IMPERIAL OIL LTD 10-K

imo-20221231 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 , 2022 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 Securities Exchange Act of 1934. 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 and post 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 Securities Exchange Act of 1934. Large accelerated filer ✓ Smaller reporting company…… Accelerated filer..... Emerging growth company…… Non-accelerated filer..... 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. ✓ Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934). Yes..... No ✓ As of the last business day of the 2022 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $ 11,744,615,092 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 8, 2023, was 584,152,718 . 1 Table of contents Page PART I 5 Item 1. Business 5 Upstream 6 Disclosure of reserves 6 Proved undeveloped reserves 7 Oil and gas production, production prices and production costs 8 Drilling and other exploratory and development activities 10 Present activities 12 Delivery commitments 12 Oil and gas properties, wells, operations and acreage 13 Downstream 15 Supply and trading 15 Transportation 15 Refining 15 Distribution 15 Marketing 16 Chemical 16 Human capital resources 17 Competition 17 Government regulations 18 The company online 20 Item 1A. Risk factors 21 Item 1B. Unresolved staff comments 30 Item 2. Properties 30 Item 3. Legal proceedings 30 Item 4. Mine safety disclosures 30 PART II 31 Item 5. Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities 31 Item 7. Management’s discussion and analysis of financial condition and results of operations 32 Item 7A. Quantitative and qualitative disclosures about market risk 32 Item 8. Financial statements and supplementary data 33 Item 9. Changes in and disagreements with accountants on accounting and financial disclosure 33 Item 9A. Controls and procedures 33 Item 9B. Other information 33 Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections 33 PART III 34 Item 10. Directors, executive officers and corporate governance 34 Item 11. Executive compensation 34 Item 12. Security ownership of certain beneficial owners and management and related stockholder matters 35 Item 13. Certain relationships and related transactions, and director independence 36 Item 14. Principal accountant fees and services 37 PART IV 38 Item 15. Exhibits, financial statement schedules 38 Item 16. Form 10-K summary 39 SIGNATURES 40 Financial section 41 Proxy information section 111 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 emission-reduction roadmaps or future plans related to carbon capture, biofuel, hydrogen, plastics recycling and other plans to drive towards net -zero emissions are dependent on future market factors, such as continued technological progress and policy support, 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 improvement of recovery through experimental operations; the infill development drilling program at Cold Lake; the timing, cost, efficiency and production of the Leming and SAGD Grand Rapids Phase 1 and LASER projects at Cold Lake and the Aspen project; the continued evaluation of other oil sands leases and unconventional assets; the upstream focus on key oil sands assets; future activities with respect to Beaufort Sea licences; the impact of the Kearl Boiler Flue Gas heat recovery unit, and progressing plans for application to up to four additional boilers by year end 2023; the ability of rail infrastructure to mitigate pipeline capacity constraints; human capital resources strategy and impact; anticipated capital and operating expenditures, including with respect to environmental protection; continued evaluation of the company’s share purchase program; being well positioned to participate in future investments and reduce commodity price risk; the company’s long-term business outlook including demand, supply and energy mix and pathways related to greenhouse gas emissions; the impact of participation in the Pathways alliance; Imperial’s company-wide net-zero goal by 2050 (Scope 1 and 2) and the company’s greenhouse gas emissions intensity goal for 2030 for its oil sands operations; the extent of ongoing effects of current global economic uncertainty and geopolitical events affecting supply and demand, including inflation, and the company’s ability to mitigate cost impacts and offset inflationary pressure; segment growth, competitive strategies and benefits from an integrated business model; the ability of the company’s current investment strategy of value and select volume growth to deliver robust returns and support long term growth; continued evaluation of opportunities such as rail shipments and pace of the Aspen project; the impact of Downstream strategies and competitive position and the expected volatility of refining margins; potential impacts from environmental risks, carbon policy, climate related regulations and biofuels mandates; the timing and production from the renewable diesel facility at Strathcona; the benefits to the Chemical business from integration with the Sarnia refinery and relationship with ExxonMobil; capital structure and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; expected full year capital expenditures of about $1.7 billion for 2023; earnings sensitivities; 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 compensation plan in long term performance and mitigating risk; the progress and impact of various initiatives including with E3 Lithium, Air Products, FLO and Atura Power; and the impact of the Sarnia products pipeline. 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; commodity prices and foreign exchange rates; 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, including its investment in the renewable diesel complex at Strathcona and the Leming, Grand Rapids and LASER projects at Cold Lake; the adoption and impact of new facilities or technologies on reductions to GHG emissions intensity, including technologies using solvents to replace energy intensive steam at Cold Lake, boiler flue gas technology at Kearl, 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; that any required support from policymakers and other stakeholders for various new technologies such as carbon capture and storage will be provided; 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; performance of third party service providers; receipt of regulatory and third party approvals in a timely manner; applicable laws and government policies, including with respect to climate change, GHG emissions reductions and low carbon fuels; refinery utilization and product sales; the ability to offset any ongoing inflationary pressures; cash generation, financing sources and capital structure, such as dividends and shareholder returns, including the timing and amounts of share repurchases; progression of COVID-19 and its impacts on Imperial’s ability to operate its assets; capital and environmental expenditures; the capture of 3 efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies; 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 or seasonal fluctuations and resulting demand, price, differential and margin impacts; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates, tax laws including taxes on share buybacks, and actions in response to COVID-19; environmental risks inherent in oil and gas activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; government policies supporting lower carbon investment opportunities; failure or delay of supportive policy and market development for emerging lower-emission energy technologies; the receipt, in a timely manner, of regulatory and third-party approvals; third-party opposition to company and service provider operations, projects and infrastructure; availability and allocation of capital; availability and performance of third-party service providers; unanticipated technical or operational difficulties; management effectiveness and disaster response preparedness; commercial negotiations; project management and schedules and timely completion of projects; unexpected technological developments; the results of research programs and new technologies, including with respect to greenhouse gas emissions, and the ability to bring new technologies to commercial scale on a cost-competitive basis; reservoir analysis and performance; the ability to develop or acquire additional reserves; operational hazards and risks; cybersecurity incidents; currency exchange rates; the impacts of COVID-19 or other public health crises, including the effects of government responses on people and economies; general economic conditions, including 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 Oil Limited. 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 necessarily material to investors or requiring 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. For example, the International Energy Agency (IEA) describes its Net Zero Emissions (NZE) by 2050 scenario as extremely challenging, requiring unprecedented innovation, unprecedented international cooperation and sustained support and participation from consumers. 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. 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. 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. 4 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 and lower-emission fuels. 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”. 5 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, 2022, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 41 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 ending 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, 2022 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 4 60 248 1,691 1,953 Undeveloped — 12 105 133 240 Total net proved 4 72 353 1,824 2,193 (a) Liquids include crude oil, condensate 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 well information such as flow rates and reservoir pressures, and 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, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. 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 2022 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. 6 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 Imperial’s proved reserves. This group also maintains the official reserves estimates for Imperial’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 20 years of petroleum industry experience, including 11 years of reserves related experience. 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 an average of 14 years of relevant technical experience in evaluating reserves, of whom 18 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 15 persons with an average of 11 years of relevant experience in evaluating and managing the evaluation of reserves. Proved undeveloped reserves As at December 31, 2022, approximately 11 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 240 million oil-equivalent barrels. Proved undeveloped reserves are associated with Syncrude and Cold Lake. This compared to 386 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2021. The decrease of 146 million oil-equivalent barrels of proved undeveloped reserves includes a decrease of 133 million oil-equivalent barrels at Cold Lake associated with a shift of future development from the traditional Cyclic Steam Stimulation (CSS) to lower emissions intensity, solvent based technologies, a decrease of 7 million oil-equivalent barrels at Syncrude, and a decrease of 6 million oil-equivalent barrels due to the Montney and Duvernay unconventional assets sale. No proved undeveloped reserves were converted into proved developed reserves during 2022. Proved undeveloped reserves that have remained undeveloped for five years or more represent about 6 percent (14 million oil-equivalent barrels) of proved undeveloped reserves and are associated with ongoing development programs at Cold Lake. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the asset. The company is reasonably certain that these 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, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. 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 $167 million during the year to progress the development of proved undeveloped reserves at Cold Lake and Syncrude. These investments represented about 15 percent of the $1,128 million in total reported Upstream capital and exploration expenditures. 7 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” on page 47 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, 2022 was as follows. All reported production volumes were from Canada. thousands of barrels per day (a) 2022 2021 2020 Bitumen: Kearl: - gross (b) 172 186 158 - net (c) 157 178 155 Cold Lake: - gross (b) 144 140 132 - net (c) 106 114 124 Total bitumen: - gross (b) 316 326 290 - net (c) 263 292 279 Synthetic crude oil (d) : - gross (b) 77 71 69 - net (c) 63 62 68 Liquids (e) : - gross (b) 9 11 13 - net (c) 9 10 12 Total: - gross (b) 402 408 372 - net (c) 335 364 359 (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, condensate 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, 2022 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. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 47 of this report for a narrative discussion on the material changes. millions of cubic feet per day (a) 2022 2021 2020 Gross production (b) (c) 85 120 154 Net production (c) (d) (e) 83 115 150 Net production available for sale (f) 50 81 115 (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. 8 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) 2022 2021 2020 Total production oil-equivalent basis: - gross (b) 416 428 398 - net (c) 349 383 384 (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, 2022 were as follows. Canadian dollars per barrel 2022 2021 2020 Bitumen 84.67 57.91 25.69 Synthetic crude oil 125.46 81.61 49.76 Liquids (a) 93.77 59.41 27.40 Canadian dollars per thousand cubic feet Natural gas 5.69 3.83 1.90 (a) Liquids include crude oil, condensate and NGLs. In 2022, Imperial's average Canadian dollar realization for bitumen increased generally in line with Western Canada Select (WCS). The company's average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs and reflect a premium over WTI driven by supply and demand. In 2021, Imperial’s average Canadian dollar realizations for bitumen increased generally in line with Western Canada Select (WCS). The company’s average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs. Average unit production costs Canadian dollars per barrel 2022 2021 2020 Bitumen 39.05 29.06 25.73 Synthetic crude oil 68.00 61.97 45.51 Total oil-equivalent basis (a) 44.02 34.32 28.73 (a) Includes liquids, bitumen, synthetic crude oil and natural gas. In 2022, bitumen unit production costs increased, primarily driven by higher energy costs. In 2022, synthetic crude oil unit production costs increased, primarily driven by higher energy costs. In 2021, bitumen unit production costs increased, primarily driven by higher energy costs. In 2021, synthetic crude oil unit production costs increased, primarily driven by higher maintenance costs and mine tailings spend. 9 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, 2022. wells 2022 2021 2020 Net productive exploratory — — — Net dry exploratory — — — Net productive development 24 13 29 Net dry development — — — Total 24 13 29 In 2022, wells drilled to add productive capacity include 24 development wells at Cold Lake. In 2021, wells drilled to add productive capacity include 12 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets. In 2020, wells drilled to add productive capacity include 28 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets. Wells drilling At December 31, 2022, the company was drilling the following development wells to add productive capacity at Cold Lake. All wells were located in Canada. 2022 Wells Gross Net Total 21 21 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 2022, additional wells were drilled on existing phases. In 2023, an infill 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, with development activities to commence in 2023 and start-up planned in 2024. The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques. Aspen, Cold Lake expansion and other 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 Alberta Energy Regulator. 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. Aspen’s project pace will continue to be evaluated and remains an important opportunity for Imperial. 10 In August 2018, Imperial received regulatory approval from the Alberta Energy Regulator for an expansion project at Cold Lake to develop the Grand Rapids interval using SA-SAGD technology, capable of producing 50,000 barrels per day before royalties. Imperial intends to develop the Grand Rapids reservoir through capital-efficient investments that make use of available steam capacity from existing plants, with the initial phase of Grand Rapids development planned as an extension from the Nabiye plant. In April 2022, the Grand Rapids Phase 1 (GRP1) project was approved by the company's board with a forecasted average production of 15,000 barrels per day before royalties. Development activities are planned to be completed by year-end 2023. Work progresses on technical and technology evaluations to support potential Clarke Creek, Corner, Clyden and Chard 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. Montney and Duvernay The company owned a 50 percent interest in XTO Energy Canada, which included Montney and Duvernay unconventional assets located in central Alberta. On August 31, 2022, jointly with ExxonMobil Canada, Imperial sold its interests in XTO Energy Canada to Whitecap Resources Inc. The sale completed the marketing effort announced in January 2022, and is consistent with Imperial’s strategy to focus upstream resources on key oil sands assets and its commitment to deliver long-term value to shareholders. The assets included 567,000 net acres in the Montney shale, 72,000 net acres in the Duvernay shale and additional acreage in other areas of Alberta. Net production from these assets was about 140 million cubic feet of natural gas per day and about 9,000 barrels of crude, condensate and natural gas liquids per day. The sale of the assets followed the company's ramp down of drilling activity and adjustment of long-term development plans in 2020 and 2021. 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 through the completion of the Beaufort Regional Strategic Environmental Assessment (BR-SEA) review. In 2022, the prohibition was extended to December 31, 2023 with a second one-year extension. During this time, the Federal Government plans to finalize the BR-SEA for public release which will be subject to a stakeholder review period that will aim to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic. The company continues to hold the licences while maintaining community engagement and participation in the BR-SEA 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. 11 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 by pipeline and rail. During 2022, the company’s share of Kearl’s net bitumen production was about 157,000 barrels per day and gross production was about 172,000 barrels per day. Total gross production for Kearl was about 242,000 barrels per day (172,000 barrels Imperial’s share), down 21,000 barrels per day (14,000 barrels Imperial's share) compared to 2021, as a result of extreme cold weather impacts in the first quarter of 2022. In 2022, the company successfully completed the startup of the second Boiler Flue Gas Unit, incorporating learnings from the first unit's startup in 2021. This technology recovers waste heat from a boiler’s combustion exhaust to pre-heat process water. Each unit has the potential to reduce operating costs and emissions. Imperial is currently progressing plans to apply this innovative technology on up to four additional boilers by year-end 2023. 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. During 2022, net bitumen production at Cold Lake was about 106,000 barrels per day and gross production was about 144,000 barrels per day. Gross production increased about 4,000 barrels per day compared to 2021 as a result of improved reliability, production optimizations, and recent capital-efficient infill drilling. Cold Lake has expanded its commercial application of Liquid Addition to Steam for Enhanced Recovery (LASER), with the technology now being applied to approximately 10 per cent of production, resulting in reduced greenhouse gas emissions compared to traditional CSS technology. 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 2022, the company’s share of Syncrude’s net production was about 63,000 barrels per day. The gross production was about 77,000 barrels per day, which is an increase of about 6,000 barrels per day compared to 2021, supported by the interconnect pipeline. 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. Delivery commitments The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements. 12 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, 2022 and December 31, 2021, is set forth in the following table. The statistics in the table are determined in part from information received from other operators. The total number of wells decreased in 2022 primarily due to divestment activities and the shut-in of multiple non-economical wells. Year ended December 31, 2022 Year ended December 31, 2021 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) 4,277 4,264 2,419 774 4,557 4,509 2,729 885 (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 2022, the company had an interest in 12 gross wells with multiple completions (2021 - 12 gross wells). Land holdings At December 31, 2022 and December 31, 2021, 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 2022 2021 2022 2021 2022 2021 Western provinces (a): Liquids and gas - gross (b) 441 1,059 185 621 626 1,680 - net (c) 260 517 135 350 395 867 Bitumen - gross (b) 196 196 584 584 780 780 - net (c) 182 182 255 255 437 437 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) 65 65 146 267 211 332 - net (c) 6 6 22 36 28 42 Total (e) : - gross (b) 823 1,441 2,818 3,375 3,641 4,816 - net (c) 480 737 932 1,161 1,412 1,898 (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). 13 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 173,000 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 30,000 net acres of oil sands leases in the Corner area, about 29,000 net acres in the Clarke Creek area and about 18,000 net acres in the Chard area. The 173,000 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 395,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2022, the company divested its interest in Horn River totalling about 103,000 net acres and its interest in XTO Energy Canada totalling about 365,000 net acres. Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two 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. 14 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 Imperial currently transports the company’s crude oil production and third-party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal has total capacity to ship up to 210,000 barrels per day of crude oil. 