IMPERIAL OIL LTD 10-K

imo-20251231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 , 2025 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from to Commission file number 0-12014 IMPERIAL OIL LIMITED (Exact name of registrant as specified in its charter) Canada 98-0017682 (State or other jurisdiction of incorporation or organization) (I.R.S. Employer Identification No.) 505 Quarry Park Boulevard S.E. , Calgary , Alberta , Canada T2C 5N1 (Address of principal executive offices) (Postal Code) 1- 800 - 567-3776 (Registrant’s telephone number, including area code) Securities registered pursuant to Section 12(b) of the Act: Title of each class Trading symbol Name of each exchange on which registered None None Securities registered pursuant to Section 12(g) of the Act: Common Shares (without par value) (Title of Class) Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act. Yes ☑ No ☐ Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Act. Yes ☐ No ☑ Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ☑ No ☐ Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files). Yes ☑ No ☐ Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Exchange Act. Large accelerated filer ☑ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act ☐ Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ☑ If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements. ☐ Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant’s executive officers during the relevant recovery period pursuant to §240.10D-1(b). ☐ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Act. Yes ☐ No ☑ As of the last business day of the 2025 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $ 16,740,858,786 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date. The number of common shares outstanding, as of February 11, 2026, was 483,592,715 . 1 Table of contents Page PART I 6 Item 1. Business 6 Upstream 7 Disclosure of reserves 7 Proved undeveloped reserves 8 Oil and gas production, production prices and production costs 9 Drilling and other exploratory and development activities 11 Present activities 13 Oil and gas properties, wells, operations and acreage 14 Downstream 16 Supply and trading 16 Transportation 16 Refining 16 Distribution 16 Marketing 17 Chemical 17 Delivery commitments 18 Human capital resources 18 Competition 18 Government regulations 19 The company online 21 Item 1A. Risk factors 22 Item 1B. Unresolved staff comments 32 Item 1C. Cybersecurity 32 Item 2. Properties 33 Item 3. Legal proceedings 33 Item 4. Mine safety disclosures 33 PART II 34 Item 5. Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities 34 Item 7. Management’s discussion and analysis of financial condition and results of operations 35 Item 7A. Quantitative and qualitative disclosures about market risk 35 Item 8. Financial statements and supplementary data 35 Item 9. Changes in and disagreements with accountants on accounting and financial disclosure 35 Item 9A. Controls and procedures 36 Item 9B. Other information 36 Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections 36 PART III 37 Item 10. Directors, executive officers and corporate governance 37 Item 11. Executive compensation 37 Item 12. Security ownership of certain beneficial owners and management and related stockholder matters 38 Item 13. Certain relationships and related transactions, and director independence 39 Item 14. Principal accountant fees and services 40 PART IV 41 Item 15. Exhibits, financial statement schedules 41 Item 16. Form 10-K summary 42 SIGNATURES 43 Financial section 44 Proxy information section 113 All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated. Note that numbers may not add due to rounding. 2 Forward-looking statements Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Similarly, discussion of roadmaps or future plans related to carbon capture, transportation and storage, biofuel, hydrogen, and other future plans to reduce emissions and emission intensity of the company, its affiliates and third parties are dependent on future market factors, such as continued technological progress, policy support and timely rule-making and permitting, and represent forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, project, predict, target, estimate, expect, strategy, outlook, schedule, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to estimates, development, timing and recovery of reserves; the development drilling program at Cold Lake; Cold Lake experimental pilot operations to improve bitumen recovery; the evaluation and pace of the Aspen project; the timing, pace and results from the EBRT field pilot; the continued evaluation of other oil sands development projects; future activities with respect to Beaufort Sea licences; the company’s strategy for the energy transition and emission reduction goals; the company’s pursuit of lower-emission business opportunities and emission-reduction services and technologies; human capital resources strategy and impact; the company’s workforce transformation and restructuring plans to centralize activities in global capability centres, including timing and impacts; the cessation of production at Norman Wells, including impacts and timing; the measures required to comply with environmental regulations and any changes in such regulations; anticipated capital and operating expenditures, including with respect to environmental protection; the ability for autonomous operations at Kearl to continue capturing productivity improvements, reducing cost and enhancing safety; the effectiveness of the company's corporate governance and strategic planning practices, including with respect to risk management and oversight; the structure and effectiveness of the cybersecurity program; continued evaluation of the company’s share purchase program; being well-positioned to participate in substantial investments to develop Canadian energy supplies; the company’s long-term business outlook, including demand, supply and energy mix and transition pathways related to greenhouse gas emissions; the extent of ongoing effects of global events affecting supply and demand, including continued or renewed inflation, and the company’s ability to mitigate cost impacts in all price environments; the company’s Upstream business and investment strategies and evaluation of opportunities, including the company’s focus on operations integrity, innovative technologies, employee development, community investment, optimization within existing assets, cost reduction opportunities and productivity enhancements; the ability of the company’s current investment strategy of value and select volume growth to deliver robust returns and support long term growth; segment growth, competitive strategies and benefits from an integrated business model; the company’s Downstream strategies and their impacts on the company’s competitive position; Chemical competitive position and the benefits from integration with the Sarnia refinery and relationship with ExxonMobil; the impact of future funding of retirement plans; capital structure, liquidity sources and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; expected 2026 full year capital and exploration expenditures; earnings sensitivities and the impacts of changes in interest rates, crude oil prices, refining margins and foreign exchange rates; the company’s asset management program and potential divestments; risks associated with use of derivative instruments; the impact of any pending litigation, accounting standards and unrecognized tax benefits; standardized measures of discounted future cash flows; the effectiveness of the company’s ethics programs, restrictions on insider trading, related party transaction controls, diversity and shareholder engagement initiatives; and the effectiveness of the company’s director and executive compensation design and share ownership guidelines, including aligning with shareholder interests, managing risk, promoting long-term business performance, strategic objectives and shareholder value, and other stated objectives. Forward-looking statements are based on the company’s current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning future energy demand, supply and mix; production rates, growth and mix across various assets; production life, resource recoveries and reservoir performance; project plans, timing, costs, technical evaluations and capacities, and the company’s ability to effectively execute on these plans and operate its assets; the adoption and impact of new facilities or technologies on reductions to greenhouse gas emissions intensity, including but not limited to technologies using solvents to replace energy intensive steam at Cold Lake, the EBRT project, Strathcona renewable diesel, carbon capture and storage including in connection with hydrogen for the renewable diesel project, recovery technologies and efficiency projects, and any changes in the scope, terms, or costs of such projects; the degree and timeliness of support that will be provided by policymakers and other stakeholders for various new technologies such as carbon capture and storage; for renewable diesel, the availability and cost of locally-sourced and grown feedstock and the supply of renewable diesel to British Columbia in connection with its low-carbon fuel legislation; the amount and timing of emissions reductions, including the impact of lower carbon fuels; availability and performance of third-party service 3 providers, including ExxonMobil global capability centres and other service providers located outside of Canada; receipt of regulatory and third-party approvals in a timely manner, especially with respect to large scale emissions reduction projects; applicable laws and government policies, including with respect to climate change, greenhouse gas emissions reductions and low carbon fuels; refinery utilization and product sales; the ability to offset any ongoing or renewed inflationary pressures; cash generation, financing sources and capital structure, such as dividends and shareholder returns, including the timing and amounts of share repurchases; capital and environmental expenditures; the capture of efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies; and commodity prices, foreign exchange rates and general market conditions, could differ materially depending on a number of factors. These factors include global, regional or local changes in supply and demand for oil, natural gas, petroleum and petrochemical products, feedstocks and other market factors, economic conditions and seasonal fluctuations and resulting demand, price, differential and margin impacts, including Canadian and foreign government action with respect to supply levels, prices, trade tariffs, trade sanctions or trade controls, disruptions, realignment or breaking of trade alliances or agreements or a broader breakdown in global trade, and disruptions in military alliances or wars; political or regulatory events, including changes in law or government policy, applicable royalty rates, and tax laws; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; environmental risks inherent in oil and gas activities; government policies supporting lower carbon investment opportunities; failure, delay, reduction, revocation or uncertainty regarding supportive policy and market development for the adoption of emerging lower-emission energy technologies and other technologies that support emissions reductions; the receipt, in a timely manner, of regulatory and third-party approvals, including for new technologies relating to the company’s lower emissions business activities; third-party opposition to company and service provider operations, projects and infrastructure; competition from alternative energy sources, other emission reduction technologies, and established competitors in such markets; availability and allocation of capital; availability and performance of third-party service providers, including ExxonMobil global capability centres and other service providers located outside of Canada; unanticipated technical or operational difficulties; effectiveness of company risk management programs and emergency response preparedness; project management and schedules and timely completion of projects; transportation for accessing markets; commercial negotiations; unexpected technological developments; the results of research programs and new technologies, including with respect to autonomous operations and greenhouse gas emissions, and the ability to bring new technologies to commercial scale on a commercially competitive basis; reservoir analysis and performance; the ability to develop or acquire additional reserves; operational hazards and risks; cybersecurity incidents including incidents caused by actors employing emerging technologies such as artificial intelligence; currency exchange rates; the occurrence, pace, rate of recovery and effects of public health crises, including the responses from governments; general economic conditions, including continued or renewed inflation and the occurrence and duration of economic recessions or downturns; and other factors discussed in "Item 1A Risk factors" and "Item 7 Management’s discussion and analysis of financial condition and results of operations" in this annual report on Form 10-K. Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial. Imperial’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law. Forward-looking and other statements regarding Imperial's environmental, social and other sustainability efforts and aspirations are not an indication that these statements are material to investors or require disclosure in the company's filings with securities regulators. In addition, historical, current and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making. Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply Imperial views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not Imperial, and their use by Imperial is not an endorsement by the company of their underlying assumptions, likelihood or probability. 4 Investment decisions are made on the basis of Imperial’s separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by Imperial of any or all of the positions or activities of such organization. Actions needed to advance the company’s medium-term greenhouse gas emission-reductions plans are incorporated into its medium-term business plans, which are updated annually. The reference case for longer-term planning is based on ExxonMobil’s Global Outlook (the Outlook) research and publication. The Outlook is reflective of the existing global policy environment and an assumption of increasing policy stringency and technology improvement to 2050. However, the Outlook does not attempt to project the degree of required future policy and technology advancement and deployment for the world to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and the company’s business plans will be updated accordingly. References to projects or opportunities may not reflect investment decisions made by the company. Individual projects or opportunities may advance based on a number of factors, including availability of stable and supportive policy, permitting, technological advancement for cost-effective abatement, insights from the company planning process, and alignment with partners and other stakeholders. Capital investment guidance in lower-emission investments is based on the company’s corporate plan; however, actual investment levels will be subject to the availability of the opportunity set, public policy support, and focused on returns. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. 5 PART I Item 1. Business Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the "CBCA") by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1. Exxon Mobil Corporation ("ExxonMobil") owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to the "company" or "Imperial" includes Imperial Oil Limited and its subsidiaries, and reference to ExxonMobil includes Exxon Mobil Corporation and its affiliates, as appropriate. The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner, a leading marketer of petroleum products, and a major producer of petrochemicals. The company also pursues lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium. The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic crude oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals. Operating data and financial information about the company’s business segments are contained in this report under the following: "Management’s discussion and analysis of financial condition and results of operations" and the "Financial section" under note 2 to the consolidated financial statements: "Business segments". 6 Upstream Disclosure of reserves Summary of oil and gas reserves at year-end The table below summarizes the net proved reserves for the company, as at December 31, 2025, as detailed in the "Supplemental information on oil and gas exploration and production activities" in the "Financial section" of this report. All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the first-day-of-the-month price for each month during the last 12-month period ended December 31. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2025 that would cause a significant change in the estimated proved reserves as of that date. Liquids (a) Natural gas Synthetic crude oil Bitumen Total oil-equivalent basis millions of barrels billions of cubic feet millions of barrels millions of barrels millions of barrels Net proved reserves: Developed — 41 288 1,641 1,936 Undeveloped — 8 — 99 100 Total net proved — 49 288 1,740 2,036 (a) Liquids include crude oil and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids. The estimation of proved reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of reservoir and well performance, development and production costs, and other factors. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion and optimization of development projects, reservoir performance, and facility processing capacity. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects. Technologies used in establishing proved reserves estimates Imperial’s proved reserves in 2025 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages. In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates. 7 Preparation of reserves estimates Imperial has a dedicated reserves management group that is separate from the base operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with the U.S. Securities and Exchange Commission rules and regulations, review of annual changes in reserves estimates and the reporting of the company’s proved reserves. This group also maintains the official reserves estimates for the company’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial. The reserves management group maintains a central database containing the company’s official reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long-standing approval guidelines. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors. The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has 23 years of petroleum industry experience, including 14 years of reserves related experience. During the last 5 years, the majority of such evaluator's time was spent evaluating resources. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 20 persons with professional designations, with an average of 13 years engaged with the company's resource evaluation. The company’s internal reserves evaluation management team is made up of 12 persons with an average of 10 years engaged with the company's resource evaluation. Proved undeveloped reserves As at December 31, 2025, approximately 4.9 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 100 million oil-equivalent barrels. Proved undeveloped reserves are associated with Cold Lake and Kearl. This compared to 227 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2024. The decrease of 127 million oil-equivalent barrels of proved undeveloped reserves is attributed to first ore extraction from Syncrude's Mildred Lake Extension - West (MLX-W) and to Cold Lake drilling start-ups, partially offset by full funding of Cold Lake drilling. As at December 31, 2025 there were no proved undeveloped reserves that have remained undeveloped for five years or more. One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $291 million during the year to progress the development of proved undeveloped reserves at Cold Lake, Syncrude, and Kearl. 8 Oil and gas production, production prices and production costs Reference is made to the portion of the "Financial section" entitled "Management’s discussion and analysis of financial condition and results of operations" of this report for a narrative discussion on the material changes. Average daily production of oil The company’s average daily oil production by final products sold during the three years ended December 31, 2025 was as follows. All reported production volumes were from Canada. thousands of barrels per day (a) 2025 2024 2023 Bitumen: Kearl: - gross (b) 199 200 191 - net (c) 188 186 177 Cold Lake: - gross (b) 151 148 135 - net (c) 122 113 106 Total bitumen: - gross (b) 350 348 326 - net (c) 310 299 283 Synthetic crude oil (d) : - gross (b) 79 75 76 - net (c) 68 62 67 Liquids (e) : - gross (b) 4 5 5 - net (c) 4 5 5 Total: - gross (b) 433 428 407 - net (c) 382 366 355 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. (c) Net production is gross production less the mineral owners’ or governments’ share or both. (d) The company’s synthetic crude oil production volumes were from the company’s share of production volumes in the Syncrude joint venture and include immaterial amounts of bitumen and other products exported to the operator's facilities using an existing interconnect pipeline. (e) Liquids include crude oil and NGLs. Average daily production and production available for sale of natural gas The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2025 are set forth below. All reported production volumes were from Canada and are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. millions of cubic feet per day (a) 2025 2024 2023 Gross production (b) (c) 29 30 33 Net production (c) (d) (e) 29 30 32 Net production available for sale (f) 8 9 11 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. (c) Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected. (d) Net production is gross production less the mineral owners’ or governments’ share or both. (e) Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure. (f) Includes sales of the company’s share of net production and excludes amounts used for internal consumption. 9 Total average daily oil-equivalent basis production The company’s total average daily production expressed in an oil-equivalent basis is set forth below, with natural gas converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. thousands of barrels per day (a) 2025 2024 2023 Total production oil-equivalent basis: – gross (b) 438 433 413 – net (c) 387 371 360 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. (c) Net production is gross production less the mineral owners’ or governments’ share or both. Average unit sales price The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2025 were as follows. Canadian dollars per barrel 2025 2024 2023 Bitumen 67.01 74.53 67.42 Synthetic crude oil 88.99 101.91 105.57 Liquids (a) 33.10 55.63 59.30 Canadian dollars per thousand cubic feet Natural gas 1.76 0.69 2.58 (a) Liquids include crude oil and NGLs. In 2025, Imperial's average Canadian dollar realization for bitumen decreased, primarily driven by lower marker prices, partially offset by the narrowing of the Western Texas Intermediate (WTI)/Western Canada Select (WCS) spread and favourable diluent. The company's average Canadian dollar realizations for synthetic crude oil decreased, primarily driven by lower WTI. In 2024, Imperial's average Canadian dollar realization for bitumen increased, primarily driven by the narrowing of the Western Texas Intermediate (WTI)/Western Canada Select (WCS) spread and lower diluent costs, partially offset by lower WTI. The company's average Canadian dollar realizations for synthetic crude oil decreased, primarily driven by a weaker Synthetic/WTI spread and lower WTI. Average unit production costs Canadian dollars per barrel 2025 2024 2023 Bitumen 28.85 29.42 32.41 Synthetic crude oil 57.25 61.84 62.57 Total oil-equivalent basis (a) 34.54 35.48 38.51 (a) Includes liquids, bitumen, synthetic crude oil and natural gas. In 2025, bitumen unit production costs decreased, primarily driven by higher Cold Lake production. In 2025, synthetic crude oil unit production costs decreased, primarily driven by higher production. In 2024, bitumen unit production costs decreased, primarily driven by lower energy costs, higher Cold Lake production due to Grand Rapids, and higher Kearl production due to improved mine fleet productivity and optimized turnaround. In 2024, synthetic crude oil unit production costs decreased, primarily driven by lower upgrading costs and lower energy costs. 10 Drilling and other exploratory and development activities The company has been involved in the exploration for and development of crude oil and natural gas in Canada only. Wells drilled The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2025. wells 2025 2024 2023 Net productive exploratory — — — Net dry exploratory — — — Net productive development 4 14 32 Net dry development — — — Total 4 14 32 In 2025, wells drilled to add productive capacity include 4 development wells at Cold Lake. In 2024, wells drilled to add productive capacity include 14 development wells at Cold Lake. Wells drilling At December 31, 2025, the company was drilling the following development wells to add productive capacity at Cold Lake. All wells were located in Canada. 2025 wells Gross Net Total 9 9 Exploratory and development activities regarding oil and gas resources Cold Lake To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. In 2025, additional development wells were drilled to add productive capacity. In 2026, a development drilling program is planned within the approved development area to add productive capacity. Additionally, in 2022, the company approved the budget for the Leming Steam-Assisted Gravity Drainage (SAGD) project that will re-develop the original pilot area of the Cold Lake field. Development activities commenced in 2023 and first oil production was achieved in November 2025. The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques. Aspen and other in-situ oil sands activities In October 2018, the company received regulatory approval for the Aspen Solvent Assisted - Steam Assisted Gravity Drainage (SA-SAGD) project from the AER. Development was proposed to occur in two phases, each producing about 75,000 barrels per day, before royalties. The first phase of the project was approved by the company’s board, and appropriated for $2.6 billion. Construction began late in the fourth quarter of 2018. In March 2019, the company slowed the pace of development given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. Although the Government of Alberta repealed the regulatory authority for imposing temporary production curtailments at the end of 2021, major investment remains on hold due to continued market uncertainty. Aspen’s pace will continue to be evaluated as the project remains an important opportunity for Imperial. The Enhanced Bitumen Recovery Technology (EBRT) field pilot on the Aspen lease received funding approval in 2023, with development work underway for pilot start-up anticipated by 2027. The pilot will test technology that has the potential to deliver higher bitumen production rates compared to industry average SAGD operations. 11 Work progresses on technical and technology evaluations to support potential future Clarke Creek and Corner in-situ development regulatory applications. The company also has interests in other oil sands leases in the Athabasca region of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development. Beaufort Sea The company holds a 25 percent interest in two exploration licences in the Beaufort Sea. In 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences were not impacted. In June 2019, the Federal Government approved selective changes to the Canada Petroleum Resources Act to prohibit and freeze the existing licences. In 2023, the Western Arctic - Tariuq (Offshore) Accord was signed and prohibition was extended to December 31, 2028. The Federal Government plans to co-develop a climate and marine science-based review of the moratorium. The company continues to hold the licences while maintaining community engagement and participation in the process. Exploratory and development activities regarding oil and gas resources extracted by mining methods The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region. 12 Present activities Review of principal ongoing activities Kearl Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation. During 2025, the company’s share of Kearl’s net bitumen production was about 188,000 barrels per day and gross production was about 199,000 barrels per day. Total gross production for Kearl was about 280,000 barrels per day (199,000 barrels Imperial’s share), which is a decrease of about 1,000 barrels per day (1,000 barrels Imperial's share) compared to 2024 . Cold Lake Cold Lake is an in-situ heavy oil bitumen operation. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. In 2025, net bitumen production at Cold Lake was about 122,000 barrels per day. The gross production was about 151,000 barrels per day, which is an increase of about 3,000 barrels per day compared to 2024. Syncrude Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. In 2025, the company’s share of Syncrude’s net productio n was about 68,000 barrels per day. The gross production was about 79,000 barrels per day, which is an increase of about 4,000 barrels per day compared to 2024. The Province of Alberta, in its capacity as lessor of Kearl, Cold Lake, and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil. 13 Oil and gas properties, wells, operations and acreage Production wells The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2025 and December 31, 2024, is disclosed in the following table. The statistics in the table are determined in part from information received from other operators. Year ended December 31, 2025 Year ended December 31, 2024 Crude oil Natural gas Crude oil Natural gas wells Gross (a) Net (b) Gross (a) Net (b) Gross (a) Net (b) Gross (a) Net (b) Total (c) 4,025 4,021 2,421 773 3,991 3,987 2,387 763 (a) Gross wells are wells in which the company owns a working interest. (b) Net wells are the sum of the fractional working interest owned by the company in gross wells, rounded to the nearest whole number. (c) Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end 2025, the company had an interest in 15 gross wells with multiple completions (2024 - 12 gross wells). Land holdings At December 31, 2025 and December 31, 2024, the company held the following oil and gas rights, and bitumen and synthetic crude oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore. Developed Undeveloped Total thousands of acres 2025 2024 2025 2024 2025 2024 Western provinces (a): Liquids and gas - gross (b) 394 413 185 185 579 598 - net (c) 250 251 135 135 385 386 Bitumen - gross (b) 196 196 578 578 774 774 - net (c) 182 182 253 253 435 435 Synthetic crude oil - gross (b) 119 119 100 100 219 219 - net (c) 30 30 25 25 55 55 Canada lands (d) : Liquids and gas - gross (b) 2 2 1,803 1,803 1,805 1,805 - net (c) 2 2 495 495 497 497 Atlantic offshore: Liquids and gas - gross (b) 23 23 146 146 169 169 - net (c) 2 2 22 22 24 24 Total (e) : - gross (b) 734 753 2,812 2,812 3,546 3,565 - net (c) 466 467 930 930 1,396 1,397 (a) Western provinces include British Columbia and Alberta. (b) Gross acres include the interests of others. (c) Net acres exclude the interests of others. (d) Canada lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other Northwest Territories. (e) Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in). 14 Western provinces The company’s bitumen leases include about 161,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 68,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 171,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area, about 29,000 net acres in the Clarke Creek area, about 28,000 net acres of oil sands leases in the Corner area, and about 18,000 net acres in the Chard area. The 171,000 net acres are suitable for in-situ recovery techniques. The company’s share of Syncrude joint venture leases covering about 55,000 net acres accounts for the entire synthetic crude oil acreage. Oil sands leases have an exploration period of 15 years and are continued beyond that point by payment of escalating rentals or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production. The company holds interests in an additional 385,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from 2 to 15 years and are continued beyond that point by proven production capability. Canada lands Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres. Exploration licences on Canada lands have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions. The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs. Atlantic offshore Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production licences or held by SDLs. 15 Downstream Supply and trading The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices, in addition to undertaking trading activities. Purchases and sales are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil. Transportation The company currently transports its crude oil production and third-party crude oil required to supply refineries by contracted or common carrier pipelines. Refining The company owns and operates three refineries, which process predominantly Canadian crude oil. The company purchases finished products to supplement its refinery production. The approximate average daily volumes of refinery throughput and utilization during the three years ended December 31, 2025, and the daily rated capacities of the refineries as at December 31, 2025, were as follows. Refinery throughput (a) Rated capacities (b) Year ended December 31 at December 31 thousands of barrels per day 2025 2024 2023 2025 Strathcona, Alberta 186 187 186 197 Sarnia, Ontario 113 110 110 124 Nanticoke, Ontario 103 102 111 113 Total 402 399 407 434 Utilization of refinery capacity (percent) 93 92 94 (a) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units. (b) Refining capacity data is based on 100 percent of rated refinery process unit stream-day capacities to process inputs to atmospheric distillation units under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. 2024 Lower refinery throughput in 2024 reflected the impact of planned turnaround activities at Nanticoke, Sarnia and Strathcona refineries. Distribution The company maintains a nationwide distribution system to move petroleum products to market by pipeline, tanker, rail and road transport. The company owns and operates fuel terminals across the country, as well as natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products pipeline companies. 16 Marketing The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers. The company supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2025, there were about 2,600 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby the company supplies fuel to independent third parties. The company also sells petroleum products, including fuel, asphalt and lubricants, to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded fuel and lubricant resellers. The approximate daily volumes of net petroleum products (excluding purchases/sales contracts with the same counterparty) sold during the three years ended December 31, 2025, are set out in the following table. thousands of barrels per day 2025 2024 2023 Gasolines 224 223 228 Heating, diesel and jet fuels 177 175 176 Lube oils and other products (a) 48 46 43 Heavy fuel oils 21 22 24 Net petroleum product sales 470 466 471 (a) In 2025 and 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast. Chemical The company’s Chemical operations manufacture and market aliphatic solvents, plasticizer intermediates, polyethylene resin, and markets refinery grade propylene. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery. The company’s total petrochemical sales volumes during the three years ended December 31, 2025, were as follows. thousands of tonnes 2025 2024 2023 Total petrochemical sales (a) 683 684 820 (a) In 2025 and 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast. In 2024, sales volumes decreased primarily due to the reclassification of benzene and aromatic solvent sales. 17 Delivery commitments The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements. Human capital resources Imperial operates in a complex, competitive and changing business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the company’s philosophy on talent development. Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of the company's business across the business cycle. The company’s compensation is market competitive, long-term oriented, and highly differentiated by individual performance. In addition, benefits and workplace programs support the company’s talent management approach, and are designed to attract and retain employees for a long-term career. Overall, this multifaceted approach has resulted in strong employee retention. Imperial views diversity as an opportunity. The company encourages and respects diversity of thought, ideas, and perspective in its workforce. The company considers diversity through all stages of employment including recruitment, training and development of its employees. The company’s goal is to reflect the mix and diversity of the communities where it operates, and it continues to focus on diverse representation at all levels of the organization. The number of regular employees was about 5,000 at the end of 2025 (2024 - 5,100, 2023 - 5,300). Regular employees are defined as active executive, management, professional, technical, administrative, and wage employees who work full-time or part-time for the company and are covered by the company’s benefit plans and programs. On September 29, 2025, the company announced restructuring plans to improve its performance by centralizing additional corporate and technical activities in global business and technology centres. The restructuring plans include a program of targeted workforce reductions and involves involuntary employee separations. The program is expected to reduce employee roles by approximately 20% and to be substantially completed by the end of 2027. Competition The Canadian energy and petrochemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities, and the refining, distribution and marketing of petroleum products and chemicals. The energy and petrochemical industries also compete with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. Certain industry participants, including Imperial, are expanding the scope of investments in lower-emission energy and emission-reduction services and technologies. 18 Government regulations Petroleum, natural gas and oil sands rights Most of the company’s petroleum, natural gas and oil sands rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum, natural gas and/or oil sands on the leased lands for a specified period. In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production. The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land. Project approval Approvals and licences from relevant provincial or federal governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes. Approval of large energy projects may be impacted by the environmental assessment framework under Canada's Impact Assessment Act (IAA). The IAA includes broader consideration for social, health, economic and gender-based impacts, the impact on Canada’s climate change commitments (including a requirement under the Strategic Assessment for Climate Change to provide a credible plan for the project to deliver net-zero greenhouse gas emissions by 2050), reliance on strategic and regional assessments and adjusted regulatory review timelines. In October 2023, the Supreme Court of Canada ruled that the new federal assessment scheme was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. The impact of this legislation is not fully apparent, but it may impact the cost, manner, duration and ability to advance large energy projects and project expansions. Environmental protection The company regards protecting the environment in connection with its various operations as a priority. The company is subject to extensive environmental regulations in Canada that apply to all phases of exploration, development, operation, and final closure. These requirements cover the management and monitoring of potential environmental impacts during active operations, including practices for land disturbance, wildlife protection, specifications for equipment operation and material storage and limitations on discharges to the environment. It also includes conducting environmental surveys and collecting operational measurements and sampling to confirm that practices are adequately protecting the environment. These regulations also specify the actions and requirements for final reclamation, abandonment and closure of facilities. