 31, 2024:

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:

Income Tax Expense

Current income tax expense for the year ended December 31, 2024, was $69.3 million (2023 - $55.7 million; 2022 - $80.6 million). 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.

The deferred income tax expense was a recovery of $27.9 million for the year ended December 31, 2024, primarily as a result of the recognition of additional tax losses resulting from a tax planning strategy, which were partially offset by tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.

The deferred income tax expense of $56.8 million and $25.3 million for the years ended December 31, 2023 and 2022, respectively, were primarily a result of tax depreciation being higher than accounting depreciation and the use of tax losses to offset taxable income in Colombia.

Our effective tax rate was 93% for the year ended December 31, 2024, compared to 106% in 2023. The decrease in the effective tax rate was primarily due to a decrease in non-deductible foreign exchange adjustments, 2022 true-up related to tax planning strategy, other permanent differences and impact of foreign taxes. 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. These were partially offset by a decrease in valuation allowance and non-deductible stock-based compensation.

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. These were partially offset by a 2022 true-up related to tax planning strategy and non-taxable foreign exchange adjustments.

During the year ended December 31, 2024, the company strategically revised its 2022 tax return to use its tax receivable balance to offset current tax liabilities, rather than applying net operating loss carryforwards. This decision was driven by the expectation of higher future income tax rates and increased profitability. As a result, there was an increase in current tax expense of approximately $27.8 million which was offset by long-term tax receivable, ensuring no impact on cash flows. This approach preserved the Company’s net operating loss carryforward for future periods, providing greater tax benefits and flexibility in recovering tax receivables, while strengthening our equity position.

The difference between our effective tax rate of 106% for the year ended December 31, 2023, and the 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 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. These were partially offset by $13.2 million of non-taxable foreign exchange gain.

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

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

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 table below shows the break-down of our 2025 capital program:

Our base capital program for 2025 is $240 million to $280 million for exploration and development activities. 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.

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.

Capital Program

Capital expenditures during the year ended December 31, 2024 were $234.2 million.

During the year ended December 31, 2024, we spud the following wells in Colombia, Ecuador and Canada:

In 2024, we drilled 10 development plus four service wells in Colombia, seven exploration wells in Ecuador, and nine development wells in Canada. Of the wells drilled in Colombia, eight were drilled in Midas Block and six in Chaza Block. In Ecuador, five wells were drilled and Charapa Block and two in Chanangue Block. In Canada, we drilled nine development wells, four of which were in Clearwater acreage with the remaining wells drilled in our Rimbey, Lodgepole and Wapiti acreage. As at December 31, 2024, of the exploration and development wells drilled, 18 were producing and eight were in-progress.

Liquidity and Capital Resources

We believe that our capital resources, including cash on hand and cash generated from operations will provide us with sufficient liquidity to maintain current operations and execute the capital program for the next 12 months and beyond, given current oil and natural gas price trends and production levels. In accordance with our investment policy, available cash balances are held in our primary cash management banks or may be invested in U.S. or Canadian government-backed federal, provincial, or state securities or other money market instruments with high credit ratings and short-term liquidity. We believe that our current financial position provides us the flexibility to respond to both internal growth opportunities and those available through acquisitions. We intend to pursue growth opportunities and acquisitions from time to time, which may require significant capital, be located in basins or countries beyond our current operations, involve joint ventures, or be sizable compared to our current assets and operations.

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”).

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

The 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.

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

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%).

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

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

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

As at December 31, 2024, we were in compliance with all applicable covenants.

On February 6, 2024 and September 18, 2024, we issued additional $100.0 million and $150.0 million of 9.50% Senior Notes due October 2029 (the “new 9.50% Senior Notes”), and received cash proceeds of $88.0 million and $139.8 million, respectively. The new 9.50% Senior Notes have the same terms and provisions as the previously issued $487.6 million 9.50% Senior Notes except for the issue price. $100.0 million of new 9.50% Senior Notes accrue interest from October 20, 2023, the date of issuance of the previously issued 9.50% Senior Notes and $150.0 million of new 9.50% Senior Notes accrue interest from April 15, 2024, the date of the last interest payment. We received a cash payment of $2.8 million and $6.1 million related to the accrued interest of the $100.0 million and $150.0 million of new 9.50% Senior Notes, respectively. As at December 31, 2023, we had a $36.4 million balance outstanding under the Company’s credit facility. On February 6, 2024, the outstanding balance under the credit facility was fully re-paid and the credit facility was terminated.