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, 2022, and the daily rated capacities of the refineries as at December 31, 2022, were as follows. Refinery throughput (a) Rated capacities (b) Year ended December 31 at December 31 thousands of barrels per day 2022 2021 2020 2022 Strathcona, Alberta 195 172 170 197 Sarnia, Ontario 113 106 86 123 Nanticoke, Ontario 110 101 84 113 Total 418 379 340 433 Utilization of refinery capacity (percent) 98 89 80 (a) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units. (b) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing. 2022 Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity. 2021 Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partially offset by a planned turnaround at Strathcona. 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. 15 Marketing The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers. Imperial supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2022, there were about 2,400 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby Imperial supplies fuel to independent third parties. Imperial 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, 2022, are set out in the following table. thousands of barrels per day 2022 2021 2020 Gasolines 229 224 215 Heating, diesel and jet fuels 176 160 146 Lube oils and other products 47 45 40 Heavy fuel oils 23 27 20 Net petroleum product sales 475 456 421 In 2022, improved petroleum product sales primarily reflects increased demand. In 2021, improved petroleum product sales primarily reflects reduced impacts associated with the COVID-19 pandemic. Chemical The company’s Chemical operations manufacture and market benzene, aromatic and 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, 2022, were as follows. thousands of tonnes 2022 2021 2020 Total petrochemical sales 842 831 749 In 2022, sales volumes increased primarily due to higher sales of propylene and polyethylene, partially offset by lower intermediates. In 2021, sales volumes increased primarily due to higher sales of intermediates and aromatics. 16 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 our 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. Imperial’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 5,300 at the end of 2022 (2021 - 5,400, 2020 - 5,800). Regular employees are defined as active executive, management, professional, technical and wage employees who work full-time or part-time for the company and are covered by the company’s benefit plans and programs. 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 investments in lower-emission energy and emission-reduction services and technologies. 17 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, 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. 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 continuous operational measurements and sampling to confirm that environmental 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 clean fuels, continued evaluation and implementation of new technologies 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 $4.5 billion on environmental protection and facilities. In 2022, the company’s environmental capital and operating expenditures totalled approximately $1.4 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Environmental expenditures are expected to increase to approximately $1.8 billion in 2023, with capital expenditures expected to account for approximately 65 percent of the total. Costs for 2024 are anticipated to increase to approximately $2.2 billion, with capital expenditures expected to account for approximately 69 percent of the total. 18 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 2022 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 on page 12 . 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. 19 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 Commissioner of 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. An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. An ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau. 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. 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. 20 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. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, 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 Imperial’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, and lower-emission fuels also depends on the growth and development of markets for those products and services, including implementation of supportive 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 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, government regulation or austerity programs, trade tariffs or broader breakdowns in global trade, security or public health issues and responses, the inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, other events or conditions that impair the functioning of financial markets and institutions also pose risks to Imperial. Other demand-related factors Factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact Imperial’s results include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for our products, including lower demand for gasoline, impacting Downstream results in the winter; increased competitiveness of, or government policy support for, alternative energy sources; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation; changes in consumer preferences for the company’s products, including consumer demand for alternative fueled 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” below. 21 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 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 oil and gas production or increase associated costs, including actions intended to reduce greenhouse gas emissions and previous Government of Alberta curtailment regulations, the occurrence of wars, hostile actions, natural disasters, trade tariffs or broader breakdowns in global trade, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt and have in the past disrupted supplies. For example, Russia's military action in Ukraine has impacted global crude oil and gas supply levels and prices, and continues to contribute to a volatile commodity environment, the duration of which is uncertain. 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. Increased differentials, have in the past, 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 trading purposes. Imperial’s future business results, including cash flows and financing needs, will also be affected by the rate of recovery from the COVID-19 pandemic, as well as the occurrence and severity of future outbreaks, 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 such as COVID-19 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, challenges to legislative jurisdiction between different levels of government, third-party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. This includes actions by policy-makers, regulators or other actors to delay or deny necessary licences and permits, restrict the availability of oil and gas leases or the operation of third-party infrastructure that the company relies on, 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 and increasing and expanding stakeholder consultation (including Indigenous stakeholders), 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 in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Changes in taxation policy, such as the Government of Canada announcement in 2022 of a tax on share buybacks, could impact the company’s results and ability to return surplus cash to shareholders. Further, the adoption of regulations mandating efficiency standards, and 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. 22 Governments are also introducing bans on certain technologies that could impact demand for products, such as the Government of Canada’s intention to ban the sale of new internal combustion engine cars and light trucks 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 impact the company’s ability to operate its projects and facilities 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. 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, 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 and implemented at the federal and provincial levels, including sulphur dioxide limits for refineries in Ontario, 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. 23 Regulation of oil sands The company’s mining operations are subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. 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 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. 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. 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) may increase the cost of 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 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 including severe weather events may impact the company’s operational performance, such as extreme cold weather that makes mining operations more difficult. 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. 24 Climate change, energy transition and greenhouse gas restrictions Net-zero scenarios Driven by concern over the risks of climate change, the provinces and the Government of Canada have adopted or have revised regulatory frameworks to reduce greenhouse gas emissions including emissions from the production and use of oil and gas, and their products. 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 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 and reflect substantial uncertainties. The company’s actions with respect to the energy transition, including its announced goal, ultimately, to achieve company-wide net-zero emissions (Scope 1 and 2) from its operated assets, carries risks that the transition, including underlying technologies, policies, and markets as discussed in more detail below, will not 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 change 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. 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 and incentives or mandates for renewable energy. The Government of Canada has updated its nationally determined contribution (NDC) under the Paris Agreement on climate change, to reduce greenhouse gas emissions economy-wide by 40 to 45 percent below 2005 levels by 2030, a substantial increase in ambition beyond its original 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 $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. 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 nominally 10 percent of a facility’s emissions in 2020. This price increased to 11 percent in 2021 and 12 percent in 2022, with the oil sands mining and upgrading facilities increasing to 17 percent in 2021 and 18 percent in 2022, and these percentages are anticipated to increase by 2 percent per year starting in 2023, followed by an increase of 4 percent in 2029 and 2030 for the oil sands sector. 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 puts a price on 8 percent of a facility’s emissions, increasing by 2.4 percent in 2023 followed by 1.5 percent in 2024. British Columbia has carbon pricing in place for all emissions, with pricing expected to meet or exceed the federal carbon pricing schedule in 2023. 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. 25 There are also various low carbon fuel standards being developed or already applicable to the company’s products. In 2022, the Government of Canada finalized draft regulations for the Clean Fuel Regulations, which will require the reduction in carbon intensity of liquid transportation fuels supplied in Canada starting in July 2023. The regulations build upon the existing federal renewable fuels regulations that require fuel producers and importers to have a specified amount of renewable fuel in gasoline and diesel. 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. The Government of Canada's Impact Assessment Act 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. 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 Imperial’s products more expensive and less competitive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower greenhouse gas emission energy sources. Current and pending greenhouse gas regulations or policies may also increase compliance and 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 market place, could negatively affect our returns and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products. Governments may also impose restrictions on production of, or emissions from, oil and gas to the extent they view such measures as a viable approach for pursuing national and global energy and climate policies. For example, the Government of Canada announced its intention to pursue a cap on greenhouse gas emission from oil and gas activities by 2030. Concern over the risks of climate change may lead governments to make laws applicable to the energy industry progressively more stringent over time. Political and other actors and their agents are also increasingly seeking to 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 and taking 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 will require new technologies to reduce the cost and increase the scalability of alternative energy sources as well as technologies such as carbon capture and storage (CCS). CCS technologies, focused initially on capturing and sequestering CO2 emissions from high-intensity industrial activities, can assist in meeting society’s objective to mitigate atmospheric greenhouse gas levels while also helping ensure the availability of the reliable and affordable energy the world requires. 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 net-zero and 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, a successful energy transition will require appropriate support from governments and private participants throughout the global economy. The company’s ability to develop and deploy CCS and other lower-emission energy technologies at commercial scale will depend in part on the continued development of supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained could adversely impact these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without 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. See also the discussion of “Supply and demand”, “Government and political factors”, and “Management effectiveness” in this Item 1A. 26 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 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 Imperial’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 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 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, and the company’s operations, market position and financial condition may be adversely impacted if these counterparties do not fulfil their obligations. Imperial may also be adversely affected by the outcome of litigation resulting from its operations or by government enforcement proceedings alleging non-compliance with applicable laws or regulations. Litigation is subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending litigation. 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". Further, with inflation rising in Canada and other countries throughout 2022, governments have increased interest rates which may further impact the company through the availability of financing, cost of debt, and exchange rate fluctuations. Additional information regarding the potential future impact of market factors on our 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 manage successfully those factors that are at least in part within its control. The extent to which Imperial 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 model and optimize reservoir performance; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and the company’s ability to respond effectively to unforeseen technical difficulties that could delay project start-up or cause unscheduled downtime. 27 Operational efficiency An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’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 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 and the need for continuous efficiency improvement. The company’s research and development organizations must be able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions intensity. To remain competitive, the company must also continuously adapt and capture the benefits of new technologies including growing the company’s capabilities to utilize digital data technologies to gain new business insights. There are risks associated with 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 environmental sustainability and reduction of greenhouse gas emissions), and financial results. Safety, business controls and environmental 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 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 weather events that impacted the company's oil sands operations in early 2022) and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. 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. Cybersecurity Imperial is regularly subject to attempted cybersecurity disruptions from a variety of sources, including state-sponsored actors. Imperial’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. 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. The company is exposed to potential harm from cybersecurity events that may affect the operations of third parties, including our partners, suppliers, service providers (including providers of cloud-based services for our data or applications), and customers. 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. Imperial 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. 28 Preparedness The company’s operations may be disrupted by severe weather events, natural disasters, human error, and similar events. Our 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. Our consideration of changing weather conditions and inclusion of safety factors in design covers 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 disaster preparedness and response, and business continuity planning. Reputation Imperial’s reputation is an important corporate asset. Factors that could have an impact on the company’s reputation including an operating incident or significant cybersecurity disruption; changes in consumer views concerning the company’s products; 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; 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 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 and environmental impact. 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. 29 Item 1B. Unresolved staff comments None. 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. 30 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 8, 2023 there were 9,342 holders of record of common shares of the company. Information for security holders outside Canada Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian non-resident withholding tax of 15 percent, but may vary from one tax convention to another. 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 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 or debt instruments 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. 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 111 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. Reference is made to the section under the “Company executives and executive compensation”: • Entitled “Performance graph” within the “Compensation discussion and analysis” section on page 170 of this report; and • Entitled “Equity compensation plan information”, within the “Compensation discussion and analysis”, on page 176 of this report. 31 Issuer purchases of equity securities Total number of shares purchased Average price paid per share (Canadian dollars) 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 (a) (b) October 2022 (October 1 - October 31) 6,673,198 65.06 6,673,198 — November 2022 (November 1 - November 30) — — — — December 2022 (December 1 - December 31) 20,689,655 72.50 20,689,655 — (a) On June 27, 2022, 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 existing share purchase program. The program enabled the company to purchase up to a maximum of 31,833,809 common shares during the period June 29, 2022 to June 28, 2023. This maximum included shares purchased under the normal course issuer bid and from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid. 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 October 21, 2022 as a result of the company purchasing the maximum allowable number of shares under the program. (b) On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $1.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 billion and 3.4 percent of Imperial’s issued and outstanding shares at the close of business on October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. The company will continue to evaluate the renewal of its normal course issuer bid share purchase program in June 2023 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 47 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 63 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. 32 Item 8. Financial statements and supplementary data Reference is made to the table of contents in the “Financial section” on page 41 of this report: • Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PCAOB ID: 271 ), Calgary, Canada dated February 22, 2023, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” on page 71 and continuing through note 18, “Divestment activities” on page 106 ; • “Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 107 . Item 9. Changes in and disagreements with accountants on accounting and financial disclosure None. 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, 2022. 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 70 of this report for “Management’s report on internal control over financial reporting” and page 71 for the “Report of Independent Registered Public Accounting Firm” on the company’s internal control over financial reporting as of December 31, 2022. 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 None. Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections Not applicable. 33 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 111 . The company’s management proxy circular is prepared in accordance with Canadian securities regulations. The company currently has seven 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 112 to 116 of this report have been nominated for election at the annual meeting of shareholders to be held May 2, 2023. All of the nominees, with the exception of S.R. Driscoll, J. Floren and G.J. Goldberg, are now directors and have been since the dates indicated. Ms. Driscoll, Mr. Floren and Mr. Goldberg are not currently directors and are being nominated for election as directors at the annual meeting of shareholders for the first time. K.T. Hoeg, J.M. Mintz and D.S. Sutherland are currently directors and are not standing for re-election in 2023 as they have reached the company's mandatory retirement age for directors. Reference is made to the section under “Nominees for director”: • “Director nominee tables”, on pages 112 to 116 of this report; Reference is made to the sections under “Corporate governance disclosure”: • “Skills and experience of our board members and nominees”, on page 121 of this report. • “Other public company directorships of our board members and nominees”, on page 125 of this report. • The table entitled “Audit committee” under “Board and committee structure”, on page 134 of this report; • “Ethical business conduct”, starting on page 147 of this report; and • “Largest shareholder”, on page 151 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 153 to 154 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 111 . 