GTE 10-K & 10-Q changes, risk factors and insider trading

We generate revenue through the production and sale of oil, natural gas and NGLs. Current and forward contract oil and natural gas prices are based on world demand, supply, weather, pipeline capacity constraints, inventory storage levels, geopolitical unrest, world health events and other factors, all of which are beyond our control. Historically, the market for oil and natural gas has been volatile and is expected to remain so. Furthermore, prices which we receive for our oil and natural gas sales, while based on international oil and natural gas prices, are established by contracts with purchasers and include the deductions for quality differentials and transportation. The differentials and transportation costs can change over time and have a detrimental impact on realized prices.

Drilling and completion operations require a large amount of water. The surface water resources of some of the regions in Canada where we operate and aspire to operate may be insufficient for the full commercial-scale development of the region at a pace matching the industry's ambitions. Thus, limitations on water access may present a ceiling on the allowed pace of development. 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 Furthermore, there can be no assurance that our Canadian governmental licenses to withdraw water will not be rescinded or that additional conditions will not be added to these licenses.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.

Ownership of some of our properties in Canada could be subject to prior undetected claims or interests. We plan to conduct title reviews from time to time according to industry practice prior to the purchase of most of our crude oil and natural gas producing properties or the commencement of drilling wells. 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 peoples have established and claimed IndigenousAboriginal rights and title in portions of Western Canada.Canada, including Alberta. Claims of Indigenous peoples and protests and demonstrations pertaining to IndigenousAboriginal rights and title may disrupt or delay third-party operations or new development on our Canadian properties. Requirements relating to theThe federal implementation of the United Nations Declaration of Rights for Indigenous Peoples, includingwhich includes the concept of free, prior and informed consent before adopting measures or approving projects that may affect Indigenous peoples, havehas 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.

We have operated and non operatednon-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 jointjointly 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,assets. thoroughThorough reviews are conducted before entering into joint venture arrangements to ensure that our operational objectives are aligned with potential joint venture partner.

All of our proved reserves and production are currently located in Colombia, Ecuador and Canada; however, we have recently entered into an exploration, development and production sharing agreement with SOCAR and may eventually expand toour operations into Azerbaijan and 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. In Ecuador, we have entered into investment agreements with the Ecuadorian government in respect of three of our five Blocks and are in the process of finalizing an additional investment agreement in connection with a recently acquired Perico Block. These agreements are intended to provide certain legal and fiscal stability protections, including stabilization of the applicable tax regime and access to international arbitration mechanisms. While these agreements are designed to mitigate political and regulatory risk, they do not eliminate the possibility of adverse governmental action.

TheApproximately vast majorityhalf of our production comes from four fields located in Colombia. For the year ended December 31, 2024,2025, the Acordionero, Costayaco, Moqueta and Cohembi fields collectively generated 79%49% of our production and at December 31, 2024,2025, these four fields accounted for 42%51% 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.

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.government, In 2024, the Colombian government commenced peace process conversations with illegal groupsspecifically in the2026, country,a butgeneral itelections isyear notin clear if these discussions will resolve the disruptions.Colombia.

Security concerns in ColombiaColombia, Ecuador or EcuadorAzerbaijan may disrupt our operations

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 toof private property and impactingimpact to 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.incidents. 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.

We may pursue strategic acquisitions, such as our recent acquisition of i3the Energy,Perico and Espejo Blocks in Ecuador, 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.

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.

Public and investor sentiment towards climate change, fossil fuels and other Environmental, Socialsustainability and Governancehuman (“ESG”)capital matters could adversely affect our cost of capital and the price of our common stock

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,human equity and inclusioncapital 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.

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 thesethe relevant 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 the new Colombia regulation, we may not be able to obtain new exploration licenses which can have adverse impact on our future exploration activities, production and operations.

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.future, such as Azerbaijan. 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.