On August 19, 2024, the Company entered into a credit facility agreement (“Loan Facility”) with a market leader in the global commodities industry to fund the cash consideration payable to i3 Energy’s shareholders in connection with the i3 Energy acquisition and associated costs (Note 3). The Loan Facility has a borrowing base of £80.0 million (US$107.0 million) and bears interest based on a three-month secured overnight financing rate posted by the Federal Reserve Bank of New York plus a margin of 3.00% per annum for the first three months after the initial drawdown and 6.00% per annum thereafter. The Loan Facility is subject to a commitment fee equal to the higher of $0.5 million and 0.50% of the borrowing base converted to U.S. dollars using the agreed upon GBP to USD foreign exchange rate at the time of initial drawdown date. The Company paid $0.6 million of commitment fees and the Loan Facility was terminated on October 31, 2024.

In connection with the i3 Energy acquisition closing on October 31, 2024, the Company amended and restated the existing revolving credit facility agreement of i3 Energy Canada Ltd. (“i3 Energy Canada”) with National Bank of Canada dated March 22, 2024. As a result of the amendment and restatement, among other things, the borrowing base was revised to C$100.0 million (US$69.5 million) with available commitment of a C$50.0 million (US$34.7 million) revolving credit facility. Subject to the next borrowing base redetermination, which will occur on or before June 30, 2025, the revolving credit facility is available until October 31, 2025 with a repayment date of October 31, 2026, which may be extended by further periods of up to 364 days, subject to lender approval. The drawn down amounts under the revolving credit facility can either be in Canadian or U.S. dollars and bear interest rates equal to either the Canadian prime rate or U.S. Base Rate plus a margin ranging from 2.00% to 4.00% per annum or for CORRA loans and SOFR loans plus a margin ranging from 3.00% to 5.00% per annum. Undrawn amounts under the revolving credit facility bear standby fee ranging from 0.75% to 1.25% per annum. In each case, the margin or standby fee, as applicable is based on Net Debt to EBITDA ratio of Gran Tierra Canada Ltd.

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. 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.

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. The 2023 Program expired on November 2, 2024. As of December 31, 2024, all shares re-purchased under the 2024 Program were held as treasury shares and all shares re-purchased under the 2023 Program were cancelled subsequent to re-purchase.

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.

Cash Flows

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

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

Contractual Obligations

The following is a schedule by year of purchase obligations, future minimum payments for firm agreements and leases that have initial or remaining non-cancelable terms in excess of one year as of December 31, 2024:

(1) Interest payments were calculated on our 6.25% Senior Notes, 7.75% Senior Notes, and 9.50% Senior Notes under assumption that Senior Notes will be held until their maturity dates of February 2025, May 2027, and October 2029, respectively. Actual results will differ from these estimates and assumptions.

At December 31, 2024, we had provided letters of credit and other credit support totaling $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.

The above table does not reflect estimated amounts expected to be incurred in the future associated with the abandonment of our oil and gas properties and other long-term liabilities, as we cannot determine with accuracy the timing of such payments. Information regarding our asset retirement obligation can be found in Note 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. If we do not meet such commitments, the acreage positions or wells may be lost, and associated penalties may be payable.

Climate Change

We have considered the impact of the climate events on the following items presented in this Annual Report on Form 10-K for the fiscal year ended December 31, 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. The estimated ceiling amount of our oil and gas properties was based on proved reserves, the life of which is generally less than 15 years. The ultimate period in which global energy markets can transition from carbon-based sources to alternative energy is highly uncertain. However, the majority of the cash flows associated with proved reserves per the 2024 reserve report should be realized prior to the potential elimination of carbon-based energy.