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. The company also maintains extensive operating procedures, processes and emergency response plans to address environmental risks at its operations. As discussed in "Item 1A. Risk factors" in this report, compliance with existing and potential future government regulations, including environmental regulations, may have material effects on the capital expenditures, earnings, and competitive position of the company. Imperial takes new and ongoing measures throughout its operations each year to prevent and minimize the impact of its operations on air, land and water. These include significant investments in refining infrastructure and technology to manufacture fuels, continued evaluation and implementation of technologies and products to reduce greenhouse gas emissions, adherence to federal and provincial greenhouse gas emissions reduction and reporting programs, enhanced water and land management, and expenditures for asset retirement obligations. In the past five years, the company has made capital and operating expenditures of about $8.0 billion on environmental protection and facilities. In 2025, the company’s environmental capital and operating expenditures totalled approximately $1.7 billion, which was spent primarily on activities to protect the land, air, and water including remediation projects. Environmental expenditures are expected to increase to approximately $2.0 billion in 2026, with capital expenditures expected 19 to account for approximately 48 percent of the total. Costs for 2027 are anticipated to be approximately $1.7 billion, with capital expenditures expected to account for approximately 41 percent of the total. Crude oil Production The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles. Additionally, the Government of Alberta has in the past used temporary mandatory production curtailment regulations to impose production limits on large producers in Alberta, such as those implemented in 2019 and repealed in 2021. Exports Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the Canada Energy Regulator (CER) and the Government of Canada. Export contracts of less than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require an order from the CER. Natural gas Production The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2025 gas production rates. Exports The Government of Canada has the authority to regulate the export price for natural gas. Exports of natural gas from Canada require approval by the CER and the Government of Canada. The Government of Canada allows the export of natural gas by CER order without volume limitation for terms not exceeding 24 months. Royalties The Government of Canada and the provinces in which the company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights. Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Kearl, Cold Lake and Syncrude, see "Upstream" section entitled "Present activities" under Item 1. Investment Canada Act The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval. The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada. By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians. 20 Competition Act The Competition Bureau seeks to ensure that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the Competition Act (the Act). A merger transaction, whether or not notifiable, is subject to examination by the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act. The Act also provides that a dominant firm (or a firm that is jointly dominant with others) can face possible prohibition orders if it engages in conduct that is intentionally anti-competitive, or if its conduct has prevented or lessened competition substantially (or is likely to do so) in a market in which it has an interest. If such a firm engaged in intentionally anti-competitive acts that resulted in a substantial prevention or lessening of competition, then the firm may be subject to administrative monetary penalties and monetary awards to persons affected, and if a prohibition order is not likely to restore competition in that market the firm may be subject to an alternative or additional remedial order to overcome the effects of the practice, including the divestiture of assets or shares. Similarly, an agreement between competitors that substantially prevents or lessens competition may be prohibited in whole or in part. Orders may be directed against any party to the agreement or any other person, and may require additional or alternative actions to restore competition, including the divestiture of assets or shares. Agreements between non-competitors, a significant purpose of which is anti-competitive, are subject to the same framework. Administrative monetary penalties may also be imposed. The company online The company’s website www.imperialoil.ca contains a variety of corporate and investor information free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. References in this annual report on Form 10-K to the company’s website are provided only as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this annual report on Form 10-K. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC. The SEC’s website, www.sec.gov, contains reports, proxy and information statements, interactive data files, and other information regarding issuers that are submitted and posted electronically with the SEC. 21 Item 1A. Risk factors Imperial’s financial and operating results are subject to a variety of risks inherent in oil, gas and petrochemical businesses and the pursuit of lower-emission business opportunities. Many of these risk factors are not within Imperial’s control and could adversely affect Imperial’s business, financial and operating results, or financial position. These risk factors include: Supply and demand The oil, gas, fuels and petrochemical businesses are fundamentally commodity businesses. This means the company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and petroleum product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity or product. Commodity prices have been volatile, and the company expects that volatility to continue during the lifespan of its major assets. Any material decline in crude oil prices could have a material adverse effect on the company’s Upstream operations, results, financial position, proved reserves and the amount spent to develop reserves. On the other hand, a material increase in crude oil prices could have a material adverse effect on the company's Downstream margins, depending on the market conditions for refined products. The company's pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium also depends on the growth and development of markets for those products and services, including implementation of supportive and stable government policies and developments in technology to enable those products and services to be provided on a cost-effective basis at commercial scale. See "Climate change, energy transition and greenhouse gas restrictions" in this Item 1A. The company may also be impacted by changes in other commodities the company utilizes, such as prices and availability of feedstocks for lower-emission fuels including renewable diesel. Economic conditions The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of economic downturns, recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s results. Other factors that affect general economic conditions, such as changes in population growth rates or living standards, government regulation or austerity programs, national or regional trade tariffs, trade sanctions or trade controls, international monetary and currency exchange rate fluctuations, decoupling of economies, disruptions to or realignment or breaking of current or historical military alliances, security or public health issues and responses, extended government shutdowns, the inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, market bubbles and corrections, de-dollarization in global trade or the growth or use of alternative common currencies, and other events or conditions that impair the functioning of financial markets and institutions, also pose risks to the company, including risks to the safety of the company’s financial assets and to the ability of the company’s partners, suppliers and customers to fulfill their commitments to the company. Disruptions to or realignment or breaking of current or historical trade alliances or agreements or global trade and supply chain networks, changes in international trade patterns or shipping routes, or a broader breakdown in global trade, pose risks. During 2025, the United States announced a variety of trade-related actions, including the imposition of tariffs on imports from Canada and other countries. In response, Canada announced its own retaliatory tariffs. The United States and Canada have continued to discuss a potential end to or reduction in such tariffs, but the full impact and duration of such tariffs is uncertain. Furthermore, there remains a possibility of further escalation in the trade dispute, and there is uncertainty regarding the future status of existing international trade agreements to which Canada is a party, including the Canada-U.S.-Mexico Agreement on trade. Although the impact of such actions on Imperial and its partners, suppliers and customers is uncertain, such actions could depress economic activity, reduce demand for the company’s products, limit or disrupt supply chains, increase costs, reduce market prices and export volumes of the company’s products, or otherwise have a material adverse effect on the company’s business, financial condition or results of operations. Other demand-related factors Factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact the company’s results, include technological improvements in energy efficiency; seasonal weather patterns; increased competitiveness of, or government policy support for, alternative energy sources or potential substitutes for the company's products; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage or other critical areas that make wind, solar, nuclear or other alternatives more competitive for power generation; government actions to increase strategic reserves to enhance energy security; increased demand for artificial intelligence, including the construction and expansion of artificial intelligence data centers; changes in customer or consumer 22 preferences for the company’s products, including consumer demand for alternative fuel or electric transportation or alternatives to plastic products; broad-based changes in personal income levels, interest rates and inflation; and security or public health issues and responses such as epidemics and pandemics. See also "Climate change, energy transition and greenhouse gas restrictions" in this Item 1A below. Other supply-related factors Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new or previously inaccessible oil and gas supply sources and technologies to enhance recovery from existing sources tends to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. Crude oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as the level of and adherence by participating countries or others to production quotas established by OPEC or "OPEC+" and other agreements among sovereigns; government policies that restrict (or may have a consequence of restricting) oil and gas production or exports, or increase associated production, reporting or compliance costs, including actions intended to reduce greenhouse gas emissions as described under “Climate change, energy transition and greenhouse gas restrictions” in this Item 1A, and previous Government of Alberta curtailment regulations; collective actions by non-governmental organizations and financial institutions to withhold funding or support from oil and gas producers; the occurrence of wars or hostile actions, including disruption of land or sea transportation routes; natural disasters; trade tariffs, sanctions or broader breakdowns in global trade; disruptions in competitors’ operations; and unexpected pipeline or rail constraints that may disrupt and have in the past disrupted supplies. For example, Russia's military action in Ukraine impacted global crude oil and gas supply levels and prices, and contributed to a volatile commodity environment. There also may be new or emerging factors that could increase global oil, gas, and petrochemical supply levels in the short or long term, such as government policies and actions intended to boost or expand development of domestic or foreign oil and gas reserves or accelerate the pace of production reaching the market, including access to previously unavailable, sanctioned, or protected oil and gas resources or the availability or opening of new shipping routes. Dynamic and unpredictable world events may lead to new oil and gas opportunities becoming available or current opportunities becoming less available or unavailable, and such events may adversely affect the company’s business and results to the extent that the company is unable to compete effectively for, or is excluded from, such opportunities or any new or existing investments result in reduced returns. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals. Canadian-specific market factors The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil, principally due to the higher transportation and refining costs. Western Canadian crude oil may also be subject to limits on transportation capacity to markets. Future crude price differentials between western Canadian crude oil relative to prices in the U.S. Gulf Coast are uncertain and changes in the heavy or light crude oil differentials could have a material adverse effect on the company’s business. For example, the United States government has indicated it may reduce trade sanctions on Venezuela and take certain steps intended to increase the volume of crude oil produced in Venezuela, and either of these actions could adversely impact western Canadian crude oil price differentials compared to the U.S. Gulf Coast and therefore the company’s business. Additionally, in the past, increased differentials have led the Government of Alberta to enact temporary mandatory production curtailment regulations that imposed production limits on large producers in Alberta, such as Imperial; although the regulatory authority to impose curtailments was repealed at the end of 2021, the use of similar curtailment regulations in the future could have an adverse effect on the company’s business. A significant portion of the company’s production is bitumen, which is blended with diluent for transportation and marketability of heavy crude oil. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business. Other market factors Market factors may also result in losses from commodity derivatives and other instruments used to hedge price exposures or for commodity and treasury trading activities. Imperial’s future business results, including cash flows and financing needs, may also be affected by the occurrence, severity, pace and rate of recovery of future public health epidemics or pandemics, the responsive actions taken by governments and others, and the resulting effects on regional and global markets and economies. If the company’s mitigation and response efforts prove insufficient, then large outbreaks of epidemics, pandemics or other health crises at operating sites, particularly in remote locations and where work camps are utilized, could materially impact the company’s personnel and its operations, reducing productivity and increasing costs. Government and political factors Imperial’s results can be adversely impacted by political, legal or regulatory developments affecting operations and markets. Changes in government policy or regulations, changes in law or interpretation of settled law, 23 challenges to legislative jurisdiction between different levels of government, third-party opposition to company or infrastructure projects, and duration of regulatory reviews could impact the company’s existing operations and planned projects. This includes actions by governments, policy makers, regulators or other actors to delay or deny necessary licences and permits; pause, reduce or retract government incentives for emissions reductions; disrupt or impact reliability as a result of policy decisions on types and pricing of energy available; or restrict the availability of oil and gas leases, investment opportunities or the operation of third-party infrastructure on which the company relies, such as pipelines to transport the company’s Upstream production to market or that supply feedstock to the company’s refineries. Additionally, changes in environmental regulations, assessment processes or other laws (including but not limited to in respect of climate change and greenhouse gas emissions and company communications relating thereto), regulatory interpretations that exclude or disfavour the company's products under government policies or programs intended to support new or developing markets or technologies or that are otherwise not technology-neutral, and increasing and expanding consultation with stakeholders and Indigenous communities, may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the company’s results. Other government and political factors that could adversely affect the company’s financial results include increases or changes in taxes or government royalty rates (including retroactive claims or punitive taxes on oil, gas and petrochemical operations) and changes in trade policies and agreements (including those potential tariffs and retaliatory actions discussed above in this Item 1A under “Economic conditions”). Changes in taxation policy could impact the company’s financial results and ability to return surplus cash to shareholders. Further, the adoption of regulations mandating efficiency standards, emission standards, procurement standards, or the use of alternative fuels or uncompetitive fuel components, could affect the company’s operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies. Governments are also introducing bans on certain technologies that could impact demand for products, such as the Government of Canada’s regulations to gradually reduce the proportion of permitted sales of new internal combustion engine cars and light trucks from 2026-2034 and ban such sales beginning in 2035. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the company’s products. Actions by policy makers, regulators or others may require changes in the company’s business or strategy that could result in reduced returns. Governments may establish regulations with respect to the control of the company’s production, such as the Government of Alberta's temporary mandatory production curtailment regulations that were in effect from 2019 through 2021, as discussed in the "Supply and demand" section above. Government intervention in free markets may introduce unintended consequences such as market volatility and uncertainty, misallocation of resources, and erosion of investor confidence. Environmental risks All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial and municipal laws and regulations, as well as international conventions (collectively, "environmental legislation"). Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported, and include those aimed at reducing consumption or addressing environmental concerns with certain end products. Changes to these requirements could adversely affect the company’s results by impacting commodity prices, increasing costs and reducing revenues. Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. This includes the requirement for specific approvals for many areas of interaction with the environment, such as land use, air quality, water use, biodiversity protection and waste, including mine tailings management. The failure to operate as anticipated and adhere to conditions, the delay or denial of approvals, and changes to conditions or regulations, could negatively impact the company’s ability to operate its projects and facilities (including but not limited to resulting in mandatory facility shutdowns or suspensions) and adversely affect the company’s results. Regulation of air, water and land The implementation of, and compliance with, policies and regulations related to air, water and land, such as Alberta’s Lower Athabasca Regional Plan and Wetland Policy applicable to the company’s oil sands assets, could restrict development in current and future areas of operation. Of note, there are currently a number of court actions against the government by Indigenous groups regarding the assessment of cumulative impacts and infringement on exercise of treaty rights. These cases may inform future government decisions and policies 24 regarding land use planning and resource development, and could impact the requirements or willingness to grant regulatory licenses or approvals. The company also depends on water obtained under licences for withdrawal, storage, reuse and discharge in both its Upstream and Downstream businesses, including future projects and expansions. Water use may be limited by regulatory requirements, seasonal fluctuations, regional drought, competing demands, environmental sensitivities, increasingly stringent water management standards, and changes to conditions or availability of licences, which may restrict and adversely affect the company’s operations. Additionally, a number of air quality regulations and frameworks are being developed or have been implemented at the federal and provincial levels, including sulphur dioxide limits for refineries in Ontario, and volatile organic compounds and benzene controls required for petroleum liquid storage tanks and loading operations at refining and terminal locations, and could impact existing and planned operations and projects through increased capital and operating expenses including retrofits to existing equipment, and could adversely impact the company’s operations and financial results. Regulation of wildlife Federal and provincial legislation aimed at protecting sensitive, threatened or endangered wildlife, such as woodland caribou and species of migratory birds, may also increase restoration and offset costs and impact the company’s projects. If it is determined that such wildlife and their habitat are not sufficiently protected, governments or other parties may take actions to limit the pace or ability to develop in areas of Imperial’s current and future projects. Regulation of oil sands The company’s mining operations are, among other regulations, subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. A failure or perceived failure to satisfy the requirements or if the company’s tailings management operations do not operate in the manner anticipated by the company or third parties could materially impact the company's ability to operate its assets. Further, the absence or evolving nature of policies and regulations for the timing and closure of tailings ponds, including the approved technologies and methods for closure (such as the use of end pit lakes and water-capped tailings), and dam safety and delicensing directives, regulations, guides and abandonment requirements, could have a material impact on conditions for approvals and ultimate mine closure costs. Additionally, successful management and closure requires the release of water to the environment, and although an Alberta water release policy and federal oil sands effluent regulations are being developed, the timing and impact of these regulations is uncertain and the absence of effective regulation could negatively impact the company’s operations and financial results. Environmental assessments In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments mandated under both federal and provincial regulations. The Government of Canada's environmental assessment framework under the Impact Assessment Act expands assessment considerations beyond the environment to include social, health, economic, and gender-based impacts and the impact on Canada’s climate change commitments (including a requirement under the Strategic Assessment for Climate Change to provide a credible plan for the project to deliver net-zero greenhouse gas emissions by 2050). It also includes a reliance on strategic and regional assessments and adjusted regulatory review timelines. In October 2023, the Supreme Court of Canada ruled that the new federal assessment scheme was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. The impact of this legislation is not fully apparent, but it may impact the cost, manner, duration and ability to advance large energy projects and project expansions. Compliance costs Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties, and liability for clean-up costs and damages. The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land, biodiversity and waste, such as mine tailings and the production or use of new or recycled plastics, as well as laws and regulations affecting production of the company's products, trading, carbon capture and storage, hydrogen, lower-emission fuels or lithium) or changes in advertising, insurance or other laws that penalize the company for past or current production of legal and/or permitted products and operations may increase the cost of operation or compliance or reduce or delay available business opportunities. Future changes in environmental legislation and the enforcement of regulations could occur and result in stricter standards and enforcement, larger fines, penalties and liability, and 25 increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations. Risk management There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if the company does not manage those risks effectively. Environmental hazards and risks, including severe weather, drought, forest fires and geological events, may impact the company’s operational performance. For example, the company's oil sands operations have in the past been particularly affected by extreme cold or wet weather and wildfires. The ability to insure risks is limited by the capacity of the applicable insurance markets, which may not be sufficient to cover the likely cost of a major adverse operating event. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts. See also "Safety, business controls and risk management" under "Operational and other factors" in this Item 1A below. Climate change, energy transition and greenhouse gas restrictions Greenhouse gas emissions reductions Driven by concern over the risks of climate change, the provinces and the Government of Canada have adopted or have revised regulatory frameworks to report on or reduce greenhouse gas emissions including emissions from the production and use of oil and gas and their products, as well as increase the use of or support for different emission-reduction technologies. These actions are being taken both independently by national and regional governments and within the framework of United Nations Conference of the Parties’ summits under which Canada has endorsed objectives to reduce the atmospheric concentration of carbon dioxide (CO2) over the coming decades, with an ambition ultimately to achieve "net zero". Net zero means that emissions of greenhouse gases from human activities would be balanced by actions that remove such gases from the atmosphere. Expectations for transition of the world’s energy system to lower-emission sources, and ultimately net zero, derive from hypothetical scenarios that reflect many assumptions about the future (including supportive policy and technology advancements) and reflect substantial uncertainties. The company’s actions with respect to the energy transition carry risks that the transition, including underlying technologies, government policies, and markets as discussed in more detail below, will not be available or develop at the pace or in the manner estimated by current net-zero scenarios. The success of Imperial's strategy for the energy transition will also depend on its ability to recognize key signposts of changes in the global energy system on a timely basis, and the corresponding ability to direct investment to the technologies and businesses, at the appropriate stage of development, to best capitalize on the company's competitive strengths. The company’s results may be impacted if the implementation pace and uncertainty of policy reduces the global competitiveness of the Canadian oil and gas industry and the company’s crude oil and refined products. Political government changes may create further policy uncertainty resulting in greater investment uncertainty and industry competitiveness concerns. Greenhouse gas restrictions Government actions intended to reduce greenhouse gas emissions include adoption of carbon emissions pricing, cap and trade regimes, carbon taxes, emissions limits, increased mileage and other efficiency standards, low carbon fuels standards, mandates for sales of electrical vehicles, restrictions on sales of gasoline-only vehicles, mandates for disclosure of plans to reduce emissions or reduce the use or production of certain products, mandates for use of specific fuels or technologies, and other incentives or mandates designed to support certain technologies for transitioning to lower-emission energy sources. International accords and underlying regional and national regulations covering climate change and greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Such laws and policies could make the company's products more expensive or less competitive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower greenhouse gas emission energy sources. Current, pending and potential greenhouse gas regulations or policies may also increase compliance costs (such as complying with increased or mandatory disclosure or due diligence requirements and government mandated energy transition plans), increase abatement costs including taxes and levies, increase abandonment and reclamation obligations and impact decommissioning timelines, lengthen project evaluation and implementation times, impact reserves evaluations and affect operations. Increased costs may not be recoverable in the marketplace, could negatively affect the company's returns and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products. In 2024, the Government of Canada updated its nationally determined contribution (NDC) under the Paris Agreement on climate change, to reduce greenhouse gas emissions economy-wide by 45 to 50 percent below 2005 levels by 2035, a substantial increase in ambition beyond its original and prior NDC. To implement these goals, the Government of Canada uses a number of policy tools including the Greenhouse Gas Pollution Pricing Act (GGPPA), which sets a federal backstop carbon price Canada-wide through a carbon levy applied to fossil fuels ($50 per tonne CO2 equivalent emissions starting in 2022 and increasing by $15 per tonne annually to 26 $170 per tonne in 2030), and an output-based pricing system for large industrial emitters. Under the GGPPA, provinces are required to either adopt the GGPPA, or obtain equivalency by adopting a price-based system (with a minimum of the federal carbon pricing) or a cap and trade system. Further, in 2021 the Government of Canada enacted legislation to formalize Canada’s target to achieve net-zero emissions by 2050 and establish interim emissions reductions targets at five year intervals. Under the Canadian Net-Zero Emissions Accountability Act, the Government of Canada is required to develop an emissions reduction plan for 2030 consistent with achieving net-zero emissions by 2050, and additional sector specific regulations may be developed to achieve this target. Under a November 2025 Memorandum of Understanding between the Government of Canada and the Government of Alberta, Canada and Alberta both confirmed they remain committed to achieving net zero greenhouse gas emissions by 2050. The Government of Alberta obtained federal equivalency for its Technology Innovation and Emissions Reduction Regulation (TIER) that came into effect in 2020 and applies to facilities with CO2 emissions in excess of 100,000 tonnes per year. TIER is designed to reduce emissions by putting a price on a nominal percentage of a facility’s emissions, which percentage increases annually in accordance with TIER (for oil sands mining and upgrading facilities, the percentage has increased from 20% for 2020 to 26% for 2026, and is to continue to increase to 38% by 2030 under current regulations). In a November 2025 Memorandum of Understanding, the Government of Canada and the Government of Alberta committed to work collaboratively to design and commit to globally competitive, long-term carbon effective prices, carbon levy recycling protocols, and sector-specific stringency factors for Alberta emitters in the oil and gas and electricity sectors through Alberta’s TIER system, which will ramp up to a minimum effective credit price of $130 per tonne, although the date for introduction of the effective price and the rate of price increases over time remain to be determined. In December 2025, the Government of Alberta introduced a compliance pathway under TIER allowing facilities to earn compliance credits though investments in approved emissions-reduction projects in Alberta. Further, the Alberta Oil Sands Emissions Limit Act sets a limit of 100 megatonnes of CO2 per year of emissions in the oil sands sector, but oil sands emissions remain below the limit and it is not yet possible to predict the impact of this act on the company’s future oil sands operations in Alberta. With respect to other provinces, Ontario obtained federal equivalency for its Emissions Performance System, which put a price on 8 percent of a facility’s emissions in 2022. The price increased by 2.4 percent in 2023 and 1.5 percent in 2024, and will increase by 1.5 percent per year thereafter. British Columbia has carbon pricing in place for all industrial emissions, with pricing that matches the federal carbon pricing schedule since 2022. Increases in carbon pricing could adversely impact the company’s operations and financial results unless the company can adapt its operations through technological innovation and investment in a cost-effective manner or meet compliance through offset credits or other mechanisms. There are also various renewable and low carbon fuel standards being developed or already applicable to the company’s products. In 2022, the Government of Canada finalized the Clean Fuel Regulations, which require the reduction in carbon intensity of liquid transportation fuels supplied in Canada starting in July 2023. The regulations require fuel suppliers to reduce the carbon intensity of gasoline and diesel by reducing the GHG emissions within the fossil fuel life cycle, blending in low carbon intensity renewables or fuel switching away from fossil fuels. Similarly, British Columbia introduced a Low Carbon Fuel Standard in 2013, which increased to a 10 percent carbon intensity reduction requirement in 2020. Beginning in 2023, the British Columbia government has further increased the carbon intensity reductions to a total of 30 percent by 2030 (compared to the 2010 baseline). Compliance can be achieved by either blending renewable fuels with low carbon intensity or by purchasing credits. In 2025, both Ontario and British Columbia introduced domestic (Canadian) renewable fuel content requirements into their provincial fuel regulations. The Government of Canada's Impact Assessment Ac t links environmental assessment approvals to climate change-related goals, and has also discussed a goal of establishing legally-binding policies for being carbon-neutral by 2050. Changes and policies related to this act could adversely impact the company’s ability to progress new oil sands projects. Uncertainty exists regarding federal overreach into provincial jurisdiction to implement such changes and policies. In October 2023, the Supreme Court of Canada ruled that the Impact Assessment Act was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. The impact of this legislation is not fully apparent. Governments may also impose restrictions on production of, or emissions from, oil and gas and electricity to the extent they view such measures as a viable approach for pursuing national and global energy and climate policies. For example, following the publication of a regulatory framework in December 2023, in November 2024, the Government of Canada released proposed regulations that will impose a cap on greenhouse gas emissions from upstream oil and gas activities by 2030, and in December 2024 the Government of Canada released final Clean Electricity Regulations that will require reductions in the carbon intensity of electricity provided to the grid between 2035 and 2050. Although the Government of Canada and Government of Alberta entered into a Memorandum of Understanding in November 2025, under which the Government of Canada committed to not implement the oil and gas emissions cap and to suspend the Clean Electricity Regulations in 27 Alberta pending a new carbon pricing agreement with Alberta to be negotiated in 2026, many details remain to be determined and uncertainty about the future of these policies remains. Concern over the risks of climate change may lead governments to make laws applicable to the energy industry progressively more stringent over time. Political actors, non-governmental organizations, and their agents also seek to collectively advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector. These actions include delaying or blocking needed infrastructure, utilizing shareholder governance mechanisms against companies or their shareholders or financial institutions in an effort to deter investments in oil and gas activities, and taking other actions intended to promote changes in business strategy for oil and gas companies. Technology and lower-emission solutions Achieving societal ambitions to reduce greenhouse gas emissions and ultimately achieve net-zero emissions will require new technologies and added infrastructure to reduce the cost and increase the scalability of solutions to reduce emissions. The company is continuing research and collaboration efforts to advance the development and deployment of carbon capture and storage, hydrogen, lower-emission fuels and lithium. The company’s future results and ability to succeed through the energy transition while helping meet Canada's emission-reduction goals and meet its own emission reduction goals will depend in part on the success of these research and collaboration efforts. It will also rely on the company’s ability to adapt and apply the strengths of its current business model to providing the energy products of the future in a cost-competitive manner. Policy and market development The scale of the world’s energy system means that, in addition to developments in technology discussed above, meeting society’s needs for energy and reducing emissions will require appropriate support from governments and private participants throughout the global economy. Ultimately, market solutions with sound business fundamentals are necessary to incentivize and sustain wide-spread solutions that drive emissions reductions. The company’s ability to develop and deploy carbon capture and storage, hydrogen, lower-emission fuels, lithium, and other new energy technologies at commercial scale will depend in part on the development of stable and supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained, or the development of these policies or markets in a manner that differs from the company’s expectations, could adversely impact or delay these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without a commensurate reduction in demand may have unpredictable adverse effects, including increased commodity price volatility; periods of significantly higher commodity prices and resulting inflationary pressures; and local or regional energy shortages. Such effects, in turn, may depress economic growth or lead to rapid or conflicting shifts in policy by different actors, with resulting adverse effects on the company’s business. In addition, the existence of supportive policies in any jurisdiction is not a guarantee that those policies will continue in the future. The company's operations and planned projects that have been developed with regard to current or anticipated policies, including but not limited to policies relating to carbon emission credits, may become uneconomic or otherwise adversely impacted if such policies change or are not adopted as anticipated. See also the discussion of "Supply and demand", "Government and political factors", and "Project management" in this Item 1A. Currency Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s reported earnings will be negatively affected. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency. Other business risks Reliance upon third-party suppliers, service providers and ExxonMobil global capability centres Imperial is reliant on a number of key chemicals, catalysts and third-party service providers, including input and output commodity transportation (pipelines, rail, trucking, marine) and utilities providing services, including electricity and water, to various company operations. The lack of availability, capacity or proximity, with respect to pipeline facilities and railcars, could negatively impact the company’s ability to produce at capacity levels. Transportation disruptions, including those caused by events unrelated to the company’s operations, could adversely affect the company’s price realizations, refining and other operations, and sales volumes. This includes outages of key third-party infrastructure, such as pipelines servicing the company’s oil sands assets or pipelines supplying feedstock to its refineries, which could impact the company’s ability to operate its assets or 28 limit the ability to deliver production and products to market. A third-party utilities outage could have an adverse impact on the company’s operations and ability to produce. The company also enters into contractual relationships with suppliers, partners and other counterparties to procure and sell goods and services, including with counterparties located outside of Canada. Furthermore, the company has agreements with affiliates of ExxonMobil to provide services to the company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems and benefit from global best practices and expertise, and in 2025 the company announced restructuring plans to centralize additional corporate and technical activities in ExxonMobil global business and technology centres, leveraging its relationship with ExxonMobil to realize substantial efficiency and effectiveness benefits from scale, integration and technology. The company’s operations, market position and financial condition may be adversely impacted if these counterparties fail to fulfil their obligations. For counterparties located outside of Canada, the risk of such failure may be enhanced and the company’s ability to mitigate against such failure may be reduced as a result of a lack of physical proximity, foreign government actions or other geopolitical factors. Litigation The company may also be adversely affected by the outcome of litigation, including class actions or arbitrations, and by government investigations or enforcement, in respect of greenhouse gas emissions, the promotion of the company’s products, or alleged non-compliance with applicable laws or regulations. Such proceedings are subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending such proceedings. Operating costs and inflation Current and future increases in operating costs such as energy, transportation and materials, including through shipping, supply chain disruptions and inflationary cost pressures, could adversely affect the company’s financial results if it is unable to control or offset these costs. In addition to direct potential impacts on the company's costs and revenues, market factors such as rates of inflation may indirectly impact results to the extent such factors reduce general rates of economic growth and therefore energy demand, as discussed under "Supply and demand". As inflationary pressures generally stabilized in Canada and other countries during 2025, many governments were able to lower interest rates over the period. Potential tariffs and retaliatory actions discussed above in this Item 1A under "Economic conditions" could reintroduce inflationary effects and may adversely impact the company through availability of financing, cost of debt, and exchange rate fluctuations. Additional information regarding the potential future impact of market factors on the company's businesses is included or incorporated by reference under "Item 7A Quantitative and qualitative disclosures about market risk" in this report. Operational and other factors In addition to external economic and political factors, Imperial’s future business results also depend on the company’s ability to successfully manage those factors that are at least in part within its control, including its capital allocation into existing and new businesses. The extent to which the company manages these factors will impact its performance relative to competition. For projects in which the company is not the operator such as Syncrude, Imperial depends on the management effectiveness of one or more co-venturers whom the company does not control. Project management The nature of the company’s Upstream, Downstream and Chemical businesses depend on complex, long-term, and capital intensive projects that require a high degree of project management expertise to maximize efficiency. This includes development, engineering, construction, commissioning and ongoing operational activities and expertise. The company’s results are affected by its ability to develop and operate projects and facilities as planned, and by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the company’s ability to obtain the necessary environmental and other regulatory approvals; changes in regulations; the ability to negotiate successfully with joint venturers, partners, governments, suppliers, customers and others; the ability to protect and enforce the company’s contractual and legal rights (including with joint venture partners); the ability to model and optimize reservoir performance and production reliability; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the ability to qualify for certain incentives available under supportive government policies for emerging markets and technologies; the impact of general economic, business and market conditions; and the company’s ability to prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project start-up or cause unscheduled downtime. 29 Operational efficiency An important component of Imperial’s competitive performance, especially given the commodity-based nature of the company’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technological integration and improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour. Research and development and technical change Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. Innovation and technology are important to maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business, the dynamic and rapidly evolving technological landscape, and the need for continuous efficiency improvement. The company’s research and development organizations must be able to adapt to a changing market, regulatory and policy environment, including developing or deploying technologies to help reduce greenhouse gas emissions intensity. To remain competitive, the company must also continuously adapt and capture the benefits of new and emerging technologies, such as artificial intelligence, including growing the company’s capabilities to utilize digital data technologies to gain new business insights and support business decisions and operations. There are risks associated with existing and new operations and projects that rely on new technology, including that the results of implementing the new technology may differ from simulated, piloted or expected results. The failure to develop and adopt new technology may have an adverse impact on the company’s operations, ability to meet regulatory requirements and operational commitments and targets (including those relating to environmental sustainability and reduction of greenhouse gas emissions), and financial results. The company’s Kearl site has converted all of its haul trucks to autonomous operation. The autonomous system is composed of perception systems, sensors and mechanical components on each truck, which feed information to a number of onboard computer systems. These onboard computer systems send real time information over a wireless network to a central server and database that displays real time information to central control room operators who manage the overall fleet’s operation. Computer automation systems are used to both maneuver the individual trucks and in an overarching truck assignment application which manages truck routing patterns. The use of the autonomous system helps the company to capture productivity improvements while also reducing costs and further enhancing operational safety. Failure of the autonomous system to operate as intended could result in material adverse impacts to production at the Kearl site and the company’s financial results, physical harm to people or the environment, damage or destruction of company assets, and negative reputational consequences. The company applies risk management, internal controls and controls management systems in respect of these risks relating to autonomous haul trucks, as described in “Safety, business controls and risk management” in this Item 1A below. See also “Cybersecurity” and “Reputation” in this Item 1A below. Safety, business controls and risk management The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil, chemical or produced water spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, including severe weather (such as extreme cold or wet weather events that have previously impacted the company's oil sands operations), drought, forest fires and geological events. The company’s results and ability to achieve its business objectives depend on effectively identifying, assessing, and mitigating these inherent risks, maintaining robust operational integrity, and reducing the potential for human error. To manage these risks, the company applies rigorous management systems, including an integrated operations integrity management system framework, structured processes for equipment inspection, surveillance, maintenance and replacement, and ongoing enhancements to critical safeguards. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. The company’s Upstream and Downstream operations may experience loss of production, slowdowns or shutdowns and increased costs due to the failure of interdependent systems, and substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended. 30 Preparedness The company’s operations have been and in the future may be disrupted by severe weather events, natural disasters, human error, cyberattacks, and similar events. The company's facilities are designed, engineered, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of uncertainties, including those associated with permafrost stability, temperature extremes, extreme rainfall events, earthquakes and other events. The company's consideration of changing weather conditions and inclusion of safety factors in design cover the engineering uncertainties that climate change and other events may potentially introduce. Imperial’s ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of its robust facility engineering, rigorous emergency preparedness and response, and business continuity planning. Cybersecurity The company is regularly subject to attempted cybersecurity disruptions from a variety of sources, including state-sponsored actors and actors potentially employing emerging technologies such as artificial intelligence technologies. The company’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions: non-technological measures such as threat information sharing with governmental and industry groups; annual internal training and awareness campaigns including routine testing of employee awareness via mock threats; and an emphasis on resiliency including business response and recovery. See "Item 1C. Cybersecurity" for information on the company's program for managing cybersecurity risks. The company has limited ability to influence third parties, including the company's partners, suppliers, service providers (including providers of cloud-based services for the company's data or applications) and customers, to implement strong cybersecurity controls, and the company is exposed to potential harm from cybersecurity events that may affect their operations. If the measures the company is taking to protect against cybersecurity disruptions prove to be insufficient or if the company’s proprietary data is otherwise not protected, the company, as well as its customers, employees or third parties, could be adversely affected. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third-party information being compromised; or otherwise disrupt the company’s business operations. The company could incur significant costs to remedy the effects of a major cybersecurity disruption, in addition to costs in connection with resulting regulatory actions, litigation or reputational harm. Competition As noted in Item 1 above, the Canadian energy and petrochemical industries are highly competitive. Technology and expertise provided by industry service companies may enhance the competitiveness of firms that may not have the internal resources and capabilities of Imperial. As described in more detail above, the company’s hydrocarbon-based energy products are also subject to growing and, in many cases, government-supported competition from alternative energy sources. In addition, as the company enters new markets in pursuit of lower-emission business opportunities, the company will need to compete effectively with established competitors in these markets, as well as with new market entrants seeking to capitalize on these opportunities, while successfully navigating changing market conditions or technologies. Reputation Imperial’s reputation is an important corporate asset. Factors that could have an impact on the company’s reputation include an operating incident or significant cybersecurity disruption; changes in consumer views concerning the company’s products; changes in consumer media preferences from traditional mainstream media to decentralized and personalized media; a perception by the public that the company is not being fully transparent in the sharing of information regarding its operations that is or may be relevant to community decision-making; actions taken by the company's business partners; a perception by investors or others that insufficient progress is being made with respect to the company’s ambition in the energy transition, or that pursuit of this ambition may result in allocation of capital to investments with reduced returns; divergent and evolving policy, legal and regulatory developments, societal views and investor pressures regarding the energy transition; and other adverse events such as those described in this Item 1A. Negative impacts on Imperial’s reputation could, in turn, make it more difficult for the company to compete successfully for new opportunities, obtain necessary regulatory approvals, obtain financing, and attract talent, or they could reduce customer or consumer demand for the company’s branded products. Imperial’s reputation may also be harmed by events which negatively affect the image of the industry as a whole, including public and investor perception of Alberta oil sands in relation to greenhouse gas emissions, Indigenous rights and environmental impact. 31 Reserves The company’s future production and cash flows from bitumen, synthetic crude oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserves. To maintain production and cash flows over the long term, the company must replace produced reserves, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and grow oil and natural gas reserves will be adversely impacted. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs. Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates, including that additional information obtained through seismic and drilling programs, reservoir analysis and production and operational history may result in revisions to reserves; the assumed effects of regulation or changes to regulation by government agencies, including royalty frameworks and environmental regulations (such as the regulation of greenhouse gas emissions, including accelerated timelines and emission reduction stringency to meet government goals, which could impose significant compliance costs on the company, require new technology, or impact the economic viability of certain projects); future commodity prices, where low commodity prices may affect reserves development; abandonment and reclamation costs, including reclamation and tailings requirements for mining operations; and operating costs. Actual production, revenues, taxes and royalties, development costs, abandonment and reclamation costs, and operating expenditures, with respect to reserves, will likely vary from such estimates, and such variances could be material. Item 1B. Unresolved staff comments None. Item 1C. Cybersecurity Imperial recognizes the importance of cybersecurity in achieving its business objectives, safeguarding its assets, and managing its daily operations. Accordingly, the company integrates cybersecurity risks into its overall enterprise risk management system . The board of directors oversees the company’s risk management approach and structure, which includes an annual review of the company’s cybersecurity program. The company’s cybersecurity program is managed by the Canada Information Technology (IT) Manager, with support from cross-functional teams led by IT and operational technology cybersecurity operations managers in the company and in Exxon Mobil Corporation and its affiliates (collectively, Cybersecurity Operations Managers). The Cybersecurity Operations Managers are responsible for the day-to-day management and effective functioning of the cybersecurity program, including the prevention, detection, investigation, and response to cybersecurity threats and incidents. The Cybersecurity Operations Managers collectively have many years of experience in cybersecurity operations. IT management provides updates to the company’s senior management throughout the year, covering, as appropriate, the company’s cybersecurity strategy, initiatives, key security metrics, penetration testing and benchmarking learnings, and business response plans, as well as the evolving cybersecurity threat landscape. The company’s cybersecurity program includes multi-layered technological capabilities designed to prevent and detect cybersecurity disruptions and leverages industry standard frameworks, including the National Institute of Standards and Technology Cybersecurity Framework. The cybersecurity program incorporates an incident response plan to engage cross-functionally and report cybersecurity incidents to appropriate levels of management based on potential impact. The company conducts annual cybersecurity awareness training and routinely tests cybersecurity awareness and business preparedness for response and recovery, which are developed based on real-world threats. In addition, IT management exchanges threat information with governmental and industry groups and proactively engages independent, third-party cybersecurity experts to test, evaluate, and recommend improvements on the effectiveness and resiliency of its cybersecurity program through penetration testing, breach assessments, regular cybersecurity incident drill testing, threat information sharing, and industry benchmarking. The company takes a risk-based approach with respect to its third-party 32 service providers, tailoring processes according to the nature and sensitivity of the data or systems accessed by such third-party service providers and performing additional risk screenings and procedures, as appropriate. As of the date of this report, the company has not identified any risks from known cybersecurity threats, including as a result of any prior cybersecurity incidents, that have materially affected, or are reasonably likely to materially affect, the company including its business strategy, results of operations, or financial condition. While the company believes its cybersecurity program to be appropriate for managing constantly evolving cybersecurity risks, no program can fully protect against all possible adverse events. For additional information on these risks and potential consequences if the measures the company is taking prove to be insufficient or if the company's proprietary data is otherwise not protected, see "Item 1A. Risk factors: Operational and other factors - Cybersecurity" in this report. Item 2. Properties Reference is made to Item 1 above. Item 3. Legal proceedings Refer to the relevant portions of note 9. "Litigation and other contingencies" of the "Financial section" of this report for additional information on legal proceedings. Imperial has elected to use a US $1 million threshold for disclosing environmental proceedings. Item 4. Mine safety disclosures Not applicable. 33 PART II Item 5. Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities Market information The company’s common shares are listed and trade on the Toronto Stock Exchange in Canada, and have unlisted trading privileges and trade on the NYSE American LLC in the United States. The symbol for the company’s common shares on these exchanges is IMO. As of February 11, 2026 there were 8,219 holders of record of common shares of the company. Information for security holders outside Canada Cash dividends paid to shareholders resident in the United States are, under the Canada-US income tax convention, subject to a Canadian non-resident withholding tax of 15 percent. The withholding tax is reduced to 5 percent on dividends paid to a corporation resident in the U.S. that owns at least 10 percent of the voting shares of the company. The rate of withholding applicable to other jurisdictions may vary. The company is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates, which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations. There is no Canadian tax on gains from selling shares owned by non-residents not carrying on business in Canada, as long as the shareholder does not, in any given 60-month period, own 25 percent or more of the shares of the company. Canada has approved several positions with respect to the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting ("MLI") , which may impact the taxability of dividends and capital gains in Canada if the shareholder’s country of residence has also approved these same positions of the MLI. The foregoing tax information is not intended to provide legal or tax advice, and shareholders are encouraged to consult a professional advisor with respect to all tax-related issues. During the fourth quarter, the company did not issue or sell any unregistered equity securities. Securities authorized for issuance under equity compensation plans Sections of the company’s management proxy circular are contained in the "Proxy information section", starting on page 113 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. Reference is made to the sections under the "Company executives and executive compensation": • Entitled "Performance graph" within the "Compensation discussion and analysis" section on page 168 of this report; and • Entitled "Equity compensation plan information", within the "Compensation discussion and analysis", on page 181 of this report. 34 Issuer purchases of equity securities Total number of shares purchased Average price paid per share (Canadian dollars) (a) Total number of shares purchased as part of publicly announced plans or programs Maximum number of shares that may yet be purchased under the plans or programs (b) October 2025 (October 1 - October 31) 5,307,343 124.40 5,307,343 7,960,969 November 2025 (November 1 - November 30) 4,824,857 134.95 4,824,857 3,136,112 December 2025 (December 1 - December 31) 3,136,112 127.32 3,136,112 — (a) Excludes 2 percent tax on repurchases of equity. (b) On June 23, 2025, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its then-existing share purchase program. The program enabled the company to purchase up to a maximum of 25,452,248 common shares during the period June 29, 2025 to June 28, 2026. This maximum included shares purchased under the normal course issuer bid from Exxon Mobil Corporation. As in the past, Exxon Mobil Corporation advised the company that it intended to participate to maintain its ownership percentage at approximately 69.6 percent. Imperial accelerated share purchases under the normal course issuer bid program, and the program completed on December 17, 2025 as a result of the company purchasing the maximum allowable number of shares under the program. The company will continue to evaluate the renewal of its normal course issuer bid share purchase program in June 2026 in the context of its overall capital activities. Purchase plans may be modified at any time without prior notice. Item 7. Management’s discussion and analysis of financial condition and results of operations Reference is made to the section entitled "Management’s discussion and analysis of financial condition and results of operations" in the "Financial section", starting on page 50 of this report. Item 7A. Quantitative and qualitative disclosures about market risk Reference is made to the section entitled "Market risks" in the "Financial section", starting on page 65 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report. Item 8. Financial statements and supplementary data Reference is made to the table of contents in the "Financial section" on page 44 of this report: • Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PCAOB ID: 271 ), Calgary, Canada dated February 18, 2026, beginning with the section entitled "Report of Independent Registered Public Accounting Firm" on page 72 and continuing through note 17 , " Other comprehensive income (loss) information " on page 108 ; • "Supplemental information on oil and gas exploration and production activities" (unaudited) starting on page 109 . Item 9. Changes in and disagreements with accountants on accounting and financial disclosure None. 35 Item 9A. Controls and procedures As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2025. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms. Reference is made to page 71 of this report for "Management’s report on internal control over financial reporting" and page 72 for the "Report of Independent Registered Public Accounting Firm" on the company’s internal control over financial reporting as of December 31, 2025. There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting. Item 9B. Other information During the three months ended December 31, 2025, none of the company's directors or officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K. Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections Not applicable. 36 PART III Item 10. Directors, executive officers and corporate governance Sections of the company’s management proxy circular are contained in the "Proxy information section", starting on page 113 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. The company currently has eight directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled "Nominees for director" on pages 114 to 118 of this report have been nominated for election at the annual meeting of shareholders to be held May 4, 2026. All of the nominees are now directors and have been since the dates indicated. D.W. Cornhill is currently a director and is not standing for re-election in 2026 as he has reached the company’s mandatory retirement age for directors. In February 2025, B.W. Corson, then chairman, president and chief executive officer, announced his intention to retire in 2025 and to not stand for re-election as director at the May 8, 2025 annual meeting of shareholders. Mr. Corson was succeeded as president by J.R. Whelan on April 1, 2025, and continued as chairman and chief executive officer until his retirement from those positions on May 8, 2025. In connection with B.W. Corson’s retirement, J.R. Whelan was appointed as president effective April 1, 2025, and he assumed the additional roles of chairman and chief executive officer on May 8, 2025. Reference is made to the section under "Nominees for director": • "Director nominee tables", on pages 114 to 118 of this report. Reference is made to the sections under "Corporate governance disclosure": • "Skills and experience of our board members and nominees", on page 123 of this report; • "Other public company directorships of our board members and nominees", on page 128 of this report; • The table entitled "Audit committee" under "Board and committee structure", on page 137 of this report; • "Ethical business conduct", starting on page 149 of this report; • "Restrictions on insider trading", starting on page 150 of this report; and • "Largest shareholders", on page 153 of this report. Reference is made to the sections under "Company executives and executive compensation": • "Named executive officers of the company" and "Other executive officers of the company", on pages 155 to 156 of this report. Item 11. Executive compensation Sections of the company’s management proxy circular are contained in the "Proxy information section", starting on page 113 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. Reference is made to the sections under "Corporate governance disclosure": • "Director compensation", on pages 141 to 148 of this report; and • "Share ownership guidelines of independent directors and chairman, president and chief executive officer", on page 148 of this report. Reference is made to the following sections under "Company executives and executive compensation": • "Letter to shareholders", on page 158 of this report; and • "Compensation discussion and analysis", on pages 157 to 185 of this report. 37 Item 12. Security ownership of certain beneficial owners and management and related stockholder matters The following table sets forth, to the extent known by the company or ascertainable from public filings, each person, or group of affiliated persons, who is known by the company to beneficially own greater than 5.0% of the company's outstanding common shares as of December 31, 2025. Any fractional shares have been rounded to the nearest whole share. Title of Class Name and Address of Beneficial Owner Aggregate and Nature of Beneficial Ownership Percent of Class Common Shares Exxon Mobil Corporation 22777 Springwoods Village Parkway Spring, Texas 77389 (a) 336,580,182 69.6% Common Shares FMR LLC 245 Summer Street Boston, Massachusetts 02210 (b) (c) 56,093,577 (c) 11.6% (c) (a) As of February 11, 2026, Exxon Mobil Corporation has sole voting and dispositive power with respect to 336,580,182 shares of the company's common shares. (b) The company is permitted to rely on the information set forth in the referenced filings and has no reason to believe that the information is incomplete or inaccurate or that the beneficial owner should have filed an amended report and did not. (c) Share ownership information is based solely on the Schedule 13G/A filed jointly by FMR LLC and Abigail P. Johnson with the SEC on February 5, 2026. As of December 31, 2025, (i) FMR LLC and Abigail P. Johnson each have beneficial ownership of the same 56,093,577 of the company's common shares, which shares are owned by FMR LLC, certain of its subsidiaries and affiliates, and other companies, (ii) FMR LLC has sole voting power with respect to 42,615,029 of those shares, and (iii) FMR LLC and Abigail P. Johnson each have sole dispositive power with respect to all such shares. Sections of the company’s management proxy circular are contained in the "Proxy information section", starting on page 113 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. Reference is made to the section under "Company executives and executive compensation" entitled "Equity compensation plan information", within the "Compensation discussion and analysis" section, on page 181 of this report. Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. The compensation of the directors and executive officers of the company for the year ended December 31, 2025 is described in the sections under "Nominees for director" starting on page 114 , "Director compensation" starting on page 141 and "Company executives and executive compensation" starting on page 155 . The following table shows the number of Imperial Oil Limited and Exxon Mobil Corporation common shares and restricted stock units beneficially owned by each named executive officer, and the incumbent directors and executive officers as a group, as of February 11, 2026. Imperial Oil Limited Exxon Mobil Corporation Named executive officer Common shares (a) Restricted stock units (b) Common shares (a) Restricted stock units (b) J.R. Whelan — 106,400 36,859 73,800 B.W. Corson (c) 10,000 423,400 135,402 44,000 D.E. Lyons — 126,400 11,565 — C.L. Gomez-Smith — 38,500 — 26,300 J.E. Burgess 109 64,550 — — I.R. Laing 6,520 55,450 — — Incumbent directors and executive officers as a group (16 people) 8,429 518,550 75,463 412,660 (a) No common shares are beneficially owned by reason of exercisable options. None of these individuals owns 0.01 percent of the outstanding shares of Imperial Oil Limited or Exxon Mobil Corporation. The directors and officers as a group own less than 0.01 percent of the outstanding shares of Imperial Oil Limited, and 0.01 percent of the outstanding shares of Exxon Mobil Corporation. Information not being within the knowledge of the company has been provided by the directors and the executive officers individually. (b) Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards. (c) B.W. Corson is a named executive officer in 2025 by virtue of acting as chief executive officer until May 8, 2025. Mr. Corson also acted as president until April 1, 2025 and chairman of the board until May 8, 2025. 38 Item 13. Certain relationships and related transactions, and director independence Sections of the company’s management proxy circular are contained in the "Proxy information section", starting on page 113 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. Reference is made to the section under "Corporate governance disclosure" entitled "Independence of our board members and nominees", on page 124 of this report. Reference is made to the section under "Corporate governance disclosure" entitled "Transactions with Exxon Mobil Corporation", on page 154 of this report. N.A. Hansen and T.T. Bryja are deemed under the relevant standards to be non-independent members of the board of directors and the committees on which they have served (in 2025, they were each members of the executive resources committee, safety and sustainability committee, nominations and corporate governance committee and finance committee; as of January 29, 2026, in connection with the board’s periodic review of its governance structures and practices, the executive resources committee and the nominations and corporate governance committee consist solely of independent directors, and as a result T.T. Bryja and N.A. Hansen ceased serving on those two committees). As employees of Exxon Mobil Corporation, N.A. Hansen and T.T. Bryja are each independent of the company’s management and are able to assist these committees by reflecting the perspective of the company’s shareholders. 39 Item 14. Principal accountant fees and services Auditor information The audit committee of the board of directors recommends that PricewaterhouseCoopers LLP (PwC) be reappointed as the auditor of the company until the close of the next annual meeting. PwC has been the auditor of the company for more than five years and is located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board and the Public Company Accounting Oversight Board (United States) (PCAOB). Auditor fees The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2025 and December 31, 2024 were as follows: thousands of Canadian dollars 2025 2024 Audit fees 2,550 2,635 Audit-related fees 95 90 Tax fees — — All other fees — — Total fees 2,645 2,725 Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2025. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services. The audit committee formally and annually evaluates the performance of the external auditor, recommends the external auditor to be appointed by the shareholders, recommends their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence. All of the services rendered by the auditor to the company were approved by the audit committee. Auditor independence The audit committee periodically discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta, the PCAOB and the rules of the SEC. The company has concluded that the auditor’s independence has been maintained. 40 PART IV Item 15. Exhibits, financial statement schedules Reference is made to the table of contents in the "Financial section" on page 44 of this report. The following exhibits, numbered in accordance with Item 601 of Regulation S-K, are filed as part of this report: (3) (i) Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit (3.1) to the company’s Current Report on Form 8-K filed on May 3, 2006 (File No. 0-12014)). (ii) Amended and Restated By-Law No. 1 of the company, dated September 17, 2024 (Incorporated herein by reference to Exhibit (3.1) to the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2024 (File No. 0-12014)). (4) (vi) Description of capital stock. (Incorporated herein by reference to Exhibit (4)(vi) of the company’s Annual Report on Form 10-K for the year ended December 31, 2019 (File No. 0-12014)). (10) (ii) (1) Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement dated June 25, 1984. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the company’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)). (2) Syncrude Bitumen Royalty Option Agreement, dated November 18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January 1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Current Report on Form 8-K filed on November 19, 2008 (File No. 0-12014)). (iii)(A) (1) Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)). (2) Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)). (3) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2016 and subsequent years, as amended effective October 26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Current Report on Form 8-K filed on October 31, 2016 (File No. 0-12014)). (4) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2020 and subsequent years, as amended effective November 24, 2020 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 2020 (File No. 0-12014)). (5) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2022 and subsequent years, as amended effective November 29, 2022 (Incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the company's Annual Report on Form 10-K for the year ended December 31, 2022 (File No. 0-12014)). (6) Amended Short Term Incentive Program, as amended effective December 1, 2023 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company's Annual Report on Form 10-K for the year ended December 31, 2023 (File No. 0-12014)). (19) Insider Trading and Blackout Guidelines (Incorporated herein by reference to Exhibit (19) of the company's Annual Report on Form 10-K for the year ended December 31, 2024 (File No. 0-12014)). 