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 139 to 146 of this report; and • “Share ownership guidelines of independent directors and chairman, president and chief executive officer”, on page 146 of this report. Reference is made to the following sections under “Company executives and executive compensation”: • “Letter to shareholders from the executive resources committee on executive compensation”, on page 155 of this report; and • “Compensation discussion and analysis”, on pages 156 to 178 of this report. 34 Item 12. Security ownership of certain beneficial owners and management and related stockholder matters Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111 . 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 176 of this report. Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 151 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, 2022 is described in the sections under “Nominees for director” starting on page 112 , “Director compensation” starting on page 139 and “Company executives and executive compensation” starting on page 153 . The following table shows the number of Imperial Oil Limited and Exxon Mobil Corporation common shares owned and restricted stock units held by each named executive officer, and the incumbent directors and executive officers as a group, as of February 8, 2023. Imperial Oil Limited Exxon Mobil Corporation Named executive officer Common shares (a) Restricted stock units (b) Common shares (a) Restricted stock units (b) B.W. Corson — 323,600 120,676 73,850 D.E. Lyons — 94,800 10,419 9,600 S.P. Younger — 54,400 8,796 13,600 B.A. Jolly 12,506 73,800 — — J.R. Wetmore 15,990 60,400 — — Incumbent directors and executive officers as a group (16 people) 113,437 807,550 161,155 225,450 (a) No common shares are beneficially owned by reason of exercisable options. None of these individuals owns more than 0.01 percent of the outstanding shares of Imperial Oil Limited or Exxon Mobil Corporation. The directors and officers as a group own approximately 0.02 percent of the outstanding shares of Imperial Oil Limited, and less than 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. 35 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 111 . 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 122 of this report. Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 151 of this report. M.R. Crocker is deemed a non-independent member of the board of directors and the executive resources committee, safety and sustainability committee, nominations and corporate governance committee and community collaboration and engagement committee under the relevant standards. As an employee of Exxon Mobil Corporation, M.R. Crocker is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders. 36 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 are 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, 2022 and December 31, 2021 were as follows: thousands of Canadian dollars 2022 2021 Audit fees 2,190 1,890 Audit-related fees 92 92 Tax fees — — All other fees — — Total fees 2,282 1,982 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 2022. 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. 37 PART IV Item 15. Exhibits, financial statement schedules Reference is made to the table of contents in the “Financial section” on page 41 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 Form 8-K filed on May 3, 2006 (File No. 0-12014)). (ii) By-laws of the company (Incorporated herein by reference to Exhibit (3)(ii) to the company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (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 Form 8-K filed on November 19, 2008 (FileNo. 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 2011 and subsequent years, as amended effective November 14, 2011 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on February 23, 2012 (File No. 0-12014)). (4) 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 Form 8-K filed on October 31, 2016 (File No. 0-12014)). (5) Amended Short Term Incentive Program with respect to awards 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 Form 8-K filed on October 31, 2016 (File No. 0-12014)). (6) 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)). ( 7 ) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2022 and subsequent years, as amended effective November 29, 2022. 38 (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, 2022. (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. (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. 39 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 22, 2023 by the undersigned, thereunto duly authorized. Imperial Oil Limited by /s/ Bradley W. Corson (Bradley W. Corson) 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 22, 2023 by the following persons on behalf of the registrant and in the capacities indicated. Signature Title /s/ Bradley W. Corson Chairman, president and chief executive officer and director (Principal executive officer) (Bradley W. Corson) /s/ Daniel E. Lyons Senior vice-president, finance and administration, and controller (Principal financial officer and principal accounting officer) (Daniel E. Lyons) /s/ David W. Cornhill Director (David W. Cornhill) /s/ Matthew R. Crocker Director (Matthew R. Crocker) /s/ Krystyna T. Hoeg Director (Krystyna T. Hoeg) /s/ Miranda C. Hubbs Director (Miranda C. Hubbs) /s/ Jack M. Mintz Director (Jack M. Mintz) /s/ David S. Sutherland Director (David S. Sutherland) 40 Financial section Table of contents Page Financial information (U.S. GAAP) 42 Frequently used terms 43 Management’s discussion and analysis of financial condition and results of operations 47 Overview 47 Business environment 48 Business results 52 Liquidity and capital resources 59 Capital and exploration expenditures 62 Market risks 63 Critical accounting estimates 65 Management’s report on internal control over financial reporting 70 Report of Independent Registered Public Accounting Firm 71 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 87 4. Employee retirement benefits 88 5. Other long-term obligations 93 6. Financial and derivative instruments 94 7. Share-based incentive compensation programs 96 8. Investment and other income 97 9. Litigation and other contingencies 97 10. Common shares 98 11. Miscellaneous financial information 100 12. Financing and additional notes and loans payable information 101 13. Leases 102 14. Long-term debt 104 15. Accounting for suspended exploratory well costs 104 16. Transactions with related parties 105 17. Other comprehensive income (loss) information 106 18. Divestment activities 106 Supplemental information on oil and gas exploration and production activities (unaudited) 107 41 Financial information (U.S. GAAP) millions of Canadian dollars 2022 2021 2020 Revenues 59,413 37,508 22,284 Net income (loss): Upstream 3,645 1,395 (2,318) Downstream 3,622 895 553 Chemical 204 361 78 Corporate and other (131) (172) (170) Net income (loss) 7,340 2,479 (1,857) Cash and cash equivalents at year-end 3,749 2,153 771 Total assets at year-end 43,524 40,782 38,031 Long-term debt at year-end 4,033 5,054 4,957 Total debt at year-end 4,155 5,176 5,184 Other long-term obligations at year-end 3,467 3,897 4,100 Shareholders’ equity at year-end 22,413 21,735 21,418 Cash flow from operating activities 10,482 5,476 798 Per share information (Canadian dollars) Net income (loss) per common share - basic 11.47 3.48 (2.53) Net income (loss) per common share - diluted 11.44 3.48 (2.53) Dividends per common share - declared 1.46 1.03 0.88 42 Frequently used terms Listed below are definitions of several of Imperial’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 2022 2021 2020 From the Consolidated balance sheet Business uses: asset and liability perspective Total assets 43,524 40,782 38,031 Less: Total current liabilities excluding notes and loans payable (8,776) (5,432) (3,153) Total long-term liabilities excluding long-term debt (8,180) (8,439) (8,276) Add: Imperial’s share of equity company debt 25 20 26 Total capital employed 26,593 26,931 26,628 Total company sources: Debt and equity perspective Notes and loans payable 122 122 227 Long-term debt 4,033 5,054 4,957 Shareholders’ equity 22,413 21,735 21,418 Add: Imperial’s share of equity company debt 25 20 26 Total capital employed 26,593 26,931 26,628 43 Return on average capital employed (ROCE) ROCE is a non-GAAP ratio. From the perspective of the business segments, ROCE is annual business segment net income divided by average business segment capital employed (an average of the beginning and end-of-year amounts). Segment net income includes Imperial’s share of segment 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’s total ROCE is net income excluding the after-tax cost of financing divided by total average capital employed. 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 2022 2021 2020 From the Consolidated statement of income Net income (loss) 7,340 2,479 (1,857) Financing (after-tax) including Imperial’s share of equity companies 55 40 52 Net income (loss) excluding financing 7,395 2,519 (1,805) Average capital employed 26,762 26,780 28,059 Return on average capital employed (percent) – corporate total 27.6 9.4 (6.4) Cash flows from 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 2022 2021 2020 From the Consolidated statement of cash flows Cash flows from (used in) operating activities 10,482 5,476 798 Proceeds from asset sales 904 81 82 Total cash flows from (used in) operating activities and asset sales 11,386 5,557 880 44 Operating costs Operating costs is a non-GAAP financial measure that are 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 are 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 2022 2021 2020 From the Consolidated statement of income Total expenses 50,186 34,307 24,796 Less: Purchases of crude oil and products 37,742 23,174 13,293 Federal excise tax and fuel charge 2,179 1,928 1,736 Financing 60 54 64 Subtotal 39,981 25,156 15,093 Imperial's share of equity company expenses 71 61 64 Total operating costs 10,276 9,212 9,767 Components of operating costs millions of Canadian dollars 2022 2021 2020 From the Consolidated statement of income Production and manufacturing 7,404 6,316 5,535 Selling and general 882 784 741 Depreciation and depletion (includes impairments) 1,897 1,977 3,293 Non-service pension and postretirement benefit 17 42 121 Exploration 5 32 13 Subtotal 10,205 9,151 9,703 Imperial's share of equity company expenses 71 61 64 Total operating costs 10,276 9,212 9,767 45 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 in a given quarter 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 2022 2021 2020 From the Consolidated statement of income Net income (loss) (U.S. GAAP) 7,340 2,479 (1,857) Less identified items included in Net income (loss) Gain/(loss) on sale of assets 208 — — Impairments — — (1,171) Subtotal of identified items 208 — (1,171) Net income (loss) excluding identified items 7,132 2,479 (686) 46 Management’s discussion and analysis of financial condition and results of operations Overview The following discussion and analysis of Imperial’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. 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 operating segments are Upstream, Downstream, Chemicals, and Corporate and other. 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, Imperial’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 Corporate Plan is a fundamental annual management process that is the basis for setting operating and capital objectives, in addition to providing the economic assumptions used for investment evaluation purposes. The foundation for the assumptions supporting the Corporate Plan is ExxonMobil’s Outlook for Energy , and Corporate Plan volume projections are based on individual field production profiles, which are also updated annually. Price ranges for crude oil, natural gas, including price differentials, refinery and chemical margins, volumes and operating costs including greenhouse gas emissions pricing, and foreign currency exchange rates are based on Corporate Plan assumptions developed annually and are utilized for investment evaluation purposes. Major investment opportunities are evaluated over a range of potential market conditions. Once the company makes major investments, it completes a reappraisal process to ensure that it learns from the investment decision and incorporates the lessons 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. 47 Business environment Long-term business outlook The “Long-term business outlook” is based on Exxon Mobil Corporation’s Outlook for Energy (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 low-carbon solutions; greenhouse gas emission-reduction technologies; and supportive 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). The IEA describes the Net Zero Emissions by 2050 (NZE) as extremely challenging, requiring all stakeholders - governments, businesses, investors, and citizens - to take immediate, unprecedented action. The IEA acknowledges 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 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. By 2050, the world’s population is projected at around 9.7 billion people, or about 2 billion more than in 2021. Coincident with this population increase, the Outlook projects worldwide economic growth to average close to 2.5 percent per year, with economic output growing by around 110 percent by 2050 compared to 2021. 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 almost 15 percent from 2021 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)). 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 CO2 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 over 75 percent from 2021 to 2050, with developing countries likely to account for about 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 and approach 15 percent of the world’s electricity in 2050, versus nearly 35 percent in 2021, in part due to policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change. From 2021 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 more than 550 percent, helping total renewables (including other sources, e.g., hydropower) to account for over 80 percent of the increase in electricity supplies worldwide through 2050. Total renewables are expected to reach about 50 percent of global electricity supplies by 2050. Natural gas and nuclear are expected to be about 25 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. 48 Under the Outlook, energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by over 30 percent from 2021 to 2050. Transportation energy demand is expected to account for around 65 percent of the growth in liquid fuels demand worldwide over this period. Light-duty vehicle demand for liquid fuels is projected to peak by around 2025, and then decline to levels seen in the early-2000s 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 almost 70 percent. By 2050, light-duty vehicles are expected to account for around 15 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 will rise about 75 percent between 2021 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 approximately 110 million oil-equivalent barrels per day, an increase of about 17 percent from 2021. The non-OECD share of global liquid fuels demand is expected to increase to nearly 70 percent by 2050, as liquid fuels demand in the OECD is expected to decline by around 20 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 emerging supply sources – including tight oil, deepwater, oil sands, natural gas liquids, and biofuels – are expected to grow to help meet rising demand. The world’s resource base is sufficient to meet projected demand through 2050 as technology advances continue to expand the availability of more economic and lower-carbon supply options. However, 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, and it is expected to grow the most of any primary energy type from 2021 to 2050, meeting about 40 percent of global energy demand growth. Global natural gas demand is expected to rise nearly 25 percent from 2021 to 2050, with around two thirds 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, about 50 percent of the growth in natural gas supplies is expected to be 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 50 percent of the increase in global demand growth, with much of this supply expected to help meet rising demand in Asia Pacific. The world’s energy mix is highly diverse and will remain so through 2050. Oil is expected to remain 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 over 480 percent from 2021 to 2050, when they are projected to be around 10 percent of the world energy mix. 49 Decarbonization of industry activities will require a suite of nascent or future lower-carbon technologies and supporting 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 CO2 emission reductions from high-emitting and hard-to-decarbonize sectors such as power generation and heavy industries, including manufacturing, refining and petrochemicals. To meet this projected demand under the Outlook and the IEA's Stated Policies Scenario (STEPS), 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 the rapidly declining demand for oil and gas envisioned in the IEA's Net Zero Emissions by 2050 scenario. 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. Imperial’s estimates of potential costs related to greenhouse gas emissions align with applicable provincial and federal regulations. Additionally, Imperial 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 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 is consistent with the global aggregation of Nationally Determined Contributions (NDCs), submitted by the nations that are signatories to the Paris Agreement, as available at the end of 2021. The Outlook seeks to identify potential impacts of climate related government policies, which often target specific sectors. 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 NDCs that nations provided around COP 27 in Egypt in November 2022 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. Imperial and its industry peers launched the Oil Sands Pathways to Net Zero alliance in 2021, with the goal of working collectively with the federal and Alberta governments to achieve net-zero greenhouse gas emissions from oil sands operations by 2050 to help Canada meet its climate goals. 50 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, Imperial has announced a company-wide goal to achieve net zero emissions (Scope 1 and 2) by 2050 in its operated assets through collaboration with government and industry partners. Successful technology development and supportive fiscal and regulatory frameworks will be needed to achieve this goal. This work builds on Imperial’s previously announced net-zero goal for operated oil sands as part of the Pathways Alliance initiative, as well as the company’s emission intensity reduction goal of 30 percent by 2030 for operated oil sands facilities when compared to 2016 levels. The company plans to achieve its net zero goal by applying oil sands recovery technologies that use less steam, implementing carbon capture and storage and implementing efficiency projects including the use of lower carbon fuels at its operations. 51 Recent business environment Prior to the COVID-19 pandemic, many companies in the industry invested below the levels needed to maintain or increase production capacity to meet anticipated demand. During the COVID-19 pandemic, this decline in investments accelerated as industry revenue collapsed, resulting in underinvestment and supply tightness as demand for petroleum and petrochemical products recovered. Across late 2021 and the first half of 2022, these reductions, along with supply chain constraints, and a continuation of demand recovery, led to a steady increase in oil and natural gas prices and refining margins. Demand for petroleum and petrochemical products grew in 2022, with the company's financial results benefiting from stronger prices and margins. Commodity and product prices are expected to remain volatile given the current global economic uncertainty and geopolitical events affecting supply and demand, including Russia's military action in Ukraine that has impacted global crude oil and gas supply levels and prices. The general rate of inflation in Canada and many other countries experienced a brief decline in the initial stage of the COVID-19 pandemic, before starting to increase steadily in 2021, due to an imbalance in supply and demand, and continued to increase in 2022. The underlying factors include, but are not limited to, time cycle of capacity investments, supply chain disruptions, shipping bottlenecks, labour constraints, and side effects from monetary and fiscal expansions. The company closely monitors market trends and works to mitigate both operating and capital cost impacts in all price environments. Business results Consolidated millions of Canadian dollars 2022 2021 2020 Net income (loss) (U.S. GAAP) 7,340 2,479 (1,857) Identified items 1 included in Net income (loss) Gain/(loss) on sale of assets 208 — — Impairments — — (1,171) Subtotal of identified items 1 208 — (1,171) Net income (loss) excluding identified items 1 7,132 2,479 (686) 2022 Net income in 2022 was $7,340 million, or $11.44 per share on a diluted basis, up from $2,479 million, or $3.48 per share in 2021. Current year results include favourable identified items 1 of $208 million after tax, related to the company’s gain on the sale of interests in XTO Energy Canada. 2021 Net income in 2021 was $2,479 million, or $3.48 per share on a diluted basis, compared to a net loss of $1,857 million, or $2.53 per share in 2020. Prior year results include unfavourable identified items 1 of $1,171 million after tax, related to the company’s decision to no longer develop a significant portion of its unconventional portfolio. 1 non-GAAP financial measure - see "Frequently used terms" section on page 43 for definition and reconciliation. 52 Upstream Overview Imperial produces crude oil and natural gas for sale predominantly into North American markets. Imperial’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. Imperial 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 will 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”. Imperial continually evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen in-situ oil sands project, as economically justified. 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. Imperial 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, governments, alternative energy sources, and other factors. To manage the risks associated with price, Imperial tests the resiliency of its annual plans and all major investments across a range of price scenarios. Key events Upstream assets demonstrated strong performance in 2022. 