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 presidentPresident of the United States declared that Canada, among other countries, is responsible for illegal immigration and drug transit to the United States and ishas in the process of implementingimplemented 10% tariffs on energy resources from Canada.Canada Implementationthat ofdo tariffsnot comply with the Canada-United States-Mexico Agreement. Tariffs could have an adverse impact on our profitability from Canadian 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 January 2017, Azerbaijan, and by ratification in July 2017, Ecuador, agreed to an international climate change agreement in Paris, France (the “Paris Agreement”), that calls for countries to set their own GHG emission targets and be transparent about the measures each country will use to achieve its GHG emission targets. 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 proposedupdates to this legislation or regulations will be adopted, if at all, and any such future laws and regulations could result in additional compliance costs or additional operating restrictions. 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.

The profitability of our business depends on government-imposed financial instrumentslevies, such as carbon taxes and output-based pricing systems, government-recognized financial instruments such as carbon tax credits.or Anypricing ofsystem thesecredits, and the liquidity and pricing conditions in which such financial instruments may be traded, to the extent they are tradeable. Any such levies, financial instruments and markets may be changed or altered by theor as a result of relevant government actions 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 effective rate of carbon taxation and the level it reaches over specified time horizons will be changed from time to time, creating an economic environment of uncertainty. This risk is further complicated by the dependency of Canadian hydrocarbon energy producers on exports to the United StatedStates and thecontinuing uncertainty as to how the United StatedStates will regulate GHG emissions related to domestic and Canadian production.

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 GHGs, including carbon dioxide and methanemethane, 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.meet or that such programs or regulatory amendments will not be further amended. 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.

We are a company focused on oil and gas exploration and production, with assets in Colombia, Canada and Ecuador. Our Colombian properties represented 47%,46%, our Canadian properties represented 46%38%, and our Ecuadorian properties represented 7%16% of our proved reserves NAR at December 31, 2024,2025, and for the year ended December 31, 2024,2025, 93%70% of our revenue was generated in Colombia (20232024 - 97%93%; and2023 2022 -100%-97%), 3%19% of our revenue was generated in Canada (2024 - 3%; 2023 and 2022 - nil) and 4%11% (2024 - 4%; 2023 - 3%, 2022 - nil3%) of our revenue was generated in Ecuador. We are headquartered in Calgary, Alberta, Canada.

As of December 31, 2024,2025, we had estimated proved reserves NAR of 135.0111.6 MMBOE, ana 82%17% increasedecrease from the prior year, of which 50%57% were proved developed reserves and 62%71% were oil.

•AdjustedLoss EBITDA(2)before income taxes in 20242025 was $366.8$232.9 million compared to $399.4income before income taxes of $44.6 million in 20232024

•In 2024,2025, we re-purchased 0.5 million and 1.70.7 million shares of Common Stock through the 2024 and 2023 share re-purchase programs,program, representing about 1% and 5%, respectively,2% of shares outstanding as of December 31, 20242025

•Our 20242025 average production NAR was 27,89038,443 BOEPD, an increase from 26,09927,890 BOEPD in 20232024 as a result of two-months of production from the newly acquired Canadian operations, and positive exploration drilling results in Ecuador, full year production from the Canadian operations, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions and trunk line repairs at the Moqueta field which resulted in the field being shut-in during the third quarter of 2025

•Oil, natural gas and natural gas liquids (“NGL”) sales for 20242025 decreased by 2%4% to $596.7 million compared to $621.8 million compared to $637.0 million in 2023,2024, primarily as a result of a 3%15% decrease in Brent price, lower in sales volumes in Colombia, offset by increase inhigher sales volumes in Ecuador, lower differentials, and thea additionfull year of naturalsales gas and NGL into the portfolio via thefrom Canadian acquisition in 2024operations

•Operating expenses per boe for 20242025 were $20.15,$18.09, 2%10% higheror $2.06 per boe lower compared to 2023,2024, primarily due to higher workovers.NAR removalsales 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.volumes. Total operating expenses were $248.7 million in 2025, compared to $202.3 million in 2024, compared to $186.9 million in 2023, representing an 8%23% increase as a result of twohigher monthsoperating costs in Ecuador driven by a production ramp-up in 2025, and the full year of Canadian productionoperations

•Quality and transportation discounts per boe increasedin South America decreased in 20242025 to $17.93$11.04 when compared to $14.90$13.93 in 2023 primarily2024 due to lower Castilla, Vasconia and Oriente differentials as a result of higher differentialsdemand for heavy oil.