41 (21) Imperial Oil Resources Limited is incorporated in Alberta, Canada and Canada Imperial Oil Limited is incorporated in Canada, and both are wholly-owned subsidiaries of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2025. (31.1) Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a). (31.2) Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a). (32.1) Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. (32.2) Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350. (97) SEC Rule 10D-1 Policy for the Recovery of Erroneously Awarded Compensation effective December 1, 2023 (Incorporated herein by reference to Exhibit (97) of the company's Annual Report on Form 10-K for the year ended December 31, 2023 (File No. 0-12014)). (101) Interactive Data Files (formatted as Inline XBRL). (104) Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101). Copies of Exhibits may be acquired upon written request of any shareholder to the vice-president, investor relations, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs. Item 16. Form 10-K summary Not applicable. 42 SIGNATURES Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 18, 2026 by the undersigned, thereunto duly authorized. Imperial Oil Limited by _____ /s/ John R. Whelan (John R. Whelan) Chairman, president and chief executive officer Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 18, 2026 by the following persons on behalf of the registrant and in the capacities indicated. Signature Title /s/ John R. Whelan Chairman, president and chief executive officer and director (Principal executive officer) (John R. Whelan) /s/ Daniel E. Lyons Senior vice-president, finance and administration, and controller (Principal financial officer and principal accounting officer) (Daniel E. Lyons) /s/ Tanya T. Bryja Director (Tanya T. Bryja) /s/ David W. Cornhill Director (David W. Cornhill) /s/ Sharon R. Driscoll Director (Sharon R. Driscoll) /s/ John N. Floren Director (John N. Floren) /s/ Gary J. Goldberg Director (Gary J. Goldberg) /s/ Neil A. Hansen Director (Neil A. Hansen) /s/ Miranda C. Hubbs Director (Miranda C. Hubbs) 43 Financial section Table of contents Page Financial information (U.S. GAAP) 45 Frequently used terms 46 Management’s discussion and analysis of financial condition and results of operations 50 Overview 50 Business environment 51 Business results 54 Liquidity and capital resources 61 Capital and exploration expenditures 64 Market risks 65 Critical accounting estimates 67 Management’s report on internal control over financial reporting 71 Report of Independent Registered Public Accounting Firm 72 Consolidated statement of income (U.S. GAAP) 74 Consolidated statement of comprehensive income (U.S. GAAP) 75 Consolidated balance sheet (U.S. GAAP) 76 Consolidated statement of shareholders’ equity (U.S. GAAP) 77 Consolidated statement of cash flows (U.S. GAAP) 78 Notes to consolidated financial statements 79 1. Summary of significant accounting policies 79 2. Business segments 85 3. Income taxes 88 4. Employee retirement benefits 90 5. Other long-term obligations 95 6. Financial and derivative instruments 96 7. Share-based incentive compensation programs 98 8. Investment and other income 99 9. Litigation and other contingencies 99 10. Common shares 100 11. Miscellaneous financial information 101 12. Financing and additional notes and loans payable information 103 13. Leases 104 14. Long-term debt 106 15. Accounting for suspended exploratory well costs 106 16. Transactions with related parties 107 17. Other comprehensive income (loss) information 108 Supplemental information on oil and gas exploration and production activities (unaudited) 109 44 Financial information (U.S. GAAP) millions of Canadian dollars 2025 2024 2023 Revenues 46,918 51,359 50,702 Net income (loss): Upstream 2,121 3,262 2,512 Downstream 1,869 1,486 2,301 Chemical 82 171 164 Corporate and other (804) (129) (88) Net income (loss) 3,268 4,790 4,889 Cash and cash equivalents at year-end 1,142 979 864 Total assets at year-end 42,309 42,938 41,199 Long-term debt at year-end 3,978 3,992 4,011 Total debt at year-end 3,997 4,011 4,132 Other long-term obligations at year-end 4,959 3,870 3,851 Shareholders’ equity at year-end 22,254 23,473 22,222 Cash flow from operating activities 6,708 5,981 3,734 Per share information (Canadian dollars) Net income (loss) per common share - basic 6.50 9.05 8.51 Net income (loss) per common share - diluted 6.48 9.03 8.49 Dividends per common share - declared 2.88 2.40 1.94 45 Frequently used terms Listed below are definitions of several of the company’s key business and financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated. Certain measures included in this document are not prescribed by U.S. Generally Accepted Accounting Principles (GAAP). These measures constitute "non-GAAP financial measures" under Securities and Exchange Commission Regulation G and Item 10(e) of Regulation S-K, and "specified financial measures" under National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosure of the Canadian Securities Administrators. Reconciliation of these non-GAAP financial measures to the most comparable GAAP measure, and other information required by these regulations, have been provided. Non-GAAP financial measures and specified financial measures are not standardized financial measures under GAAP and do not have a standardized definition. As such, these measures may not be directly comparable to measures presented by other companies, and should not be considered a substitute for GAAP financial measures. Capital employed Capital employed is a non-GAAP financial measure that is a measurement of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity. The most directly comparable financial measure that is disclosed in the financial statements is total assets within the company’s Consolidated balance sheet. Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed. Reconciliation of capital employed millions of Canadian dollars 2025 2024 2023 From the Consolidated balance sheet Business uses: asset and liability perspective Total assets 42,309 42,938 41,199 Less: Total current liabilities excluding notes and loans payable (6,597) (6,988) (6,482) Total long-term liabilities excluding long-term debt (9,461) (8,466) (8,363) Add: Imperial’s share of equity company debt 13 25 21 Total capital employed 26,264 27,509 26,375 Total company sources: debt and equity perspective Notes and loans payable 19 19 121 Long-term debt 3,978 3,992 4,011 Shareholders’ equity 22,254 23,473 22,222 Add: Imperial’s share of equity company debt 13 25 21 Total capital employed 26,264 27,509 26,375 46 Return on average capital employed (ROCE) ROCE is a non-GAAP ratio. The company's total ROCE is net income excluding the after-tax cost of financing divided by total average capital employed (an average of the beginning and end-of-year amounts). Net income includes Imperial’s share of net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing. Capital employed is a non-GAAP financial measure and is disclosed and reconciled above. The company has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in a capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions. Components of return on average capital employed millions of Canadian dollars 2025 2024 2023 From the Consolidated statement of income Net income (loss) 3,268 4,790 4,889 Financing (after-tax) including Imperial’s share of equity companies 30 43 66 Net income (loss) excluding financing 3,298 4,833 4,955 Average capital employed 26,887 26,942 26,484 Return on average capital employed (percent) – corporate total 12.3 17.9 18.7 Cash flows from (used in) operating activities and asset sales Cash flows from operating activities and asset sales is a non-GAAP financial measure that is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the Consolidated statement of cash flows. This cash flow reflects the total sources of cash both from operating the company’s assets and from the divesting of assets. The most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company’s Consolidated statement of cash flows. The company employs a long-standing and regular disciplined review process to ensure that assets are contributing to the company’s strategic objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions. Reconciliation of cash flows from (used in) operating activities and asset sales millions of Canadian dollars 2025 2024 2023 From the Consolidated statement of cash flows Cash flows from (used in) operating activities 6,708 5,981 3,734 Proceeds from asset sales 101 25 86 Total cash flows from (used in) operating activities and asset sales 6,809 6,006 3,820 47 Operating costs Operating costs is a non-GAAP financial measure that is the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing and maintenance costs. It excludes the cost of raw materials, taxes and interest expense and is presented on a before-tax basis. The most directly comparable financial measure that is disclosed in the financial statements is total expenses within the company’s Consolidated statement of income. While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance. Reconciliation of operating costs millions of Canadian dollars 2025 2024 2023 From the Consolidated statement of income Total expenses 42,816 45,293 44,600 Less: Purchases of crude oil and products 29,807 33,184 32,399 Federal excise tax and fuel charge 1,715 2,535 2,402 Financing 12 41 69 Subtotal 31,534 35,760 34,870 Imperial's share of equity company expenses 67 80 76 Total operating costs 11,349 9,613 9,806 Components of operating costs millions of Canadian dollars 2025 2024 2023 From the Consolidated statement of income Production and manufacturing 7,269 6,599 6,879 Selling and general 1,386 945 857 Depreciation and depletion 2,579 1,983 1,907 Non-service pension and postretirement benefit 41 3 82 Exploration 7 3 5 Subtotal 11,282 9,533 9,730 Imperial's share of equity company expenses 67 80 76 Total operating costs 11,349 9,613 9,806 48 Net income (loss) excluding identified items Net income (loss) excluding identified items is a non-GAAP financial measure that is total net income (loss) excluding individually significant non-operational events with an absolute corporate total earnings impact of at least $100 million in a given quarter. The net income (loss) impact of an identified item for an individual segment may be less than $100 million when the item impacts several segments or several periods. The most directly comparable financial measure that is disclosed in the financial statements is "Net income (loss)" within the company’s Consolidated statement of income. Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational events from business results. The company believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management. Net income (loss) excluding identified items is not meant to be viewed in isolation or as a substitute for net income (loss) as prepared in accordance with U.S. GAAP. All identified items are presented on an after-tax basis. Reconciliation of net income (loss) excluding identified items millions of Canadian dollars 2025 2024 2023 From the Consolidated statement of income Net income (loss) (U.S. GAAP) 3,268 4,790 4,889 Less identified items included in Net income (loss) Impairments (570) — — Restructuring charges (249) — — Other (a) (212) — — Subtotal of identified items (1,031) — — Net income (loss) excluding identified items 4,299 4,790 4,889 (a) Contractual obligations associated with the Norman Wells end of field life acceleration. 49 Management’s discussion and analysis of financial condition and results of operations Overview The following discussion and analysis of the company’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the management of Imperial Oil Limited. The company’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium. Imperial, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new Canadian energy supplies. The company’s reportable segments are Upstream, Downstream, and Chemicals. The company’s integrated business model generally reduces the company’s risk from changes in commodity prices. While commodity prices depend on supply and demand and may be volatile on a short-term basis, the company’s investment decisions are grounded on fundamentals reflected in its long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities. The annual company plan process establishes the economic assumptions used for evaluating investments and sets operating and capital objectives. ExxonMobil's Global Outlook (the Outlook), developed annually, is the foundation for the plan assumptions . Price ranges for crude oil, including price differentials, refinery and chemical margins, volumes, operating costs including greenhouse gas emissions pricing, and foreign currency exchange rates are part of the company plan assumptions developed annually. Company plan volume projections are based on individual field production profiles, which are also updated at least annually. Major investment opportunities are evaluated over a range of potential market conditions. All major investments are reappraised to ensure the company learns from its investment decisions, and the development and execution of the project. Lessons learned are incorporated into future projects. The term "project" as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. 50 Business environment Long-term business outlook The "Long-term business outlook" is based on Exxon Mobil Corporation’s Global Outlook (the Outlook), which combined with the near-term pathways, is used to help inform the company’s long-term business strategies and investment plans. The company’s business planning is underpinned by a deep understanding of long-term market fundamentals. These fundamentals include supply and demand trends; the scale and variety of energy needs worldwide; capability, practicality and affordability of energy alternatives, including lower-carbon solutions; greenhouse gas emission-reduction technologies; and relevant government policies. The Outlook considers these fundamentals to form the basis for the company’s long-term business planning, investment decisions, and research programs. The Outlook reflects the company’s view of global energy demand and supply through 2050. It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development. The Outlook uses projections and scenarios from reputable third parties such as the International Energy Agency (IEA) and the Intergovernmental Panel on Climate Change (IPCC). Included in the range of these scenarios are: the IPCC Likely Below 2°C scenarios and three scenarios from the IEA; IEA Stated Policies Scenario (STEPS; 2025 World Energy Outlook (WEO)), which reflects a sector-by-sector assessment of current policy in place and those announced by governments; IEA Announced Pledges Scenario (APS; 2024 WEO), which reflects aspirational government targets met on time and in full; and IEA Net Zero Emissions by 2050 Scenario (NZE; 2025 WEO), which the IEA describes as highly ambitious and challenging, acknowledging that society is not currently on the IEA NZE pathway. No single transition pathway can be reasonably predicted, given the wide range of uncertainties. Key unknowns include yet-to-be-developed or changes in developed government policies, market conditions, and advances in technology that may influence the cost, pace, and potential availability of certain pathways. Scenarios that employ a full complement of technology options are likely to provide the most economically efficient pathways. Using the company's own experts and third-party sources, the company monitors a variety of signposts that may indicate a potential shift in the energy transition. For example, the regional pace of the transition could be influenced by the cost of new technologies compared to existing or alternative energy sources. By 2050, the world’s population is projected to be around 9.7 billion people, or nearly 2 billion more than in 2024. Coincident with this population increase, the Outlook projects worldwide economic growth to average approximately 2.5 percent per year, with economic output nearly doubling by 2050 compared to 2024. As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise. Even with significant efficiency gains, global energy demand is projected to rise by over 10 percent from 2024 to 2050. This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic Co-operation and Development (OECD)). By contrast, energy use in developed nations is expected to decline by more than 10 percent as efficiency improves. As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices, as well as lower-emission products, will continue to help significantly reduce energy consumption and CO 2 emissions per unit of economic output over time. Substantial efficiency gains are likely in all key aspects of the world’s economy through 2050, affecting energy requirements for power generation, transportation, industrial applications, and residential and commercial needs. Under the Outlook, global electricity demand is expected to increase more than 70 percent from 2024 to 2050, with developing countries likely to account for approximately 80 percent of the increase. Consistent with this projection, power generation is expected to remain the largest and fastest growing major segment of global primary energy demand, supported by a wide variety of energy sources. The share of coal-fired generation is expected to decline substantially to approximately 15 percent of the world’s electricity in 2050, versus approximately 35 percent in 2024, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2024 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is expected to more than double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal. Electricity from wind and solar is expected to increase nearly 400 percent, helping total renewables (including other sources, e.g., hydropower) to account for approximately 90 percent of the increase in electricity supplies through 2050. Total renewables are expected to 51 reach over 50 percent of global electricity supplies by 2050. Natural gas and nuclear are expected to be about 20 percent and 10 percent, respectively, of global electricity supplies by 2050. Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors, including the cost and availability of various energy supplies and policy developments. Energy for transportation - including cars, trucks, ships, trains, and airplanes - is expected to increase by nearly 25 percent from 2024 to 2050. Transportation energy demand is expected to account for over 50 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to have peaked this decade, and then decline to levels seen in the early-2010s by 2050, as the impact of better fuel economy and significant growth in electric cars, led by China, Europe, and the United States, work to offset growth in the worldwide car fleet of approximately 60 percent. By 2050, light-duty vehicles are expected to account for around 20 percent of global liquid fuels demand. During the same time period, nearly all the world’s commercial transportation fleets are expected to continue to run on liquid fuels, including biofuels, which are expected to be widely available and offer practical advantages in providing a large quantity of energy in small volumes. Almost half of the world’s energy use is dedicated to industrial activity. As the global middle class continues to grow, demand for durable products, appliances, and consumable goods will increase. Industry uses energy products both as a fuel and as a feedstock for chemicals, asphalt, lubricants, waxes, and other specialty products. The Outlook anticipates technology advances, as well as the increasing shift toward cleaner forms of energy, such as electricity and natural gas, with coal declining. Demand for oil will continue to grow as a feedstock for industry. As populations grow and prosperity rises, more energy will be needed to power homes, offices, schools, shopping centers, hospitals, etc. Combined residential and commercial energy demand is projected to rise by around 15 percent through 2050. Led by the growing economies of developing nations, average worldwide household electricity use is expected to rise more than 60 percent between 2024 and 2050. Liquid fuels provide the largest share of global energy supplies today reflecting broad-based availability, affordability, ease of transportation, and fitness as a practical solution to meet a wide variety of needs. By 2050, global demand for liquid fuels is projected to grow to nearly 115 million oil-equivalent barrels per day, an increase of about 10 percent from 2024. The non-OECD share of global liquid fuels demand is expected to increase to about 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by more than 25 percent. Much of the global liquid fuels demand today is met by crude production from conventional sources; these supplies will remain important, and significant development activity is expected to offset much of the natural declines from these fields. At the same time, a variety of supply sources - including tight oil, deepwater, oil sands, natural gas liquids, and biofuels - are expected to grow to help meet rising demand. Timely investments will remain critical to meeting global needs with reliable and affordable supplies. Natural gas is a lower-emission, versatile and practical fuel for a wide variety of applications. Global natural gas demand is expected to rise nearly 20 percent from 2024 to 2050, with approximately 70 percent of that increase coming from the Asia Pacific region. Significant growth in supplies of unconventional gas - the natural gas found in shale and other tight rock formations - will help meet these needs. In total, over 40 percent of the growth in natural gas supplies is expected to come from unconventional sources. At the same time, conventionally-produced natural gas is likely to remain the cornerstone of global supply, meeting around two-thirds of worldwide demand in 2050. Liquefied natural gas (LNG) trade will expand significantly, meeting about 75 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in the Asia Pacific region. The world’s energy mix is highly diverse and will remain so through 2050. Oil is expected to continue as the largest source of energy with its share remaining close to 30 percent in 2050. Coal and natural gas are the next largest sources of energy today, with the share of natural gas growing to more than 25 percent by 2050, while the share of coal falls to about half that of natural gas. Nuclear power is projected to grow, as many nations are likely to expand nuclear capacity to address rising electricity needs as well as energy security and environmental issues. Total renewable energy is expected to exceed 20 percent of global energy by 2050, with other renewables (e.g., biomass, hydropower, geothermal) contributing a combined share of more than 10 percent. Total energy supplied from wind and solar is expected to increase rapidly, growing nearly 350 percent from 2024 to 2050, when they are projected to be greater than 10 percent of the world energy mix. 52 Decarbonization of industrial activities will require a suite of lower-carbon technologies supported by stable policies. Lower-emission fuels, hydrogen-based fuels, and carbon capture and storage are three key lower-carbon solutions needed to support a lower-emission future, in addition to wind and solar. Along with electrification, lower-emission fuels are expected to play an important role in decarbonization of the transportation sector, particularly in hard-to-decarbonize areas, such as aviation. Low-carbon hydrogen will be a key enabler replacing traditional furnace fuel to decarbonize the industrial sector. Hydrogen and hydrogen-based fuels like ammonia are also expected to make inroads into commercial transportation as technology improves to lower its cost and policy develops to support the needed infrastructure development. Carbon capture and storage on its own, or in combination with hydrogen production, is among the few proven technologies that could enable CO 2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining, and petrochemicals. The Outlook projects that oil demand will remain above 100 million barrels per day to 2050. And even under the average of IPCC Likely Below 2°C scenarios, oil demand still comes to 65 million barrels per day in 2050 – about two thirds of current consumption. The Outlook shows oil production declines at a rate of about 15 percent per year. At that rate, in the absence of continued investment, by 2030 oil supplies would fall from 100 million barrels per day to less than 30 million barrels, more than 70 million barrels per day short of what is needed to meet demand. Limiting investment to only existing fields would slow the decline to about 4 percent, however, this would still be well below the oil demand in the average of IPCC Likely Below 2°C scenarios. To meet projected demand, the company anticipates that the world’s available oil and gas resource base will grow, not only from new discoveries, but also from increases in previously discovered fields. Technology will underpin these increases. The investments to develop and supply resources to meet global demand through 2050 will be significant and would be needed to meet even rapidly declining demand for oil and gas envisioned in aggressive decarbonization scenarios. International accords and underlying regional and national regulations covering greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. The company’s estimates of potential costs related to greenhouse gas emissions align with applicable provincial and federal regulations. Additionally, the company uses the Outlook as a foundation for estimating energy supply and demand requirements from various energy sources and uses, and the Outlook takes into account policies established to reduce energy related greenhouse gas emissions. The climate accord reached at the 2015 Conference of the Parties (COP 21) in Paris set many new goals, and many related policies are still emerging. The Outlook reflects an environment with increasingly stringent climate policies and seeks to identify potential impacts of these climate related government policies, which often target specific sectors. For purposes of the Outlook, a proxy cost on energy-related CO 2 emissions is assumed, based on regional considerations and relative levels of economic development, and by 2050, reaches up to $150 USD per metric ton for OECD nations and up to $100 USD per metric ton for non-OECD nations. As people and nations look for ways to reduce risks of global climate change, they will continue to need practical solutions that do not jeopardize the affordability or reliability of the energy they need. The company continues to monitor the updates to the Nationally Determined Contributions (NDCs) that are submitted by nations that are signatories to the Paris Agreement, as well as other policy developments in light of net-zero ambitions formulated by some nations, including Canada. The information provided in the Outlook includes ExxonMobil's internal estimates and projections based upon internal data and analyses, as well as publicly available information from external sources including the International Energy Agency. Progress reducing emissions Practical solutions to the world’s energy and climate challenges will benefit from market competition in addition to well-informed, well-designed and transparent policy approaches that carefully weigh costs and benefits. Such policies are likely to help manage the risks of climate change while also enabling societies to pursue other high priority goals around the world – including clean air and water, access to reliable and affordable energy, and economic progress for all people. The company encourages sound policy solutions that reduce climate-related risks across the economy at the lowest societal cost. All practical and economically viable energy sources will need to be pursued to continue meeting global energy demand, recognizing the scale and variety of worldwide energy needs, as well as the importance of expanding access to modern energy to promote better standards of living for billions of people. 53 As part of the company’s efforts to provide solutions that lower the greenhouse gas emissions intensity of its operations and provide lower life-cycle emissions products to customers, the company will continue to evaluate and deploy technologies such as oil sands technologies that use less steam, carbon capture and storage, energy efficiency projects, and low-emissions fuels. Decisions to deploy these technologies will be informed by market conditions and government policies. Recent business environment During 2025, the price of crude oil decreased relative to 2024, as increased OPEC+ output, record U.S. production, and global economic growth deceleration created a significant supply‑demand imbalance, while brief geopolitical price spikes faded quickly and failed to counter the broader downward pressure. In addition, the Canadian WTI/WCS spread narrowed as expanded TMX export capacity improved market access, while steady U.S. refinery demand and reduced western Canadian inventories in the second quarter, driven by turnarounds and wildfire‑related supply impacts, further tightened the differential. Industry refining margins improved in 2025, influenced by geopolitical factors and supply disruptions. The company closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. During 2025, the United States announced a variety of trade-related actions, including the imposition of tariffs on imports from Canada and several other countries. In response, Canada announced its own retaliatory tariffs. Despite the current uncertainty as to what effects these actions will ultimately have on Imperial, its suppliers and its customers, the company does not anticipate any material near-term financial impacts. Business results Consolidated millions of Canadian dollars 2025 2024 2023 Net income (loss) (U.S. GAAP) 3,268 4,790 4,889 Identified items 1 included in Net income (loss) Impairments (570) — — Restructuring charges (249) — — Other (a) (212) — — Subtotal of identified items 1 (1,031) — — Net income (loss) excluding identified items 1 4,299 4,790 4,889 (a) Contractual obligations associated with the Norman Wells end of field life acceleration. 2025 Net income in 2025 was $3,268 million, or $6.48 per share on a diluted basis, compared to $4,790 million, or $9.03 per share in 2024. Current year results include identified items 1 of: $320 million after-tax ($421 million before-tax) related to the Norman Wells end of field life acceleration; a $306 million after-tax ($406 million before-tax) non-cash impairment charge of the Calgary Imperial Campus; a $249 million after-tax ($330 million before-tax) restructuring charge; and a one-time $156 million after-tax ($206 million before-tax) charge associated with the optimization of materials and supplies inventory. 2024 Net income in 2024 was $4,790 million, or $9.03 per share on a diluted basis, compared to $4,889 million, or $8.49 per share in 2023. 1 Non-GAAP financial measure - see "Frequently used terms" section for definition and reconciliation. 54 Upstream Overview The company produces crude oil and natural gas for sale predominantly into North American markets. The company’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities. These strategies include improving asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness. These strategies are underpinned by a relentless focus on operations integrity, commitment to innovative technologies, disciplined approach to investing and cost management, development of employees and investment in the communities within which the company operates. The company has a significant oil and gas resource base and a large inventory of potential projects. The company’s current investment strategy is to invest for value and select volume growth, with focus on optimization within existing assets, cost reduction opportunities and productivity enhancements that aim to deliver robust returns at a wide range of prices. The company also continues to evaluate opportunities to support long-term growth. Although actual volumes typically vary from year to year, the focus is on value-add, long-term growth opportunities within the context of the factors described in "Item 1A. Risk factors". The company continually evaluates opportunities, including the pace of development for the Aspen project. Prices for most of the company's crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets. Additionally, the market price for WCS is typically lower than light and medium grades of oil, and price differentials between WCS and WTI can fluctuate. The company believes prices over the long term will be driven by market supply and demand, with the demand side largely being a function of general economic activity, alternative energy sources, levels of prosperity, technology advancements, consumer preference and government policies. On the supply side, prices may be significantly impacted by political events, logistics constraints, the actions of OPEC or OPEC+, governments, alternative energy sources, and other factors. To manage the risks associated with price, the company tests the resiliency of its annual plans and all major investments across a range of price scenarios. Key events Upstream assets demonstrated strong operational performance in 2025. The company continued to benefit from its actions implemented in prior years to manage the cost structure and improve the reliability of its assets, enabling the Upstream to capture significant value. Upstream full-year production averaged 438,000 gross oil-equivalent barrels per day. At Kearl, gross production was about 280,000 barrels per day (199,000 barrels Imperial’s share), which is a decrease of about 1,000 barrels per day (1,000 barrels Imperial's share) compared to 2024 . At Cold Lake, annual production averaged 151,000 barrels per day, which is an increase of about 3,000 barrels per day compared to 2024. At Syncrude, annual production averaged 79,000 barrels per day, which is an increase of about 4,000 barrels per day compared to 2024. As described in more detail in "Item 1A. Risk factors", environmental risks and climate related regulations could have negative impacts on the upstream business. 55 Results of operations 2025 Net income (loss) factor analysis millions of Canadian dollars Price – Average bitumen realizations decreased by $7.52 per barrel, primarily driven by lower marker prices partially offset by narrowing WTI/WCS spread and favourable diluent. Synthetic crude oil realizations decreased by $12.92 per barrel, primarily driven by lower WTI. Volume – Inventory impacts partially offset by higher production. Royalty – Lower royalties were primarily driven by lower commodity prices. Other – Primarily due to favourable foreign exchange impacts of about $190 million. Identified items 1 – $320 million after-tax ($421 million before-tax) related to the Norman Wells end of field life acceleration and a separate one-time $100 million after-tax ($131 million before-tax) charge associated with the Upstream portion of the optimization of materials and supplies inventory. 2024 Net income (loss) factor analysis millions of Canadian dollars Price – Average bitumen realizations increased by $7.11 per barrel, primarily driven by the narrowing WTI/WCS spread and lower diluent costs, partially offset by lower marker prices. Synthetic crude oil realizations decreased by $3.66 per barrel, primarily driven by a weaker Synthetic/WTI spread and lower WTI. Volume – Higher volumes were primarily driven by Grand Rapids production at Cold Lake, as well as improved mine fleet productivity and optimized turnaround at Kearl. Royalty – Higher royalties were primarily driven by higher volumes and prices. Other – Primarily due to lower operating expenses of about $210 million, mainly driven by lower energy prices, and favourable foreign exchange impacts of about $120 million, partially offset by lower electricity sales at Cold Lake due to lower prices. 1 Non-GAAP financial measure - see "Frequently used terms" section for definition and reconciliation. 56 Marker prices and average realizations Canadian dollars, unless otherwise noted 2025 2024 2023 West Texas Intermediate (US$ per barrel) 64.73 75.78 77.60 Western Canada Select (US$ per barrel) 53.76 61.04 58.97 WTI/WCS Spread (US$ per barrel) 10.97 14.74 18.63 Bitumen (per barrel) 67.01 74.53 67.42 Synthetic crude oil (per barrel) 88.99 101.91 105.57 Conventional crude oil (per barrel) 33.10 55.63 59.30 Natural gas (per thousand cubic feet) 1.76 0.69 2.58 Average foreign exchange rate (US$) 0.72 0.73 0.74 Crude oil - production and sales (a) thousands of barrels per day 2025 2024 2023 gross net gross net gross net Bitumen 350 310 348 299 326 283 Synthetic crude oil (b) 79 68 75 62 76 67 Conventional crude oil 4 4 5 5 5 5 Total crude oil production 433 382 428 366 407 355 Bitumen sales, including diluent (c) 475 471 442 Natural gas - production and production available for sale (a) millions of cubic feet per day 2025 2024 2023 gross net gross net gross net Production (d) (e) 29 29 30 30 33 32 Production available for sale (f) 8 9 11 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both. (b) The company’s synthetic crude oil production volumes were from the company’s share of production volumes in the Syncrude joint venture and include immaterial amounts of bitumen and other products exported to the operator's facilities using an existing interconnect pipeline. (c) Diluent is natural gas condensate or other light hydrocarbons added to crude bitumen to facilitate transportation. (d) Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected. (e) Net production is gross production less the mineral owners’ or governments’ share or both. Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure. (f) Includes sales of the company’s share of net production and excludes amounts used for internal consumption. 2024 Higher bitumen production was mainly attributable to Grands Rapids production at Cold Lake, as well as improved mine fleet productivity and optimized turnaround at Kearl. 57 Downstream Overview The company’s Downstream serves predominantly Canadian markets with refining, trading, logistics and marketing activities. The company's Downstream business strategies competitively position the company across a range of market conditions. These strategies include targeting industry-leading performance in reliability, safety and operations integrity, as well as maximizing value from advanced technologies, capitalizing on integration across the company’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers. The company owns and operates three refineries in Canada with aggregate distillation capacity of 434,000 barrels per day. Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel, fuel oil and asphalt). Crude oil and many products are widely traded with published prices, including those quoted on the New York Mercantile Exchange. Prices for these commodities are determined by the global and regional marketplaces and are influenced by many factors, including global and regional supply/demand balances, inventory levels, industry refinery operations, import/export balances, currency fluctuations, seasonal demand, weather and geopolitical considerations. While industry refining margins significantly impact earnings, strong operational performance, product mix optimization, and disciplined cost control are also critical to the company's strong financial performance. The company's integration across the value chain, from refining to marketing, enhances overall value across the fuels business. Key events Refining margins strengthened in 2025 driven by strong distillate demand and relatively low inventory levels due to global supply disruptions. The company continues to closely monitor industry and global economic conditions. In January 2023, the company fully funded the Strathcona renewable diesel project, the largest such facility in Canada, located at Strathcona refinery. The facility uses hydrogen, locally sourced and grown feedstocks and the company's proprietary catalyst to produce renewable diesel. Facility construction commenced in 2023 and was completed and commissioned with first on-spec renewable diesel produced in July 2025 bringing lower-emission fuels to market. As described in more detail in "Item 1A. Risk factors", proposed carbon policy and other climate related regulations, as well as continued biofuels mandates, could have negative impacts on the Downstream business. The company supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2025, there were about 2,600 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby the company supplies fuel to independent third parties. Results of operations 2025 Net income (loss) factor analysis millions of Canadian dollars Margins – Higher margins primarily reflect improved market conditions. Other – Primarily due to higher operating expenses of about $140 million driven by higher energy costs, additional maintenance in the company's eastern manufacturing hub of about $70 million, and unfavourable wholesale volume impacts of about $60 million, partially offset by lower turnaround impacts of about $100 million. 