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 and take advantage of the improving business environment throughout 2022. Upstream full-year production averaged 416,000 gross oil-equivalent barrels per day. At Kearl, gross production was about 242,000 barrels per day (172,000 barrels Imperial’s share), down 21,000 barrels per day (14,000 barrels Imperial's share) compared to 2021, as a result of extreme cold weather impacts in Q1 2022. At Cold Lake, annual production averaged 144,000 gross oil-equivalent barrels per day. At Syncrude, annual production averaged 77,000 gross oil-equivalent barrels per day, supported by the interconnect pipeline. On August 31, 2022, jointly with ExxonMobil Canada, Imperial sold its interests in XTO Energy Canada to Whitecap Resources Inc. As described in more detail in Item 1A. “Risk factors”, environmental risks and climate related regulations could have negative impacts on the upstream business. 53 Results of operations 2022 Net income (loss) factor analysis millions of Canadian dollars Price – Higher realizations were generally in line with increases in marker prices, driven primarily by increased demand. Average bitumen realizations increased by $26.76 per barrel generally in line with WCS, and synthetic crude oil realizations increased by $43.85 per barrel. Volumes – Lower volumes were primarily the result of downtime at Kearl in the first half of the year, partly offset by higher production at Syncrude and Cold Lake. Royalty – Higher royalties primarily driven by improved commodity prices. Identified items 1 – Current year results include favourable identified items 1 related to the company's gain on the sale of interests in XTO Energy Canada. Other – Higher operating expenses of about $500 million, primarily from higher energy prices, partially offset by favourable foreign exchange impacts of about $270 million, and higher electricity sales at Cold Lake of about $60 million due to increased prices. 2021 Net income (loss) factor analysis millions of Canadian dollars Price – Higher realizations were primarily driven by average bitumen realizations increasing by $32.22 per barrel generally in line with WCS, and synthetic crude oil realizations increasing by $31.85 per barrel generally in line with WTI. Volumes – Higher volumes primarily driven by the absence of production balancing with market demands that occurred in 2020 increased net income by about $550 million. Royalty – Higher royalties primarily driven by higher commodity prices. Identified items 1 – Prior year results included unfavourable identified items 1 of $1,171 million related to the company's decision to no longer develop a significant portion of its unconventional portfolio. Other – Higher operating expenses of about $720 million, unfavourable foreign exchange impacts of about $230 million and lower Canada Emergency Wage Subsidy received by the company compared to prior year of about $60 million, which includes Imperial's proportionate share of a joint venture. 1 non-GAAP financial measure - see "Frequently used terms" section on page 43 for definition and reconciliation. 54 Marker prices and average realizations Canadian dollars, unless otherwise noted 2022 2021 2020 West Texas Intermediate (US$) (per barrel) 94.36 68.05 39.26 Western Canada Select (US$) (per barrel) 76.28 54.96 26.87 WTI/WCS Spread (US$) (per barrel) 18.08 13.09 12.39 Bitumen (per barrel) 84.67 57.91 25.69 Synthetic crude oil (per barrel) 125.46 81.61 49.76 Conventional crude oil (per barrel) 97.45 59.84 29.34 Natural gas liquids (per barrel) 64.92 35.87 13.85 Natural gas (per thousand cubic feet) 5.69 3.83 1.90 Average foreign exchange rate (US$) 0.77 0.80 0.75 Crude oil and natural gas liquids (NGL) - production and sales (a) thousands of barrels per day 2022 2021 2020 gross net gross net gross net Bitumen 316 263 326 292 290 279 Synthetic crude oil (b) 77 63 71 62 69 68 Conventional crude oil 8 8 10 9 11 10 Total crude oil production 401 334 407 363 370 357 NGLs available for sale 1 1 1 1 2 2 Total crude oil and NGL production 402 335 408 364 372 359 Bitumen sales, including diluent (c) 424 451 401 NGL sales (d) 1 — 2 Natural gas - production and production available for sale (a) millions of cubic feet per day 2022 2021 2020 gross net gross net gross net Production (e) (f) 85 83 120 115 154 150 Production available for sale (g) 50 81 115 (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 to market by pipeline and rail. (d) 2021 NGL sales round to 0. (e) Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected. (f) 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. (g) Includes sales of the company’s share of net production and excludes amounts used for internal consumption. 2022 Lower production at Kearl was primarily a result of downtime in the first half of the year. 2021 Higher production at Kearl was primarily driven by the absence of prior year production balancing with market demands. 55 Downstream Overview Imperial’s Downstream serves predominantly Canadian markets with refining, trading, logistics and marketing activities. Imperial’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 Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers. Imperial owns and operates three refineries in Canada with aggregate distillation capacity of 433,000 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 political considerations. While industry refining margins significantly impact earnings, strong operations performance, product mix optimization, and disciplined cost control are also critical to the company's strong financial performance. Imperial's integration across the value chain, from refining to marketing, enhances overall value across the fuels business. Key events Refining margins increased sharply in 2022 in the face of strengthening demand, low inventory levels, and supply uncertainty. While refining margins are anticipated to remain volatile in the near term, the company continues to closely monitor industry and global economic conditions. The company progressed the Strathcona renewable diesel project in 2022, culminating in a final investment decision in January 2023 to construct the largest such facility in Canada, designed to produce more than one billion litres of renewable diesel annually. 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. Imperial supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2022, there were about 2,400 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby Imperial supplies fuel to independent third parties. Results of operations 2022 Net income (loss) factor analysis millions of Canadian dollars Margins – Higher margins primarily reflect improved market conditions. Other – Lower turnaround impacts of about $140 million, reflecting the absence of turnaround activities at Strathcona refinery, improved volumes of about $130 million, favourable foreign exchange impacts of about $120 million, and absence of the prior year unfavourable out-of-period inventory adjustment of $74 million, partially offset by higher operating expenses of about $190 million. 56 2021 Net income (loss) factor analysis millions of Canadian dollars Margins – Higher margins reflect improved product demand. Other – Unfavourable foreign exchange impacts of about $150 million and an unfavourable inventory adjustment of $74 million 1 , partially offset by lower operating expenses of about $50 million. Refinery utilization thousands of barrels per day (a) 2022 2021 2020 Total refinery throughput (b) 418 379 340 Rated capacity at December 31 (c) 433 428 428 Utilization of total refinery capacity (percent) 98 89 80 (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) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing. 2022 Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity. 2021 Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partially offset by a planned turnaround at Strathcona. Petroleum product sales thousands of barrels per day (a) 2022 2021 2020 Gasolines 229 224 215 Heating, diesel and jet fuels 176 160 146 Lube oils and other products 47 45 40 Heavy fuel oils 23 27 20 Net petroleum product sales 475 456 421 (a) Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period. 2022 Improved petroleum product sales in 2022 primarily reflects increased demand. 2021 Improved petroleum product sales in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic. 1 In 2021, the company recorded an unfavourable $74 million ($82 million, before tax) inventory adjustment (including the proportionate share of LIFO changes) related to reconciliations of additives and products inventory at equity and third-party terminals. The out-of-period impact of $57 million ($63 million, before tax) occurred over a number of years, and has been resolved. 57 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 2022, margins were adversely impacted by increased domestic supply of polyethylene. Imperial 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 2022 Net income (loss) factor analysis millions of Canadian dollars Margins – Lower margins primarily reflect weaker industry polyethylene margins. 2021 Net income (loss) factor analysis millions of Canadian dollars Margins – Improved margins were primarily due to stronger industry polyethylene margins. Sales thousands of tonnes 2022 2021 2020 Polymers and basic chemicals 635 599 574 Intermediates 207 232 175 Total petrochemical sales 842 831 749 Corporate and other millions of Canadian dollars 2022 2021 2020 Net income (loss) (131) (172) (170) 58 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. Imperial’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, 2019. A valuation of the company’s registered retirement plans as at December 31, 2022 is expected to be completed in 2023. The company contributed $174 million to the registered retirement plans in 2022. 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 2022 2021 2020 Cash provided by (used in) Operating activities 10,482 5,476 798 Investing activities (618) (1,012) (802) Financing activities (8,268) (3,082) (943) Increase (decrease) in cash and cash equivalents 1,596 1,382 (947) Cash and cash equivalents at end of year 3,749 2,153 771 Cash flow from operating activities 2022 Cash flow generated from operating activities primarily reflects higher Upstream realizations, improved Downstream margins, and favourable working capital impacts. 2021 Cash flow generated from operating activities primarily reflects higher Upstream realizations and stronger Downstream margins. Cash flow used in investing activities 2022 Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment, which were partially offset by proceeds from the sale of interests in XTO Energy Canada. 2021 Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment. 59 Cash flow used in financing activities 2022 At the end of 2022, total debt outstanding was $4,155 million, compared with $5,176 million at the end of 2021. During the third quarter of 2022, the company decreased its long-term debt by $1 billion by partially repaying an existing facility with an affiliated company of ExxonMobil. During the second quarter of 2022, the company reduced its existing $500 million committed long-term line of credit to $250 million and extended the maturity date to June 30, 2023. Subsequently in the fourth quarter of 2022, this committed long-term line of credit was cancelled in full. The company also extended one of its $250 million committed long-term lines of credit to June 30, 2024. In November 2022, the company extended the maturity date of an existing $250 million committed short-term line of credit to November 2023. The company has not drawn on any of its outstanding $500 million of available credit facilities. 2021 At the end of 2021, total debt outstanding was $5,176 million, compared with $5,184 million at the end of 2020. During the second quarter of 2021, the company extended the maturity date of two of its short-term lines of credit, totalling $750 million, to May 2023, these facilities are now long-term. The company also extended its $300 million committed short-term line of credit to June 2022. In November 2021, the company extended the maturity date of an existing $250 million committed short-term line of credit to November 2022. The company has not drawn on these facilities. Share repurchases millions of Canadian dollars, unless noted 2022 2021 2020 Share repurchases 6,395 2,245 274 Number of shares purchased (millions) (a) 93.9 56.0 9.8 (a) Share repurchases were made under the company’s normal course issuer bid program, and substantial issuer bids that commenced on May 6, 2022 and November 4, 2022, and expired on June 10, 2022 and December 9, 2022, respectively. Includes shares purchased from Exxon Mobil Corporation concurrent with, but outside of, the normal course issuer bid, and by way of a proportionate tender under the company’s substantial issuer bids. 2022 On June 27, 2022, the company announced that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid. The program enabled the company to purchase up to a maximum of 31,833,809 common shares during the period June 29, 2022 to June 28, 2023. The program completed on October 21, 2022 as a result of the company purchasing the maximum allowable number of shares under the program. On May 6, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $2.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on June 15, 2022, with the company taking up and paying for 32,467,532 common shares at a price of $77.00 per share, for an aggregate purchase of $2.5 billion and 4.9 percent of Imperial’s issued and outstanding shares at the close of business on May 2, 2022. This included 22,597,379 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. 60 On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $1.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $72.50 per share, for an aggregate purchase of $1.5 billion and 3.4 percent of Imperial's issued and outstanding shares at the close of business on October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. 2021 On April 30, 2021, the company announced an amendment to its normal course issuer bid to increase the number of common shares that were available to be purchased. Under the amendment, the number of common shares available for purchase increased to a maximum of 29,363,070 common shares during the period June 29, 2020 to June 28, 2021. In 2021, the company purchased 29,356,095 shares under this amended program. On June 23, 2021, the company announced that it received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its existing share purchase program. The program enabled the company to purchase up to a maximum of 35,583,671 common shares during the period June 29, 2021 to June 28, 2022. In accordance with the company’s announcement in November 2021 that it intended to accelerate purchases under the normal course issuer bid, the program was subsequently completed on January 31, 2022 as a result of the company purchasing the maximum allowable number of shares under the program. Dividends millions of Canadian dollars, unless noted 2022 2021 2020 Dividends paid 851 706 649 Per share dividend paid (dollars) 1.29 0.98 0.88 Financial strength The table below shows Imperial’s consolidated debt-to-capital ratio. The data demonstrates the company’s creditworthiness: percent At December 31 2022 2021 2020 Debt to capital (a) 16 19 19 (a) Debt, defined as the sum of “Notes and loans payable” and “Long-term debt” (page 76 ), divided by capital, defined as the sum of debt and “Total shareholders’ equity” (page 76 ). Debt-related interest incurred in 2022, before capitalization of interest, was $111 million, up from $63 million in 2021. The weighted-average interest rate on the company’s debt was 2.2 percent in 2022, up from 1.2 percent in 2021. 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, 13 and 14 to the consolidated financial statements. Other long-term purchase agreements are commitments that are non-cancelable, or cancelable only under certain conditions, as well as long-term commitments, other than unconditional purchase obligations. They include primarily transportation services agreements, raw material supply and community benefits agreements. The total obligation at year-end 2022 was $8.8 billion, of which $783 million is due in 2023, and $670 million is due in 2024. 61 Litigation and other contingencies As discussed in note 9 to the consolidated financial statements on page 97 , 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, 2022, 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. 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 Imperial’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 2022 2021 Upstream (a) 1,128 632 Downstream 295 476 Chemical 10 8 Corporate and other 57 24 Total 1,490 1,140 (a) Exploration expenses included. For the Upstream segment, capital and exploration expenditures were primarily related to sustaining activity in support of the company’s in-situ and oil sands assets. For the Downstream segment, capital expenditures were primarily for enhancing the company’s distribution network as well as refinery projects to improve environmental performance, reliability, feedstock flexibility, and energy efficiency. Total capital and exploration expenditures are expected to be approximately $1.7 billion in 2023. Expected capital and exploration expenditures for 2023 includes firm capital commitments of $407 million for the construction and purchase of fixed assets and other permanent investments. An additional $211 million of firm capital commitments have been made for years 2024 and beyond. Actual spending could vary depending on the progress of individual projects. 62 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. Imperial’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. Imperial’s integrated business model reduces the company’s risk from changes in commodity prices. For instance, when differentials between North American crude benchmarks and western Canadian prices widen, Imperial is able to mitigate the impact of widening differentials on the Upstream through integration with Downstream investments in refineries, pipeline commitments and the Edmonton rail terminal. 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 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 Canadian / U.S. dollar exchange rate fluctuates, the company’s earnings will be affected. Imperial 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 Imperial’s debt would not be material to earnings or cash flow. Imperial 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 + (-) 105 One dollar (U.S.) per barrel increase (decrease) in refining 2-1-1 margins (b) + (-) 140 One cent decrease (increase) in the value of the Canadian dollar versus the U.S. dollar + (-) 170 (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, 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. 63 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 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 note 6 on page 94 . The company maintains a system of controls that includes the authorization, reporting and monitoring of derivative activity. 64 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 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 and lower-emission fuels. Imperial 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 the consolidated financial statements on page 79 . 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 well information such as flow rates and reservoir pressures, and 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, regulatory approvals, government policies, consumer preferences, royalty frameworks and significant changes in oil and natural gas price levels. • 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. 65 In 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the SEC definition of proved reserves. Downward revisions to proved synthetic crude oil reserves were a result of lower prices, offset by the addition of proved undeveloped reserves associated with future development at Syncrude. Changes to the liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties. In 2021, upward revisions of proved bitumen reserves were a result of improved prices. The 1.7 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake qualified as proved reserves under the SEC definition of proved reserves. Upward revisions to proved synthetic crude oil reserves were a result of improved prices. Changes to the liquids and natural gas proved reserves were the result of updated development plans and divestments at the Montney and Duvernay unconventional assets. In 2022, downward revisions of proved bitumen reserves were driven by a decrease of 0.2 billion barrels at Kearl as a result of higher royalty obligations associated with pricing, and a decrease of 0.2 billion barrels at Cold Lake due to an updated development plan. An increase to the bitumen reserves of 0.1 billion barrels is associated with extensions at Cold Lake for the Grand Rapids Phase 1 SA-SAGD and Leming SAGD projects. Downward revisions to proved synthetic crude oil reserves were a result of mine development plan updates and higher royalty obligations at Syncrude associated with pricing. Changes to the liquids and natural gas proved reserves were primarily a result of the sale of the company’s interest in the Montney and Duvernay unconventional assets. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. 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. This approach was applied in 2021, with the corresponding effect on depreciation expense being immaterial compared to prior periods. For 2022 and 2023, all properties have sufficient reserves at current SEC prices which will enable equitable allocation of cost over the economic lives of the Upstream assets. 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. 66 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, industry margins, and 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, Imperial 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. Outlook for Energy 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 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 required future policy and technology advancement and deployment for the world or the company, 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, such as the International Energy Agency Net Zero Emissions by 2050 , 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. 67 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. 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 2020, the company announced its decision to not further develop a significant portion of its unconventional portfolio in Alberta, resulting in a non-cash, after-tax impairment charge of $1,171 million in the company’s 2020 Upstream results. 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 4.3 percent used in 2022 compares to actual returns of 5.6 percent and 6.5 percent achieved over the last 10- and 20-year periods respectively, ending December 31, 2022. 