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. 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. In total, we converted 2.8 billion standard cubic feet of natural gas into electricity instead of being flared for the 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.

Established in 2017, NaturAmazonas addresses the root causes of deforestation and develops nature-based solutions for reversing the process while increasing the well-being of nearby communities. We are an industry leader in reforestation and conservation in Colombia. It has created an effective model for creating change at scale by engaging communities in protecting their environment and securing partnerships with public and private institutions, as well as stakeholders in long-term reforestation and conservation efforts. NaturAmazonas is projected to sequester approximately 8.7 million tonnes of CO2, equivalent to approximately 19 years of our 2024 Scope 1 and Scope 2 emissions1. We have planted over 1.9 million trees and conserved, preserved, or reforested more than 5,300 hectares of land through all of our environmental efforts to date.

1 2024 emissions are based on full year emissions from Colombia and Ecuador, plus post-transaction date emissions in Canada (November & December).

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.

Share capital

The evolving energy transition and general sentiment to the oil and gas industry may result in reduced access to capital markets.

Critical Accounting Policies and Estimates

The preparation of financial statements under GAAP requires management to make estimates, judgments, and assumptions that affect the reported amounts of assets and liabilities as well as the revenues and expenses reported and disclosure of contingent liabilities. Changes in these estimates related to judgments and assumptions will occur as a result of changes in facts and circumstances or discovery of new information, and, accordingly, actual results could differ from the amounts estimated.

On a regular basis, we evaluate our estimates, judgments, and assumptions. We also discuss our critical accounting policies and estimates with the Audit Committee of the Board of Directors.

Certain accounting estimates are considered to be critical if (a) the nature of the estimates and assumptions is material due to the level of subjectivity and judgment necessary to account for highly uncertain matters or the susceptibility of such matters to changes; and (b) the impact of the estimates and assumptions on financial condition or operating performance is material. The areas of accounting and the associated critical estimates and assumptions made are discussed below.

Full Cost Method of Accounting and the impact of estimated proved oil and gas reserves on the calculations of depletion expense and the ceiling test related to Oil and Gas Properties.

We follow the full cost method of accounting for our oil and natural gas properties in accordance with SEC Regulation S-X Rule 4-10, as described in Note 2 to the Consolidated Financial Statements, Significant Accounting Policies, in Item 8 “Financial Statements and Supplementary Data.”

Our estimates of proved oil and natural gas reserves are a major component of the depletion and full cost ceiling calculations. Additionally, our proved reserves represent the element of these calculations that require the most subjective judgments. Estimates of reserves are forecasts based on engineering data, projected future rates of production, and the amount and timing of future expenditures. The process of estimating oil and natural gas reserves requires substantial judgment, resulting in imprecise determinations, particularly for new discoveries. Different reserve engineers may make different estimates of reserve quantities based on the same data.

We believe our assumptions are reasonable based on the information available to us at the time we prepare our estimates. However, these estimates may change substantially as additional data from ongoing development activities and production performance becomes available and as economic conditions impact oil and natural gas prices and costs change.

Management is responsible for estimating the quantities of proved oil and natural gas reserves and for preparing related disclosures. Estimates and related disclosures are prepared in accordance with SEC requirements and generally accepted industry practices in the United States as prescribed by the Society of Petroleum Engineers. Reserve estimates are evaluated at least annually by independent reservoir engineering specialists.

While the quantities of proved reserves require substantial judgment, the associated prices of oil and natural gas and the applicable discount rate that are used to calculate the discounted present value of the reserves do not require judgment. The ceiling test calculation dictates that a 10% discount factor be used and future net revenues are calculated using the unweighted arithmetic average of the first-day-of-the month Brent price for the 12-month period prior to the ending date of the period covered by the balance sheet. Therefore, the future net revenues associated with the estimated proved reserves are not based on our assessment of future prices or costs but reflect adjustments for gravity, quality, local conditions, gathering and transportation fees, and distance from market. Estimates of standardized measure of our future cash flows from proved reserves for our December 31, 2024 ceiling tests were based on wellhead prices per boe as of the first day of each month within that twelve-month period.