1 Non-GAAP financial measure - see "Frequently used terms" section for definition and reconciliation. 58 2024 Net income (loss) factor analysis millions of Canadian dollars Margins – Lower margins primarily reflect weaker market conditions. Other – Primarily due to lower turnaround impacts of about $120 million and favourable foreign exchange impacts of about $110 million, partially offset by lower volumes of about $60 million. Refinery utilization thousands of barrels per day (a) 2025 2024 2023 Total refinery throughput (b) 402 399 407 Rated capacity at December 31 (c) 434 434 433 Utilization of total refinery capacity (percent) 93 92 94 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units. (c) Refining capacity data is based on 100 percent of rated refinery process unit stream-day capacities to process inputs to atmospheric distillation units under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time. 2024 Lower refinery throughput in 2024 reflected the impact of planned turnaround activities at Nanticoke, Sarnia and Strathcona refineries. Petroleum product sales thousands of barrels per day (a) 2025 2024 2023 Gasolines 224 223 228 Heating, diesel and jet fuels 177 175 176 Lube oils and other products (b) 48 46 43 Heavy fuel oils 21 22 24 Net petroleum product sales 470 466 471 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. (b) In 2025 and 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast. 59 Chemical Overview North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers. Key events In 2025, the Chemicals business had strong operating performance, building on the improvements achieved following the completion of maintenance activities in prior years. The company maintains a competitive advantage through continued operational excellence, consistent product quality, investment and cost discipline, and integration of its chemical plant in Sarnia with the refinery. The company also benefits from its relationship with ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments. Results of operations 2025 Net income (loss) factor analysis millions of Canadian dollars Margins – Lower margins primarily reflect weaker industry polyethylene margins. 2024 Net income (loss) factor analysis millions of Canadian dollars Sales thousands of tonnes 2025 2024 2023 Total petrochemical sales (a) 683 684 820 (a) In 2025 and 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast. Corporate and other millions of Canadian dollars 2025 2024 2023 Net income (loss) (804) (129) (88) Current year results include identified items 1 of a $306 million after-tax ($406 million before-tax) non-cash impairment charge of the Calgary Imperial Campus and a $249 million after-tax ($330 million before-tax) restructuring charge; results also reflect higher incentive compensation as a result of the higher share price. 1 Non-GAAP financial measure - see "Frequently used terms" section for definition and reconciliation. 60 Liquidity and capital resources Sources and uses of cash The company issues long-term debt from time to time and maintains a commercial paper program. However, internally generated funds cover the majority of its financial requirements. Cash that may be temporarily surplus to the company’s immediate needs is carefully managed through counterparty quality and investment guidelines to ensure that it is secure and readily available to meet the company’s cash requirements and to optimize returns. Cash flows from operating activities are highly dependent on crude oil and natural gas prices, as well as petroleum and chemical product margins. In addition, to provide for cash flow in future periods, the company needs to continually find and develop new resources, and continue to develop and apply new technologies to existing fields in order to maintain or increase production. The company’s financial strength enables it to make large, long-term capital expenditures. The company’s portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks for the company and its cash flows. Further, due to its financial strength, debt capacity and portfolio of opportunities, the risk associated with delay of any single project would not have a significant impact on the company’s liquidity or ability to generate sufficient cash flows for its operations and fixed commitments. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based on an independent actuarial valuation completed at least once every three years depending on funding status. The most recent valuation of the company’s registered retirement plans was completed as at December 31, 2022. A valuation of the company's registered retirement plans as at December 31, 2025 is expected to be completed in 2026. The company contributed $148 million to the registered retirement plans in 2025. Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities. millions of Canadian dollars 2025 2024 2023 Cash flows from (used in): Operating activities 6,708 5,981 3,734 Investing activities (1,892) (1,825) (1,694) Financing activities (4,653) (4,041) (4,925) Increase (decrease) in cash and cash equivalents 163 115 (2,885) Cash and cash equivalents at end of year 1,142 979 864 Cash flows from operating activities 2025 Cash flows from operating activities primarily reflect favourable working capital impacts. 2024 Cash flows from operating activities primarily reflect lower unfavourable working capital impacts mainly related to an income tax catch-up payment of $2.1 billion in the prior year. Cash flows used in investing activities 2025 Cash flows used in investing activities primarily reflect higher additions to property, plant and equipment. 2024 Cash flows used in investing activities primarily reflect higher additions to property, plant and equipment. 61 Cash flows used in financing activities 2025 At the end of 2025, total debt outstanding was $3,997 million, compared with $4,011 million at the end of 2024. During the fourth quarter of 2025, the company extended the maturity dates of its two existing $250 million committed lines of credit to November 2026 and November 2027, respectively. The company has not drawn on any of its outstanding $500 million of available credit facilities. 2024 At the end of 2024, total debt outstanding was $4,011 million, compared with $4,132 million at the end of 2023. In June 2024, the company extended the maturity date of its existing long-term, variable-rate, Canadian dollar loan from ExxonMobil to June 30, 2035. All other terms and conditions remain unchanged. During the fourth quarter of 2024, the company extended the maturity dates of its two existing $250 million committed lines of credit to November 2025 and November 2026, respectively. The company has not drawn on any of its outstanding $500 million of available credit facilities. Share repurchases millions of Canadian dollars, unless noted 2025 2024 2023 Share repurchases (a) 3,180 2,681 3,800 Number of shares purchased (millions) (a) 25.5 26.8 48.3 (a) Share repurchases were made under the company's normal course issuer bid program for the periods disclosed. A Substantial issuer bid was undertaken and commenced on November 3, 2023 and expired on December 8, 2023. Includes shares purchased from Exxon Mobil Corporation under and in connection with the normal course issuer bid and by way of a proportionate tender under the company's substantial issuer bids. 2025 On June 23, 2025, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its then-existing share purchase program. The program enabled the company to purchase up to a maximum of 25,452,248 common shares during the period June 29, 2025 to June 28, 2026. The program completed on December 17, 2025 as a result of the company purchasing the maximum allowable number of shares under the program. 2024 On June 24, 2024, the company announced that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its then-existing share purchase program. The program enabled the company to purchase up to a maximum of 26,791,840 common shares during the period June 29, 2024 to June 28, 2025. The program completed on December 19, 2024 as a result of the company purchasing the maximum allowable number of shares under the program. 62 Dividends millions of Canadian dollars, unless noted 2025 2024 2023 Dividends paid 1,401 1,238 1,103 Per share dividend paid (dollars) 2.76 2.30 1.88 Financial strength The table below shows the company’s consolidated debt-to-capital ratio at December 31. The data demonstrates the company’s creditworthiness: percent 2025 2024 2023 Debt to capital (a) 15 15 16 (a) Debt, defined as the sum of “Notes and loans payable” and “Long-term debt” on the Consolidated balance sheet, divided by capital, defined as the sum of debt and “Total shareholders’ equity” on the Consolidated balance sheet. Debt-related interest incurred in 2025, before capitalization of interest, was $131 million, compared with $192 million in 2024. The weighted-average interest rate on the company’s debt was 3.1 percent in 2025, compared with 4.7 percent in 2024. The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets across a range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value. Contractual obligations The company has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs. These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, other long-term obligations, and firm capital commitments. Further information on this topic can be found in notes 4, 5, 11, 13, 14 to the consolidated financial statements. Other long-term purchase agreements are commitments that are non-cancellable, or cancellable only under certain conditions, as well as long-term commitments, other than unconditional purchase obligations. They include primarily raw material supply, transportation services agreements, and community benefits agreements. The total obligation at year-end 2025 was $14.5 billion, of which $1.5 billion is due in 2026, and $1.5 billion is due in 2027. Litigation and other contingencies As discuss ed in note 9 to t he consolidated financial statements, a variety of claims have been made against Imperial and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole. Additionally, as discussed in note 9, Imperial was contingently liable at December 31, 2025, for guarantees relating to performance under contracts. These guarantees do not have a material effect on the company’s operations, financial condition, or financial statements taken as a whole. There are no events or uncertainties beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition. 63 Capital and exploration expenditures Capital and exploration expenditures represent the combined total of additions at cost to property, plant and equipment, additions to finance leases, additional investments and acquisitions; exploration expenses on a before-tax basis from the Consolidated statement of income; and the company’s share of similar costs for equity companies. Capital and exploration expenditures exclude the purchase of carbon emission credits. While the company’s management is responsible for all investments and elements of net income, particular focus is placed on managing the controllable aspects of this group of expenditures. millions of Canadian dollars 2025 2024 Upstream (a) 1,480 1,078 Downstream 412 572 Chemical 11 30 Corporate and other 124 187 Total 2,027 1,867 (a) Exploration expenses included. For the Upstream segment, capital and exploration expenditures were primarily related to sustaining activity in support of the company’s oil sands and in-situ assets. For the Downstream segment, capital expenditures were primarily for completing the Strathcona renewable diesel facility as well as other refinery and distribution projects to improve environmental performance, reliability, and energy efficiency. Total capital and exploration expenditures are expected to range between $2.0 billion to $2.2 billion in 2026. Expected capital and exploration expenditures for 2026 includes firm capital commitments of $585 million for the construction and purchase of fixed assets and other permanent investments. An additional $89 million of firm capital commitments have been made for years 2027 and beyond. Actual spending could vary depending on the progress of individual projects. 64 Market risks Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces. The impacts of these price fluctuations on earnings from Upstream, Downstream and Chemical operations have varied. The company’s earnings are influenced by North American crude oil benchmark prices as well as changes in the differentials between these benchmarks and western Canadian prices for light and heavy crude oil. The company’s integrated business model reduces its risk from changes in commodity prices. For instance, when differentials between North American crude benchmarks and western Canadian prices widen, the company is able to mitigate the impact of widening differentials on the Upstream through integration with Downstream investments in refineries and pipeline commitments. In the competitive downstream and chemical environments, earnings are primarily determined by margin capture rather than absolute price levels on products sold. Refining margins are a function of the difference between what a refiner pays for its raw materials (primarily crude oil) and the market prices for the range of products produced. These prices, in turn, depend on global and regional supply/demand balances, inventory levels, refinery operations, import/export balances and weather. Industry crude oil commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S. dollars. The majority of the company’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the Canadian/U.S. dollar exchange rate fluctuates, the company’s earnings will be affected. The company is exposed to changes in interest rates, primarily on its debt which carries floating interest rates. The impact of a quarter percent change in interest rates affecting the company’s debt would not be material to earnings or cash flow. The company has access to significant sources of long-term and short-term liquidity. Internally generated funds are expected to cover the majority of financial requirements, supplemented by long-term and short-term debt as needed. The company’s potential exposure to commodity price and margin, and Canadian/U.S. dollar exchange rate fluctuations, is summarized in the earnings sensitivities table, which shows the estimated annual effect, under current conditions, on the company’s after-tax net income. For any given period, the extent of actual benefit or detriment will be dependent on the price movements of individual types of crude oil and products, production and sales volumes, transportation capacity, costs and egress methods, and other factors. Accordingly, changes in benchmark prices for crude oil and crude oil differentials, and other factors listed in the table following, only provide broad indicators of changes in the earnings experienced in any particular period. Earnings sensitivities (a) millions of Canadian dollars, after-tax One dollar (U.S.) per barrel increase (decrease) in crude oil prices + (-) 115 One dollar (U.S.) per barrel increase (decrease) in refining 2-1-1 margins (b) + (-) 145 One cent decrease (increase) in the value of the Canadian dollar versus the U.S. dollar + (-) 130 (a) Each sensitivity calculation shows the annual impact on net income resulting from a change in one factor, after tax and royalties, and holding all other factors constant. These sensitivities have been updated to reflect current market conditions. They may not apply proportionately to larger fluctuations. (b) The 2-1-1 crack spread is an indicator of the refining margin generated by converting two barrels of crude oil into one barrel of gasoline and one barrel of diesel. The demand for crude oil, petroleum products and petrochemical products are generally linked closely with economic growth. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s financial results. Although price levels of crude oil may rise and fall significantly over the short to medium-term due to global economic conditions, political events, decisions by OPEC or OPEC+, governments and other factors, industry economics over the long-term will continue to be driven by market supply and demand. The company evaluates investments over a range of prices, including estimated greenhouse gas emission costs. The global energy markets can give rise to extended periods in which market conditions are adverse to one or more of the company’s businesses. Such conditions, along with the capital-intensive nature of the industry and 65 very long lead times associated with many of the company’s projects, underscore the importance of maintaining a strong financial position. Management views the company’s financial strength as a competitive advantage. In general, segment results are not dependent on the ability to sell and/or purchase products to/from other segments. Where such intersegment sales take place, they are the result of efficiencies and competitive advantages from integrated business segments and refinery and chemical complexes. The company’s intersegment sales include crude oil produced by the Upstream and sold to the Downstream, as well as sales between refineries and the chemical plant related to raw materials, feedstocks and finished products. All intersegment sales are at market based prices. Refer to note 2 for additional information on intersegment revenue. The company has an active asset management program in which nonstrategic assets are considered for divestment. The asset management program includes a disciplined, regular review to ensure that assets are contributing to the company’s strategic objectives. Risk management The company’s size, strong capital structure and the complementary nature of its business segments reduces the company’s enterprise-wide risk from changes in commodity prices and currency exchange rates. In addition, the company may use commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. The company’s derivatives are not accounted for under hedge accounting. Credit risk associated with the company’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. No material market or credit risks to the company’s financial position, results of operations or liquidity exist as a result of the derivatives described in n ote 6 . The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. 66 Critical accounting estimates The company’s financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP). U.S. GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. The company’s accounting and financial reporting fairly reflect its integrated business model involving exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium. The company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The company’s significant accounting policies are summarized in note 1 to th e consolidated financial statements. Oil and natural gas reserves Evaluations of oil and natural gas reserves are important to the effective management of upstream assets. They are an integral part of investment decisions about oil and gas properties such as whether development should proceed. The estimation of proved reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of reservoir and well performance, development and production costs, and other factors. The estimation of proved reserves is controlled by the company through long-standing approval guidelines. Reserves changes are made within a well-established, disciplined process driven by qualified geoscience and engineering professionals, assisted by the reserves management group which has significant technical experience, culminating in reviews with and approval by senior management and the company’s board of directors. Notably, the company does not use specific quantitative reserves targets to determine compensation. Key features of the reserves estimation process are covered in "Disclosure of reserves" in Item 1. Oil and natural gas reserves include both proved and unproved reserves. • Proved oil and natural gas reserves are determined in accordance with U.S. Securities and Exchange Commission (SEC) requirements. Proved reserves are those quantities of oil and natural gas which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible under existing economic and operating conditions and government regulations. Proved reserves are determined using the average of first-day-of-the-month oil and natural gas prices during the reporting year. Proved reserves can be further subdivided into developed and undeveloped reserves. Proved developed reserves include amounts which are expected to be recovered through existing wells, facilities, or mining activities with existing equipment and operating methods. Proved undeveloped reserves include amounts expected to be recovered from new wells, existing wells, facilities, or mining activities, where a relatively major capital expenditure is required. Proved undeveloped reserves are recognized when a development plan has been adopted indicating that the reserves are scheduled to be developed within five years, unless specific circumstances support a longer period of time. The company is reasonably certain that proved reserves will be produced. However, the timing and amount recovered can be affected by a number of factors, including completion and optimization of development projects, reservoir performance, and facility processing capacity. • Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves. Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered. Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-day-of-the-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment and facility capacity. 67 In 2023, upward revisions of proved bitumen of 0.1 billion barrels were driven by lower royalty obligations associated with lower pricing and minor technical revisions at Cold Lake and Kearl. A slight increase in proved reserves for synthetic crude oil is associated with lower royalty obligations associated with pricing. Conventional proved liquids reserves decreased to zero under existing pricing and operating conditions. In 2024, upward revisions of proved bitumen of 0.1 billion barrels were primarily driven by updates to the Kearl geological model, Kearl well density, and Cold Lake infill drilling, partially offset by reductions associated with higher royalty obligations and Kearl pit limit updates. A decrease to synthetic oil proved reserves is associated with regulatory approval for ore sterilization at Syncrude. In 2025, upward revisions of proved bitumen were primarily driven by steam scheduling, development drilling, Liquid Addition to Steam for Enhanced Recovery (LASER) process at Cold Lake and lower royalty obligations associated with pricing for both Kearl and Cold Lake. An increase in proved reserves for synthetic crude oil is associated with lower royalty obligation. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to the company. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the SEC definition. Unit-of-production depreciation Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. Depreciation is calculated by taking the ratio of asset cost to total proved reserves or proved developed reserves applied to actual production. The volumes produced and asset cost are known, while proved reserves are based on estimates that are subject to some variability. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the company uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. Impact of oil and gas reserves and prices and margins on testing for impairment The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932 and relies, in part, on the company’s planning and budgeting cycle. Because the lifespans of the vast majority of the company’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development and production costs. Significant reductions in the company’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360, can be indicators of potential impairment as well. In general, the company does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources and levels of prosperity. During the lifespan of its major 68 assets, the company expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices and margins. Global Outlook and cash flow assessment The annual planning and budgeting process, known as the company plan, is the mechanism by which resources (capital, operating expenses and people) are allocated across the company. The foundation for the energy supply and demand assumptions supporting the company plan begins with Exxon Mobil Corporation's Global Outlook (the Outlook), which contains demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and consequently, the company’s business plans will be updated accordingly. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the company plan, which is reviewed and approved by the board of directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, including greenhouse gas emissions prices, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. The greenhouse gas emission prices reflect existing or anticipated policy actions of applicable provincial and federal governments. While third-party scenarios may be used to test the resiliency of company’s businesses or strategies, they are not used as a basis for developing future cash flows for impairment assessments. Fair value of impaired assets An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based on the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. Other impairment estimates Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Judgment is required to determine if assets are held for sale, and to determine the fair value less cost to sell. 69 Investments accounted for by the equity method are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable. Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region. If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value. In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment. Recent impairments In 2025, the company signed an agreement to sell the Calgary Imperial Campus which resulted in a non-cash impairment charge of $306 million after-tax in the Corporate and other segment. Factors which could put further assets at risk of impairment in the future include reductions in the company’s price or margin outlooks, changes in the allocation of capital or development plans, reduced long-term demand for the company’s products and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases or margins. However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the company’s long-lived assets. Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements. Pension benefits The company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 4.4 percent used in 2025 compares to actual returns of 4.5 percent and 5.6 percent achieved over the last 10- and 20-year periods respectively, ending December 31, 2025. If different assumptions are used, the obligation and expense could increase or decrease as a result. As an indication of the company’s potential exposure to changes in the critical assumptions, such as the expected rate of return on plan assets, a reduction of 1 percent in the long-term rate of return on plan assets would increase the annual pension expense by approximately $85 million before tax. At the company, differences between actual returns on plan assets and the long-term expected returns are not recorded in pension expense in the year the differences occur. Such differences are deferred, along with other actuarial gains and losses, and are amortized into pension expense over the expected average remaining service life of employees. Employee benefits expense represented about 1 percent of total expenses in 2025. Asset retirement obligations The company is subject to retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. Note 5 to the consolidated financial statements provides a three-year continuity table detailing the changes in asset retirement obligations. Tax contingencies The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. The benefits of uncertain tax positions that the company has taken or expects to take in its income tax returns are recognized in the financial statements if management concludes that it is more likely than not that the position will be sustained with the tax authorities. For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized. Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict. The company’s unrecognized tax benefits and a description of open tax years are summarized in note 3 to the consolidated financial statements. 70 Management’s report on internal control over financial reporting Management, including the company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2025. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2025, as stated in their report which is included herein. /s/ John R. Whelan John R. Whelan Chairman, president and chief executive officer (Principal executive officer) /s/ Daniel E. Lyons Daniel E. Lyons Senior vice-president, finance and administration, and controller (Principal accounting officer and principal financial officer) February 18, 2026 71 Report of Independent Registered Public Accounting Firm To the Board of Directors and Shareholders of Imperial Oil Limited Opinions on the Financial Statements and Internal Control over Financial Reporting We have audited the accompanying consolidated balance sheets of Imperial Oil Limited and its subsidiaries (the Company) as of December 31, 2025 and 2024, and the related consolidated statements of income, of comprehensive income, of shareholders’ equity and of cash flows for each of the three years in the period ended December 31, 2025, including the related notes (collectively referred to as the consolidated financial statements). We also have audited the Company’s internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control ‒ Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the Company as of December 31, 2025 and 2024, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2025 in conformity with accounting principles generally accepted in the United States of America. Also in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2025, based on criteria established in Internal Control ‒ Integrated Framework (2013) issued by the COSO. Basis for Opinions The Company’s management is responsible for these consolidated financial statements, 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 Report on Internal Control over Financial Reporting. Our responsibility is to express opinions on the Company’s consolidated financial statements and on the Company’s internal control over financial reporting based on our audits. We are a public accounting firm registered with the Public Company Accounting Oversight Board (United States) (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 audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audits to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud, and whether effective internal control over financial reporting was maintained in all material respects. Our audits of the consolidated financial statements included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. 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 audits also included performing such other procedures as we considered necessary in the circumstances. We believe that our audits provide a reasonable basis for our opinions. 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 (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) 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 (iii) 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. 72 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. Critical Audit Matters The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates. The Impact of Proved Developed Oil and Natural Gas Reserve Volumes on Upstream Property, Plant and Equipment, Net As described in Notes 1 and 2 to the consolidated financial statements, the Company’s consolidated upstream property, plant and equipment (PP&E), net balance was $26,037 million as of December 31, 2025, and the related depreciation and depletion expense for the year ended December 31, 2025 was $1,906 million. Management uses the successful efforts method to account for its exploration and production activities. Costs incurred to purchase, lease or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. As disclosed by management, proved oil and natural gas reserve volumes are used as the basis to calculate unit-of-production depreciation rates for most upstream assets. The estimation of proved oil and natural gas reserve volumes is an ongoing process based on technical evaluations, commercial and market assessments, detailed analysis of reservoir and well performance, development and production costs, and other factors. As further disclosed by management, reserves changes are made within a well-established, disciplined process driven by qualified geoscience and engineering professionals, assisted by the reserves management group (together, management’s specialists). The principal considerations for our determination that performing procedures relating to the impact of proved developed oil and natural gas reserve volumes on upstream PP&E, net is a critical audit matter are (i) the significant judgment by management, including the use of management’s specialists, when developing the estimates of proved developed oil and natural gas reserve volumes, and (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved developed oil and natural gas reserve volumes. Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements. These procedures included testing the effectiveness of controls relating to management’s estimates of proved developed oil and natural gas reserve volumes. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of the proved developed oil and natural gas reserve volumes. As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with management’s specialists was assessed. The procedures performed, also included i) evaluating the methods and assumptions used by management’s specialists, ii) testing the completeness and accuracy of the data used by management’s specialists related to historical production volumes, and iii) evaluating management’s specialists’ findings related to future production volumes by comparing the future production volumes to relevant historical and current period production volumes, as applicable. /s/PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Canada February 18, 2026 We have served as the Company’s auditor since 1934. 73 Consolidated statement of income (U.S. GAAP) millions of Canadian dollars For the years ended December 31 2025 2024 2023 Revenues and other income Revenues (a) 46,918 51,359 50,702 Investment and other income (note 8) 160 173 267 Total revenues and other income 47,078 51,532 50,969 Expenses Exploration (note 15) 7 3 5 Purchases of crude oil and products (b) 29,807 33,184 32,399 Production and manufacturing (c) 7,269 6,599 6,879 Selling and general (c) (note 11) 1,386 945 857 Federal excise tax and fuel charge 1,715 2,535 2,402 Depreciation and depletion (includes impairments) (note 11) 2,579 1,983 1,907 Non-service pension and postretirement benefit 41 3 82 Financing (d) (note 12) 12 41 69 Total expenses 42,816 45,293 44,600 Income (loss) before income taxes 4,262 6,239 6,369 Income taxes (note 3) 994 1,449 1,480 Net income (loss) 3,268 4,790 4,889 Per share information (Canadian dollars) Net income (loss) per common share - basic (note 10) 6.50 9.05 8.51 Net income (loss) per common share - diluted (note 10) 6.48 9.03 8.49 (a) Amounts from related parties included in revenues (note 16). 13,534 14,654 16,166 (b) Amounts to related parties included in purchases of crude oil and products (note 16). 5,369 6,651 6,747 (c) Amounts to related parties included in production and manufacturing, and selling and general expenses (note 16). 568 541 473 (d) Amounts to related parties included in financing (note 16). 97 161 169 The information in the notes to consolidated financial statements is an integral part of these statements. 74 Consolidated statement of comprehensive income (U.S. GAAP) millions of Canadian dollars For the years ended December 31 2025 2024 2023 Net income (loss) 3,268 4,790 4,889 Other comprehensive income (loss), net of income taxes Postretirement benefits liability adjustment (excluding amortization) 181 412 ( 206 ) Amortization of postretirement benefits liability adjustment included in net benefit costs 19 51 41 Total other comprehensive income (loss) 200 463 ( 165 ) Comprehensive income (loss) 3,468 5,253 4,724 The information in the notes to consolidated financial statements is an integral part of these statements. 75 Consolidated balance sheet (U.S. GAAP) millions of Canadian dollars At December 31 2025 2024 Assets Current assets Cash and cash equivalents 1,142 979 Accounts receivable - net (a) 4,371 5,758 Inventories of crude oil and products (note 11) 2,211 1,642 Materials, supplies and prepaid expenses 693 975 Total current assets 8,417 9,354 Investments and long-term receivables (b) 1,103 1,084 Property, plant and equipment, less accumulated depreciation and depletion (note 11) 30,863 30,807 Goodwill 166 166 Other assets, including intangibles - net 1,760 1,527 Total assets 42,309 42,938 Liabilities Current liabilities Notes and loans payable (note 12) 19 19 Accounts payable and accrued liabilities (a) (note 5, 11) 6,595 6,907 Income taxes payable 2 81 Total current liabilities 6,616 7,007 Long-term debt (c) (note 14) 3,978 3,992 Other long-term obligations (note 5, 11) 4,959 3,870 Deferred income tax liabilities (note 3) 4,502 4,596 Total liabilities 20,055 19,465 Commitments and contingent liabilities (note 9) Shareholders’ equity Common shares at stated value (d) (note 10) 895 942 Earnings reinvested 21,373 22,745 Accumulated other comprehensive income (loss) (note 17) ( 14 ) ( 214 ) Total shareholders’ equity 22,254 23,473 Total liabilities and shareholders’ equity 42,309 42,938 (a) Accounts receivable - net included net amounts receivable from related parties (note 16). 399 756 (b) Investments and long-term receivables included amounts from related parties (note 16). 251 266 (c) Long-term debt included amounts to related parties (note 16). 3,447 3,447 (d) Number of common shares authorized (millions) (note 10). 1,100 1,100 Number of common shares outstanding (millions) (note 10). 484 509 The information in the notes to consolidated financial statements is an integral part of these statements. Approved by the directors. /s/ John R. Whelan /s/ Daniel E. Lyons John R. Whelan Daniel E. Lyons Chairman, president and Senior vice-president chief executive officer finance and administration, and controller 76 Consolidated statement of shareholders’ equity (U.S. GAAP) millions of Canadian dollars At December 31 2025 2024 2023 Common shares at stated value (note 10) At beginning of year 942 992 1,079 Share purchases at stated value ( 47 ) ( 50 ) ( 87 ) At end of year 895 942 992 Earnings reinvested At beginning of year 22,745 21,907 21,846 Net income (loss) for the year 3,268 4,790 4,889 Share purchases in excess of stated value ( 3,196 ) ( 2,685 ) ( 3,713 ) Dividends declared ( 1,444 ) ( 1,267 ) ( 1,115 ) At end of year 21,373 22,745 21,907 Accumulated other comprehensive income (loss) (note 17) At beginning of year ( 214 ) ( 677 ) ( 512 ) Other comprehensive income (loss) 200 463 ( 165 ) At end of year ( 14 ) ( 214 ) ( 677 ) Shareholders’ equity at end of year 22,254 23,473 22,222 The information in the notes to consolidated financial statements is an integral part of these statements. 