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 and the discount rate for measuring the pension plan benefits obligation, a reduction of 1 percent in the discount rate would increase the benefits obligation by approximately $1 billion. Similarly, a reduction of 1 percent in the long-term rate of return on plan assets would increase the annual pension expense by approximately $95 million before tax. At Imperial, 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 2022. 68 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. On page 93 , note 5 to the consolidated financial statements provides a three-year continuity table detailing the changes in asset retirement obligations. Suspended exploratory well costs The company continues capitalization of exploratory well costs when it 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. Exploratory well costs not meeting these criteria are charged to expense. Assessing whether the company is making sufficient progress on a project requires careful consideration of the facts and circumstances. The facts and circumstances that support continued capitalization of suspended wells at year-end are disclosed in note 15 to the consolidated financial statements on page 104 . 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. 69 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, 2022. PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2022, as stated in their report which is included herein. /s/ Bradley W. Corson Bradley W. Corson 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 22, 2023 70 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 (together, the Company) as of December 31, 2022 and 2021, and the related consolidated statements of income, comprehensive income, shareholders’ equity and cash flows for each of the three years in the period ended December 31, 2022, 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, 2022, 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, 2022 and 2021, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2022 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, 2022, 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. 71 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. 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 Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net As described in Notes 1 and 2 to the consolidated financial statements, the Company’s upstream property, plant and equipment (PP&E), net balance was $26,949 million as of December 31, 2022, and the related depreciation and depletion expense for the year ended December 31, 2022 was $1,673 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 well information such as flow rates and reservoir pressures, and development and production costs, among 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 oil and natural gas reserves 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 oil and natural gas reserve volumes, as the reserve volumes are based on engineering assumptions and methods, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating the audit evidence related to the data, methods, and assumptions used by management and its specialists in developing the estimates of proved oil and natural gas reserve volumes. 72 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 oil and natural gas reserve volumes. The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of estimates of proved 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 evaluation of the methods and assumptions used by management’s specialists, tests of the data used by management’s specialists, and an evaluation of management’s specialists’ findings. /s/ PricewaterhouseCoopers LLP Chartered Professional Accountants Calgary, Canada February 22, 2023 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 2022 2021 2020 Revenues and other income Revenues (a) 59,413 37,508 22,284 Investment and other income (note 8, 18) 257 82 104 Total revenues and other income 59,670 37,590 22,388 Expenses Exploration (note 15) 5 32 13 Purchases of crude oil and products (b) 37,742 23,174 13,293 Production and manufacturing (c) (note 11) 7,404 6,316 5,535 Selling and general (c) 882 784 741 Federal excise tax and fuel charge 2,179 1,928 1,736 Depreciation and depletion (includes impairments) (note 2, 11) 1,897 1,977 3,293 Non-service pension and postretirement benefit 17 42 121 Financing (d) (note 12) 60 54 64 Total expenses 50,186 34,307 24,796 Income (loss) before income taxes 9,484 3,283 ( 2,408 ) Income taxes (note 3) 2,144 804 ( 551 ) Net income (loss) 7,340 2,479 ( 1,857 ) Per share information (Canadian dollars) Net income (loss) per common share - basic (note 10) 11.47 3.48 ( 2.53 ) Net income (loss) per common share - diluted (note 10) 11.44 3.48 ( 2.53 ) (a) Amounts from related parties included in revenues, (note 16). 17,042 8,777 5,107 (b) Amounts to related parties included in purchases of crude oil and products, (note 16). 3,795 2,737 2,484 (c) Amounts to related parties included in production and manufacturing, and selling and general expenses, (note 16). 460 420 579 (d) Amounts to related parties included in financing, (note 16). 78 28 61 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 2022 2021 2020 Net income (loss) 7,340 2,479 ( 1,857 ) Other comprehensive income (loss), net of income taxes Postretirement benefits liability adjustment (excluding amortization) 582 679 ( 212 ) Amortization of postretirement benefits liability adjustment included in net benefit costs 83 133 134 Total other comprehensive income (loss) 665 812 ( 78 ) Comprehensive income (loss) 8,005 3,291 ( 1,935 ) 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 2022 2021 Assets Current assets Cash and cash equivalents 3,749 2,153 Accounts receivable - net (a) 4,719 3,869 Inventories of crude oil and products (note 11) 1,514 1,102 Materials, supplies and prepaid expenses 754 689 Total current assets 10,736 7,813 Investments and long-term receivables (b) 893 757 Property, plant and equipment, less accumulated depreciation and depletion (note 2, 18) 30,506 31,240 Goodwill 166 166 Other assets, including intangibles - net 1,223 806 Total assets 43,524 40,782 Liabilities Current liabilities Notes and loans payable (note 12) 122 122 Accounts payable and accrued liabilities (a) (note 11) 6,194 5,184 Income taxes payable 2,582 248 Total current liabilities 8,898 5,554 Long-term debt (c) (note 14) 4,033 5,054 Other long-term obligations (note 5) 3,467 3,897 Deferred income tax liabilities (note 3) 4,713 4,542 Total liabilities 21,111 19,047 Commitments and contingent liabilities (note 9) Shareholders’ equity Common shares at stated value (d) (note 10) 1,079 1,252 Earnings reinvested 21,846 21,660 Accumulated other comprehensive income (loss) (note 17) ( 512 ) ( 1,177 ) Total shareholders’ equity 22,413 21,735 Total liabilities and shareholders’ equity 43,524 40,782 (a) Accounts receivable - net included net amounts receivable from related parties of $ 1,108 million (2021 – $ 1,031 million), (note 16). (b) Investments and long-term receivables included amounts from related parties of $ 288 million (2021 – $ 298 million), (note 16). (c) Long-term debt included amounts to related parties of $ 3,447 million (2021 – $ 4,447 million), (note 16). (d) Number of common shares authorized and outstanding were 1,100 million and 584 million, respectively (2021 – 1,100 million and 678 million, respectively), (note 10). The information in the notes to consolidated financial statements is an integral part of these statements. Approved by the directors. /s/ Bradley W. Corson /s/ Daniel E. Lyons Bradley W. Corson 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 2022 2021 2020 Common shares at stated value (note 10) At beginning of year 1,252 1,357 1,375 Share purchases at stated value ( 173 ) ( 105 ) ( 18 ) At end of year 1,079 1,252 1,357 Earnings reinvested At beginning of year 21,660 22,050 24,812 Net income (loss) for the year 7,340 2,479 ( 1,857 ) Share purchases in excess of stated value ( 6,222 ) ( 2,140 ) ( 256 ) Dividends declared ( 932 ) ( 729 ) ( 647 ) Cumulative effect of accounting change — — ( 2 ) At end of year 21,846 21,660 22,050 Accumulated other comprehensive income (loss) (note 17) At beginning of year ( 1,177 ) ( 1,989 ) ( 1,911 ) Other comprehensive income (loss) 665 812 ( 78 ) At end of year ( 512 ) ( 1,177 ) ( 1,989 ) Shareholders’ equity at end of year 22,413 21,735 21,418 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 2022 2021 2020 Operating activities Net income (loss) 7,340 2,479 ( 1,857 ) Adjustments for non-cash items: Depreciation and depletion (includes impairments) (note 2) 1,897 1,977 3,273 Impairment of intangible assets (note 11) — — 20 (Gain) loss on asset sales (note 8, 18) ( 158 ) ( 49 ) ( 35 ) Deferred income taxes and other ( 77 ) 91 ( 521 ) Changes in operating assets and liabilities: Accounts receivable ( 862 ) ( 1,950 ) 780 Inventories, materials, supplies and prepaid expenses ( 477 ) 45 78 Income taxes payable 1,876 248 ( 106 ) Accounts payable and accrued liabilities 948 2,020 ( 1,087 ) All other items - net (b) ( 5 ) 615 253 Cash flows from (used in) operating activities 10,482 5,476 798 Investing activities Additions to property, plant and equipment ( 1,526 ) ( 1,108 ) ( 868 ) Proceeds from asset sales (note 8, 18) 904 81 82 Additional investments ( 6 ) — — Loans to equity companies - net 10 15 ( 16 ) Cash flows from (used in) investing activities ( 618 ) ( 1,012 ) ( 802 ) Financing activities Short-term debt - net (note 12) — ( 111 ) — Long-term debt - reduction (note 14) ( 1,000 ) — — Finance lease obligations - reduction (note 14) ( 22 ) ( 20 ) ( 20 ) Dividends paid ( 851 ) ( 706 ) ( 649 ) Common shares purchased (note 10) ( 6,395 ) ( 2,245 ) ( 274 ) Cash flows from (used in) financing activities ( 8,268 ) ( 3,082 ) ( 943 ) Increase (decrease) in cash 1,596 1,382 ( 947 ) Cash and cash equivalents at beginning of year 2,153 771 1,718 Cash and cash equivalents at end of year (a) 3,749 2,153 771 (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)  Included contributions to registered pension plans. ( 174 ) ( 164 ) ( 195 ) Income taxes (paid) refunded. ( 374 ) 58 ( 42 ) Interest (paid), net of capitalization. ( 60 ) ( 43 ) ( 62 ) 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 and lower-emission fuels. 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. Prior years’ data have been reclassified in certain cases to conform to the 2022 presentation basis. All amounts are in Canadian dollars unless otherwise indicated. 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 Imperial 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 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. Derivative instruments Imperial 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” or “Purchases of crude oil and products” 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 or 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 Imperial’s share of earnings since the investment was made, less dividends received. Imperial’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 and a rail loading joint venture 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. Imperial does not invest in these investments in order to remove liabilities from its balance sheet. 80 Property, plant and equipment Cost basis Imperial 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. This approach was applied in 2021, with the corresponding effect on depreciation expense being immaterial compared to prior periods. For 2022 and 2023, all properties have sufficient reserves at current SEC prices which will enable equitable allocation of cost over the economic lives of the Upstream assets. 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, industry margins, and 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, Imperial 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 Outlook for Energy 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 Outlook for Energy (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 project the degree of required future policy and technology advancement and deployment for the world or the company, 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. On page 93 , 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 2. Business segments The company operates its business in Canada. The Upstream, Downstream and Chemical functions best define the operating segments of the business that are reported separately. The factors used to identify these reportable segments are based on the nature of the operations that are undertaken by each segment and the structure of the company’s internal organization. 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. These functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available. 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. 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 Chemical millions of Canadian dollars 2022 2021 2020 2022 2021 2020 2022 2021 2020 Revenues and other income Revenues (a) (b) 494 5,863 6,263 57,466 30,207 15,178 1,453 1,438 843 Intersegment sales (c) 19,135 9,956 2,527 7,476 4,520 1,480 523 319 165 Investment and other income (note 8, 18) 135 12 7 43 59 78 — 1 — 19,764 15,831 8,797 64,985 34,786 16,736 1,976 1,758 1,008 Expenses Exploration (note 15) 5 32 13 — — — — — — Purchases of crude oil and products (c) (note 11) 7,971 7,492 4,834 55,569 29,505 12,047 1,330 966 579 Production and manufacturing (note 11) 5,491 4,661 3,852 1,640 1,445 1,468 273 210 215 Selling and general — — — 653 572 619 85 90 92 Federal excise tax and fuel charge — — — 2,177 1,928 1,736 2 — — Depreciation and depletion (d) (note 11) 1,673 1,775 3,084 179 158 166 18 18 19 Non-service pension and postretirement benefit — — — — — — — — — Financing (note 12) 5 15 3 1 — — — — — Total expenses 15,145 13,975 11,786 60,219 33,608 16,036 1,708 1,284 905 Income (loss) before income taxes (note 11) 4,619 1,856 ( 2,989 ) 4,766 1,178 700 268 474 103 Income tax expense (benefit) (note 3) 974 461 ( 671 ) 1,144 283 147 64 113 25 Net income (loss) (c) (note 11) 3,645 1,395 ( 2,318 ) 3,622 895 553 204 361 78 Cash flows from (used in) operating activities (c) 5,834 4,913 286 4,415 179 470 276 421 114 Capital and exploration expenditures (e) 1,128 632 561 295 476 251 10 8 21 Property, plant and equipment Cost 45,784 48,200 47,693 6,926 6,772 6,321 995 984 975 Accumulated depreciation and depletion ( 18,835 ) ( 20,389 ) ( 18,786 ) ( 4,143 ) ( 4,096 ) ( 3,962 ) ( 741 ) ( 721 ) ( 699 ) Net property, plant and equipment (f) 26,949 27,811 28,907 2,783 2,676 2,359 254 263 276 Total assets (c) 28,830 29,416 31,835 9,277 7,945 4,554 491 474 408 Corporate and other Eliminations Consolidated millions of Canadian dollars 2022 2021 2020 2022 2021 2020 2022 2021 2020 Revenues and other income Revenues (a) (b) — — — — — — 59,413 37,508 22,284 Intersegment sales (c) — — — ( 27,134 ) ( 14,795 ) ( 4,172 ) — — — Investment and other income (note 8, 18) 79 10 19 — — — 257 82 104 79 10 19 ( 27,134 ) ( 14,795 ) ( 4,172 ) 59,670 37,590 22,388 Expenses Exploration (note 15) — — — — — — 5 32 13 Purchases of crude oil and products (c) (note 11) — — — ( 27,128 ) ( 14,789 ) ( 4,167 ) 37,742 23,174 13,293 Production and manufacturing (note 11) — — — — — — 7,404 6,316 5,535 Selling and general 150 128 35 ( 6 ) ( 6 ) ( 5 ) 882 784 741 Federal excise tax and fuel charge — — — — — — 2,179 1,928 1,736 Depreciation and depletion (d) (note 11) 27 26 24 — — — 1,897 1,977 3,293 Non-service pension and postretirement benefit 17 42 121 — — — 17 42 121 Financing (note 12) 54 39 61 — — — 60 54 64 Total expenses 248 235 241 ( 27,134 ) ( 14,795 ) ( 4,172 ) 50,186 34,307 24,796 Income (loss) before income taxes (note 11) ( 169 ) ( 225 ) ( 222 ) — — — 9,484 3,283 ( 2,408 ) Income tax expense (benefit) (note 3) ( 38 ) ( 53 ) ( 52 ) — — — 2,144 804 ( 551 ) Net income (loss) (c) (note 11) ( 131 ) ( 172 ) ( 170 ) — — — 7,340 2,479 ( 1,857 ) Cash flows from (used in) operating activities (c) ( 59 ) ( 47 ) ( 64 ) 16 10 ( 8 ) 10,482 5,476 798 Capital and exploration expenditures (e) 57 24 41 — — — 1,490 1,140 874 Property, plant and equipment Cost 863 806 782 — — — 54,568 56,762 55,771 Accumulated depreciation and depletion ( 343 ) ( 316 ) ( 290 ) — — — ( 24,062 ) ( 25,522 ) ( 23,737 ) Net property, plant and equipment (f) 520 490 492 — — — 30,506 31,240 32,034 Total assets (c) 5,312 3,196 1,632 ( 386 ) ( 249 ) ( 398 ) 43,524 40,782 38,031 86 (a) Includes export sales to the United States of $ 12,394 million (2021 - $ 7,228 million, 2020 - $ 4,614 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 2022 2021 2020 Revenue from contracts with customers 52,265 34,275 22,199 Revenue outside the scope of ASC 606 7,148 3,233 85 Total 59,413 37,508 22,284 (c) In 2021, the Downstream segment acquired a portion of Upstream crude inventory for $ 444 million. There was no earnings impact and the effects of this transaction have been eliminated for consolidation purposes. (d) In 2020, the Upstream segment included a non-cash impairment charge of $ 1,531 million, before-tax, related to the company’s decision not to further develop a significant portion of its unconventional portfolio. (e) 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. (f) Includes property, plant and equipment under construction of $ 2,676 million (2021 - $ 2,348 million, 2020 - $ 1,874 million). 3. Income taxes millions of Canadian dollars 2022 2021 2020 Current income tax expense (benefit) (a) 2,228 711 ( 27 ) Deferred income tax expense (benefit) (a) ( 84 ) 93 ( 524 ) Total income tax expense (benefit) (a) 2,144 804 ( 551 ) Statutory corporate tax rate (percent) 24.1 24.0 25.0 Increase (decrease) resulting from: Enacted tax rate change (a) — — 0.1 Other (b) ( 1.5 ) 0.5 ( 2.2 ) Effective income tax rate (percent) 22.6 24.5 22.9 (a) On June 28, 2019, the Alberta government enacted a 4 percent decrease in the provincial tax rate, from 12 percent to 8 percent by 2022. On December 9, 2020, the Alberta government enacted an accelerated decrease in the province’s general corporate income tax rate from 10 percent to 8 percent, effective July 1, 2020. The cumulative effect of the 2020 legislative tax changes on the company’s financial statements was immaterial. (b) Other primarily relates to disposals, prior year adjustments and re-assessments. In 2022, the company's sale of its interests in XTO Energy Canada decreased the effective income tax rate by 1.3 percent. 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 2022 2021 2020 Depreciation and amortization 5,388 5,284 5,319 Successful drilling and land acquisitions 236 331 363 Pension and benefits ( 105 ) ( 303 ) ( 534 ) Asset retirement obligation ( 529 ) ( 418 ) ( 403 ) Capitalized interest 127 120 120 LIFO inventory valuation ( 454 ) ( 413 ) ( 150 ) Tax loss carryforwards ( 84 ) ( 42 ) ( 460 ) Valuation allowance 73 — — Other ( 53 ) ( 101 ) ( 154 ) Net deferred income tax liabilities 4,599 4,458 4,101 87 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 2022 2021 2020 Balance as of January 1 47 36 35 Additions based on current year’s tax position 12 16 2 Additions for prior years’ tax positions 10 — — Settlements with tax authorities ( 9 ) ( 5 ) ( 1 ) Balance as of December 31 60 47 36 The unrecognized tax benefit balances shown above are predominately related 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 2022, 2021 and 2020 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 2018 to 2022 are subject to examination by the tax authorities. Tax filings from 2007 to 2017 have open objections and therefore are also subject to examination by the tax authorities. The Canada Revenue 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. Many of these outstanding matters will not be resolved until after 2023. 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. 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. 88 The benefit obligations and plan assets associated with the company’s defined benefit plans are measured on December 31. Pension benefits Other postretirement benefits 2022 2021 2022 2021 Assumptions used to determine benefit obligations at December 31 (percent) Discount rate 5.10 3.00 5.10 3.00 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 9,850 10,716 818 873 Service cost 280 324 23 28 Interest cost 295 271 24 22 Actuarial loss (gain) (a) ( 2,528 ) ( 925 ) ( 248 ) ( 83 ) Benefits paid (b) ( 523 ) ( 536 ) ( 28 ) ( 22 ) Benefit obligation at December 31 7,374 9,850 589 818 Accumulated benefit obligation at December 31 6,820 8,885 (a) Actuarial loss (gain) primarily driven by changes in the year-end discount rate and salary experience. (b) Benefit payments for funded and unfunded plans. 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 6.01 percent in 2023 and gradually decline to 3.57 percent by 2040 and beyond. Pension benefits Other postretirement benefits millions of Canadian dollars 2022 2021 2022 2021 Change in plan assets Fair value at January 1 9,440 9,426 Actual return (loss) gain ( 1,594 ) 319 Company contributions 174 164 Benefits paid (a) ( 479 ) ( 469 ) Fair value at December 31 7,541 9,440 Plan assets in excess of (less than) projected benefit obligation at December 31 Funded plans 543 89 Unfunded plans ( 376 ) ( 499 ) ( 589 ) ( 818 ) Total (b) 167 ( 410 ) ( 589 ) ( 818 ) (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. 89 Pension benefits Other postretirement benefits millions of Canadian dollars 2022 2021 2022 2021 Amounts recorded in the Consolidated balance sheet consist of: Other assets, including intangibles - net 543 190 — — Current liabilities ( 35 ) ( 26 ) ( 28 ) ( 30 ) Other long-term obligations ( 341 ) ( 574 ) ( 561 ) ( 788 ) Total recorded 167 ( 410 ) ( 589 ) ( 818 ) Amounts recorded in accumulated other comprehensive income consist of: Net actuarial loss (gain) 666 1,272 ( 84 ) 173 Prior service cost 235 252 — — Total recorded in accumulated other comprehensive income, before-tax 901 1,524 ( 84 ) 173 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 2022 long-term expected return of 4.3 percent used in the calculations of pension expense compares to an actual rate of return of 5.6 percent and 6.5 percent over the last 10- and 20-year periods respectively, ending December 31, 2022. Pension benefits Other postretirement benefits 2022 2021 2020 2022 2021 2020 Assumptions used to determine net periodic benefit cost for years ended December 31 (percent) Discount rate 3.00 2.50 3.10 3.00 2.50 3.10 Long-term rate of return on funded assets 4.30 4.50 4.50 — — — Long-term rate of compensation increase 4.00 4.00 4.50 4.00 4.00 4.50 millions of Canadian dollars Components of net periodic benefit cost Service cost 280 324 305 23 28 24 Interest cost 295 271 308 24 22 24 Expected return on plan assets ( 412 ) ( 427 ) ( 391 ) — — — Amortization of prior service cost 17 17 14 — — — Amortization of actuarial loss (gain) 84 143 153 9 16 13 Net periodic benefit cost 264 328 389 56 66 61 Changes in amounts recorded in accumulated other comprehensive income Net actuarial loss (gain) ( 522 ) ( 817 ) 129 ( 248 ) ( 83 ) 152 Amortization of net actuarial (loss) gain included in net periodic benefit cost ( 84 ) ( 143 ) ( 153 ) ( 9 ) ( 16 ) ( 13 ) Amortization of prior service cost included in net periodic benefit cost ( 17 ) ( 17 ) ( 14 ) — — — Total recorded in other comprehensive income ( 623 ) ( 977 ) ( 38 ) ( 257 ) ( 99 ) 139 Total recorded in net periodic benefit cost and other comprehensive income, before-tax ( 359 ) ( 649 ) 351 ( 201 ) ( 33 ) 200 Costs for defined contribution plans, primarily the employee savings plan, were $ 43 million in 2022 (2021 - $ 47 million, 2020 - $ 47 million). 