•Capital expenditures increased by $7.7$8.2 million or 3% to $234.2$256.3 million compared to 2023$248.1 due to a higher number of wells drilledmillion 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,gross naturalprofit gasadjusted for depletion and NGLaccretion salesrelated lessto operatingproducing and transportation expenses.assets. Management believes that operating netback is a useful supplemental measure for management and investors to analyze financial performance and provides an indication of the results generated by our principal business activities prior to the consideration of other income and expenses. A reconciliation from oil,gross natural gas and NGL salesprofit to operating netback is provided in the table above.below.

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

Funds flow from operations, as presented, is defined as net income (loss) adjusted for DD&A expenses, asset impairment, deferred tax expense or recovery, stock-based compensation expense or recovery,expense, amortization of debt issuance costs, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gains or losses, unrealized derivative instruments gains or losses, 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:

Oil, natural gas and NGL production NAR for the year ended December 31, 2024,2025, increased by 7%38% to 38,443 BOEPD compared to 27,890 BOEPD compared to 26,099 BOEPD in 2023.2024. The increase in production was a result of twopositive monthsexploration ofwell drilling in Ecuador, full-year production from the Canadian operations acquired on October 31, 2024 and positive exploration well drilling results in Ecuador,2024, partially offset by lower production in the Acordionero and Costayaco fields as a result of export pipeline disruptions, and trunk line repairs in the Moqueta field causedwhich byresulted downtimein relatedthe tofield workovers.being shut-in during the third quarter.

Oil production NAR for the year ended December 31, 2023,2024, increased by 10%7% to 27,890 BOEPD compared to 26,099 BOEPD compared to 23,815 BOEPD in 2022.2023. The increase in production was a result of successfultwo months production from Canadian operations acquired on October 31, 2024 and positive exploration well drilling and workover campaignsresults in allEcuador, majorpartially fields,offset andby increasedlower production in Ecuador.the Acordionero field caused by downtime related to workovers.

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, 2023,2025, decreased 3%4% compared to 20222024 commensurate with the decrease in benchmark oil prices and the price sensitive royalty regime in ColombiaColombia, Ecuador, and Ecuador.Canada. Royalties as a percentage of production for the year ended December 31, 2024, were comparable to 2023.

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

Oil, natural gas and NGL sales for the year ended December 31, 2024,2025, decreased by 2%4% to $596.7 million compared to $621.8 million compared to $637.0 million in 2023,2024, primarily as a result of a 3%15% decrease in Brent priceprice, anda 6%15% decrease in sales volumes in Colombia, offset by increase inhigher sales volumes in Ecuador, lower differentials, and twothe monthsfull year of sales from Canadian operations of $19.0$115.7 million in 2024.2025 Vasconia, Castilla and Oriente differentials decreasedcompared to $4.78,the $8.54two andmonth $8.75 per boeperiod in 2024 fromof $5.39,$19.0 $10.22 and $9.91 per boe in 2023, respectively.million.

On a per boe basis, the average realized pricesprice for Colombia decreased by 18%14% to $67.26$56.54 for the year ended December 31, 2023,2025, compared to $82.25$65.80 in 2022,2024, primarily as a result of the15% decrease in benchmarkBrent oil prices, offset by higher Castilla and Vasconia differentials in 2023.price.