77 Consolidated statement of cash flows (U.S. GAAP) millions of Canadian dollars For the years ended December 31 2025 2024 2023 Operating activities Net income (loss) 3,268 4,790 4,889 Adjustments for non-cash items: Depreciation and depletion (includes impairments) (note 11) 2,579 1,983 1,907 (Gain) loss on asset sales (note 8) 5 ( 18 ) ( 73 ) Deferred income taxes and other ( 156 ) ( 142 ) ( 85 ) Changes in operating assets and liabilities: Accounts receivable 1,387 ( 1,276 ) 237 Inventories, materials, supplies and prepaid expenses ( 287 ) 335 ( 688 ) Income taxes payable ( 79 ) ( 170 ) ( 2,331 ) Accounts payable and accrued liabilities ( 346 ) 616 81 All other items - net (c) 337 ( 137 ) ( 203 ) Cash flows from (used in) operating activities 6,708 5,981 3,734 Investing activities Additions to property, plant and equipment ( 2,005 ) ( 1,867 ) ( 1,785 ) Proceeds from asset sales (note 8) 101 25 86 Additional investments ( 4 ) — — Loans to equity companies - net 16 17 5 Cash flows from (used in) investing activities ( 1,892 ) ( 1,825 ) ( 1,694 ) Financing activities Short-term debt - net (note 12) — ( 100 ) — Finance lease obligations - reduction (note 14) ( 18 ) ( 22 ) ( 22 ) Dividends paid ( 1,401 ) ( 1,238 ) ( 1,103 ) Common shares purchased (b) (note 10) ( 3,234 ) ( 2,681 ) ( 3,800 ) Cash flows from (used in) financing activities ( 4,653 ) ( 4,041 ) ( 4,925 ) Increase (decrease) in cash and cash equivalents 163 115 ( 2,885 ) Cash and cash equivalents at beginning of year 979 864 3,749 Cash and cash equivalents at end of year (a) 1,142 979 864 (a) Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less. (b) Includes 2 percent tax paid on repurchases of equity. (c) Includes contributions to registered pension plans. ( 148 ) ( 150 ) ( 148 ) Interest (paid), net of capitalization. ( 28 ) ( 42 ) ( 69 ) The information in the notes to consolidated financial statements is an integral part of these statements. 78 Notes to consolidated financial statements The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited. The company’s principal business involves exploration for, and production of, crude oil and natural gas; manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products; and pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, lower-emission fuels, and lithium. The consolidated financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (U.S. GAAP), which requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities. Actual results could differ from these estimates. All amounts are in Canadian dollars unless otherwise indicated. Note 1. Summary of significant accounting policies Principles of consolidation The consolidated financial statements include the accounts of subsidiaries the company controls. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Imperial Oil Resources Limited and Canada Imperial Oil Limited are significant subsidiaries included in the consolidated financial statements and are wholly owned by Imperial Oil Limited. The consolidated financial statements also include the company’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses, including its 70.96 percent interest in the Kearl joint venture and its 25 percent interest in the Syncrude joint venture. Revenues The company generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices. In some cases, products may be sold under long-term agreements, with periodic price adjustments to reflect market conditions. Revenue is recognized at the amount the company expects to receive when the customer has taken control, which is typically when title transfers and the customer has assumed the risks and rewards of ownership. The prices of certain sales are based on price indices that are sometimes not available until the next period. In such cases, estimated realizations are accrued when the sale is recognized, and are finalized when final information is available. Such adjustments to revenue from performance obligations satisfied in previous periods are not significant. Payment for revenue transactions is typically due within 30 days. Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “Purchases of crude oil and products” in the Consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “Selling and general” expenses. The company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the company provide the customer with a right of return. Future volume delivery obligations that are unsatisfied at the end of the period are expected to be fulfilled through ordinary production or purchases. These performance obligations are based on market prices at the time of the transaction and are fully constrained due to market price volatility. Purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another are combined and recorded as exchanges measured at the book value of the item sold. "Revenues" and "Accounts receivable - net" include revenue and receivables both within the scope of ASC 606 Revenue from Contracts with Customers , and those outside the scope of ASC 606 . Long-term receivables are primarily from receivables outside the scope of ASC 606 . Contract assets are mainly from marketing assistance programs and are not significant. Contract liabilities are mainly customer prepayments and accruals of expected volume discounts, and are not significant. 79 Consumer and other taxes Taxes levied on the consumer and collected by the company are excluded from the Consolidated statement of income. These are primarily provincial taxes on motor fuels, the federal goods and services tax and the federal/provincial harmonized sales tax. Similar taxes, for which the company is not considered to be an agent for the government, are reported on a gross basis (included in both "Revenues" and "Federal excise tax and fuel charge"). Derivative instruments The company may use derivative instruments for trading purposes and to offset exposures associated with commodity prices, currency exchange rates and interest rates that arise from existing assets, liabilities, firm commitments and forecasted transactions. All derivative instruments, except those designated as normal purchase and normal sale, are recorded at fair value. Derivative assets and liabilities with the same counterparty are netted if the right of offset exists and certain other criteria are met. Collateral payables or receivables are netted against derivative assets and derivative liabilities, respectively. Recognition and classification of the gain or loss that results from adjusting a derivative to fair value depends on the purpose for the derivative. The gains and losses resulting from changes in the fair value of derivatives are recorded under "Revenues" in the Consolidated statement of income. Fair value Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants. Hierarchy levels 1, 2 and 3 are terms for the priority of inputs to valuation techniques used to measure fair value. Hierarchy level 1 inputs are quoted prices in active markets for identical assets or liabilities. Hierarchy level 2 inputs are inputs other than quoted prices included within level 1 that are directly or indirectly observable for the asset or liability. Hierarchy level 3 inputs are inputs that are not observable in the market. Inventories Inventories are recorded at the lower of current market value or cost. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period. Inventory costs include expenditures and other charges (including depreciation), directly and indirectly incurred in bringing the inventory to its existing condition and location. Selling and general expenses are reported as period costs and excluded from inventory costs. Inventories of materials and supplies are valued at cost or less. Investments The company’s interests in the underlying net assets of affiliates it does not control, but over which it exercises significant influence, are accounted for using the equity method. They are recorded at the original cost of the investment plus the company’s share of earnings since the investment was made, less dividends received. The company’s share of the after-tax earnings of these investments is included in “Investment and other income” in the Consolidated statement of income. Investments in equity securities, other than consolidated subsidiaries and equity method investments, are measured at fair value, with changes in the fair value recognized in net income. The company uses a modified approach for equity securities that do not have a readily determinable fair value. This modified approach measures investments at cost minus impairment, if any, plus or minus changes resulting from observable price changes in orderly transactions in similar investments of the same issuer. Dividends from these investments are included in “Investment and other income”. These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of liquids in the conduct of company operations. Other parties who also have an equity interest in these investments share in the risks and rewards according to their percentage of ownership. The company does not invest in these investments in order to remove liabilities from its balance sheet. 80 Property, plant and equipment Cost basis The company uses the "successful efforts" method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis. Costs incurred to purchase, lease, or otherwise acquire a property (whether unproved or proved) are capitalized when incurred. Exploratory well costs are carried as an asset when the well has found a sufficient quantity of reserves to justify its completion as a producing well and where the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. Exploratory well costs not meeting these criteria are charged to expense. Other exploratory expenditures, including geophysical costs and annual lease rentals, are expensed as incurred. Development costs, including costs of productive wells and development dry holes, are capitalized. Interest costs incurred to finance expenditures during the construction phase of projects are capitalized as part of the historical cost of acquiring the constructed assets. The project construction phase commences with the development of the detailed engineering design and ends when the constructed assets are ready for their intended use. Capitalized interest costs are included in property, plant and equipment and are depreciated over the service life of the related assets. Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized. Depreciation, depletion and amortization Depreciation, depletion and amortization are primarily determined under either the unit-of-production method or the straight-line method, which is based on estimated asset service life taking obsolescence into consideration. Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Acquisition costs of proved properties are amortized using a unit-of-production method, computed on the basis of total proved oil and natural gas reserve volumes. Capitalized exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production rates based on the amount of proved developed reserves of oil and gas that are estimated to be recoverable from existing facilities using current operating methods. Under the unit-of-production method, oil and natural gas volumes are considered produced once they have been measured through meters at custody transfer or sales transaction points at the outlet valve on the lease or field storage tank. In the event that the unit-of-production method does not result in an equitable allocation of cost over the economic life of an upstream asset, an alternative method is used. The straight-line method is used in limited situations where the expected life of the asset does not reasonably correlate with that of the underlying reserves. For example, certain assets used in the production of oil and natural gas have a shorter life than the reserves, and as such, the company uses straight-line depreciation to ensure the asset is fully depreciated by the end of its useful life. Investments in mining heavy equipment and certain ore processing plant assets at oil sands mining properties are depreciated on a straight-line basis over a maximum of 15 years and 50 years respectively. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. To the extent that proved reserves for a property are substantially de-booked and that property continues to produce such that the resulting depreciation charge does not result in an equitable allocation of cost over the expected life, assets will be depreciated using a unit-of-production method based on reserves determined at the most recent SEC price which results in a more meaningful quantity of proved reserves, appropriately adjusted for production and technical changes. Investments in refinery and chemical process manufacturing equipment are generally depreciated on a straight-line basis over a 25 -year life. Maintenance and repairs, including planned major maintenance, are expensed as incurred. Major renewals and improvements are capitalized and the assets replaced are retired. 81 Impairment assessment The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following: • a significant decrease in the market price of a long-lived asset; • a significant adverse change in the extent or manner in which an asset is being used or in its physical condition, including a significant decrease in current and projected reserve volumes; • a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator; • an accumulation of project costs significantly in excess of the amount originally expected; • a current-period operating loss combined with a history and forecast of operating or cash flow losses; and • a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life. The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year. This process is aligned with the requirements of ASC 360 and ASC 932 and relies, in part, on the company’s planning and budgeting cycle. Asset valuation analysis, profitability reviews and other periodic control processes assist the company in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable. Because the lifespans of the vast majority of the company’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices and industry margins, development and production costs. Significant reductions in the company’s view of oil or natural gas commodity prices or margin ranges, especially the longer-term prices and margins, and changes in the development plans, including decisions to defer, reduce or eliminate planned capital spending, can be an indicator of potential impairment. Other events or changes in circumstances, including indicators outlined in ASC 360, can be indicators of potential impairment as well. In general, the company does not view temporarily low prices or margins as an indication of impairment. Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand. Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals. On the supply side, industry production from mature fields is declining. This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements. OPEC+ investment activities and production policies also have an impact on world oil supplies. The demand side is largely a function of general economic activities, alternative energy sources and levels of prosperity. During the lifespan of its major assets, the company expects that oil and gas prices and industry margins will experience significant volatility. Consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses. In assessing whether events or changes in circumstances indicate the carrying value of an asset may not be recoverable, the company considers recent periods of operating losses in the context of its longer-term view of prices and margins. In the Upstream, the standardized measure of discounted cash flows included in the “Supplemental information on oil and gas exploration and production activities” is required to use prices based on the average of first-day-of-month prices in the year. These prices represent discrete points in time and could be higher or lower than the company’s price assumptions which are used for impairment assessments. The company believes the standardized measure does not provide a reliable estimate of the expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its oil and gas reserves and therefore does not consider it relevant in determining whether events or changes in circumstances indicate the need for an impairment assessment. 82 Global Outlook and cash flow assessment The annual planning and budgeting process, known as the company plan, is the mechanism by which resources (capital, operating expenses and people) are allocated across the company. The foundation for the energy supply and demand assumptions supporting the company plan begins with Exxon Mobil Corporation's Global Outlook (the Outlook), which contains demand and supply projections based on its assessment of current trends in technology, government policies, consumer preferences, geopolitics, economic development, and other factors. Reflective of the existing global policy environment, the Outlook does not attempt to project the degree of necessary future policy and technology advancement and deployment for the world to meet net zero by 2050. As future policies and technology advancements emerge, they will be incorporated into the Outlook, and consequently, the company’s business plans will be updated accordingly. If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, the company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In performing this assessment, assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. Cash flows used in recoverability assessments are based on the assumptions developed in the company plan, which is reviewed and approved by the board of directors, and are consistent with the criteria management uses to evaluate investment opportunities. These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, including greenhouse gas emissions prices, and foreign currency exchange rates. Volumes are based on projected field and facility production profiles, throughput, or sales. Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities. The greenhouse gas emission prices reflect existing or anticipated policy actions of applicable provincial and federal governments. Fair value of impaired assets An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value. Impairments are measured by the excess of the carrying value over fair value. The assessment of fair value is based on the views of a likely market participant. The principal parameters used to establish fair value include estimates of acreage values and flowing production metrics from comparable market transactions, market-based estimates of historical cash flow multiples, and discounted cash flows. Inputs and assumptions used in discounted cash flow models include estimates of future production volumes, throughput and product sales volumes, commodity prices (which are consistent with the average of third-party industry experts and government agencies), refining and chemical margins, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group. Other impairment estimates Unproved properties are assessed periodically to determine whether they have been impaired. Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties. Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period. Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell. If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value. Gains on sales of proved and unproved properties are only recognized when there is neither uncertainty about the recovery of costs applicable to any interest retained nor any substantial obligation for future performance by the company. 83 Asset retirement obligations and other environmental liabilities The company incurs retirement obligations for certain assets. The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed. In the estimation of fair value, the company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation, technical assessments of the assets, estimated amounts and timing of settlements, discount rates, and inflation rates. Asset retirement obligations incurred in the current period were level 3 fair value measurements. The costs associated with these liabilities are capitalized as part of the related assets and depreciated as the reserves are produced. Over time, the liabilities are accreted for the change in their present value. Asset retirement obligations for downstream and chemical facilities generally become firm at the time the facilities are permanently shut down and dismantled. These obligations may include the costs of asset disposal and additional soil remediation. However, these sites generally have indeterminate lives based on plans for continued operations, and as such, the fair value of the conditional legal obligations cannot be measured, since it is impossible to estimate the future settlement dates of such obligations. Note 5 to the consolidated financial statements provides a three-year continuity table detailing the changes in asset retirement obligations. The company accrues environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated. Provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. These provisions are not reduced by possible recoveries from third parties and projected cash expenditures are not discounted. Foreign-currency translation Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income. 84 Note 2. Business segments The company operates its business in Canada, and its three reportable segments are Upstream, Downstream and Chemical. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment, the structure of the company’s internal organization, and reflect the nature of internal reviews by the company's Management Committee (MC). The MC is considered collectively, and not in their individual capacity, to be the company's Chief Operating Decision Maker (CODM), and includes the company's CEO, CFO, and a senior vice-president, who oversee the Upstream, Downstream and Chemical businesses. The Upstream segment is organized and operates to explore for and ultimately produce crude oil and its equivalent, and natural gas. The Downstream segment is organized and operates to refine crude oil into petroleum products and to distribute and market these products. The Chemical segment is organized and operates to manufacture and market hydrocarbon-based chemicals and chemical products. The above segmentation has been the long-standing practice of the company and is broadly understood across the petroleum and petrochemical industries. Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, capitalized interest costs, short-term borrowings, long-term debt and liabilities associated with incentive compensation, pension and other postretirement benefit liabilities. Net earnings effects under Corporate and other activities primarily include debt-related financing, corporate governance costs, non-service pension and postretirement benefit costs, share-based incentive compensation expenses and interest income. The CODM generally allocates resources through an annual planning process. They also allocate capital based on detailed project economics and long-term strategic objectives across reportable segments. The CODM primarily uses changes in Net Income (loss) to assess segment financial performance. Segment accounting policies are the same as those described in note 1, "Summary of significant accounting policies". Upstream, Downstream and Chemical expenses include amounts allocated from Corporate and other activities. The allocation is based on proportional segment expenses. Transfers of assets between segments are recorded at book amounts. Intersegment sales are made essentially at prevailing market prices. Assets and liabilities that are not identifiable by segment are allocated. 85 Upstream Downstream (e) Chemical (e) millions of Canadian dollars 2025 2024 2023 2025 2024 2023 2025 2024 2023 Revenues and other income Revenues (a) (b) 291 121 222 45,638 50,114 49,241 989 1,124 1,239 Intersegment sales 15,645 17,868 16,274 6,371 6,771 6,509 388 323 342 Investment and other income (note 8) 14 26 16 81 59 108 — 2 — Total revenues and other income 15,950 18,015 16,512 52,090 56,944 55,858 1,377 1,449 1,581 Expenses Exploration (note 15) 7 3 5 — — — — — — Purchases of crude oil and products 6,263 7,367 6,636 45,017 49,856 47,886 923 916 997 Production and manufacturing 5,015 4,644 4,917 1,992 1,741 1,702 241 197 260 Selling and general (note 11) — — — 725 706 693 81 92 89 Federal excise tax and fuel charge — — — 1,710 2,531 2,399 5 4 3 Depreciation and depletion (note 11) 1,906 1,747 1,680 203 181 183 16 15 15 Non-service pension and postretirement benefit — — — — — — — — — Financing (note 12) ( 14 ) 4 7 — — — — — — Total expenses 13,177 13,765 13,245 49,647 55,015 52,863 1,266 1,224 1,364 Income (loss) before income taxes 2,773 4,250 3,267 2,443 1,929 2,995 111 225 217 Income tax expense (benefit) (note 3 ) 652 988 755 574 443 694 29 54 53 Net income (loss) 2,121 3,262 2,512 1,869 1,486 2,301 82 171 164 Cash flows from (used in) operating activities 3,606 4,664 3,100 3,372 1,049 608 ( 28 ) 211 53 Capital and exploration expenditures (c) 1,480 1,078 1,108 412 572 472 11 30 23 Property, plant and equipment Cost 49,388 47,920 46,776 8,265 7,887 7,368 1,029 1,015 1,018 Accumulated depreciation and depletion ( 23,351 ) ( 21,658 ) ( 19,936 ) ( 4,602 ) ( 4,430 ) ( 4,301 ) ( 758 ) ( 743 ) ( 757 ) Net property, plant and equipment (d) (f) (note 11) 26,037 26,262 26,840 3,663 3,457 3,067 271 272 261 Total assets 29,111 28,042 28,718 11,036 11,624 10,114 540 474 475 Corporate and other Eliminations Consolidated millions of Canadian dollars 2025 2024 2023 2025 2024 2023 2025 2024 2023 Revenues and other income Revenues (a) (b) — — — — — — 46,918 51,359 50,702 Intersegment sales — — — ( 22,404 ) ( 24,962 ) ( 23,125 ) — — — Investment and other income (note 8) 65 86 143 — — — 160 173 267 Total revenues and other income 65 86 143 ( 22,404 ) ( 24,962 ) ( 23,125 ) 47,078 51,532 50,969 Expenses Exploration (note 15) — — — — — — 7 3 5 Purchases of crude oil and products — — — ( 22,396 ) ( 24,955 ) ( 23,120 ) 29,807 33,184 32,399 Production and manufacturing 21 17 — — — — 7,269 6,599 6,879 Selling and general (note 11) 588 154 80 ( 8 ) ( 7 ) ( 5 ) 1,386 945 857 Federal excise tax and fuel charge — — — — — — 1,715 2,535 2,402 Depreciation and depletion (note 11) 454 40 29 — — — 2,579 1,983 1,907 Non-service pension and postretirement benefit 41 3 82 — — — 41 3 82 Financing (note 12) 26 37 62 — — — 12 41 69 Total expenses 1,130 251 253 ( 22,404 ) ( 24,962 ) ( 23,125 ) 42,816 45,293 44,600 Income (loss) before income taxes ( 1,065 ) ( 165 ) ( 110 ) — — — 4,262 6,239 6,369 Income tax expense (benefit) (note 3) ( 261 ) ( 36 ) ( 22 ) — — — 994 1,449 1,480 Net income (loss) ( 804 ) ( 129 ) ( 88 ) — — — 3,268 4,790 4,889 Cash flows from (used in) operating activities ( 282 ) 69 ( 37 ) 40 ( 12 ) 10 6,708 5,981 3,734 Capital and exploration expenditures (c) 124 187 175 — — — 2,027 1,867 1,778 Property, plant and equipment Cost 1,349 1,226 1,038 — — — 60,031 58,048 56,200 Accumulated depreciation and depletion ( 457 ) ( 410 ) ( 371 ) — — — ( 29,168 ) ( 27,241 ) ( 25,365 ) Net property, plant and equipment (d) (f) (note 11) 892 816 667 — — — 30,863 30,807 30,835 Total assets 3,658 2,962 2,366 ( 2,036 ) ( 164 ) ( 474 ) 42,309 42,938 41,199 86 (a) Includes export sales to the United States of $ 9,223 million (2024 - $ 10,300 million, 2023 - $ 8,982 million). (b) Revenues include both revenue within the scope of ASC 606 and outside the scope of ASC 606 . Trade receivables in "Accounts receivable - net" reported on the Consolidated balance sheet include both receivables within the scope of ASC 606 and outside the scope of ASC 606 . Revenue and receivables outside the scope of ASC 606 primarily relate to physically settled commodity contracts accounted for as derivatives. Contractual terms, credit quality and type of customer are generally similar between contracts within the scope of ASC 606 and those outside it. Revenues millions of Canadian dollars 2025 2024 2023 Revenue from contracts with customers 38,678 40,901 44,465 Revenue outside the scope of ASC 606 8,240 10,458 6,237 Total 46,918 51,359 50,702 (c) Capital and exploration expenditures (CAPEX) include exploration expenses, additions to property, plant and equipment, additions to finance leases, additional investments and acquisitions and the company’s share of similar costs for equity companies. CAPEX excludes the purchase of carbon emission credits. (d) Includes property, plant and equipment under construction of $ 3,467 million (2024 - $ 3,632 million, 2023 - $ 3,251 million). (e) In 2025 and 2024, benzene and aromatic solvents are reported under the Downstream segment, whereas in 2023, they were reported under the Chemicals segment. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast. (f) In 2025, in conjunction with the company signing an agreement to sell the Calgary Imperial Campus, the Upstream segment transferred the asset to the Corporate and other segment for $ 466 million. The effects of this transaction have been eliminated for consolidation purposes. Prior periods have not been recast. 87 Note 3. Income taxes In 2025, the company adopted the Financial Accounting Standards Board’s ASU No. 2023‑09, Improvements to Income Tax Disclosures on a retrospective basis in accordance with the transition provision. millions of Canadian dollars 2025 2024 2023 Current income tax expense (benefit) 1,125 1,586 1,556 Deferred income tax expense (benefit) ( 131 ) ( 137 ) ( 76 ) Total income tax expense (benefit) 994 1,449 1,480 Federal 625 902 920 Provincial 369 547 560 Total income tax expense (benefit) 994 1,449 1,480 Income (loss) before income taxes 4,262 6,239 6,369 Canadian federal statutory tax rate 639 15.0 % 935 15.0 % 955 15.0 % Provincial (a) 376 8.8 % 567 9.1 % 582 9.1 % Increase (decrease) resulting from: Other ( 21 ) ( 0.5 %) ( 53 ) ( 0.9 %) ( 57 ) ( 0.9 %) Effective income tax rate 994 23.3 % 1,449 23.2 % 1,480 23.2 % (a) Provincial taxes in Alberta make up the majority (50 percent or more). Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are re-measured at each year-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were: millions of Canadian dollars 2025 2024 2023 Depreciation and amortization 5,311 5,267 5,366 Successful drilling and land acquisitions 236 236 237 Pension and benefits 38 ( 15 ) ( 168 ) Asset retirement obligation ( 858 ) ( 686 ) ( 655 ) Capitalized interest 202 185 155 LIFO inventory valuation ( 297 ) ( 468 ) ( 406 ) Tax loss carryforwards ( 65 ) ( 66 ) ( 69 ) Valuation allowance 65 66 69 Other ( 214 ) ( 35 ) ( 60 ) Net deferred income tax liabilities 4,418 4,484 4,469 The following table summarizes total income taxes (paid) refunded: millions of Canadian dollars 2025 2024 2023 Federal ( 901 ) ( 1,119 ) ( 2,562 ) Provincial Alberta ( 342 ) ( 380 ) ( 1,048 ) Ontario ( 131 ) ( 176 ) ( 343 ) Other ( 61 ) ( 96 ) ( 200 ) Total income taxes (paid) refunded ( 1,435 ) ( 1,771 ) ( 4,153 ) 88 Unrecognized tax benefits Unrecognized tax benefits reflect the difference between positions taken or expected to be taken on income tax returns and the amounts recognized in the financial statements. The following table summarizes the movement in unrecognized tax benefits: millions of Canadian dollars 2025 2024 2023 Balance as of January 1 34 47 60 Additions based on current year’s tax position 6 2 7 Additions for prior years’ tax positions 3 — — Settlements with tax authorities ( 1 ) ( 15 ) ( 20 ) Balance as of December 31 42 34 47 The unrecognized tax benefit balances shown above predominantly relate to tax positions that would reduce the company’s effective tax rate if the positions are favourably resolved. Unfavourable resolution of these tax positions generally would not increase the effective tax rate. The 2025, 2024 and 2023 changes in unrecognized tax benefits did not have a material effect on the company’s net income or cash flow. The company’s tax filings from 2020 to 2025 are subject to examination by the tax authorities. Tax filings fro m 2009 to 2024 have open objections and therefore are also subject to examination by the tax authorities. The Canada Revenu e Agency has made certain adjustments to the company’s filings. Management has evaluated these adjustments and is formally disputing those matters to which the company disagrees. The impact on unrecognized tax benefits and the company’s effective income tax rate from these matters is not expected to be material. Resolution of the related tax positions could take many years to complete. It is difficult to predict the timing of resolution for tax positions since such timing is not entirely within the control of the company. The company classifies interest on income tax related balances as interest expense or interest income and classifies tax related penalties as operating expense. Unrecognized tax benefits are not classified as future commitments because the company does not expect there will be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency. 89 Note 4. Employee retirement benefits Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension income and certain health care and life insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Pension income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health care and life insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels, as well as a projection of salaries to retirement. The expense and obligations for both funded and unfunded benefits are determined in accordance with accepted actuarial practices and U.S. GAAP. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets. The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31. Pension benefits Other postretirement benefits 2025 2024 2025 2024 Assumptions used to determine benefit obligations at December 31 (percent) Discount rate 4.90 4.70 4.90 4.70 Long-term rate of compensation increase 4.00 4.00 4.00 4.00 millions of Canadian dollars Change in benefit obligation Benefit obligation at January 1 8,131 8,154 476 581 Service cost 186 186 4 13 Interest cost 369 365 22 25 Actuarial loss (gain) (a) ( 247 ) ( 88 ) ( 43 ) ( 29 ) Amendments and other 19 — 1 ( 78 ) Benefits paid (b) ( 502 ) ( 486 ) 5 ( 36 ) Benefit obligation at December 31 7,956 8,131 465 476 Accumulated benefit obligation at December 31 7,225 7,385 (a) Actuarial loss (gain) primarily driven by changes in the year-end discount rate. (b) Benefit payments for funded and unfunded plans. 90 The discount rate for the purpose of calculating year-end postretirement benefits plan obligation is determined by using the Canadian Institute of Actuaries recommended spot yield curve for high-quality, long-term Canadian corporate bonds with an average maturity (or duration) approximating that of the liabilities. For the measurement of the accumulated postretirement benefit obligation, the assumed health care cost trend rates start with 6.14 percent in 2026 and gradually decline to 3.57 percent by 2038 and beyond. Pension benefits Other postretirement benefits millions of Canadian dollars 2025 2024 2025 2024 Change in plan assets Fair value at January 1 8,553 8,054 Actual return (loss) gain 345 805 Company contributions 148 150 Benefits paid (a) ( 459 ) ( 452 ) Other ( 5 ) ( 4 ) Fair value at December 31 8,582 8,553 Plan assets in excess of (less than) projected benefit obligation at December 31 Funded plans 1,035 853 Unfunded plans ( 409 ) ( 431 ) ( 465 ) ( 476 ) Total (b) 626 422 ( 465 ) ( 476 ) (a) Benefit payments for funded plans only. (b) Fair value of assets less projected benefit obligation shown above. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based on an independent actuarial valuation. In accordance with authoritative guidance relating to the accounting for defined pension and other postretirement benefits plans, the overfunded or underfunded status of the company’s defined benefit postretirement plans was recorded as an asset or liability in the Consolidated balance sheet, and the changes in that funded status in the year in which the changes occurred was recognized through other comprehensive income. Pension benefits Other postretirement benefits millions of Canadian dollars 2025 2024 2025 2024 Amounts recorded in the Consolidated balance sheet consist of: Other assets, including intangibles - net 1,035 853 — — Current liabilities ( 34 ) ( 33 ) ( 29 ) ( 28 ) Other long-term obligations ( 375 ) ( 398 ) ( 436 ) ( 448 ) Total recorded 626 422 ( 465 ) ( 476 ) Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss (gain) 29 237 ( 145 ) ( 110 ) Prior service cost 346 373 ( 73 ) ( 78 ) Total recorded in accumulated other comprehensive income, before-tax 375 610 ( 218 ) ( 188 ) 91 The company establishes the long-term expected rate of return on plan assets by developing a forward-looking long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation percentages and the long-term return assumption for each asset class. The 2025 long-term expected return of 4.4 percent used in the calculations of pension expense compares to an actual rate of return of 4.5 percent and 5.6 percent over the last 10- and 20-year periods respectively, ending December 31, 2025. Pension benefits Other postretirement benefits 2025 2024 2023 2025 2024 2023 Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) Discount rate 4.70 4.60 5.10 4.70 4.60 5.10 Long-term rate of return on funded assets 4.40 5.60 4.80 — — — Long-term rate of compensation increase 4.00 4.00 4.00 4.00 4.00 4.00 millions of Canadian dollars Components of net periodic benefit cost Service cost 186 186 162 4 13 12 Interest cost 369 365 373 22 25 28 Expected return on plan assets ( 395 ) ( 454 ) ( 373 ) — — — Amortization of prior service cost 27 27 19 ( 5 ) — — Amortization of actuarial loss (gain) 11 48 44 ( 8 ) ( 8 ) ( 9 ) Net pension and other post retirement benefit enhancement 19 — — 1 — — Net periodic benefit cost 217 172 225 14 30 31 Changes in amounts recorded in accumulated other comprehensive income Net actuarial loss (gain) ( 197 ) ( 439 ) 102 ( 43 ) ( 29 ) ( 14 ) Amortization of net actuarial (loss) gain included in net periodic benefit cost ( 11 ) ( 48 ) ( 44 ) 8 8 9 Prior service cost — — 184 — ( 78 ) — Amortization of prior service cost included in net periodic benefit cost ( 27 ) ( 27 ) ( 19 ) 5 — — Total recorded in other comprehensive income ( 235 ) ( 514 ) 223 ( 30 ) ( 99 ) ( 5 ) Total recorded in net periodic benefit cost and other comprehensive income, before-tax ( 18 ) ( 342 ) 448 ( 16 ) ( 69 ) 26 Costs for defined contribution plans, primarily the employee savings plan, were $ 47 million in 2025 (2024 - $ 47 million, 2023 - $ 44 million). A summary of the change in accumulated other comprehensive income is shown in the table below: Total pension and other postretirement benefits millions of Canadian dollars 2025 2024 2023 (Charge) credit to other comprehensive income, before-tax 265 613 ( 218 ) Deferred income tax (charge) credit (note 17) ( 65 ) ( 150 ) 53 (Charge) credit to other comprehensive income, after-tax 200 463 ( 165 ) 92 The company’s investment strategy for pension plan assets reflects a long-term view, a careful assessment of the risks inherent in plan assets and liabilities and broad diversification to reduce the risk of the portfolio. The pension plan assets are primarily invested in passive global equity and domestic fixed income index funds to diversify risk while minimizing costs. The fixed income funds are largely invested in investment-grade corporate and government debt securities with interest rate sensitivity designed to approximate the interest rate sensitivity of plan liabilities. The target asset allocation for the pension plan is reviewed periodically and set based on considerations such as risk, diversification, liquidity, and funding level. The target asset allocation for equity securities is 15 percent with the remainder in fixed-income securities. The fair value measurement levels are accounting terms that refer to different methods of valuing assets. The terms do not represent the relative risk or credit quality of an investment. The 2025 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2025, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Value Asset class Equity securities Canadian — — Non-Canadian 1,466 1,466 Debt securities - Canadian Corporate 1,693 1,693 Government 4,950 4,950 Asset backed 4 4 Other 45 45 Equities – Venture capital 167 167 Real Estate 207 207 Cash 50 18 32 Total plan assets at fair value 8,582 18 8,564 The 2024 fair value of the pension plan assets, including the level within the fair value hierarchy, is shown in the table below: Fair value measurements at December 31, 2024, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Value Asset class Equity securities Canadian — — Non-Canadian 2,584 2,584 Debt securities - Canadian Corporate 1,220 1,220 Government 4,400 4,400 Asset backed 4 4 Other 18 18 Equities – Venture capital 134 134 Real Estate 154 154 Cash 39 3 36 Total plan assets at fair value 8,553 3 8,550 93 A summary of pension plans with accumulated benefit obligation and projected benefit obligation in excess of plan assets is shown in the table below: Pension benefits millions of Canadian dollars 2025 2024 For unfunded pension plans covered by book reserves: Projected benefit obligation 409 431 Accumulated benefit obligation 368 386 (a) In 2025 and 2024, the fair value of plan assets exceeded the projected benefit obligation for both the company sponsored plan and its proportionate share of a joint venture sponsored plan. Cash flows Benefit payments expected in: millions of Canadian dollars Pension benefits Other postretirement benefits 2026 490 30 2027 490 30 2028 490 32 2029 490 32 2030 490 32 2031 - 2035 2,450 154 In 2026, the company expects to make cash contributions of about $ 151 million to its pension plans. 