90 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 2022 2021 2020 (Charge) credit to other comprehensive income, before-tax 880 1,076 ( 101 ) Deferred income tax (charge) credit (note 17) ( 215 ) ( 264 ) 23 (Charge) credit to other comprehensive income, after-tax 665 812 ( 78 ) 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 and liquidity. The target asset allocation for equity securities is 30 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 2022 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, 2022, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Value Asset class Equity securities Canadian 96 96 Non-Canadian 2,215 2,215 Debt securities - Canadian Corporate 1,156 1,156 Government 3,842 3,842 Asset backed 2 2 Equities – Venture capital 199 199 Cash 31 10 21 Total plan assets at fair value 7,541 10 7,531 91 The 2021 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, 2021, using: millions of Canadian dollars Total Level 1 Level 2 Level 3 Net Asset Value Asset class Equity securities Canadian 247 247 Non-Canadian 2,539 2,539 Debt securities - Canadian Corporate 1,496 1,496 Government 4,865 4,865 Asset backed 1 1 Equities – Venture capital 249 249 Cash 43 36 7 Total plan assets at fair value 9,440 36 9,404 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 2022 2021 For funded pension plans with projected benefit obligation in excess of plan assets: (a) (b) Projected benefit obligation — 1,132 Fair value of plan assets — 1,031 Projected benefit obligation less fair value of plan assets — 101 For unfunded pension plans covered by book reserves: Projected benefit obligation 376 499 Accumulated benefit obligation 353 461 (a) In 2022, 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. (b) In 2021, projected benefit obligation exceeded the fair value of plan assets only for the company’s proportionate share of a joint venture sponsored pension plan. Cash flows Benefit payments expected in: millions of Canadian dollars Pension benefits Other postretirement benefits 2023 480 29 2024 470 30 2025 470 30 2026 470 31 2027 470 31 2028 - 2032 2,360 166 In 2023, the company expects to make cash contributions of about $ 180 million to its pension plans. 92 5. Other long-term obligations millions of Canadian dollars 2022 2021 Employee retirement benefits (a) (note 4) 902 1,362 Asset retirement obligations and other environmental liabilities (b) (c) 2,150 1,713 Share-based incentive compensation liabilities (note 7) 101 79 Operating lease liability (note 13) 151 147 Other obligations 163 596 Total other long-term obligations 3,467 3,897 (a) Total recorded employee retirement benefits obligations also included $ 63 million in current liabilities (2021 – $ 56 million). (b) Total asset retirement obligations and other environmental liabilities also included $ 116 million in current liabilities (2021 – $ 102 million). (c) For 2022, the asset retirement obligations were discounted at 6 percent (2021 - 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 2022 2021 2020 Balance as at January 1 1,721 1,674 1,400 Additions (deductions) 415 6 265 Accretion 101 99 82 Settlement ( 59 ) ( 58 ) ( 73 ) Balance as at December 31 2,178 1,721 1,674 Estimated cash payments for asset retirement obligations are $ 82 million in 2023 and $ 64 million in 2024. 93 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, 2022 and December 31, 2021, the fair value of long-term debt ($ 3,447 million and $ 4,447 million respectively, 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 and currency exchange 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”. The company does not designate derivative instruments as a hedge for hedge accounting purposes. 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 2022 2021 Crude 1,800 7,390 Products ( 350 ) ( 560 ) Realized and unrealized gain or (loss) on derivative instruments recognized in the Consolidated statement of income is included in the following lines on a before-tax basis: millions of Canadian dollars 2022 2021 2020 Revenues 148 ( 46 ) ( 13 ) Purchases of crude oil and products — ( 33 ) ( 21 ) Total 148 ( 79 ) ( 34 ) The estimated fair value of derivative instruments, and the related hierarchy level for the fair value measurement is as follows: At December 31, 2022 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) 17 32 — 49 ( 27 ) — 22 L iabilities Derivative liabilities (b) 21 20 — 41 ( 27 ) ( 4 ) 10 (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”. 94 At December 31, 2021 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) 24 17 — 41 ( 31 ) — 10 L iabilities Derivative liabilities (b) 31 12 — 43 ( 31 ) ( 7 ) 5 (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, 2022 and December 31, 2021, the company had $ 14 million and $ 6 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. 95 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. As a result of an employee stock program expansion implemented in 2022, some new participants will be eligible for 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, 2022: Restricted stock units Deferred share units Outstanding at January 1, 2022 3,950,615 166,665 Granted 884,140 13,219 Vested / Exercised ( 787,110 ) — Forfeited and cancelled ( 11,290 ) — Outstanding at December 31, 2022 4,036,355 179,884 96 In 2022, the before-tax compensation expense charged against income for these programs was $ 113 million (2021 - $ 96 million expense, 2020 - $ 2 million benefit). Income tax benefit recognized in income related to compensation expense for the year was $ 27 million (2021 - $ 23 million, 2020 - $ 0 million ). Cash payments of $ 78 million were made for these programs in 2022 (2021 - $ 52 million, 2020 - $ 33 million). As of December 31, 2022, there was $ 133 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 4.1 years. All units under the deferred share programs have vested as of December 31, 2022. 8. Investment and other income Investment and other income includes gains and losses on asset sales as follows: millions of Canadian dollars 2022 2021 2020 Proceeds from asset sales 904 81 82 Book value of asset sales 746 32 47 Gain (loss) on asset sales, before tax (a) 158 49 35 Gain (loss) on asset sales, after tax (a) 241 43 32 (a) 2022 included a gain of $ 116 million ($ 208 million, after tax) from the sale of interests in XTO Energy Canada, which included the removal of a deferred tax liability. 9. Litigation and other contingencies A variety of claims have been made against Imperial 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 or financial condition. Unconditional purchase obligations, as defined by accounting standards, are those long-term commitments that are non-cancelable or cancelable 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. As a result of the completed sale of Imperial’s remaining company-owned Esso retail sites, the company was contingently liable at December 31, 2022, for guarantees relating to performance under contracts of other third-party obligations totalling $ 17 million (2021 - $ 21 million). 97 10. Common shares At December 31 thousands of shares 2022 2021 Authorized 1,100,000 1,100,000 Common shares outstanding 584,153 678,080 The most recent 12-month normal course issuer bid program came into effect June 29, 2022, under which Imperial continued its existing share purchase program. The program enabled the company to purchase up to a maximum of 31,833,809 common shares ( 5 percent of the total shares on June 15, 2022) which included shares purchased under the normal course issuer bid and from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid. 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 October 21, 2022 as a result of the company purchasing the maximum allowable number of shares under the program. On May 6, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $ 2.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on June 15, 2022, with the company taking up and paying for 32,467,532 common shares at a price of $ 77.00 per share, for an aggregate purchase of $ 2.5 billion and 4.9 percent of Imperial’s issued and outstanding shares at the close of business on May 2, 2022. This included 22,597,379 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. On November 4, 2022, the company commenced a substantial issuer bid pursuant to which it offered to purchase for cancellation up to $ 1.5 billion of its common shares through a modified Dutch auction and proportionate tender offer. The substantial issuer bid was completed on December 14, 2022, with the company taking up and paying for 20,689,655 common shares at a price of $ 72.50 per share, for an aggregate purchase of $ 1.5 billion and 3.4 percent of Imperial’s issued and outstanding shares at the close of business on October 31, 2022. This included 14,399,985 shares purchased from Exxon Mobil Corporation by way of a proportionate tender to maintain its ownership percentage at approximately 69.6 percent. 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, 2020 743,902 1,375 Issued under employee share-based awards 7 — Purchases at stated value ( 9,832 ) ( 18 ) Balance as at December 31, 2020 734,077 1,357 Issued under employee share-based awards 7 — Purchases at stated value ( 56,004 ) ( 105 ) Balance as at December 31, 2021 678,080 1,252 Issued under employee share-based awards — — Purchases at stated value ( 93,927 ) ( 173 ) Balance as at December 31, 2022 584,153 1,079 98 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: 2022 2021 2020 Net income (loss) per common share – basic Net income (loss) (millions of Canadian dollars) 7,340 2,479 ( 1,857 ) Weighted-average number of common shares outstanding (millions of shares) 640.2 711.6 735.3 Net income (loss) per common share (dollars) 11.47 3.48 ( 2.53 ) Net income (loss) per common share – diluted Net income (loss) (millions of Canadian dollars) 7,340 2,479 ( 1,857 ) Weighted-average number of common shares outstanding (millions of shares) 640.2 711.6 735.3 Effect of employee share-based awards (millions of shares) (a) 1.3 1.6 — Weighted-average number of common shares outstanding, assuming dilution (millions of shares) 641.5 713.2 735.3 Net income (loss) per common share (dollars) 11.44 3.48 ( 2.53 ) Dividends per common share – declared (dollars) 1.46 1.03 0.88 (a) For 2020, the Net income (loss) per common share – diluted excludes the effect of 1.9 million employee share-based awards. Share-based awards have the potential to dilute basic earnings per share in the future. 99 11. Miscellaneous financial information LIFO inventory In 2022, net income included an after-tax gain of $ 62 million (2021 – $ 13 million loss, 2020 – $ 19 million loss) 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, 2022 by about $ 2 billion (2021 – $ 1.8 billion). Inventories of crude oil and products at year-end consisted of the following: millions of Canadian dollars 2022 2021 Crude oil 809 674 Petroleum products 471 310 Chemical products 76 73 Other 158 45 Total 1,514 1,102 In 2021, the company recorded an unfavourable $ 74 million ($ 82 million, before tax) inventory adjustment (including the proportionate share of LIFO changes) related to reconciliations of additives and products inventory at equity and third-party terminals. The out-of-period impact of $ 57 million ($ 63 million, before tax) occurred over a number of years, and has been resolved. The company determined that the adjustment was not material to the consolidated financial statements for the year ended December 31, 2021, or any of the prior periods related to the adjustment. Accordingly, comparative periods presented in the consolidated financial statements have not been restated. 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 2022 were $ 74 million (2021 – $ 89 million, 2020 – $ 105 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 $ 458 million at December 31, 2022 (2021 – $ 415 million). Goodwill impairment In the first quarter of 2020, the company assessed its goodwill balances for impairment and recognized a non-cash goodwill impairment charge of $ 20 million in the company’s Upstream segment. The goodwill impairment was reflected in “Depreciation and depletion” on the Consolidated statement of income and “Goodwill” on the Consolidated balance sheet. The remaining balance of goodwill is associated with the Downstream segment. Government assistance The company received subsidies as part of the Government of Canada’s COVID-19 Economic Response Plan, which included the company’s proportionate share of a joint venture. It was recognized as a reduction to expense (2020 – $ 155 million before tax) and was included in the Consolidated statement of income, primarily as part of “Production and manufacturing”. In 2022, the company prospectively adopted the Financial Accounting Standards Board’s standard, Government Assistance (Topic 832) . The standard requires the annual 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 in the Consolidated balance sheet. During 2022, government assistance was immaterial to the company’s financial results . 100 12. Financing and additional notes and loans payable information millions of Canadian dollars 2022 2021 2020 Debt-related interest (a) 111 63 102 Capitalized interest ( 57 ) ( 24 ) ( 41 ) Net interest expense 54 39 61 Other interest 6 15 3 Total financing (b) 60 54 64 (a) Includes related party interest with ExxonMobil. (b) The weighted-average interest rate on short-term borrowings in 2022 was 2.0 percent (2021 – 0.2 percent, 2020 – 0.8 percent) and on long-term borrowings, with ExxonMobil, in 2022 was 1.9 percent (2021 – 0.6 percent, 2020 – 1.4 percent). During the second quarter of 2022, the company reduced its existing $ 500 million committed long-term line of credit to $ 250 million and extended the maturity date to June 30, 2023. Subsequently, in the fourth quarter of 2022, this committed long-term line of credit was cancelled in full. The company also extended one of its $ 250 million committed long-term lines of credit to June 30, 2024. In November 2022, the company extended the maturity date of an existing $ 250 million committed short-term line of credit to November 2023. The company has not drawn on any of its outstanding $ 500 million of available credit facilities. In 2021, the company repaid the $ 111 million outstanding balance and terminated the non-interest bearing, revolving demand loan under an arrangement with an affiliate company of ExxonMobil. 101 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 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: 2022 2021 2020 millions of Canadian dollars Operating leases Finance leases Operating leases Finance leases Operating leases Finance leases Operating lease cost 119 123 157 Short-term and other (net of sublease rental income) 40 19 40 Amortization of right of use assets 19 17 29 Interest on lease liabilities 30 33 38 Total lease cost 159 49 142 50 197 67 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: 2022 2021 millions of Canadian dollars Operating leases Finance leases Operating leases Finance leases Right of use assets Included in Other assets, including intangibles - net 245 245 Included in Property, plant and equipment, less 618 637 accumulated depreciation and depletion Total right of use assets 245 618 245 637 Lease liability due within one year Included in Accounts payable and accrued liabilities 100 — 102 — Included in Notes and loans payable 22 22 L ong-term lease liability Included in Other long-term obligations 151 — 147 — Included in Long-term debt 586 607 Total lease liability 251 608 249 629 Weighted-average remaining lease term (years) 5 37 4 38 Weighted-average discount rate (percent) 1.1 4.7 1.2 4.8 102 The maturity analysis of the company’s lease liabilities as at December 31 are summarized below: 2022 millions of Canadian dollars Operating leases Finance leases Maturity analysis of lease liabilities 2023 102 50 2024 70 49 2025 15 46 2026 10 44 2027 10 43 2028 and beyond 56 900 Total lease payments 263 1,132 Discount to present value ( 12 ) ( 524 ) Total lease liability 251 608 In addition to the operating lease liabilities in the table immediately above, at December 31, 2022, additional undiscounted commitments for leases not yet commenced totalled $ 14 million (2021 - $ 5 million). Estimated cash payments for operating and finance leases not yet commenced are $ 5 million in both 2023 and 2024. 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: 2022 2021 2020 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 — 122 — 136 15 Cash flows from financing activities 22 20 20 Non-cash right of use assets recorded for lease liabilities In exchange for lease liabilities during the year 117 — 176 123 63 14 103 14. Long-term debt At December 31 millions of Canadian dollars 2022 2021 Long-term debt (a) (b) 3,447 4,447 Finance leases (c) 586 607 Total long-term debt 4,033 5,054 (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, 2025, cancelable if ExxonMobil provides at least 370 days advance written notice. (b) During the third quarter of 2022, the company decreased its long-term debt by $ 1 billion, partially repaying an existing facility with an affiliated company of ExxonMobil. (c) Finance leases are primarily associated with transportation facilities and services agreements. The average imputed interest rate was 4.7 percent in 2022 (2021 – 4.8 percent). Total finance lease obligations also include $ 22 million in current liabilities (2021 - $ 22 million). Principal payments on finance leases of approximately $ 20 million on average per year are due in each of the next four years after December 31, 2023. 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, 2022, 2021 and 2020. 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, 2022, 2021 and 2020. 104 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 computer and customer support 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. The company had an existing agreement with ExxonMobil to provide for the delivery of management, business and technical services to Syncrude Canada Ltd. by ExxonMobil, which was terminated in connection with the transfer of operatorship of Syncrude on September 30, 2021. Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate. The amounts of purchases and revenues by Imperial in 2022, with ExxonMobil, were $ 3,719 million and $ 17,042 million respectively (2021 - $ 2,669 million and $ 8,777 million respectively). As at December 31, 2022, the company had an outstanding long-term loan of $ 3,447 million (2021 – $ 4,447 million) from ExxonMobil (see note 14, "Long-term debt", on page 104 and note 12, "Financing and additional notes and loans payable information", on page 101 for further details). The amount of financing costs with ExxonMobil were $ 78 million (2021 - $ 28 million). Imperial has other related party transactions not detailed above in note 16, as they are not significant. 105 17. Other comprehensive income (loss) information Changes in accumulated other comprehensive income (loss): millions of Canadian dollars 2022 2021 2020 Balance at January 1 ( 1,177 ) ( 1,989 ) ( 1,911 ) Postretirement benefits liability adjustment: Current period change excluding amounts reclassified from accumulated other comprehensive income 582 679 ( 212 ) Amounts reclassified from accumulated other comprehensive income 83 133 134 Balance at December 31 ( 512 ) ( 1,177 ) ( 1,989 ) Amounts reclassified out of accumulated other comprehensive income (loss) - before-tax income (expense): millions of Canadian dollars 2022 2021 2020 Amortization of postretirement benefits liability adjustment included in net benefit cost (a) ( 110 ) ( 176 ) ( 180 ) (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 2022 2021 2020 Postretirement benefits liability adjustments: Postretirement benefits liability adjustment (excluding amortization) 188 221 ( 69 ) Amortization of postretirement benefits liability adjustment included in net benefit cost 27 43 46 Total 215 264 ( 23 ) 18. Divestment activities Jointly with ExxonMobil Canada, Imperial signed an agreement in the second quarter of 2022 with Whitecap Resources Inc. for the sale of its interests in XTO Energy Canada which included assets in the Montney and Duvernay areas of central Alberta, for total cash consideration of approximately $ 1.9 billion ($ 0.9 billion Imperial's share). The transaction closed on August 31, 2022 and the company recognized a gain of approximately $ 0.2 billion , after tax. Imperial’s total assets associated with this transaction include about $ 0.9 billion (about $ 0.8 billion of property, plant and equipment) and about $ 0.2 billion total liabilities in the Upstream segment. 106 Supplemental information on oil and gas exploration and production activities (unaudited) The information on pages 107 to 108 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 2022 2021 2020 Revenue Sales to third parties (a) 7,154 5,081 2,066 Transfers (a) (b) 4,182 3,037 1,777 11,336 8,118 3,843 Production expenses 5,521 4,728 3,977 Exploration expenses 5 32 13 Depreciation and depletion (includes impairments) 1,467 1,579 2,857 Income taxes 1,030 457 (678) Results of operations 3,313 1,322 (2,326) 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 2022 2021 2020 Property costs (c) Proved — — — Unproved — — — Exploration costs 5 32 13 Development costs 1,602 576 816 Total costs incurred in property acquisitions, exploration and development activities 1,607 608 829 (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. (c) “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. 107 Capitalized costs millions of Canadian dollars 2022 2021 Property costs (a) Proved 1,840 2,045 Unproved 493 2,468 Producing assets 39,075 39,926 Incomplete construction 2,375 1,762 Total capitalized cost 43,783 46,201 Accumulated depreciation and depletion (18,512) (20,112) Net capitalized costs 25,271 26,089 (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 2022 2021 2020 Future cash flows 198,923 161,577 23,911 Future production costs (104,765) (101,580) (18,787) Future development costs (23,392) (21,903) (6,096) Future income taxes (16,872) (8,192) (155) Future net cash flows 53,894 29,902 (1,127) Annual discount of 10 percent for estimated timing of cash flows (28,340) (15,732) 1,065 Discounted future cash flows 25,554 14,170 (62) Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves millions of Canadian dollars 2022 2021 2020 Balance at beginning of year 14,170 (62) 5,511 Changes resulting from: Sales and transfers of oil and gas produced, net of production costs (6,113) (3,841) (447) Net changes in prices, development costs and production costs (a) 23,215 7,681 (8,661) Extensions, discoveries, additions and improved recovery, less related costs 664 52 114 Development costs incurred during the year 1,160 650 563 Revisions of previous quantity estimates (4,431) 13,482 459 Accretion of discount 1,439 24 623 Net change in income taxes (4,550) (3,816) 1,776 Net change 11,384 14,232 (5,573) Balance at end of year 25,554 14,170 (62) (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”. 