Because the ceiling test calculation dictates the use of prices that are not representative of future prices and requires a 10% discount factor, the resulting value should not be construed as the current market value of the estimated oil and gas reserves attributable to our properties. Historical oil and gas prices for any particular 12-month period can be either higher or lower than our price forecast. Therefore, oil and gas property write-downs that result from applying the full cost ceiling limitation, and that are caused by fluctuations in price as opposed to reductions to the underlying quantities of reserves should not be viewed as absolute indicators of a reduction of the ultimate value of the related reserves.

Our Reserves Committee oversees the annual review of our oil and gas reserves and related disclosures. The Board meets with management periodically to review the reserves process, results and related disclosures and appoints and meets with the independent reservoir engineering specialists to review the scope of their work, whether they have had access to sufficient information, the nature and satisfactory resolution of any material differences of opinion, and in the case of the independent reservoir engineering specialists, their independence.

For the years ended December 31, 2024, 2023 and 2022, we had no ceiling test impairment losses. We used an average Brent Crude price of $80.42 per boe, Edmonton Light Crude of C$98.01 per boe, Alberta AECO spot price of C$1.46 per MMBtu Edmonton Propane C$30.46 per boe, Edmonton Butane C$48.39 per boe and Edmonton Condensate C$100.83 per boe for the December 31, 2024 ceiling test calculations (December 31, 2023, and 2022 Brent Crude - $82.51 and $97.98 per boe, respectively).

It is difficult to predict with reasonable certainty the amount of expected future impairment losses given the many factors impacting the asset base and the cash flows used in the prescribed GAAP ceiling test calculation. These factors include, but are not limited to, future commodity pricing, royalty rates in different pricing environments, operating costs and negotiated savings, foreign exchange rates, capital expenditures timing and negotiated savings, production and its impact on depletion and cost base, upward or downward reserve revisions as a result of ongoing exploration and development activity, and tax attributes.

Unproved Properties

Unproved properties are not depleted pending the determination of the existence of proved reserves. Costs are transferred into the amortization base on an ongoing basis as the properties are evaluated and proved reserves are established or impairment is determined. Unproved properties are evaluated quarterly to ascertain whether impairment has occurred. Unproved properties, the costs of which are individually significant, are assessed individually by considering seismic data, plans or requirements to relinquish acreage, drilling results and activity, remaining time in the commitment period, remaining capital plans and political, economic and market conditions. Where it is not practicable to individually assess the amount of impairment of properties for which costs are not individually significant, these properties are grouped for purposes of assessing impairment. During any period in which factors indicate an impairment, the cumulative costs incurred to date for such property are transferred to the full cost pool and are then subject to amortization. The transfer of costs into the amortization base involves a significant amount of judgment and may be subject to changes over time based on our drilling plans and results, seismic evaluations, the assignment of proved reserves, availability of capital and other factors. For countries where a reserve base has not yet been established, the impairment is charged to earnings.

Asset Retirement Obligations (“ARO”)

We are required to remove or remedy the effect of our activities on the environment at our present and former operating sites by dismantling and removing production facilities and remediating any damage caused. Estimating our future ARO requires us to make estimates and judgments with respect to activities that will occur many years into the future. In addition, the ultimate financial impact of environmental laws and regulations is not always clearly known and cannot be reasonably estimated as standards evolve in the countries in which we operate.

We record ARO in our consolidated financial statements by discounting the present value of the estimated retirement obligations associated with our oil and gas wells and facilities. In arriving at amounts recorded, we make numerous assumptions and judgments with respect to the existence of a legal obligation for an ARO, estimated probabilities, amounts and timing of settlements, inflation factors, credit-adjusted risk-free discount rates and changes in legal, regulatory, environmental and political environments. Because costs typically extend many years into the future, estimating future costs is difficult and requires management to make judgments that are subject to future revisions based upon numerous factors, including changing technology and the political and regulatory environment. In periods subsequent to initial measurement of the ARO, we must recognize period-to-period changes in the liability resulting from the passage of time and revisions to either the timing or the amount of the original estimate of undiscounted cash flows. Increases in the ARO liability due to passage of time impact net income as accretion expense. The related capitalized costs, including revisions thereto, are charged to expense through DD&A.