94 Note 5. Other long-term obligations millions of Canadian dollars 2025 2024 Employee retirement benefits (a) (note 4) 811 846 Asset retirement obligations and other environmental liabilities (b) (c) 3,348 2,641 Share-based incentive compensation liabilities (note 7) 198 119 Operating lease liability (note 13) 149 144 Restructuring liability (note 11) 173 — Other obligations 280 120 Total other long-term obligations 4,959 3,870 (a) Total recorded employee retirement benefits obligations also included $ 63 million in current liabilities (2024 - $ 61 million). (b) Total asset retirement obligations and other environmental liabilities also included $ 318 million in current liabilities (2024 - $ 291 million). (c) For 2025, the asset retirement obligations were discounted at 6 percent (2024 - 6 percent). Asset retirement obligations incurred in the current period were level 3 fair value measurements. The following table summarizes the activity in the liability for asset retirement obligations: millions of Canadian dollars 2025 2024 2023 Balance as at January 1 2,833 2,703 2,178 Additions (deductions) 721 96 471 Accretion 171 163 132 Settlement ( 195 ) ( 129 ) ( 78 ) Balance as at December 31 3,530 2,833 2,703 Estimated cash payments for asset retirement obligations are $ 241 million in 2026 and $ 227 million in 2027. 95 Note 6. Financial and derivative instruments Financial instruments The fair value of the company’s financial instruments is determined by reference to various market data and other appropriate valuation techniques. There are no material differences between the fair value of the company’s financial instruments and the recorded carrying value. At December 31, 2025 and December 31, 2024, the fair value of long-term debt ($ 3,447 million, excluding finance lease obligations) was primarily a level 2 measurement. Derivative instruments The company’s size, strong capital structure and the complementary nature of its business segments reduce the company’s enterprise-wide risk from changes in commodity prices, currency rates and interest rates. In addition, the company uses commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading. Commodity contracts held for trading purposes are presented in the Consolidated statement of income on a net basis in the line "Revenues" and in the Consolidated statement of cash flows in "Cash flows from (used in) operating activities". The company’s commodity derivatives are not accounted for under hedge accounting. Credit risk associated with the company’s derivative position is mitigated by several factors, including the use of derivative clearing exchanges and the quality of and financial limits placed on derivative counterparties. The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. At December 31, the net notional long/(short) position of derivative instruments was: thousands of barrels 2025 2024 Crude 954 4,260 Products ( 702 ) ( 371 ) Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the following line on a before-tax basis: millions of Canadian dollars 2025 2024 2023 Revenues 41 ( 69 ) ( 5 ) The estimated fair value of derivative instruments, and the related hierarchy level for the fair value measurement were as follows: At December 31, 2025 millions of Canadian dollars Fair value Effect of counterparty netting Effect of collateral netting Net carrying value Level 1 Level 2 Level 3 Total Assets Derivative assets (a) 20 39 — 59 ( 18 ) ( 2 ) 39 L iabilities Derivative liabilities (b) 18 14 — 32 ( 18 ) — 14 (a) Included in the Consolidated balance sheet line: "Materials, supplies and prepaid expenses", "Accounts receivable - net" and "Other assets, including intangibles - net". (b) Included in the Consolidated balance sheet line: "Accounts payable and accrued liabilities" and "Other long-term obligations". 96 At December 31, 2024 millions of Canadian dollars Fair value Effect of counterparty netting Effect of collateral netting Net carrying value Level 1 Level 2 Level 3 Total Assets Derivative assets (a) 38 21 — 59 ( 38 ) — 21 L iabilities Derivative liabilities (b) 52 30 — 82 ( 38 ) ( 14 ) 30 (a) Included in the Consolidated balance sheet line: "Materials, supplies and prepaid expenses", "Accounts receivable - net" and "Other assets, including intangibles - net". (b) Included in the Consolidated balance sheet line: "Accounts payable and accrued liabilities" and "Other long-term obligations". At December 31, 2025, and December 31, 2024, the company had $ 6 million and $ 22 million, respectively, of collateral under a master netting arrangement not offset against the derivatives on the Consolidated balance sheet in "Accounts receivable - net", primarily related to initial margin requirements. 97 Note 7. Share-based incentive compensation programs Share-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the company’s future business performance and shareholder value over the long-term. The nonemployee directors also participate in share-based incentive compensation programs. Restricted stock units and deferred share units Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the company, upon vesting, an amount equal to the value of one common share of the company, based on the five-day average of the closing price of the company’s common shares on the Toronto Stock Exchange on and immediately prior to the vesting dates. For the majority of the units, 50 percent of the units vest on the third anniversary of the grant date, and the remainder vest on the seventh anniversary of the grant date. Some management, professional, and technical participants will receive awards granted that vest 100 percent after three years . The company may also issue units to the chairman, president and chief executive officer where 50 percent of the units vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of the grant date, except that for awards granted prior to 2020, the vesting of the tenth anniversary portion is delayed until retirement if later than 10 years. The deferred share unit plan is made available to nonemployee directors. The nonemployee directors can elect to receive all or part of their eligible directors’ fees in units. The number of units granted is determined at the end of each calendar quarter by dividing the dollar amount of the nonemployee director’s fees for that calendar quarter elected to be received as deferred share units by the average closing price of the company’s shares for the five consecutive trading days ("average closing price") immediately prior to the last day of the calendar quarter. Additional units are granted to represent dividends on unexercised units, and are calculated by dividing the cash dividend payable on the company’s shares by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient, as adjusted for any share splits. Deferred share units cannot be exercised until after termination of service as a director, including termination due to death, and must be exercised in their entirety in one election no later than December 31 of the year following the year of termination of service. On the exercise date, the cash value to be received for the units is determined based on the company’s average closing price immediately prior to the date of exercise, as adjusted for any share splits. All units require settlement by cash payments with the following exceptions. The restricted stock unit program provides that, for units granted to Canadian residents, the recipient may receive one common share of the company per unit or elect to receive the cash payment for the units that vest on the seventh year anniversary of the grant date. For units where 50 percent vest on the fifth anniversary of the grant date and the remainder vest on the tenth anniversary of grant, the recipient may receive one common share of the company per unit or elect to receive cash payment for all that vest. The company accounts for all units by using the fair-value-based method. The fair value of awards in the form of restricted stock and deferred share units is the market price of the company’s stock. Under this method, compensation expense related to the units of these programs is measured each reporting period based on the company’s current stock price and is recorded in the Consolidated statement of income over the requisite service period of each award. The following table summarizes information about these units for the year ended December 31, 2025: Restricted stock units Deferred share units Outstanding at January 1, 2025 4,223,070 44,706 Granted 918,900 6,393 Vested/Exercised ( 717,310 ) — Forfeited and cancelled ( 42,620 ) — Outstanding at December 31, 2025 4,382,040 51,099 98 In 2025, the before-tax compensation expense charged against income for the restricted stock units and deferred share units was $ 212 million (2024 - $ 116 million, 2023 - $ 52 million). Income tax benefit recognized in income related to this compensation expense for the year was $ 51 million (2024 - $ 28 million, 2023 - $ 13 million). Cash payments of $ 107 million were made related to this compensation expense in 2025 (2024 - $ 74 million, 2023 - $ 68 million). As of December 31, 2025, there was $ 251 million of total before-tax unrecognized compensation expense related to non-vested restricted stock units based on the company’s share price at the end of the current reporting period. The weighted-average vesting period of non-vested restricted stock units is 4.2 years. All units under the deferred share programs have vested as of December 31, 2025. Note 8. Investment and other income Investment and other income includes gains and losses on asset sales as follows: millions of Canadian dollars 2025 2024 2023 Proceeds from asset sales 101 25 86 Book value of asset sales 106 7 13 Gain (loss) on asset sales, before-tax ( 5 ) 18 73 Gain (loss) on asset sales, after-tax ( 9 ) 16 63 Note 9. Litigation and other contingencies A variety of claims have been made against the company and its subsidiaries in a number of lawsuits. Management has regular litigation reviews, including updates from corporate and outside counsel to assess the need for accounting recognition or disclosure of these contingencies. The company accrues an undiscounted liability for those contingencies where the incurrence of a loss is probable and the amount can be reasonably estimated. If a range of amounts can be reasonably estimated and no amount within the range is a better estimate than any other amount, then the minimum of the range is accrued. The company does not record liabilities when the likelihood that the liability has been incurred is probable but the amount cannot be reasonably estimated or when the liability is believed to be only reasonably possible or remote. For contingencies where an unfavourable outcome is reasonably possible and which are significant, the company discloses the nature of the contingency and, where feasible, an estimate of the possible loss. For purposes of the company’s contingency disclosures, "significant" includes material matters, as well as other matters which management believes should be disclosed. Based on a consideration of all relevant facts and circumstances, the company does not believe the ultimate outcome of any currently pending lawsuits against the company will have a material adverse effect on the company’s operations, financial condition, or financial statements taken as a whole. Additionally, the company has other commitments arising in the normal course of business for operating and capital needs, all of which are expected to be fulfilled with no adverse consequences material to the company’s operations, financial condition, or financial statements taken as a whole. Unconditional purchase obligations, as defined by accounting standards, are long-term commitments that are non-cancellable or cancellable only under certain conditions and that third parties have used to secure financing for the facilities that will provide the contracted goods and services. The company has not entered into any unconditional purchase obligations. There were outstanding letters of credit aggregating to $ 668 million at December 31, 2025 (2024 - $ 475 million), issued as security for financial and performance conditions in relation to certain contracts and commitments. These letters of credit do not reduce any available funds under current borrowing arrangements. As a result of the completed sale of the remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2025, for guarantees relating to performance under contracts of other third-party obligations totalling $ 7 million (2024 - $ 10 million). In the fourth quarter of 2025, the company recorded contractual obligations associated with the Norman Wells end of field life acceleration (see note 11, "Miscellaneous financial information"). 99 Note 10. Common shares At December 31 thousands of shares 2025 2024 Authorized 1,100,000 1,100,000 Outstanding 483,593 509,045 The most recent 12-month normal course issuer bid program came into effect June 29, 2025, under which Imperial continued its then-existing share purchase program. The program enabled the company to purchase up to a maximum of 25,452,248 common shares ( 5 percent of the total shares on June 15, 2025) which included shares purchased under the normal course issuer bid from Exxon Mobil Corporation. As in the past, Exxon Mobil Corporation advised the company that it intended to participate to maintain its ownership percentage at approximately 69.6 percent. The program completed on December 17, 2025 as a result of the company purchasing the maximum allowable number of shares under the program. The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of earnings reinvested. The company’s common share activities are summarized below: Thousands of shares Millions of dollars Balance as at January 1, 2023 584,153 1,079 Purchases at stated value ( 48,316 ) ( 87 ) Balance as at December 31, 2023 535,837 992 Purchases at stated value ( 26,792 ) ( 50 ) Balance as at December 31, 2024 509,045 942 Purchases at stated value ( 25,452 ) ( 47 ) Balance as at December 31, 2025 483,593 895 The following table provides the calculation of basic and diluted earnings per common share and the dividends declared by the company on its outstanding common shares: 2025 2024 2023 Net income (loss) per common share – basic Net income (loss) (millions of Canadian dollars) 3,268 4,790 4,889 Weighted-average number of common shares outstanding (millions of shares) 502.8 529.4 574.8 Net income (loss) per common share (dollars) 6.50 9.05 8.51 Net income (loss) per common share – diluted Net income (loss) (millions of Canadian dollars) 3,268 4,790 4,889 Weighted-average number of common shares outstanding (millions of shares) 502.8 529.4 574.8 Effect of employee share-based awards (millions of shares) 1.2 1.2 1.1 Weighted-average number of common shares outstanding, assuming dilution (millions of shares) 504.0 530.6 575.9 Net income (loss) per common share (dollars) 6.48 9.03 8.49 Dividends per common share – declared (dollars) 2.88 2.40 1.94 100 Note 11. Miscellaneous financial information LIFO inventory In 2025, net income included an after-tax gain of $ 61 million (2024 - $ 61 million gain, 2023 - $ 5 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2025 by about $ 1.5 billion (2024 - $ 2.0 billion). Inventories of crude oil and products at year-end consisted of the following: millions of Canadian dollars 2025 2024 Crude oil 1,067 701 Petroleum products 461 513 Chemical products 64 57 Biofuels 225 40 Other 394 331 Total 2,211 1,642 Research and development Research expenditures are mainly spent on developing technologies to improve bitumen recovery, reduce costs and reduce the environmental impact of upstream operations, including technologies to reduce greenhouse gas emissions intensity, supporting environmental and process improvements in the refineries, as well as accessing ExxonMobil’s research worldwide. The company has scientific research agreements with affiliates of ExxonMobil, which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents, and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties. Net research and development costs charged to expenses in 2025 were $ 134 million (2024 - $ 118 million, 2023 - $ 84 million). These costs are included in expenses due to the uncertainty of future benefits. Accounts payable and accrued liabilities “Accounts payable and accrued liabilities” included accrued taxes other than income taxes of $ 393 million at December 31, 2025 (2024 - $ 524 million), dividends payable of $ 350 million at December 31, 2025 (2024 - $ 307 million) and other miscellaneous current liabilities of $ 1,151 million at December 31, 2025 (2024 - $ 739 million). Government assistance ASC 832 "Government Assistance" requires disclosure of certain types of government assistance not otherwise covered by authoritative accounting guidance. The company receives allowances from governments in the form of emission credits as a result of performing better than facility level expectations for emission targets and records these at a nominal amount, generally in "Inventories of crude oil and products" on the Consolidated balance sheet. During 2024 and 2025, government assistance was immaterial to the company’s financial results. 101 Restructuring charges On September 29, 2025, the company announced restructuring plans to improve its performance by centralizing additional corporate and technical activities in global business and technology centres. The restructuring plans include a program of targeted workforce reductions. The program, which is expected to be substantially completed by the end of 2027, involves involuntary employee separations. In the third quarter of 2025, the company recorded charges of $ 330 million, before-tax, consisting primarily of restructuring costs associated with announced workforce reduction programs. These costs are captured in " Selling and general " on the Consolidated statement of income and reported in the Corporate and other segment. The following table summarizes the reserves and charges related to the workforce reduction program, which are recorded in "Accounts payable and accrued liabilities" and "Other long-term obligations" on the Consolidated balance sheet. millions of Canadian dollars 2025 Balance at January 1 — Additions/adjustments 330 Payments made — Balance at December 31 330 Calgary Imperial Campus In the third quarter of 2025, the Corporate and other segment included a non-cash impairment charge of $ 406 million, before-tax, in conjunction with the company signing an agreement to sell the Calgary Imperial Campus. The impairment was reflected in "Depreciation and depletion (includes impairments)" on the Consolidated statement of income and in "Property, plant and equipment, less accumulated depreciation and depletion" on the Consolidated balance sheet. The transaction closed in the fourth quarter of 2025. Norman Wells In the fourth quarter of 2025, the company accelerated the end of field life of the Norman Wells asset, resulting in a $ 421 million expense, before-tax, reported in the Upstream segment. The expense consisted of a non-cash impairment charge of $ 142 million, reflected in "Depreciation and depletion (includes impairments)" on the Consolidated statement of income and in "Property, plant and equipment, less accumulated depreciation and depletion" on the Consolidated balance sheet, and a one-time charge of $ 279 million related to contractual obligations associated with the end of field life acceleration, reflected in "Production and manufacturing" on the Consolidated statement of income. 102 Note 12. Financing and additional notes and loans payable information millions of Canadian dollars 2025 2024 2023 Debt-related interest (a) 131 192 203 Capitalized interest ( 105 ) ( 155 ) ( 141 ) Net interest expense 26 37 62 Other interest ( 14 ) 4 7 Total financing 12 41 69 (a) Includes related party interest with ExxonMobil. During the fourth quarter of 2025, the company extended the maturity dates of its two existing $ 250 million committed lines of credit to November 2026 and November 2027, respectively. The company has not drawn on any of its outstanding $ 500 million of available credit facilities. At December 31, 2025 and at December 31, 2024, the company had no short-term borrowings outstanding. 103 Note 13. Leases The company generally purchases the property, plant and equipment used in operations, but there are situations where assets are leased, primarily storage tanks, rail cars, marine vessels, and transportation and other facilities. Right of use assets and lease liabilities are established on the balance sheet for leases with an expected term greater than one year, by discounting the amounts fixed in the lease agreement for the duration of the lease which is reasonably certain, considering the probability of exercising any early termination and extension options. The portion of the fixed payment related to service costs for tankers and finance leases is excluded from the calculation of right of use assets and lease liabilities. Usually, assets are leased only for a portion of their useful lives and are accounted for as operating leases. In limited situations, assets are leased for nearly all of their useful lives and are accounted for as finance leases. In general, leases are capitalized using the company’s incremental borrowing rate. Variable payments under these lease agreements are not significant. Residual value guarantees, restrictions, or covenants related to leases, and transactions with related parties are also not significant. The company’s activities as a lessor are not material. The table below summarizes the total lease cost incurred: 2025 2024 2023 millions of Canadian dollars Operating leases Finance leases Operating leases Finance leases Operating leases Finance leases Operating lease cost 105 111 114 Short-term and other (net of sublease rental income) 108 50 30 Amortization of right of use assets 16 16 19 Interest on lease liabilities 27 28 29 Total lease cost 213 43 161 44 144 48 The following table summarizes the amounts related to operating leases and finance leases recorded on the Consolidated balance sheet, weighted-average remaining lease term and weighted-average discount rates applied at December 31: 2025 2024 millions of Canadian dollars Operating leases Finance leases Operating leases Finance leases Right of use assets Included in Other assets, including intangibles - net 285 240 Included in Property, plant and equipment, less 582 579 accumulated depreciation and depletion Total right of use assets 285 582 240 579 Lease liability due within one year Included in Accounts payable and accrued liabilities 87 — 100 — Included in Notes and loans payable 19 18 L ong-term lease liability Included in Other long-term obligations 149 — 144 — Included in Long-term debt 531 545 Total lease liability 236 550 244 563 Weighted-average remaining lease term (years) 5 35 5 35 Weighted-average discount rate (percent) 3.2 5.8 4.1 4.8 104 The maturity analysis of the company’s lease liabilities as at December 31 are summarized below: 2025 millions of Canadian dollars Operating leases Finance leases Maturity analysis of lease liabilities 2026 93 49 2027 44 48 2028 39 47 2029 31 45 2030 16 44 2031 and beyond 29 862 Total lease payments 252 1,095 Discount to present value ( 16 ) ( 545 ) Total lease liability 236 550 In addition to the operating lease liabilities in the table immediately above, at December 31, 2025, there were no additional undiscounted commitments for leases not yet commenced (2024 - $ 56 million). There are no estimated cash payments for operating and finance leases not yet commenced in 2026 and 2027. The table below summarizes the cash paid for amounts included in the measurement of lease liabilities and the right of use assets obtained in exchange for new lease liabilities: 2025 2024 2023 millions of Canadian dollars Operating leases Finance leases Operating leases Finance leases Operating leases Finance leases Cash paid for amounts included in the measurement of lease liabilities Cash flows from operating activities 121 — 118 — 56 — Cash flows from financing activities 18 22 22 Non-cash right of use assets recorded for lease liabilities In exchange for lease liabilities during the year 107 17 152 — 61 — 105 Note 14. Long-term debt At December 31 millions of Canadian dollars 2025 2024 Long-term debt (a) (b) 3,447 3,447 Finance leases (c) 531 545 Total long-term debt 3,978 3,992 (a) Borrowed under an existing agreement with an affiliated company of ExxonMobil that provides for a long-term, variable-rate, Canadian dollar loan from ExxonMobil to the company of up to $ 7.75 billion at interest equivalent to Canadian market rates. The agreement is effective until June 30, 2035, cancellable if ExxonMobil provides at least 370 days advance written notice. (b) The weighted-average interest rate on long-term borrowings outstanding with ExxonMobil, at December 31, 2025 was 2.7 percent (2024 - 3.9 percent). (c) Finance leases are primarily associated with transportation facilities and services agreements. The average imputed interest rate was 5.8 percent in 2025 (2024 - 4.8 percent). Total finance lease obligations also include $ 19 million in current liabilities (2024 - $ 18 million). Principal payments on finance leases of approximately $ 17 million on average per year are due in each of the next four years after December 31, 2026. Note 15. Accounting for suspended exploratory well costs The company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project. The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports. The company had no capitalized suspended exploratory well costs as at December 31, 2025, 2024 and 2023. Exploration activity involves drilling multiple wells, over a number of years, to fully evaluate a project. The company had no projects with exploratory wells costs capitalized as at December 31, 2025, 2024 and 2023. 106 Note 16. Transactions with related parties Revenues and expenses of the company also include the results of transactions with affiliated companies of ExxonMobil in the normal course of operations. These were conducted on terms comparable to those which would have been conducted with unrelated parties and primarily consisted of the purchase and sale of crude oil, natural gas, petroleum and chemical products, as well as technical, engineering and research and development costs. Transactions with ExxonMobil also included amounts paid and received in connection with the company’s participation in a number of upstream activities conducted jointly in Canada. In addition, the company has existing agreements with ExxonMobil: a) To provide services to the company and to share common business and operational support services that allow the companies to consolidate duplicate work and systems; b) To operate certain western Canada production properties owned by ExxonMobil, as well as provide for the delivery of management, business and technical services to ExxonMobil in Canada. These agreements are designed to provide organizational efficiencies and to reduce costs. No separate legal entities were created from these arrangements. Separate books of account continue to be maintained for the company and ExxonMobil. The company and ExxonMobil retain ownership of their respective assets, and there is no impact on operations or reserves; c) To provide for the option of equal participation in new upstream opportunities; and d) To enter into derivative agreements on each other’s behalf. Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate. Related party revenues and purchases in 2025 were $ 13,534 million and $ 5,369 million, respectively. Related party revenues and purchases in 2024 have been revised from $ 11,725 million to $ 14,654 million and from $ 3,722 million to $ 6,651 million, respectively. Related party revenues and purchases in 2023 have been revised from $ 13,544 million to $ 16,166 million and from $ 4,125 million to $ 6,747 million, respectively. Impacts of the revision offset to zero. • Related party revenues and purchases with ExxonMobil in 2025 were $ 13,534 million and $ 5,227 million, respectively. Related party revenues and purchases with ExxonMobil in 2024 have been revised from $ 11,725 million to $ 14,654 million and from $ 3,617 million to $ 6,546 million, respectively. Related party revenues and purchases with ExxonMobil in 2023 have been revised from $ 13,544 million to $ 16,166 million and from $ 4,026 million to $ 6,648 million, respectively. Impacts of the revision offset to zero. As at December 31, 2025, the company had an outstanding long-term loan of $ 3,447 million (2024 - $ 3,447 million) from ExxonMobil (see note 14, "Long-term debt", and note 12, "Financing and additional notes and loans payable information" for further details). The amount of financing costs with ExxonMobil in 2025 were $ 97 million (2024 - $ 161 million). Imperial has other related party transactions not detailed above in note 16, as they are not significant. 107 Note 17. Other comprehensive income (loss) information Changes in accumulated other comprehensive income (loss): millions of Canadian dollars 2025 2024 2023 Balance at January 1 ( 214 ) ( 677 ) ( 512 ) Postretirement benefits liability adjustment: Current period change excluding amounts reclassified from accumulated other comprehensive income 181 412 ( 206 ) Amounts reclassified from accumulated other comprehensive income 19 51 41 Balance at December 31 ( 14 ) ( 214 ) ( 677 ) Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense): millions of Canadian dollars 2025 2024 2023 Amortization of postretirement benefits liability adjustment included in net benefit cost (a) ( 25 ) ( 67 ) ( 54 ) (a)  This accumulated other comprehensive income component is included in the computation of net periodic benefit cost (note 4). Income tax expense (credit) for components of other comprehensive income (loss): millions of Canadian dollars 2025 2024 2023 Postretirement benefits liability adjustments: Postretirement benefits liability adjustment (excluding amortization) 59 134 ( 66 ) Amortization of postretirement benefits liability adjustment included in net benefit cost 6 16 13 Total 65 150 ( 53 ) 108 Supplemental information on oil and gas exploration and production activities (unaudited) The information on pages 109 to 110 excludes items not related to oil and natural gas extraction, such as administrative and general expenses, pipeline operations, gas plant processing fees and gains or losses on asset sales. The company’s 25 percent interest in proved synthetic crude oil reserves in the Syncrude joint venture is included as part of the company’s total proved oil and gas reserves and in the calculation of the standardized measure of discounted future cash flows, in accordance with U.S. Securities and Exchange Commission (SEC) and U.S. Financial Accounting Standards Board rules. Results of operations, costs incurred in property acquisitions, exploration and development activities, and capitalized costs include the company’s share of Kearl, Syncrude and other unproved mineable acreages in the following tables. Results of operations millions of Canadian dollars 2025 2024 2023 Revenue Sales to third parties (a) 6,509 7,171 6,420 Transfers (a) (b) 3,010 3,337 3,220 9,519 10,508 9,640 Production expenses 4,828 4,769 5,015 Exploration expenses 7 3 5 Depreciation and depletion 1,697 1,539 1,475 Income taxes 714 974 733 Results of operations 2,273 3,223 2,412 (a) Sales to third parties or transfers do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments or diluent costs. These items are reported gross in note 2 in "Revenues", "Intersegment sales" and in "Purchases of crude oil and products". (b) Sales of crude oil to consolidated affiliates are at market value, using posted field prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be obtainable in a competitive, arm’s-length transaction. The amounts reported as costs incurred in property acquisitions, exploration and development activities include both capitalized costs and costs charged to expense during the year. Costs incurred also include new asset retirement obligations established in the current year, as well as increases or decreases to the asset retirement obligation resulting from changes in cost estimates or abandonment date. Costs incurred in property acquisitions, exploration and development activities millions of Canadian dollars 2025 2024 2023 Property costs (a) Proved — — — Unproved — — — Exploration costs 7 3 5 Development costs 2,178 1,171 1,580 Total costs incurred in property acquisitions, exploration and development activities 2,185 1,174 1,585 (a) "Property costs" are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under "producing assets"). "Proved" represents areas where successful drilling has delineated a field capable of production. "Unproved" represents all other areas. 109 Capitalized costs millions of Canadian dollars 2025 2024 Property costs (a) Proved 1,839 1,840 Unproved 492 492 Producing assets 42,789 41,034 Incomplete construction 2,872 2,555 Total capitalized cost 47,992 45,921 Accumulated depreciation and depletion (23,032) (21,247) Net capitalized costs 24,960 24,674 (a) "Property costs" are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under "producing assets"). "Proved" represents areas where successful drilling has delineated a field capable of production. "Unproved" represents all other areas. Standardized measure of discounted future cash flows As required by the U.S. Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying first-day-of-the-month average prices, year-end costs and legislated tax rates, and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and remediation obligations. The company believes the standardized measure does not provide a reliable estimate of the company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions, including first-day-of-the-month average prices, which represent discrete points in time and therefore may cause significant variability in cash flows from year to year as prices change. Standardized measure of discounted future net cash flows related to proved oil and gas reserves millions of Canadian dollars 2025 2024 2023 Future cash flows 142,478 158,677 158,347 Future production costs (79,939) (88,061) (101,640) Future development costs (24,960) (24,792) (24,074) Future income taxes (8,319) (10,196) (7,016) Future net cash flows 29,260 35,628 25,617 Annual discount of 10 percent for estimated timing of cash flows (13,910) (17,461) (11,615) Discounted future cash flows 15,350 18,167 14,002 Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves millions of Canadian dollars 2025 2024 2023 Balance at beginning of year 18,167 14,002 25,554 Changes resulting from: Sales and transfers of oil and gas produced, net of production costs (4,775) (6,041) (4,918) Net changes in prices, development costs and production costs (a) (3,616) 7,134 (16,908) Extensions, discoveries, additions and improved recovery, less related costs — — 58 Development costs incurred during the year 1,642 1,191 1,182 Revisions of previous quantity estimates 1,085 1,788 2,146 Accretion of discount 1,868 1,485 2,535 Net change in income taxes 979 (1,392) 4,353 Net change (2,817) 4,165 (11,552) Balance at end of year 15,350 18,167 14,002 (a) SEC rules require the company’s reserves to be calculated on the basis of average first-day-of-the-month oil and natural gas prices during the reporting year. Future net cash flows are determined based on the net proved reserves as outlined in the "Net proved reserves table". 110 Net proved reserves (a) Liquids (b) Natural gas Synthetic crude oil Bitumen Total oil-equivalent basis (c) millions of barrels billions of cubic feet millions of barrels millions of barrels millions of barrels Beginning of year 2023 4 72 353 1,824 2,193 Revisions (2) 2 26 90 114 Improved recovery — — — — — (Sale) purchase of reserves in place — (1) — — — Discoveries and extensions — — — — — Production (2) (12) (25) (103) (132) End of year 2023 — 61 354 1,811 2,175 Revisions 2 3 (35) 114 82 Improved recovery — — — — — (Sale) purchase of reserves in place — — — — — Discoveries and extensions — — — — — Production (2) (11) (23) (109) (136) End of year 2024 — 53 296 1,816 2,121 Revisions 2 7 17 37 57 Improved recovery — — — — — (Sale) purchase of reserves in place — — — — — Discoveries and extensions — — — — — Production (2) (11) (25) (113) (142) End of year 2025 — 49 288 1,740 2,036 Net proved developed reserves included above, as of January 1, 2023 4 60 248 1,691 1,953 December 31, 2023 — 53 242 1,706 1,957 December 31, 2024 — 41 190 1,697 1,894 December 31, 2025 — 41 288 1,641 1,936 Net proved undeveloped reserves included above, as of January 1, 2023 — 12 105 133 240 December 31, 2023 — 8 112 105 218 December 31, 2024 — 12 106 119 227 December 31, 2025 — 8 — 99 100 (a) Net reserves are the company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F. (b) Liquids include crude oil and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids. (c) Gas converted to oil-equivalent at six million cubic feet per one thousand barrels. The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2023, 2024 and 2025. The definitions used are in accordance with the SEC Rule 4-10 (a) of Regulation S-X. Proved oil and natural gas reserves are those quantities of oil and gas, which, by analysis of geoscience and engineering data, can be estimated with reasonable certainty to be economically producible – from a given date forward, from known reservoirs, and under existing economic conditions, operating methods and government regulations – prior to the time at which contracts providing the right to operate expire. In some cases, substantial new investments in additional wells and other facilities will be required to recover these proved reserves. 