108 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 2020 41 581 415 2,939 3,492 Revisions (29) (348) (79) (2,757) (2,923) Improved recovery — — — — — (Sale) purchase of reserves in place — (10) — — (2) Discoveries and extensions — — 133 1 134 Production (5) (55) (25) (102) (141) End of year 2020 7 168 444 81 560 Revisions 13 165 17 2,239 2,297 Improved recovery — — — 2 2 (Sale) purchase of reserves in place — (10) — — (2) Discoveries and extensions — — — — — Production (4) (42) (23) (106) (140) End of year 2021 16 281 438 2,216 2,717 Revisions — (41) (62) (363) (432) Improved recovery — — — — — (Sale) purchase of reserves in place (9) (141) — — (32) Discoveries and extensions — 2 — 67 67 Production (3) (29) (23) (96) (127) End of year 2022 4 72 353 1,824 2,193 Net proved developed reserves included above, as of January 1, 2020 22 291 415 2,609 3,095 December 31, 2020 7 167 311 76 422 December 31, 2021 14 205 326 1,957 2,331 December 31, 2022 4 60 248 1,691 1,953 Net proved undeveloped reserves included above, as of January 1, 2020 19 290 — 330 397 December 31, 2020 — 1 133 5 138 December 31, 2021 2 76 112 259 386 December 31, 2022 — 12 105 133 240 (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, condensate 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 2020, 2021 and 2022. 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. 109 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 2020, downward revisions of proved bitumen reserves were a result of low prices. The 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake no longer qualified as proved reserves under the SEC definition of proved reserves. Downward revisions to proved synthetic crude oil reserves were a result of lower prices, offset by the addition of proved undeveloped reserves associated with future development at Syncrude. Changes to the liquids and natural gas proved reserves were the result of updated development plans at the Montney and Duvernay unconventional assets and the divestment of conventional properties. In 2021, upward revisions of proved bitumen reserves were a result of improved prices. The 1.7 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake qualified as proved reserves under the SEC definition of proved reserves. Upward revisions to proved synthetic crude oil reserves were a result of improved prices. Changes to the liquids and natural gas proved reserves were the result of updated development plans and divestments at the Montney and Duvernay unconventional assets. In 2022, downward revisions of proved bitumen reserves were driven by a decrease of 0.2 billion barrels at Kearl as a result of higher royalty obligations associated with pricing, and a decrease of 0.2 billion barrels at Cold Lake due to an updated development plan. An increase to the bitumen reserves of 0.1 billion barrels is associated with extensions at Cold Lake for the Grand Rapids Phase 1 SA-SAGD and Leming SAGD projects. Downward revisions to proved synthetic crude oil reserves were a result of mine development plan updates and higher royalty obligations at Syncrude associated with pricing. Changes to the liquids and natural gas proved reserves were primarily a result of the sale of the company’s interest in the Montney and Duvernay unconventional assets. Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial. 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. 110 Proxy information section Table of contents Page Nominees for director 112 Director nominee tables 112 Majority voting policy 116 Corporate governance disclosure 117 Corporate governance disclosure at a glance 118 Statement of corporate governance practice 119 Composition of our board nominees 119 Tenure of our board nominees 120 Skills and experience of our board members and nominees 121 Independence of our board members and nominees 122 Committee membership of our board 123 Number of meetings 123 Attendance of our board members in 2022 124 Other public company directorships of our board members and nominees 125 Interlocking directorships of our board members 125 Director qualification and selection process 126 Director orientation, education and development 127 Board performance assessment 128 Board and committee structure 128 Director compensation 139 Share ownership guidelines of independent directors and chairman, president and chief executive officer 146 Ethical business conduct 147 Restrictions on insider trading 148 Diversity 148 Shareholder engagement 150 Largest shareholder 151 Transactions with Exxon Mobil Corporation 151 Company executives and executive compensation 153 Named executive officers of the company 153 Other executive officers of the company 154 Letter to shareholders from the executive resources committee on executive compensation 155 Compensation discussion and analysis 156 Overview 157 Compensation program design 161 Compensation decision making process and considerations for named executive officers 166 Executive compensation tables and narratives 172 Appendix 179 Appendix A – Board of director and committee charters 179 111 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, with the exception of S.R. Driscoll, J. Floren and G.J. Goldberg, are now directors and have been since the dates indicated. K.T. Hoeg, J.M. Mintz and D.S. Sutherland are currently directors and are not standing for re-election in 2023 as they have all reached the company's mandatory retirement age for directors. Ms. Driscoll, Mr. Floren and Mr. Goldberg are not currently directors and are being nominated for election as directors for the first time. 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 8, 2023, the effective date of this circular, unless otherwise indicated. For more information on our director nominees, please see the Statement of corporate governance practice starting on page 119 . Director nominee tables David W. Cornhill Calgary, Alberta, Canada Nonemployee director (independent) Age: 69 Director since : November 29, 2017 Skills and experience: Leadership of large organizations, Operations/technical, Project management, Strategy development, Environment and sustainability, Audit committee financial expert, Financial expertise, Executive compensation, Risk management Mr. Cornhill is a director of AltaGas Ltd., and is the chairman of the board of directors of TriSummit Utilities Inc. (formerly AltaGas Canada Inc.), a privately owned corporation. Mr. Cornhill is a founding shareholder of AltaGas (and its predecessors). He was chief executive officer of AltaGas from 1994 to 2016 and served as interim co-chief executive officer from July to December 2018. Prior to forming AltaGas, Mr. Cornhill served in various capacities with Alberta and Southern Gas Co. Ltd, including vice-president, finance and administration, treasurer and president and chief operating officer. Mr. Cornhill is an experienced leader in the business community and is a strong supporter of communities and community collaboration, investment and enhancement. He is a member of the Ivey Advisory Board at Western University. Mr. Cornhill holds a BSc (Hons.) degree and a MBA degree from Western University, and he was awarded an honorary Doctor of Laws degree by the University in 2015. 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 8, 2023 (#) 12,500 (<0.01%) 13,308 25,808 16,900 42,708 Total market value as at February 8, 2023 ($) 869,625 925,838 1,795,463 1,175,733 2,971,196 Year over year change (#) 0 2,355 2,355 2,000 4,355 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Imperial Oil Limited board 8 of 8 (100%) – AltaGas Ltd. (2010 – present) Audit committee 5 of 5 (100%) – AltaGas Canada Inc. (2018 – 2020) Executive resources committee 6 of 7 (86%) – Alterra Power Corp. (2008 – 2018) Safety and sustainability committee 3 of 4 (75%) Nominations and corporate governance committee (Chair) 6 of 6 (100%) *no public board interlocks Community collaboration and engagement committee 1 of 1 (100%) Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: Votes Withheld: – AltaGas Ltd., Chairman of the board (1994 – 2019) 540,497,248 (89.79%) 61,434,933 (10.21%) – AltaGas Ltd., Interim co-CEO (July to December 2018) 112 Bradley W. Corson Calgary, Alberta, Canada Non-independent director Age: 61 Director since : September 17, 2019 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 Mr. Corson was appointed as president and a director of Imperial Oil Limited on September 17, 2019, and assumed the additional roles of chairman and chief executive officer on January 1, 2020. Mr. Corson has worked for Exxon Mobil Corporation and its predecessor companies since 1983 in various upstream and downstream assignments, with responsibilities in the United States, Hong Kong and London. In his previous position, Mr. Corson was vice-president of Exxon Mobil Corporation and president of ExxonMobil Upstream Ventures, a division of Exxon Mobil Corporation. 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 8, 2023 (#) 0 0 0 323,600 323,600 Total market value as at February 8, 2023 ($) 0 0 0 22,512,852 22,512,852 Year over year change (#) 0 0 0 89,000 89,000 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Imperial Oil Limited board (Chair) 8 of 8 (100%) None Community collaboration and engagement committee 1 of 1 (100%) *no public board interlocks Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: Votes Withheld: – President, Imperial Oil Limited (2019 – present) 586,247,361 (97.39%) 15,684,820 (2.61%) – President, ExxonMobil Upstream Ventures (2015 – 2019) (Affiliate) Matthew R. Crocker Spring, Texas, United States of America Non-independent director Age: 49 Director since : May 4, 2021 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 Mr. Crocker is senior vice-president, product, strategy and new assets for ExxonMobil's Low Carbon Solutions business since April, 2022 and is responsible for product development across the portfolio, creation and alignment on business strategies and has oversight for product execution and start-up of new assets. Mr. Crocker has also held leadership positions within refining, upstream business development, chemicals and controllers. Prior to his current position, Mr. Crocker was senior vice-president, fuels, at ExxonMobil Fuels and Lubricants Company, responsible for the global fuels value chain, from crude to customer. 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 8, 2023 (#) 0 0 0 0 0 Total market value as at February 8, 2023 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 *No share ownership guidelines apply Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Imperial Oil Limited board 8 of 8 (100%) None Executive resources committee 7 of 7 (100%) *no public board interlocks Safety and sustainability committee 4 of 4 (100%) Nominations and corporate governance committee 6 of 6 (100%) Community collaboration and engagement committee 1 of 1 (100%) Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: Votes Withheld: – Senior vice president, fuels, ExxonMobil Fuels & Lubricants Company, (2020 – Present) (Affiliate) 577,063,393 (95.87%) 24,868,788 (4.13%) – Vice-president, strategy and portfolio management, ExxonMobil Upstream Business Development Company (2019 – 2020) (Affiliate) – Special assignment, strategy and portfolio management, ExxonMobil Upstream Business Development Company (2019) (Affiliate) – Vice-president, intermediates, performance derivatives, ExxonMobil Chemical Company (2017 – 2019) (Affiliate) 113 Sharon R. Driscoll Vancouver, British Columbia, Canada Nonemployee director (independent) Age : 61 Director since : Not currently a member of the board; first nomination for election as director 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 Sharon Driscoll is the executive vice-president and advisor to the chief executive officer of Ritchie Bros. Auctioneers Incorporated. Ms. Driscoll joined Ritchie Bros. in July 2015 as the chief financial officer where she led global financial operations including capital allocation, financing strategies, treasury operations, risk management, investor relations and regulatory compliance. Ms. Driscoll also served as Co-CEO in 2019 to support the company's planned CEO transition. Prior to joining Ritchie Bros., Ms. Driscoll served as the executive vice-president and chief financial officer for 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. Ms. Driscoll also serves as a director of Empire Company Limited. 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 8, 2023 (#) 0 0 0 0 0 Total market value as at February 8, 2023 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Not currently a member of the board or any of its committees n/a – Empire Company Limited (2018 – Present) *no public board interlocks Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: n/a Votes Withheld: n/a – Ritchie Bros. Auctioneers Incorporated, Executive vice-president and advisor to CEO (2022 – present) – Ritchie Bros. Auctioneers Incorporated, Chief financial officer (2015 - 2022) – Ritchie Bros. Auctioneers Incorporated, Chief financial officer and Co-chief executive officer (2019) John Floren Oakville, Ontario, Canada Nonemployee director (independent) Age : 64 Director since : Not currently a member of the board; first nomination for election as director 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 Mr. Floren is the former president and chief executive officer of Methanex Corporation, and prior to that appointment held the positions of senior vice-president, global marketing and logistics and regional director, marketing and logistics, North America. Mr. Floren was an employee of Methanex for approximately 22 years and has worked in the chemical industry for over 37 years. 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 attended the Harvard Business School’s Program for Management Development, the International Executive Program at INSEAD and completed the Directors Education Program at the Institute of Corporate Directors. 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 8, 2023 (#) 0 0 0 0 0 Total market value as at February 8, 2023 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Not currently a member of the board or any of its committees n/a – West Fraser Timber Co. Ltd. (2016 – present) – Methanex Corporation (2013 - 2022) *no public board interlocks Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: n/a Votes Withheld: n/a – Methanex Corporation, President and chief executive officer (2013 – 2022) 114 Gary J. Goldberg Castle Pines, Colorado, United States of America Nonemployee director (independent) Age : 63 Director since : Not currently a member of the board; first nomination for election as director 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 Mr. Goldberg has more than 35 years of global experience in the mining industry, including in executive, operational and strategic roles, and currently serves as a non-executive director of BHP Group Limited. Mr. Goldberg served as the chief executive officer of Newmont Corporation from 2013 to 2019, and prior to that, was president and chief executive officer of Rio Tinto Minerals. Mr. Goldberg was also a non-executive director of Port Waratah Coal Services Limited and Rio Tinto Zimbabwe, and served as 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. 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 8, 2023 (#) 0 0 0 0 0 Total market value as at February 8, 2023 ($) 0 0 0 0 0 Year over year change (#) 0 0 0 0 0 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Not currently a member of the board or any of its committees n/a – BHP Group Limited (2020 – present) – Newmont Corporation (previously Newmont Mining Corporation) (2013 – 2019) *no public board interlocks Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: Votes Withheld: – Newmont Corporation, Executive advisor (2019 – 2020) n/a n/a – Newmont Corporation, Chief executive officer (2018 – 2019) – Newmont Corporation, President and chief executive officer (2013 – 2018) Miranda C. Hubbs Toronto, Ontario, Canada Nonemployee director (independent) Age: 56 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 Ms. Hubbs is currently an independent director of Nutrien Ltd. and also serves as a director of PSP Investments (Public Sector Pension Investment Board), New Self-Regulatory Organization of Canada and serves as vice-chair of the board of the Canadian Red Cross. Prior to retirement in 2011, Ms. Hubbs was executive vice president and managing director of McLean Budden, one of Canada’s leading investment managers. Ms. Hubbs holds a BSc from Western University and an MBA from Schulich School of Business at York University and is a CFA charterholder. Ms. Hubbs serves on the ICD Climate Strategy Advisory Board and the Global Risk Institute Sustainable Finance Advisory Committee, holds the Fundamentals of Sustainability Accounting credential from the Sustainability Accounting Standards Board, and has received her CERT Certificate in Cybersecurity Oversight issued by the Software Engineering Institute at Carnegie Mellon University. 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 8, 2023 (#) 0 16,735 16,735 15,600 32,335 Total market value as at February 8, 2023 ($) 0 1,164,254 1,164,254 1,085,292 2,249,546 Year over year change (#) 0 2,352 2,352 3,300 5,652 *Meets the necessary share ownership requirements Board and Standing Committee Membership Meeting Attendance 2022 Public Company Directorships in the Past Five Years* Imperial Oil Limited board 8 of 8 (100%) – Nutrien Ltd. (2018 – present) Audit committee 5 of 5 (100%) – Agrium Inc. (2016 – 2018) Executive resources committee 7 of 7 (100%) *no public board interlocks Safety and sustainability committee 4 of 4 (100%) Nominations and corporate governance committee 6 of 6 (100%) Community collaboration and engagement committee (Chair) 1 of 1 (100%) Voting Results of 2022 Annual General Meeting: Other Positions in the Past Five Years: (position, date office held, and status of employer) Votes in Favour: Votes Withheld: None 596,301,725 (99.06%) 5,630,456 (0.94%) 115 Footnotes to director nominee tables on pages 112 through 115 : (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 142 . The company’s plan for deferred share units for nonemployee directors is described on page 141 . 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 2016 through 2022 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 $69.57 on February 8, 2023. Director and nominee holdings in Exxon Mobil Corporation (a) Director XOM Common Shares (#) XOM Restricted Stock (#) (b) Total Common Shares and Restricted Stock (#) Total Market Value of Common Shares and Restricted Stock ($) (c) B.W. Corson 120,676 73,850 194,526 29,759,204 M.R. Crocker 15,534 128,400 143,934 22,019,479 D.S. Sutherland 5,730 — 5,730 876,594 (a) Holdings as at February 8, 2023. 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. Current directors D.W. Cornhill, K.T. Hoeg, M.C. Hubbs and J.M. Mintz, and nominees S.R. Driscoll, J. Floren, G.J. Goldberg, 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 $113.92 U.S., which is converted to Canadian dollars at the daily rate of exchange of $1.3429 provided by the Bank of Canada for February 8, 2023. 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. 116 Corporate governance disclosure Table of contents Corporate governance disclosure 117 2022 Corporate governance highlights 117 Corporate governance at a glance 118 Statement of corporate governance practice 119 Composition of our board nominees 119 Tenure of our board nominees 120 Skills and experience of our board members and nominees 121 Independence of our board members and nominees 122 Committee membership of our board 123 Number of meetings 123 Attendance of our board members in 2022 124 Other public company directorships of our board members and nominees 125 Interlocking directorships of our board members 125 Director qualifications and selection process 126 Director orientation, education and development 127 Board performance assessment 128 Board and committee structure 128 Director compensation 139 Director compensation table 144 Outstanding share-based awards and option-based awards for directors 145 Incentive plan awards for directors - Value vested or earned during the year 145 Share ownership guidelines of independent directors and chairman, president and CEO 146 Ethical business conduct 147 Restrictions on insider trading 148 Diversity 148 Shareholder engagement 150 Largest shareholder 151 Transactions with Exxon Mobil Corporation 151 2022 Corporate governance highlights • Five of seven of our directors and our director nominees are independent and meet the criteria for independence set by Canadian securities regulators, the SEC and the NYSE American LLC • 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. The independent directors collectively have more than $23.3 million in shareholdings in the company • The independent directors regularly meet in executive sessions without management present • 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 2022 annual meeting • Two of seven or 29% of the directors and director nominees, and 11 of 24 or 46% of the executive officers of the company and its major subsidiaries are women 117 Corporate governance at a glance Controlled company Yes Size of board 7 Number of independent directors (board and nominees) 5 Women on board (board and nominees) 2 Average attendance of directors at board and committee meetings 99% Independent chair of the executive sessions 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 83% Independent status of nominations and corporate governance committee 83% Majority of independent directors on all committees Yes Individual director elections Yes Average tenure of director nominees (approximate) 2 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 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 118 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. 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 148 . 119 Tenure of our board nominees 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. K.T. Hoeg, J.M. Mintz and D.S. Sutherland are not standing for re-election in 2023 as they have reached the company’s mandatory retirement age for directors. In anticipation of these retirements, the board undertook an extensive director recruitment process resulting in S.R. Driscoll, J. Floren and G.J. Goldberg being nominated for election to the board for the first time. The following chart shows the current years of service of the nominees for the board of directors and the year they would normally be expected to retire from the board. Name of director nominee Years of service on the board Year of expected retirement from the board for independent directors D.W. Cornhill 5 years 2026 B.W. Corson 3 years - M.R. Crocker 2 years - S.R. Driscoll (a) - 2034 J. Floren (a) - 2031 G.J. Goldberg (a) - 2031 M.C. Hubbs 4 years 2039 (a) S.R. Driscoll, J. Floren, and G.J. Goldberg are being nominated for election as directors at the annual meeting of shareholders and are not currently directors. 