It is difficult to determine the impact of a change in any one of our assumptions. As a result, we are unable to provide a reasonable sensitivity analysis of the impact a change in our assumptions would have on our financial results.

Income Taxes

We carry on business in several countries and as a result, we are subject to income taxes in numerous jurisdictions. The determination of our income tax provision is inherently complex and we are required to interpret continually changing regulations and make certain judgments. While income tax filings are subject to audits and reassessments, we believe we have made adequate provision for all income tax obligations. However, changes in facts and circumstances as a result of income tax audits, reassessments, jurisprudence and any new legislation may result in an increase or decrease in our provision for income taxes.

To assess the realization of deferred tax assets, we consider whether it is more likely than not that some portion or all of the deferred tax assets will not be realized. The ultimate realization of deferred tax assets is dependent upon the generation of future taxable income during the periods in which those temporary differences become deductible. We consider the scheduled reversal of deferred tax liabilities, projected future taxable income and tax planning strategies in making this assessment. This determination involves numerous judgments and assumptions and includes estimating factors such as commodity prices, production and other operating conditions. If any of those factors, assumptions or judgments change, the deferred tax asset could change, and in particular decrease in a period where we determine it is more likely than not that the asset will not be realized. Alternatively, a valuation allowance may be reversed where it is determined it is more likely not that the asset will be realized.

Legal and Other Contingencies

A provision for legal and other contingencies is charged to expense when the loss is probable and the cost can be reasonably estimated. Determining when expenses should be recorded for these contingencies and the appropriate amount for accrual is a complex estimation process that includes the subjective judgment of management. In many cases, management’s judgment is based on interpretation of laws and regulations, which can be interpreted differently by regulators and/or courts of law. Management closely monitors known and potential legal and other contingencies and periodically determines when we should record losses for these items based on information available to us.

Stock-Based Compensation

Our stock-based compensation cost is measured based on the fair value of the awards that are ultimately expected to vest. Fair values are determined using pricing models such as the Black-Scholes simulation stock option-pricing model and/or observable share prices. These estimates depend on certain assumptions, including volatility, risk-free interest rate, the term of the awards, the forfeiture rate and performance factors, which, by their nature, are subject to measurement uncertainty. We use historical data to estimate the expected term used in the Black-Scholes option pricing model, option exercises and employee departure behavior. 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. Assets acquired and liabilities assumed in a business combination are recognized at their fair values. Any excess of the consideration paid over the fair value of the net assets acquired and liabilities assumed is recognized as a goodwill and any excess of the fair value of the net assets acquired and liabilities assumed over the consideration paid is recognized as bargain purchase gain in the consolidated statements of operations.

Commodity Price Risk

Our principal market risk relates to oil, natural gas and NGL prices which are volatile and unpredictable and influenced by concerns over world supply and demand imbalance and many other market factors outside of our control. Our revenues are from oil sales at Brent or 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. 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. In Colombia, we receive 100% of our revenues in U.S. dollars and the majority of our capital expenditures are in U.S. dollars or are based on U.S. dollar prices. The majority of income and VAT and G&A expenses in all locations are in local currency. In Canada, we receive 100% of our revenue in Canadian dollar and majority of our capital and operating expenditures are in Canadian dollars or are based on Canadian dollar prices.

Additionally, foreign exchange gains and losses result primarily from the fluctuation of the U.S. dollar to the Colombian peso due to our accounts payable, taxes receivable and payable and deferred tax assets and liabilities in Colombia are denominated in the local currency of the Colombian foreign operations which are our monetary assets. As a result, a foreign exchange gain or loss must be calculated on conversion to the U.S. dollar functional currency. 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, 2024, our credit facility remained undrawn (December 31, 2023 - $36.4 million).