Operating expenses for the year ended December 31, 2024, increased by 8% to $202.3 million compared to $186.9 million in 2023. On a per boe basis, operating expenses increased by only 2% or $0.42 to $20.15 in 2024 compared to $19.73 in the prior year,2023, primarily as a result of $0.48 higher workovers, removal of diesel subsidies and higher natural gas and electricity costs in Colombia, partially offset by lower operating costs in Ecuador as a result of production ramp-up in 2024.Ecuador.

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.expense as transportation costs are netted against the sales price. Volumes sold in Ecuador and Canada are transported via pipeline.pipeline and trucks. We focus on maximizing operating netback (1) per boe when choosing a transportation method.

Key Highlights for the firstsecond quarter of 2026

•Loss beforeNet income taxes for the firstsecond quarter of 2026 was $145.8$24.9 million,million or $0.70 per share basic and diluted, compared to a net loss before income taxes of $15.7$12.7 million or $(0.36) per share basic and diluted for the firstsecond quarter of 2025 and a net loss before income taxes of $177.8$119.2 million or $(3.38) per share for the prior quarterquarter.

•CapitalIncome expendituresbefore income taxes for the firstsecond quarter of 2026 werewas $45.4$45.3 millionmillion, compared to $94.7loss before income taxes of $8.1 million infor the firstsecond quarter of 2025 and $53.0loss before income taxes of $145.8 million infor the prior quarter

•During the firstsecond quarter, we enteredsatisfied intoall outstanding conditions precedent to and received regulatory approval for a strategic partnership with Ecopetrol S.A.S.A., to earn, subject to regulatory approvals and conditions precedent,earning a 49% WIworking interest in the Tisquirama Block in ColombiaColombia. Additionally, we completed all capital commitments related to Suroriente Block.

(*) Calculated as DD&A expenses for the three months ended MarchJune 31,30, 2026 and 2025 of $46.4$43.5 million and $48.7$50.5 million less depreciation of administrative assets of $5.7$5.5 million and $3.7$2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million, less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $53.3$46.4 million, less depreciation of administrative assets of $3.9$5.7 million.

(*) Calculated as DD&A expenses for the three months ended MarchJune 31,30, 2026 and 2025 of $69.9$10.3 million and $72.2$4.4 million less depreciation of administrative assets of $6.0$0.6 million and $3.8nil, million,respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $26.3 million and $14.8 million less depreciation of administrative assets of $0.7 million and nil, respectively. For the prior quarter, calculated as DD&A expenses of $72.5$16.0 million, less depreciation of administrative assets of $4.3$0.1 million.

EBITDA, as presented, is defined as net income (loss) adjusted for depletion, depreciation and accretion (“DD&A”) expenses, interest expense, and income tax expense or recovery. Adjusted EBITDA, as presented, is defined as EBITDA adjusted for asset impairment, severance expense, non-cash lease expense, lease payments, foreign exchange gains or losses, stock-based compensation expense or recovery, other non-cash gains or losses and unrealized derivative instruments gains or losses. 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, asset impairment, deferred income tax expense or recovery, stock-based compensation expense or recovery, amortization of debt issuance costs, Senior Notes exchange fees, non-cash interest, non-cash lease expense, lease payments, unrealized foreign exchange gain or loss, unrealized derivative instruments gains or losslosses 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. A reconciliation from net loss to funds flow from operations is as follows:

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

Oil, natural gas and NGL production NAR for the three and six months ended MarchJune 31,30, 2026, decreased by 2%20% and 11% to 37,74131,990 BOEPD and 34,850 BOEPD, respectively, compared to the corresponding periodperiods of 2025 due to lower production in AcordioneroColombia, fieldhigher inin-kind Colombiaroyalties driven by higher oil prices and the sale of Simonette area in Canada,Canada at the end of prior quarter, partially offset by higher than anticipated production results from Conejo-1 well in Charapa Block and additional production from Perico Block in Ecuador acquired in December 2025. Oil, natural gas and NGL production NAR decreased by 4%15% compared to the prior quarter forprimarily due to the samesale reasonof mentionedthe above.Simonette area in Canada and lower production in the Acordionero and Cohembi fields in Colombia as a result of failure of artificial lift systems.