120 Skills and experience of our board members and nominees Our directors bring a wide range of skills, diversity and experience. The current directors and director nominees collectively 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 nominees tables on pages 112 through 116 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. D.W. Cornhill B.W. Corson M.R. Crocker S.R. Driscoll (a) J. Floren (a) G.J. Goldberg (a) K.T. Hoeg (b) M.C. Hubbs J.M. Mintz (b) D.S. Sutherland (b) Leadership of large organizations ü ü ü ü ü ü ü ü Operations / technical ü ü ü ü ü ü Project management ü ü ü ü ü ü ü Global experience ü ü ü ü ü ü ü ü ü Strategy development ü ü ü ü ü ü ü ü ü ü Environment and sustainability ü ü ü ü ü ü ü ü ü ü Audit committee financial expert ü ü ü ü ü Financial expertise ü ü ü ü ü ü ü ü ü ü Government relations ü ü ü ü ü ü Information technology / cybersecurity oversight ü ü Executive compensation ü ü ü ü ü ü ü ü ü ü Risk management ü ü ü ü ü ü ü ü ü ü (a) S.R. Driscoll, J. Floren and G.J. Goldberg are being nominated for election as directors at the annual meeting of shareholders and are not currently directors. (b) K.T. Hoeg, J.M. Mintz and D.S. Sutherland are currently directors but are not standing for re-election at the annual meeting of shareholders. 121 Independence of our board members and nominees Five out of seven of the director nominees are independent. The board is currently composed of seven directors, four of whom will be standing for re-election at the annual meeting of shareholders on May 2, 2023. K.T. Hoeg, J.M. Mintz and D.S. Sutherland will not stand for re-election in 2023 as they have reached the company's mandatory retirement age for directors. S.R. Driscoll, J. Floren and G.J. Goldberg are being nominated for election as directors at the annual meeting of shareholders and are not currently directors . The majority of the board and nominees (five 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. B.W. Corson is a director and chairman, president and chief executive officer of the company and not considered to be independent. The board believes that Mr. Corson’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. M.R. Crocker is also a non-independent director as he is an employee of Exxon Mobil Corporation. The company believes that Mr. Crocker, although deemed non-independent under the relevant standards by virtue of his employment, can be viewed as independent of the company’s management and that his ability to reflect the perspective of the company’s shareholders enhances the effectiveness of the board. Name of director and nominee Management Independent Not independent Reason for non-independent status D.W. Cornhill ü B.W. Corson ü ü B.W. Corson is a director and chairman, president and chief executive officer of Imperial Oil Limited. M.R. Crocker ü M.R. Crocker is an employee of Exxon Mobil Corporation. S.R. Driscoll (a) ü J. Floren (a) ü G G.J. Goldberg (a) ü K.T. Hoeg (b) ü M.C. Hubbs ü J.M. Mintz (b) ü D.S. Sutherland (b) ü (a) S.R. Driscoll, J. Floren and G.J. Goldberg are being nominated for election as directors at the annual meeting of shareholders and are not currently directors. (b) K.T. Hoeg, J.M. Mintz and D.S. Sutherland are current directors, but are not standing for re-election at the annual meeting of shareholders. 122 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 Community collaboration and engagement committee D.W. Cornhill (c) ü Chair ü ü ü ü B.W. Corson (a) — — — — ü M.R. Crocker (a) ü — ü ü ü K.T. Hoeg (c) ü ü Chair ü ü ü M.C. Hubbs (c) ü ü ü ü ü Chair J.M. Mintz ü ü ü Chair ü ü D.S. Sutherland (c) ü ü ü ü Chair ü (a) Not independent directors. (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. In addition to its standing committees, the board may establish ad hoc committees or special committees from time to time. Two special committees of independent directors were active during 2022; one that was established in September, 2021, and one that was established in September, 2022, both for the purposes of considering certain matters. The special committees were chaired by D.W. Cornhill and consisted of the five independent directors. Number of meetings The chart below shows the number of board and standing committee meetings held in 2022. This includes seven regular meetings and one additional special meeting of the board. With restrictions related to COVID-19 easing throughout the year, the majority of the board meetings in 2022 returned to an in-person format. More information on the board’s activities in relation to COVID-19 can be found in the Risk oversight section starting on page 130 . Meetings of the board and standing committees in 2022: Board 8 Audit committee Executive resources committee Safety and sustainability committee Nominations and corporate governance committee Community collaboration and engagement committee 5 7 4 6 1 123 Attendance of our board members in 2022 99% board and standing committee meeting attendance from all members. The following chart provides a summary of the attendance record of each of the directors in 2022. The attendance record of each director nominee is also set out in his or her biographical information on pages 112 through 116 . 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 (a) Nominations and corporate governance committee Community collaboration and engagement committee Annual meeting Total Percentage by director D.W. Cornhill 8 of 8 5 of 5 6 of 7 3 of 4 6 of 6 (chair) 1 of 1 1 of 1 30 of 32 94% B.W. Corson 8 of 8 (chair) — — — — 1 of 1 1 of 1 10 of 10 100% M.R. Crocker 8 of 8 — 7 of 7 4 of 4 6 of 6 1 of 1 1 of 1 27 of 27 100% K.T. Hoeg 8 of 8 5 of 5 (chair) 7 of 7 4 of 4 6 of 6 1 of 1 1 of 1 32 of 32 100% M.C. Hubbs 8 of 8 5 of 5 7 of 7 4 of 4 6 of 6 1 of 1 (chair) 1 of 1 32 of 32 100% J.M. Mintz 8 of 8 5 of 5 7 of 7 4 of 4 (chair) 6 of 6 1 of 1 1 of 1 32 of 32 100% D.S. Sutherland 8 of 8 5 of 5 7 of 7 (chair) 4 of 4 6 of 6 1 of 1 1 of 1 32 of 32 100% Percentage by committee 100% 100% 98% 96% 100% 100% 100% 195 of 197 Overall attendance 99% (a) In 2023, the public policy and corporate responsibility committee was changed to the safety and sustainability committee. 124 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 D.W. Cornhill AltaGas Ltd. Diversified energy company ALA:TSX No committees B.W. Corson — — — — M.R. Crocker — — — — S.R. Driscoll Empire Company Limited Food retailing EMP.A:TSX Audit committee (chair), Nominating and governance committee, and Corporate governance and social responsibility committee J. Floren West Fraser Timer Co. Ltd Basic Materials- Forest Products WFG:TSX Health, safety and environment committee (chair), and 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 (chair) and Nominations and governance committee K.T. Hoeg New Flyer Industries Inc. Manufacturer of heavy duty transit buses NFI:TSX Audit committee M.C. Hubbs Nutrien Ltd. Fertilizer manufacturing NTR:TSX, NYSE Human resources and compensation committee and Safety and sustainability committee (chair) J.M. Mintz — — — — D.S. Sutherland GATX Corporation Commercial rail vehicles and aircraft engines – shipping GMT:NYSE Compensation committee (chair) United States Steel Corporation Iron and steel X:NYSE Chairman of the board Interlocking directorships of our board members As of the date of this proxy circular, there are no interlocking public company directorships among the directors listed in this circular. 125 Director qualification and selection process The nominations and corporate governance committee is responsible for identifying and recommending new candidates for board nomination. The committee identifies candidates from a number of sources, including executive search firms and referrals from existing directors. The process for selection is described in paragraph 10 (a) of the Board of Directors Charter found in Appendix A of this circular. The committee will consider potential future candidates as required. In considering the qualifications of potential nominees for election as directors, the nominations and corporate governance committee considers the work experience and other areas of expertise of the potential nominees, with the objective of providing for diversity among the nonemployee directors. The following key criteria are considered to be relevant to the work of the board of directors and its committees: Work experience • Experience in leadership of businesses or other large organizations (Leadership of large organizations) • Operations/technical experience (Operations / technical) • Project management experience (Project management) • Experience in working in a global work environment (Global experience) • Experience in development of business strategy (Strategy development) • Experience with environmental, health, community relations and/or safety policy, practices and management (Environment and sustainability) Other expertise • Audit committee financial expert (also see the financial expert section in the audit committee table starting on page 134 ) • Expertise in financial matters (Financial expertise) • Expertise in managing relations with government (Government relations) • Expertise in information technology and cybersecurity oversight (Information technology / cybersecurity oversight) • Expertise in executive compensation policies and practices (Executive compensation) • Expertise in oversight of risk management policies and practices (Risk management) The nominations and corporate governance committee may consider the following additional factors in assessing potential nominees: • possessing expertise in any of the following areas: law, science, marketing, administration, social/political environment or community and civic affairs; • individual competencies in business and other areas of endeavour in contributing to the collective experience of the directors; and • providing diversity of age, regional association, gender and other diversity elements (including Aboriginal peoples, persons with disabilities and members of visible minorities). The nominations and corporate governance committee assesses the work experience and other expertise each existing director possesses and whether the candidate is able to fill any gaps in such experience, expertise and diversity of age, regional association, gender and other diversity elements. More detailed information on diversity of the board, including in connection with the director recruitment process in 2022, can be found at page 148 . Consideration is also given to whether candidates possess the ability to contribute to the broad range of issues with which the board and its committees must deal, are able to devote the necessary amount of time to prepare for and attend board and committee meetings and are free of any potential legal impediment or conflict of interest. Candidates are expected to remain qualified to serve for a minimum of five years and independent directors are expected to achieve ownership of no less than 16,500 common shares, deferred share units and restricted share units within five years of becoming an independent director. When the committee is recommending candidates for re-nomination, it assesses such candidates against the criteria for re-nomination as set out in paragraph 10 (b) of the Board of Directors Charter found in Appendix A of this circular. Candidates for re-nomination are expected not to change their principal position, the thrust of their involvement or their regional association in a way that would significantly detract from their value as a director of the corporation. They are also expected to continue to be compatible with the criteria that led to their selection as nominees. Under exceptional circumstances, the nominations and corporate governance committee, on the 126 request of the chairman, may continue to support the nomination of a director who has attained the mandatory retirement age. In anticipation of K.T. Hoeg, J.M. Mintz and D.S. Sutherland reaching mandatory retirement age, the board and nominations and corporate governance committee began an extensive director recruitment process in 2021, including engaging executive search firms to cultivate a diverse selection of potential nominees. The board reviewed the recruitment process on a regular basis, including discussing numerous candidates, conducting extensive interviews and ensuring that all board members had the opportunity to meet the candidates to ensure a strong fit for the board. This process has resulted in three new nominees for the 2023 annual meeting, S.R. Driscoll, J. Floren and G.J. Goldberg, to replace Ms. Hoeg, Mr. Mintz and Mr. Sutherland upon their retirement. Ms. Driscoll brings extensive chief financial officer, chief executive officer and board experience through various roles at Ritchie Bros. Auctioneers Incorporated, service as a director of Empire Company Limited and other corporate experience. Mr. Floren is the former president and chief executive officer of Methanex Corporation, with over 37 years experience in the chemicals industry and currently serving on the board of West Fraser Timber Co. Mr. Goldberg has more than 35 years of global experience including substantial chief executive officer experience in the mining industry, has served on various mining industry councils and organizations and is currently a nonemployee director of BHP Group Limited. The board is pleased to welcome these highly experienced and successful individuals as nominees, and looks forward to their leadership and oversight for the company. Director orientation, education and development The company regularly provides in-depth presentations to the directors on relevant and emerging issues and encourages continuing education opportunities. The corporate secretary organizes an orientation program for all new directors. In a series of meetings over several days, new directors are briefed by staff and functional managers on all significant areas of the company’s operations, industry specific topics, risk oversight and regulatory issues. New directors are also briefed on significant company policies, organizational structure, security, information technology management and on critical planning and reserves processes. They also receive key governance and disclosure documents and a comprehensive board manual which contains a record of historical information about the company, by-laws, company policies, the charters of the board and its committees, other relevant company business information, information on directors’ duties and additional board related activities and calendars. With S.R. Driscoll, J. Floren and G.J. Goldberg being nominated for election for the first time this year, the corporate secretary plans to commence an extensive orientation program shortly after their election to the board. Continuing education is provided to board and committee members through regular presentations by management, which focus on providing more in-depth information about key aspects of the business. Subject to exceptional circumstances, each year the board has an extended meeting that focuses on a particular area of the company’s operations and includes a visit to one or more of the company’s operating sites or a site of relevance. These site visits help directors better understand the strengths and business opportunities unique to various operations and markets across the country, and enhance the board’s perspective of the integrated nature of the company’s business. In September 2022, the board visited the Sarnia refinery, chemical plant and research centre for a tour of the facilities and presentations specific to the operations and research at Sarnia. Throughout 2022, the board and its committees received regular presentations and updates that focused on performance, strategy and opportunities for the business. Some of these presentations included ongoing reviews of upstream and downstream performance, plans and strategies, internal audit reviews, a pension management review, a review of harassment in workplace policy stewardship, community engagement strategy, litigation reviews, conflict of interest and ethics reviews and a competition and anti-corruption review. Recognizing the importance of cybersecurity oversight for the company, the board was also provided an information technology and cybersecurity update including strategic cybersecurity priorities, key security initiatives and mitigation efforts and system improvements throughout the year. The board continued to engage with management on pandemic specific topics throughout 2022, such as response and mitigation plans and actions, health and safety initiatives, strategic business actions and the company’s response to the gradual lessening of restrictions across Canada over the year. 127 With strong market conditions and business performance throughout the year, the board focused on strategic direction, operational priorities, capital allocation and prioritizing shareholder returns. This included reviews and approval of the acceleration of the company's normal course issuer bid and the completion of two substantial issuer bids during the year, as well as the sale of the company’s interests in XTO Energy Canada with proceeds used to reduce the company’s outstanding debt. The board also reviewed and discussed the company’s various environmental, social and governance initiatives throughout the year, including the publication of the company’s advancing climate solutions and sustainability reports. There was a continued focus by the board on the company’s progress with emissions reduction initiatives, including the company’s founding membership in the Oil Sands Pathways to Net Zero initiative and setting and tracking emissions reduction goals. The board also undertook reviews of disclosure and emissions performance, safety performance and Canada climate policy updates. More information on the board’s role in relation to the environment can be found in the Risk oversight section starting on page 130 . Members of ExxonMobil’s management also provide reviews of various aspects of ExxonMobil’s global business. In 2022, the directors received a presentation on ExxonMobil’s cybersecurity update, as well as an overview of ExxonMobil’s corporate strategy and the ExxonMobil Outlook for Energy. Members of the board receive an extensive package of materials prior to each board meeting that provides a comprehensive summary on each agenda item to be discussed. Similarly, the committee members also receive a comprehensive summary on each agenda item to be discussed by that particular committee. Informational communications and other written publications or reports of interest to the directors are also forwarded routinely. The board members are canvassed as to whether there are any additional topics relevant to the board or to a specific committee that they would like to see addressed, and management schedules presentations covering these areas. In addition, at every meeting the board receives an extensive update from the chairman, president and chief executive officer on business environment trends, relevant geopolitical activities, federal government priorities, key provincial issues and competitor activities, as appropriate. Directors are encouraged to participate in other continuing education programs and events to ensure their skills and knowledge remain current. Board performance assessment The board and its committees, as well as the performance of the directors, are assessed on an annual basis. For 2022, the directors engaged in a performance assessment with the chairman, president and chief executive officer, which includes discussion and evaluation of the board and each committee’s effectiveness in various areas. The chairman, president and chief executive officer also meets regularly with directors individually to discuss any outstanding issues. The nominations and corporate governance committee discuss a summary of these assessment outcomes in the first quarter of each year. Board and committee structure Leadership structure The company has chosen to combine the positions of chairman, president and chief executive officer. The board believes the interests of all shareholders are best served at the present time through a leadership model with a combined chairman and chief executive officer position. Through more than 39 years of experience with ExxonMobil and Imperial, the current chief executive officer possesses an in-depth knowledge of the evolving energy industry supply and demand fundamentals and the array of challenges to be faced by the company. The board believes that the extensive experience and other insights put the chief executive officer in the best position to provide broad leadership for the board as it considers strategy and exercises its fiduciary responsibilities. Further, the board has demonstrated its commitment and ability to provide independent oversight of management. The company does not have a lead director. While the chairman of the board is not an independent director, K.T. Hoeg, chair of the executive sessions of the board, provides leadership for the independent directors. The duties of the chair of the executive sessions include presiding at executive sessions, reviewing and modifying, if necessary, the agenda of the meetings of the board in advance to ensure that the board may successfully carry out its duties, and acting as a liaison with the chairman of the board, including the provision of feedback, as appropriate, from the executive sessions. The position description of the chair of the executive sessions, as well as the purpose of those executive sessions, are fully described in paragraphs 9 (c) and (d) of the Board of Directors Charter attached as Appendix A. 128 Independent director executive sessions The executive sessions of the board are in camera meetings of the independent directors and are held in conjunction with every board meeting. These meetings are held in the absence of management. The independent directors held eight executive sessions in 2022. The purposes of the executive sessions of the board include the following: • raising substantive issues that are more appropriately discussed in the absence of management; • discussing the need to communicate to the chairman of the board any matter of concern raised by any committee or director; • addressing issues raised but not resolved at meetings of the board and assessing any follow-up needs with the chairman of the board; • discussing the quality, quantity, and timeliness of the flow of information from management that is necessary for the independent directors to effectively and responsibly perform their duties, and advising the chairman of the board of any changes required; and • seeking feedback about board processes. In camera sessions of the board committees Various committees also regularly hold in camera sessions without management present. The audit committee regularly holds private sessions of the committee members as well as private meetings of the committee with each of the external auditor, the internal auditor and senior management as part of every regularly scheduled committee meeting. Committee structure The board has created five standing committees to help carry out its duties. Each committee is chaired by a different independent director and all of the independent directors are members of each committee. M.R. Crocker is also a member of each committee, with the exception of the audit committee, which is composed entirely of independent directors. B.W. Corson is also a me