Our investment objectives are focused on preservation of principal and liquidity. By policy, we manage our exposure to market risks by limiting investments to high quality bank issues at overnight rates, or U.S. or Canadian government-backed federal, provincial or state securities or other money market instruments with high credit ratings and short-term liquidity. A 10% change in interest rates would not have a material effect on the value of our investment portfolio. We do not hold any of these investments for trading purposes.

Disclosure Controls and Procedures

We have established disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the Securities Exchange Act of 1934, or Exchange Act). Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, evaluated the effectiveness of the design and operation of our disclosure controls and procedures as of the end of the period covered by this report, as required by Rule 13a-15(b) of the Exchange Act. Based on their evaluation, our Chief Executive Officer and Chief Financial Officer have concluded that Gran Tierra’s disclosure controls and procedures were effective as of December 31, 2024, to provide reasonable assurance that the information required to be disclosed by Gran Tierra in the reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and that such information is accumulated and communicated to management, including our Chief Executive Officer and Chief Financial Officer, as appropriate, to allow timely decisions regarding required disclosure.

Management’s Annual Report on Internal Control Over Financial Reporting

Our management is responsible for establishing and maintaining adequate internal control over financial reporting for Gran Tierra, as such term is defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. Our management, with the participation of our Chief Executive Officer and Chief Financial Officer, conducted an evaluation of the effectiveness of our internal control over financial reporting as of December 31, 2024, based on the framework in Internal Control — Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission in 2013 (the “2013 COSO Framework”). Based on this evaluation under the 2013 COSO Framework, management concluded that our internal control over financial reporting was effective as of December 31, 2024. The effectiveness of our internal control over financial reporting as of December 31, 2024, has been audited by KPMG LLP, an independent registered public accounting firm, which also audited our financial statements included in this Annual Report on Form 10-K as stated in their report which appears herein.

On October 31, 2024, the Company completed the acquisition of i3 Energy Plc (“i3 Energy”), a publicly traded oil and gas company that was listed on the TSX venture exchange. i3 Energy’s operations have been included in the consolidated financial statements of Gran Tierra since October 31, 2024. However, Gran Tierra has not had sufficient time to appropriately assess the disclosure controls and procedures and internal controls over financial reporting previously used by i3 Energy and integrate them with those of Gran Tierra. As a result, the certifying officers have limited the scope of their design of disclosure controls and procedures and internal controls over financial reporting to exclude controls, policies and procedures of i3 Energy (as permitted by applicable securities laws in U.S.). Gran Tierra has a program in place to complete its assessment of the controls, policies and procedures of the acquired operations by October 31, 2025. In 2024, the assets previously held by i3 Energy, contributed $19.0 million (representing 3% ) of total Company’s oil, natural gas and NGL sales and as at December 31, 2024, $310.1 million of total assets were associated with acquired entity.

Changes in Internal Controls over Financial Reporting

There were no changes in our internal controls over financial reporting during the fourth quarter ended December 31, 2024, that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting.

Report of Independent Registered Public Accounting Firm

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

Opinion on Internal Control Over Financial Reporting

We have audited Gran Tierra Energy Inc. and subsidiaries’ (the Company) internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2024 and 2023, the related consolidated statements of operations, shareholders’ equity, and cash flows for each of the years in the three-year period ended December 31, 2024, and the related notes (collectively, the consolidated financial statements), and our report dated February 24, 2025 expressed an unqualified opinion on those consolidated financial statements.

The Company acquired i3 Energy Plc during 2024, and management excluded from its assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2024, i3 Energy Plc’s internal control over financial reporting associated with total assets of $310.1 million and total oil, natural gas and NGL sales of $19.0 million included in the consolidated financial statements of the Company as of and for the year ended December 31, 2024. Our audit of internal control over financial reporting of the Company also excluded an evaluation of the internal control over financial reporting of i3 Energy Plc.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management’s Annual Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP

Chartered Professional Accountants

Calgary, Canada

February 24, 2025