Royalties as a percentage of production for the three and six months ended MarchJune 31,30, 2026 wereincreased comparableto 23% and 20%, respectively, compared to the corresponding periodperiods of 2025.2025 Royalties as a percentage of production increased 2% compared toand the prior quarter commensurateas witha theresult increaseof inhigher benchmark oil prices and the price sensitive royalty regime in Colombia, Ecuador,Colombia and Canada.Ecuador.

During the three and six months ended MarchJune 31,30, 2026,2026 and 2025, 100% of sales from South America was priced against Brent.

WTI - For the three and six months ended MarchJune 31,30, 2026, WTI increased 2%by 45% and 22% from the corresponding periodperiods of 2025 and increased 23%27% from the prior quarter. During the firstthree quarterand ofsix months ended June 30, 2026, 25%22% and 23% of NAR production in Canada was oil, compared to 21%26% and 23% for the comparablecorresponding periodperiods of 2025,2025 and 26%25% forin the prior quarter.quarter, respectively.

NGLs - For the three and six months ended MarchJune 31,30, 2026, the weighted average NGL price received was 10%7% and 12% of WTI compared to 14%11% percentand 12% of WTI in the comparablecorresponding periodperiods of 20252025, respectively, and 22% percent10% of WTI in the prior quarter. During the firstthree quarterand ofsix months ended June 30, 2026, 26% ofNGLs production in Canada werewas NGLs,27% comparedin each reporting period, and comparable to 27% from the comparablecorresponding periodperiods of 2025 and 24% in the prior quarter.

AECO - For the three and six months ended MarchJune 31,30, 2026, AECO price decreased 7%by 3% and 9%5% from the comparablecorresponding periodperiods of 2025 and decreased 19% from the prior quarter, respectively.quarter. During the firstthree quarterand ofsix months ended June 30, 2026, 49%52% and 50% of production in Canada was natural gas, compared to 52%50% fromand 51%, in the comparablecorresponding periodperiods of 20252025, respectively, and 50%49% in the prior quarter.

Oil, natural gas and NGL sales for the three and six months ended MarchJune 31,30, 2026, increased by 2%25% and 13% to $172.1$187.2 million and $359.2 million compared to the corresponding periodperiods of 20252025, primarily due to 3%increases higherof sales volumes driven by selling production from newly acquired Perico Block in Ecuador45% and 5% increase24% in Brent price, partially offset by 16% and 6% lower sales volumes in Colombia and Canada and higher quality and transportation discounts in Colombia. Higher qualityQuality and transportation discounts incurredin dueColombia towere affected by using alternative transportation route associated withfor Putumayo production whichas Colombia and Ecuador border remained closed. The alternative transportation route was significantly more expensive and resulted in approximately $4.1$5.9 million and $10.0 million for the currentthree quarter.and six months ended June 30, 2026.

The following table shows the effect of changes in realized price and sale volumes on our oiloil, natural gas and NGL sales for the three and six months ended MarchJune 31,30, 2026, compared to the prior quarter and the corresponding periodperiods of 2025:

(*) Calculated as DD&A expenses for the three months ended MarchJune 31,30, 2026 and 2025 of $46.4$43.5 million and $48.7$50.5 million less depreciation of administrative assets of $5.7$5.5 million and $3.7$2.6 million, respectively. For the six months ended June 30, 2026 and 2025, DD&A expenses of $89.9 million and $99.1 million less depreciation of administrative assets of $11.2 million and $6.2 million, respectively. For the prior quarter, calculated as DD&A expenses of $53.3$46.4 million, less depreciation of administrative assets of $3.9$5.7 million.