111 In accordance with SEC rules, the year-end reserves volumes, as well as the reserves change categories shown in the proved reserves tables are required to be calculated on the basis of average prices during the 12-month period prior to the ending date of the period covered by the report, determined as an unweighted arithmetic average of the first-day-of-the-month price for each month within such period. These reserves quantities were also used in calculating unit-of-production depreciation rates and in calculating the standardized measure of discounted net cash flow. Revisions in previously estimated volumes of proved reserves for existing fields can occur due to the evaluation or re-evaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes in the average of first-day-of-the-month oil and natural gas prices and/or costs that are used in the estimation of reserves. Revisions can also result from significant changes in either development strategy or production equipment and facility capacity. In 2023, upward revisions of proved bitumen of 0.1 billion barrels were driven by lower royalty obligations associated with lower pricing and minor technical revisions at Cold Lake and Kearl. A slight increase in proved reserves for synthetic crude oil is associated with lower royalty obligations associated with pricing. Conventional proved liquids reserves decreased to zero under existing pricing and operating conditions. In 2024, upward revisions of proved bitumen of 0.1 billion barrels were primarily driven by updates to the Kearl geological model, Kearl well density, and Cold Lake infill drilling, partially offset by reductions associated with higher royalty obligations and Kearl pit limit updates. A decrease to synthetic oil proved reserves is associated with regulatory approval for ore sterilization at Syncrude. In 2025, upward revisions of proved bitumen were primarily driven by steam scheduling, development drilling, LASER process at Cold Lake and lower royalty obligations associated with pricing for both Kearl and Cold Lake. An increase in proved reserves for synthetic crude oil is associated with lower royalty obligation. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to the company. The company’s operating decisions and its outlook for future production volumes are not impacted by proved reserves as disclosed under the SEC definition. Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For liquids and natural gas, net proved reserves are based on estimated future royalty rates as of the date the estimate is made incorporating the applicable governments’ oil and gas royalty regimes. For bitumen, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of each of the Cold Lake and Kearl fields, and they incorporate the Alberta government’s oil sands royalty regime. For synthetic crude oil, net proved reserves are based on the company’s best estimate of average royalty rates over the remaining life of the project, and they incorporate the Alberta government’s oil sands royalty regime. In all cases, actual future royalty rates may vary with production, price and costs. Net proved developed reserves are those volumes that are expected to be recovered through existing wells, facilities, or mining activities with existing equipment and operating methods or in which the cost of the required equipment is relatively minor compared to the cost of a new well or facility. Net proved undeveloped reserves are those volumes that are expected to be recovered as a result of future investments to drill new wells, to recomplete existing wells and/or to install facilities to collect and deliver the production from existing and future wells, facilities, or mining activities. 112 Proxy information section Table of contents Page Nominees for director 114 Director nominee tables 114 Majority voting policy 118 Corporate governance disclosure 119 Corporate governance at a glance 120 Statement of corporate governance practice 121 Composition of our board nominees 121 Tenure of our board nominees 122 Skills and experience of our board members and nominees 123 Independence of our board members and nominees 124 Committee membership of our board 125 Number of meetings 126 Attendance of our board members in 2025 127 Other public company directorships of our board members and nominees 128 Interlocking directorships of our board nominees 128 Director qualification and selection process 129 Director orientation, education and development 130 Board performance assessment 132 Board and committee structure 132 Director compensation 141 Share ownership guidelines of independent directors and chairman, president and chief executive officer 148 Ethical business conduct 149 Restrictions on insider trading 150 Diversity 151 Shareholder engagement 152 Largest shareholders 153 Transactions with Exxon Mobil Corporation 154 Company executives and executive compensation 155 Named executive officers of the company 155 Other executive officers of the company 156 Compensation discussion and analysis 157 Executive summary 158 Compensation design 159 Determining compensation 166 Other compensation elements 170 Risk and governance 172 Executive compensation tables 176 Appendix 186 Appendix A – Board of director and committee charters 186 113 Nominees for director The director nominee tables on the following pages provide information on the seven nominees proposed for election to the board of directors of the company. All of the nominees are now directors and have been since the dates indicated. D.W. Cornhill is a current director and is not standing for re-election in 2026 as he has reached the company’s mandatory retirement age for directors. T.T. Bryja was appointed to the board on September 16, 2025. Included in these tables is information relating to the director nominees’ biographies, independence status, expertise, standing committee memberships, attendance, public board memberships and shareholdings in the company. The information is as of February 11, 2026, the effective date of this circular, unless otherwise indicated. The board of directors has general oversight responsibility for the company’s business and affairs in accordance with applicable laws. In exercising its fiduciary duties, the board considers the interests of all shareholders and is committed to strong corporate governance as reflected through its policies and practices. For more information on our director nominees, please see the Statement of corporate governance practice section. Director nominee tables TANYA T. BRYJA Ms. Bryja serves as senior vice-president of Energy Products, ExxonMobil Product Solutions Company, headquartered in Spring, Texas. She earned a Bachelor of Science degree in Chemical Engineering from Northwestern University in 1997 and joined ExxonMobil that same year. Over the course of her career, Ms. Bryja has held leadership roles across ExxonMobil’s technology, commercial, refining operations, maintenance, technical, and corporate planning organizations with assignments across the United States and Belgium. Ms. Bryja assumed her current position in May 2025, where she oversees the integrated, global Energy Products business, encompassing fuels, aromatics, catalysts, and technology licensing. Houston, Texas, United States of America Age: 51 Non-independent director Director since: September 16, 2025 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Environment and sustainability, Financial expertise, Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 3 of 3 (100%) Executive resources (until January 29, 2026) 3 of 3 (100%) Votes For: n/a Safety and sustainability 2 of 2 (100%) Votes Against: n/a Nominations and corporate governance (until January 29, 2026) 3 of 3 (100%) Total Votes: n/a Finance 3 of 3 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 0 0 0 0 Total market value as at February 11, 2026 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 *No share ownership guidelines apply Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – None *no public board interlocks – Senior vice-president, Energy Products, ExxonMobil Product Solutions Company, (2025 – present) (Affiliate) – Vice-president, fuels, ExxonMobil Fuels & Lubricants Company, (2023 – 2025) (Affiliate) – Site Manager, Joliet Refinery, Exxon Mobil Corporation (2021 – 2023) (Affiliate) – Strategy and planning manager, Research and engineering, Exxon Mobil Corporation (2019 – 2021) (Affiliate) 114 SHARON R. DRISCOLL Ms. Driscoll currently serves as an independent director of Empire Company Limited and as a director of Elswood Investment Corporation, a privately held company. Prior to her retirement in 2023, she held executive leadership roles at RB Global Incorporated, including chief financial officer, co-chief executive officer and executive vice-president and advisor to the chief executive officer. Prior to joining RB Global, Ms. Driscoll was executive vice-president and chief financial officer at Katz Group Canada Ltd. from 2013 to 2015, and senior vice-president and chief financial officer at Sears Canada Inc. from 2008 to 2013. Ms. Driscoll is a Chartered Professional Accountant and has a Bachelor of Commerce (Honours) degree from Queen’s University. Vancouver, British Columbia, Canada Age: 64 Nonemployee director (independent) Director since: May 2, 2023 Skills and experience: Leadership of large organizations, Project management, Global experience, Strategy development, Environment and sustainability, Audit committee financial expert, Financial expertise, Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 9 of 9 (100%) Audit (Chair) 6 of 6 (100%) Votes For: 460,709,337 (97.96%) Executive resources 7 of 7 (100%) Votes Against: 9,602,197 (2.04%) Safety and sustainability 5 of 5 (100%) Total Votes: 470,311,534 Nominations and corporate governance 9 of 9 (100%) Finance 8 of 8 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 3,382 3,382 9,900 13,282 Total market value as at February 11, 2026 ($) 0 548,696 548,696 1,606,176 2,154,872 Year over year change (#) 0 1,031 1,031 3,300 4,331 *Has 5 years from date of appointment to meet the necessary share ownership requirements Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – Empire Company Limited (2018 – Present) – Gildan Activewear Ltd (2023 – 2024) *no public board interlocks – RB Global (formerly Ritchie Bros. Auctioneers Incorporated) Executive vice-president and advisor to CEO (2022 – 2023) – RB Global (formerly Ritchie Bros. Auctioneers Incorporated), Chief financial officer (2015 – 2022) JOHN N. FLOREN Mr. Floren is the former president and chief executive officer of Methanex Corporation. Prior to his appointment to such positions, he held senior leadership roles including senior vice-president, global marketing and logistics and regional director, marketing and logistics for North America. Mr. Floren spent approximately 22 years with Methanex and has over 37 years of experience in the chemical industry. He currently serves as a director of West Fraser Timber Co. Ltd. Mr. Floren holds a Bachelor of Arts in Economics from the University of Manitoba and has completed executive education programs at Harvard Business School (Program for Management Development), INSEAD (International Executive Program), and the Institute of Corporate Directors (Directors Education Program). Oakville, Ontario, Canada Age: 67 Nonemployee director (independent) Director since: May 2, 2023 Skills and experience: Leadership of large organizations, Operations/technical Project management, Global experience, Strategy development, Environment and sustainability, Financial expertise, Government relations Information technology/Cybersecurity oversight Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 9 of 9 (100%) Audit 6 of 6 (100%) Votes For: 458,402,042 (97.47%) Executive resources 7 of 7 (100%) Votes Against: 11,912,559 (2.53%) Safety and sustainability (Chair) 5 of 5 (100%) Total Votes: 470,314,601 Nominations and corporate governance 9 of 9 (100%) Finance 8 of 8 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 3,382 3,382 9,900 13,282 Total market value as at February 11, 2026 ($) 0 548,696 548,696 1,606,176 2,154,872 Year over year change (#) 0 1,031 1,031 3,300 4,331 *Has 5 years from date of appointment to meet the necessary share ownership requirements Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – West Fraser Timber Co. Ltd. (2016 – present) – Methanex Corporation (2013 – 2022) *no public board interlocks – Methanex Corporation, President and chief executive officer (2013 – 2022) 115 GARY J. GOLDBERG Mr. Goldberg has more than 40 years of global experience in the mining industry, spanning executive leadership, operational management and strategic roles. He currently serves as a non-executive director of BHP Group Limited. From 2013 to 2019, Mr. Goldberg served as the chief executive officer of Newmont Corporation, and prior to that, was president and chief executive officer of Rio Tinto Minerals. His previous board roles include non-executive director of Port Waratah Coal Services Limited and Rio Tinto Zimbabwe. In addition, Mr. Goldberg has held prominent industry leadership positions, including vice-chair of the World Gold Council, treasurer of the International Council on Mining and Metals, and chair of the National Mining Association in the United States. Breckenridge, Colorado, United States of America Age: 66 Nonemployee director (independent) Director since: May 2, 2023 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Environment and sustainability, Financial expertise, Government relations, Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 9 of 9 (100%) Audit 6 of 6 (100%) Votes For: 460,671,058 (97.95%) Executive resources (Chair) 7 of 7 (100%) Votes Against: 9,643,543 (2.05%) Safety and sustainability 5 of 5 (100%) Total Votes: 470,314,601 Nominations and corporate governance 9 of 9 (100%) Finance 8 of 8 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 3,382 3,382 9,900 13,282 Total market value as at February 11, 2026 ($) 0 548,696 548,696 1,606,176 2,154,872 Year over year change (#) 0 1,031 1,031 3,300 4,331 *Has 5 years from date of appointment to meet the necessary share ownership requirements Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – BHP Group Limited (2020 – present) *no public board interlocks – Korn Ferry, Consultant (2025 – present) NEIL A. HANSEN Mr. Hansen was appointed senior vice-president and chief financial officer of Exxon Mobil Corporation on February 1, 2026. Prior to this appointment, he served as president of ExxonMobil Global Business Solutions beginning in May 2025. From April 2022 to May 2025, Mr. Hansen held the role of senior vice-president, energy products for ExxonMobil Product Solutions Company, and from March 2020 to April 2022, he was vice-president for Europe, Africa & Middle East fuels. Earlier in his career, Mr. Hansen held several senior finance positions within the corporation’s controllers organization and also served as vice-president, investor relations and corporate secretary at Exxon Mobil Corporation. The Woodlands, Texas, United States of America Age: 51 Non-independent director Director since: April 30, 2024 Skills and experience: Leadership of large organizations, Project management, Global experience, Strategy development, Environment and sustainability, Financial expertise, Government relations, Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 9 of 9 (100%) Votes For: 431,100,735 (91.66%) Executive resources (until January 29, 2026) 7 of 7 (100%) Votes Against: 39,213,866 (8.34%) Safety and sustainability 5 of 5 (100%) Total Votes: 470,314,601 Nominations and corporate governance (until January 29, 2026) 9 of 9 (100%) Finance 8 of 8 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 0 0 0 0 Total market value as at February 11, 2026 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 * No share ownership guidelines apply Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – None *no public board interlocks – Senior vice-president, and chief financial officer, Exxon Mobil Corporation (2026 – present) (Affiliate) – President, global business solutions, ExxonMobil Global Services Company (2025 – 2026) (Affiliate) – Senior vice-president, energy products, ExxonMobil Product Solutions Company (2022 – 2025) (Affiliate) – Vice-president, fuels, ExxonMobil Fuels & Lubricants Company (2020 – 2022) (Affiliate) 116 MIRANDA C. HUBBS Ms. Hubbs is an independent director with deep institutional investment and capital markets experience. She currently serves on the boards of Nutrien Ltd., PSP Investments (Public Sector Pension Investment Board) and is Chair of the Canadian Investment Regulatory Organization (CIRO). She is also Chair of the Board of the Canadian Red Cross. Previously, Ms Hubbs was Executive Vice-President and Managing Director of McLean Budden Ltd., one of Canada’s leading investment management firms prior to its sale to Sun Life. During her investment career, she was recognized by Brendan Wood International TopGun Awards as one of the Top 50 Portfolio Managers in Canada and one of the TopGun Investment Minds in Oil and Gas (Canada). Ms. Hubbs holds a BSc from Western University, an MBA from the Schulich School of Business, and is a CFA charterholder. She holds the FSA (Fundamentals of Sustainability Accounting) credential, the CERT Certificate in Cybersecurity Oversight and is a graduate of the NYU-Nasdaq Center for Board Excellence Cyberscholar Program. In 2025, she was awarded the King Charles III Coronation Medal. Toronto, Ontario, Canada Age: 59 Lead director Nonemployee director (independent) Director since: July 26, 2018 Skills and experience: Global experience, Strategy development, Environment and sustainability, Audit committee financial expert, Financial expertise, Information technology/Cybersecurity oversight Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board 9 of 9 (100%) Audit 6 of 6 (100%) Votes For: 434,627,097 (92.41%) Executive resources 7 of 7 (100%) Votes Against: 35,680,453 (7.59%) Safety and sustainability 5 of 5 (100%) Total Votes: 470,307,550 Nominations and corporate governance (Chair) 9 of 9 (100%) Finance 8 of 8 (100%) Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 22,012 22,012 21,000 43,012 Total market value as at February 11, 2026 ($) 0 3,571,227 3,571,227 3,407,040 6,978,267 Year over year change (#) 0 1,586 1,586 1,800 3,386 *Meets the necessary share ownership requirements Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – Nutrien Ltd. (2018 – present) *no public board interlocks – None JOHN R. WHELAN Mr. Whelan was appointed president of Imperial Oil Limited on April 1, 2025, and assumed the additional roles of chairman and chief executive officer on May 8, 2025. From 2022 until his current appointment, he served as senior vice-president, conventional and heavy oil, ExxonMobil Upstream Company, a division of Exxon Mobil Corporation. Throughout his career, Mr. Whelan has held a variety of engineering, project, operations, commercial and leadership roles located in Canada, Norway, and the United States, with responsibilities spanning global operations. Mr. Whelan served as Imperial Oil’s senior vice president, upstream from 2017 to 2020. Originally from Newfoundland and Labrador, Mr. Whelan holds a bachelor's degree in mechanical engineering from Memorial University in Newfoundland. Calgary, Alberta, Canada Age: 60 Non-independent director Director since: May 8, 2025 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Global experience, Strategy development, Environment and sustainability, Financial expertise, Government relations, Executive compensation, Risk management Board and Standing Committee Membership Attendance in 2025 Voting Results of Last Annual Meeting Board (Chair) 6 of 6 (100%) Votes For: 467,228,982 (99.34%) Votes Against: 3,084,807 (0.66%) Total Votes: 470,313,789 Imperial Oil Limited Ownership and Value of Equity (a) (b) (c) (d) IMO Common Shares (% of class) IMO Deferred Share Units (DSU) Total Vested Equity Holdings (Common + DSU) Restricted Stock Units (RSU) Total Holdings* (Common + DSU + RSU) Holdings as at February 11, 2026 (#) 0 0 0 106,400 106,400 Total market value as at February 11, 2026 ($) 0 0 0 17,262,336 17,262,336 Year over year change (#) 0 0 0 84,400 84,400 *Meets the necessary share ownership requirements Public Company Directorships in the Past Five Years* Other Positions in the Past Five Years (position, date office held and status of employer) – None *no public board interlocks – Chairman, president and chief executive officer, Imperial Oil Limited (2025 – present) – Senior vice-president, conventional and heavy oil, ExxonMobil Upstream Company (2022 – 2025) (Affiliate) – Vice-president, heavy oil, ExxonMobil Upstream Company (2020 – 2022) (Affiliate) 117 Footnotes to director nominee tables on pages 114 through 117 : (a) The information includes the beneficial ownership of common shares of Imperial Oil Limited, which information not being within the knowledge of the company has been provided by the nominees individually. (b) The company’s plan for restricted stock units for nonemployee directors is described on page 144 . The company’s plan for deferred share units for nonemployee directors is described on page 143 . The company’s plan for restricted stock units for selected employees is described on page 163 . (c) The numbers for the company’s restricted stock units represent the total of the outstanding restricted stock units received in 2018 through 2025 and deferred share units received since directors’ appointment. (d) The value for Imperial Oil Limited common shares, deferred share units and restricted stock units is based on the closing price for Imperial Oil Limited common shares on the Toronto Stock Exchange of $162.24 on February 11, 2026. Director and nominee holdings in Exxon Mobil Corporation (a) Director XOM Common Shares (#) XOM Restricted Stock (#) (b) Total Common Shares and Restricted Stock (#) Total Market Value of Common Shares and Restricted Stock ($) (c) T.T. Bryja 2,968 58,550 61,518 12,989,965 N.A. Hansen 0 241,500 241,500 50,994,450 J.R. Whelan 36,859 73,800 110,659 23,366,438 (a) Holdings as at February 11, 2026. The information includes the beneficial ownership of common shares of Exxon Mobil Corporation, which information not being within the knowledge of the company has been provided by the nominees and directors individually. None of these individuals own more than 0.01 percent of the outstanding shares of Exxon Mobil Corporation. D.W. Cornhill, S.R. Driscoll, J.N. Floren, G.J. Goldberg and M.C. Hubbs do not own common shares or hold restricted stock of Exxon Mobil Corporation. (b) The numbers for Exxon Mobil Corporation restricted stock include outstanding restricted stock and restricted stock units granted under its restricted stock plan which is similar to the company’s restricted stock unit plan. (c) The value for Exxon Mobil Corporation common shares and restricted stock is based on the closing price for Exxon Mobil Corporation common shares on the New York Stock Exchange of $155.56 U.S., which is converted to Canadian dollars at the daily rate of exchange of 1.3574 provided by the Bank of Canada for February 11, 2026. Majority voting policy In 2022, amendments to the Canada Business Corporations Act came into force implementing majority voting requirements for uncontested director elections. These amendments provide for the election of a director only if the number of “for” votes represents a majority of the votes cast both “for” and “against” the director. Following the implementation of these amendments, the company’s existing majority voting policy was rendered redundant and was revoked by the board. 118 Corporate governance disclosure Table of contents Corporate governance disclosure 119 2025 Corporate governance highlights 119 Corporate governance at a glance 120 Statement of corporate governance practice 121 Composition of our board nominees 121 Tenure of our board nominees 122 Skills and experience of our board members and nominees 123 Independence of our board members and nominees 124 Committee membership of our board 125 Number of meetings 126 Attendance of our board members in 2025 127 Other public company directorships of our board members and nominees 128 Interlocking directorships of our board nominees 128 Director qualification and selection process 129 Director orientation, education and development 130 Board performance assessment 132 Board and committee structure 132 Director compensation 141 Director compensation table 146 Outstanding share-based awards and option-based awards for directors 147 Incentive plan awards for directors - Value vested or earned during the year 147 Share ownership guidelines of independent directors and chairman, president and chief executive officer 148 Ethical business conduct 149 Restrictions on insider trading 150 Diversity 151 Shareholder engagement 152 Largest shareholders 153 Transactions with Exxon Mobil Corporation 154 2025 Corporate governance highlights • Five of eight of our current directors, and four of seven of our director nominees, are independent and meet the criteria for independence set by Canadian securities regulators, the SEC and the NYSE American LLC. • The company delivered an extensive orientation program to J.R. Whelan and T.T. Bryja upon their election to the board for the first time in 2025. • The directors are highly qualified with diversity of gender, background, experience and skill. • The company’s independent directors have significant stock ownership requirements, all of which have been met (S.R. Driscoll, J.N. Floren and G.J. Goldberg were each elected to the board on May 2, 2 023 and are expected to meet the share ownership guidelines within five years from the date of their appointment). The independent directors collectively have nearly $20.1 million in shareholdings in the company. • The independent directors regularly meet in executive se ssions without management present. • J.R. Whelan was appointed as president of the company on April 1, 2025 and assumed the additional roles of chairman and chief executive officer on May 8, 2025 in connection with B.W. Corson’s retirement . J.R. Whelan satisfies the company's chief executive officer share ownership guidelines. • Shares of the company are listed on the TSX and trade on the NYSE American LLC, and our corporate governance practices comply with applicable policies and practices of each exchange. • 96% average vote in favour for the election of our directors at the 2025 annual meeting. • Three of seven or 43% of the director nominees, and 7 of 22 or 32% of the executive officers of the company and its major subsidiaries, are women. 119 Corporate governance at a glance Controlled company Yes Size of board (current / nominees) 8 / 7 Number of independent directors (current / nominees) 5 / 4 Women on board (current and nominees) 3 Average attendance of directors at board and committee meetings 100% Lead director Yes In camera sessions of independent directors at every board meeting Yes Independent status of audit committee 100% Audit committee members financially literate All Independent status of executive resources committee (current) 100% Independent status of nominations and corporate governance committee (current) 100% Majority of independent directors on all committees Yes Individual director elections Yes Average tenure of director nominees (approximate) 3 years Average age of director nominees (approximate) 60 years Mandatory retirement age 72 years Separate board chair and CEO No Number of board interlocks None No director serves on more than two boards of another reporting issuer Yes Share ownership requirements for independent directors Yes Share ownership requirements for chairman and chief executive officer Yes Board orientation and education program Yes Code of business conduct and ethics Yes Board and committee charters Yes Position descriptions for the chairman and chief executive officer, lead director and the chair of each committee Yes Skills matrix for directors Yes Annual board evaluation process Yes Annual advisory vote on executive compensation No Dual-class shares No Change of control agreements No 120 Statement of corporate governance practice The company continually reviews its governance practices and monitors regulatory changes. This section provides information pertaining to our board, the committees of the board, ethics, diversity and shareholder engagement. The company is committed to high corporate governance standards and best practices. The company’s corporate governance policies and practices comply with and in most cases exceed the requirements of National Instrument 52-110 Audit Committees (NI 52-110), National Policy 58-201 Corporate Governance Guidelines (NP 58-201) and National Instrument 58-101 Disclosure of Corporate Governance Practices (NI 58-101). The company’s common shares trade on the Toronto Stock Exchange and the NYSE American LLC, and our corporate governance practices reflect the standards of these exchanges. In accordance with NYSE American LLC requirements for non-U.S. companies, the company is in compliance with NYSE American standards in all significant respects except as described on the company’s website at www.imperialoil.ca. References in this proxy circular to the company’s website are provided only as a convenience and do not constitute, and should not be viewed as, an incorporation by reference of the information contained on, or available through, the website. Therefore, such information should not be considered part of this proxy circular. Composition of our board nominees More information on diversity, including on the board and among executive officers of the company, can be found at page 151 . 121 Tenure of our board nominees Our board nominees have varying lengths of tenure providing a blend of continuity and renewal that supports effective governance. The board charter provides that incumbent directors will not be re-nominated if they have attained the age of 72, except under exceptional circumstances and at the request of the chairman. The company does not have term limits for independent directors because it values the comprehensive knowledge of the company that long-serving directors possess and independent directors are expected to remain qualified to serve for a minimum of five years. The following chart shows the current years of service of the nominees for the board of directors and the year they would normally be required to retire from the board. Name of director nominee Years of service on the board Year of mandatory retirement from the board for independent directors T.T. Bryja 5 months — S.R. Driscoll 3 years 2034 J.N. Floren 3 years 2031 G.J. Goldberg 3 years 2031 N.A. Hansen 2 years — M.C. Hubbs 7 years 2039 J.R. Whelan 1 year — 122 Skills and experience of our board members and nominees Our directors and nominees bring a wide range of skills, diversity and experience. The current directors and director nominees have the experience and expertise required to ensure effective oversight, stewardship and governance of the company. The key areas of experience and skills for each of the nominees for election as directors can also be found in each of the director nominee tables on pages 114 through 118 of this circular. The table below sets out the diverse skill set required of the board and identifies the particular experience, qualifications, attributes, and skills of each director and nominee that led the board to conclude that such person should serve as a director of the company. T.T. Bryja (a)(b) D.W. Cornhill (c) S.R. Driscoll J.N. Floren G.J. Goldberg N.A. Hansen (b) M.C. Hubbs J.R. Whelan Leadership of large organizations ü ü ü ü ü ü ü Operations / technical ü ü ü ü ü Project management ü ü ü ü ü ü ü Global experience ü ü ü ü ü ü ü Strategy development ü ü ü ü ü ü ü ü Environment and sustainability ü ü ü ü ü ü ü ü Audit committee financial expert ü ü ü Financial expertise ü ü ü ü ü ü ü ü Government relations ü ü ü ü Information technology / cybersecurity oversight ü ü Executive compensation ü ü ü ü ü ü ü ü Risk management ü ü ü ü ü ü ü ü (a) T.T. Bryja was appointed to the board and the nominations and corporate governance committee, finance committee, safety and sustainability committee and executive resources committee on September 16, 2025. (b) As of January 29, 2026, in connection with the board’s periodic review of its governance structures and practices, the executive resources committee and the nominations and corporate governance committee consist solely of independent directors, and as a result T.T. Bryja and N.A. Hansen ceased serving on those committees. (c) D.W. Cornhill is a current director and is not standing for re-election in 2026 as he has reached the company’s mandatory retirement age for directors. 123 Independence of our board members and nominees Four out of seven of the director nominees are independent. The board is currently composed of eight directors, seven of whom will be standing for re-election at the annual meeting of shareholders on May 4, 2026. D.W. Cornhill is a current director, but will not stand for re-election as he has reached the company's mandatory retirement age for directors. The majority of the board (five out of eight) and nominees (four out of seven) are independent. The independent directors and nominees are not employees of the company. The board determines independence on the basis of the standards specified by National Instrument 52-110 Audit Committees (NI 52-110) , the U.S. Securities and Exchange Commission rules and the listing standards of the NYSE American LLC. The board has reviewed relevant relationships between the company and each nonemployee director and director nominee to determine compliance with these standards. Based on the directors’ responses to an annual questionnaire, the board determined that none of the independent directors has any interest, business or other relationship that could or could reasonably be perceived to constitute a material relationship with the company. J.R.Whelan is a director and chairman, president and chief executive officer of the company and is not considered to be independent. The board believes that Mr. Whelan's extensive knowledge of the business of the company and Exxon Mobil Corporation is beneficial to the other directors and his participation enhances the effectiveness of the board. T.T. Bryja and N.A. Hansen are also non-independent directors as they are both employees of Exxon Mobil Corporation. Ms. Bryja holds the position of senior vice-president, energy products at ExxonMobil Product Solutions Company, a division of Exxon Mobil Corporation. Mr. Hansen holds the position of senior vice-president and chief financial officer, Exxon Mobil Corporation. The company believes that Ms. Bryja and Mr. Hansen, although deemed non-independent under the relevant standards by virtue of their employment, can be viewed as independent of the company’s management and that their ability to reflect the perspective of the company’s shareholders enhances the effectiveness of the board. Name of director and/or nominee Management Independent Not independent Reason for non-independent status T.T. Bryja ü T.T. Bryja is an employee of Exxon Mobil Corporation. D.W. Cornhill (a) ü S.R. Driscoll ü J.N. Floren ü G.J. Goldberg ü N.A. Hansen ü N.A. Hansen is an employee of Exxon Mobil Corporation. M.C. Hubbs ü J.R. Whelan ü ü J.R. Whelan is a director and chairman, president and chief executive officer of Imperial Oil Limited. (a) D.W. Cornhill is a current director and is not standing for re-election at the annual meeting of shareholders as he has reached the company's mandatory retirement age for directors. 124 Committee membership of our board Each standing committee is chaired by a different independent director and all of the independent directors are members of each committee. The chart below shows the company’s current standing committee memberships and the chair of each committee. Director Nominations and corporate governance committee Audit committee (b) Safety and sustainability committee Executive resources committee Finance committee T.T. Bryja (a) — — ü — ü D.W. Cornhill (c) (d) ü ü ü ü ü Chair S.R. Driscoll (c) ü ü Chair ü ü ü J.N. Floren ü ü ü Chair ü ü G.J. Goldberg ü ü ü ü Chair ü N.A. Hansen (a) — — ü — ü M.C. Hubbs (c) ü Chair ü ü ü ü J.R. Whelan (a) — — — — — (a) Not independent directors. T.T. Bryja and N.A. Hansen were members of the nominations and corporate governance committee and executive resources committee during 2025. As of January 29, 2026, in connection with the board’s periodic review of its governance structures and practices, the executive resources committee and the nominations and corporate governance committee consist solely of independent directors, and as a result T.T. Bryja and N.A. Hansen ceased serving on those committees. (b) All members of the audit committee are independent and financially literate within the meaning of National Instrument 52-110 Audit Committees and the listing standards of the NYSE American LLC. (c) Audit committee financial experts under U.S. regulatory requirements. (d) D.W. Cornhill is a current director and is not standing for re-election at the annual meeting of shareholders as he has reached the company's mandatory retirement age for directors. In addition to its standing committees, the board may establish ad hoc committees or special committees from time to time. 125 Number of meetings The board meets at least seven times each year to ensure regular oversight and timely decision-making. The chart below shows the number of board and standing committee meetings held in 2025. This includes seven regular meetings and two additional special meetings of the board. Meetings of the board and standing committees in 2025: 126 Attendance of our board members in 2025 100% board and standing committee meeting attendance from all members. The following chart provides a summary of the attendance record of each of the directors and nominees in 2025. The attendance record of each director nominee is also set out in their biographical information within the nominee section. The attendance chart also provides an overall view of the attendance per standing committee. Senior management directors and other members of management periodically attend standing committee meetings at the request of the committee chair. Director Board Audit committee Executive resources committee Safety and sustainability committee Nominations and corporate governance committee Finance committee Annual meeting Total Percentage by director T.T. Bryja (a)(b) 3 of 3 — 3 of 3 2 of 2 3 of 3 3 of 3 — 14 of 14 100% D.W. Cornhill 9 of 9 6 of 6 7 of 7 5 of 5 9 of 9 8 of 8 (chair) 1 of 1 45 of 45 100% B.W. Corson (c) 3 of 3 — — — — — 1 of 1 4 of 4 100% S.R. Driscoll 9 of 9 6 of 6 (chair) 7 of 7 5 of 5 9 of 9 8 of 8 1 of 1 45 of 45 100% J.N. Floren 9 of 9 6 of 6 7 of 7 5 of 5 (chair) 9 of 9 8 of 8 1 of 1 45 of 45 100% G.J. Goldberg 9 of 9 6 of 6 7 of 7 (chair) 5 of 5 9 of 9 8 of 8 1 of 1 45 of 45 100% N.A. Hansen (b) 9 of 9 — 7 of 7 5 of 5 9 of 9 8 of 8 1 of 1 39 of 39 100% M.C. Hubbs 9 of 9 6 of 6 7 of 7 5 of 5 9 of 9 (chair) 8 of 8 1 of 1 45 of 45 100% J.R. Whelan (d) 6 of 6 (chair) — — — — — 1 of 1 7of 7 100% Percentage by committee 100% 100% 100% 100% 100% 100% 100% 289 of 289 Overall attendance 100% (a) T.T. Bryja was appointed to the board and its committees (other than the audit committee) on September 16, 2025. (b) As of January 29, 2026, in connection with the board’s periodic review of its governance structures and practices, the executive resources committee and the nominations and corporate governance committee consist solely of independent directors, and as a result T.T. Bryja and N.A. Hansen ceased serving on those committees. (c) B.W. Corson was succeeded as president by J.R. Whelan on April 1, 2025 and continued as chairman and chief executive officer until his retirement from those positions on May 8, 2025. (d) J.R. Whelan was appointed as president of the company effective April 1, 2025. Mr. Whelan assumed the additional roles of chief executive officer and chairman of the board on May 8, 2025, in connection with B.W. Corson's retirement. 127 Other public company directorships of our board members and nominees No director or nominee serves on more than two boards of another reporting issuer. The following table shows which directors and nominees serve on the boards of other reporting issuers and the committee memberships in those companies. Name of director or nominee Other reporting issuers of which director or nominee is also a director Type of company Stock symbol: Exchange Committee appointments T.T. Bryja — — — — D.W. Cornhill (a) AltaGas Ltd. Diversified energy company ALA:TSX Environment, health and safety committee S.R. Driscoll Empire Company Limited Food retailing EMP.A:TSX Audit committee (chair), Nominating committee, and Corporate governance and social responsibility committee J.N. Floren West Fraser Timber Co. Ltd Basic Materials- Forest Products WFG:TSX Health, safety and environment committee (chair), Human resources and compensation committee, and Governance and nominating committee G.J. Goldberg BHP Group Limited Basic Materials- Other industrial Metals and mining BHP:ASX Sustainability committee and Nomination and governance committee N.A. Hansen — — — — M.C. Hubbs Nutrien Ltd. Fertilizer manufacturing NTR:TSX, NYSE