IMPERIAL OIL LTD - Annual Report: 2021 (Form 10-K)

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Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation (§ 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 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 of the Securities Exchange Act of 1934.

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Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 of the Securities Exchange Act of 1934). Yes..... No

As of the last business day of the 2021 second fiscal quarter, the aggregate market value of the voting stock held by of the registrant was Canadian $8,092,185,812 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are 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 development drilling program at Cold Lake; the timing, cost, efficiency and production of the Aspen project and expansion project at Cold Lake; the continued evaluation of other oil sands leases and unconventional assets; the company’s intention to market its interest in XTO Energy Canada, and operations continuing as normal throughout marketing process and if it does not result in a sale; 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 potential further investment in this technology; the ability to capture additional synergies from the operatorship transition at Syncrude; the ability of rail infrastructure to mitigate pipeline capacity constraints; human capital resources strategy and impact; anticipated capital, exploration 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; Imperial’s Scope 1 and 2 net zero goal by 2050 and the company’s greenhouse gas emissions intensity goals for 2023 and 2030 for its oil sands operations; the impact of participation in the Oil Sands Pathways to Net Zero alliance; market uncertainty and the extent of ongoing effects of the pandemic on economic activity and supply and demand; the impact of measures implemented by the company in response to COVID-19; inflation and uncertainty in global economic recovery, and the company’s ability to mitigate related cost impacts; 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 rail shipments and pace of the Aspen project; the impact of Downstream strategies and competitive position; potential impacts from environmental risks, carbon policy, climate related regulations and biofuels mandates; 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 $1.4 billion for 2022; 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; anticipated productivity and greenhouse gas emissions intensity benefits from the LASER project at Cold Lake; the impact of the Sarnia products pipeline; and plans to construct a renewable diesel facility at Strathcona, including timing of a final investment decision.

These factors include global, regional or local changes in supply and demand for oil, natural gas, petroleum and petrochemical products, feedstocks and other market or economic conditions 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, and actions in response to environmental risks inherent in oil and gas activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; 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, including in light of restrictions related to unanticipated technical or operational difficulties; management effectiveness and disaster response preparedness, including business continuity plans in response to 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 pace of regional and global economic recovery from the COVID-19 pandemic and the occurrence and severity of future outbreaks and variants; general economic conditions, including the occurrence and duration of economic recessions; 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.

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the (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.

All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the price for each month during the last period ending December 31. Natural gas is converted to an basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2021 that would cause a significant change in the estimated proved reserves as of that date.

As a result of improved prices in 2021, under the U.S. Securities and Exchange Commission definition of proved reserves, an additional 1.7 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake qualified as proved reserves at 2021.

As at December 31, 2021, approximately 14 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 386 million barrels. Proved undeveloped reserves are associated with Syncrude, Cold Lake, and the Montney and Duvernay unconventional assets. This compared to 138 million barrels of proved undeveloped reserves reported at the end of 2020. The increase of 248 million barrels of proved undeveloped reserves includes an increase of 262 million oil-equivalent barrels at Cold Lake, an increase of 6 million barrels at the Montney and Duvernay unconventional assets, partially offset by a decrease of 20 million barrels at Syncrude. Conversion of proved undeveloped reserves into proved developed was 34 million barrels during 2021, associated with Cold Lake and the Montney and Duvernay unconventional assets.

Proved undeveloped reserves that have remained undeveloped for five years or more represent about 53 percent (204 million 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.

The company’s total average daily production expressed in an basis is set forth below, with natural gas converted to an basis at six million cubic feet per one thousand barrels.

In October 2018, the company received regulatory approval for the Aspen solvent-assisted, steam-assisted gravity drainage 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.

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 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. Imperial continues to progress this opportunity.

Work progresses on technical and technology evaluations to support potential Clarke Creek, Corner, Clyden and Chard development regulatory applications.

The company owns a 50 percent interest in XTO Energy Canada which includes the Montney and Duvernay unconventional assets located in central Alberta. In 2020, the company ramped down development drilling and revised long-term development plans to exclude a significant portion of the and undeveloped areas of the Montney and Duvernay unconventional assets. In 2021, the company resumed limited drilling activity to develop select portions of the acreage with other operators. In January 2022, Imperial announced its intention to market its interest in XTO Energy Canada jointly with ExxonMobil Canada, consistent with Imperial’s strategy to focus its upstream resources and efforts on its key oil sands assets. A definitive decision to sell the Montney and Duvernay unconventional assets has not been made. Operations will continue as normal throughout the marketing process and should the process not result in a sale. XTO Energy Canada net production from these assets is about 140 million cubic feet of natural gas per day and about 9,000 barrels per day of crude, condensate and natural gas liquids.

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 to prohibit and freeze the existing licences through the completion of the Beaufort Sea Regional Environmental Assessment review. In 2021, the prohibition was extended until December 31, 2022, during which time the Federal Government will continue to consult with stakeholders as part of the review 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 process.

Kearl is a joint venture established to recover shallow deposits of oil sands using 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.

Kearl successfully started up the first Kearl Boiler Flue Gas heat recovery unit in 2021. This technology recovers waste heat from a boiler’s combustion exhaust to process water. This not only has the potential to reduce operating costs, but also emissions by up to 30,000 tonnes / year of carbon dioxide equivalent. Imperial is currently progressing plans to apply this innovative technology on up to five additional boilers.

Cold Lake is an 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.

Syncrude is a joint venture established to recover shallow deposits of oil sands using 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.

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 recovery techniques.

Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the pandemic, partially offset by a planned turnaround at Strathcona.

Lower throughput was driven by reduced demand due to the pandemic, partially offset by lower refinery turnaround activity and reliability events, including impacts from the Sarnia fractionation tower incident which occurred in April 2019.

In 2021, improved petroleum product sales primarily reflects reduced impacts associated with the pandemic.

In 2020, lower sales were primarily driven by reduced demand due to the pandemic.

Approvals and licences from relevant provincial or federalgovernmental 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.

In 2019, the Canadian government implemented a new environmental assessment framework in Canada under the (IAA), which may impact the manner in which large energy projects are approved. 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 greenhouse gas emissions by 2050), reliance on strategic and regional assessments and adjusted regulatory review timelines.

The 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 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 (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.

The company’s website contains a variety of corporate and investor information, including the company’s annual report on Form quarterly reports on Form and current reports on Form 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.

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. In 2019, the Government of Canada implemented a new environmental assessment framework under the , which 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 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.

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 costs and damages.

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 ambition, ultimately, to achieve net zero with respect to emissions from its upstream oil sands operations, 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 expected by current scenarios.

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 (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 emissions by 2050 and establish interim emissions reductions targets at five year intervals. For 2022, under the Canadian Emissions Accountability Act, the Government of Canada is required to develop an emissions reduction plan for 2030 consistent with achieving emissions by 2050.

The Government of Alberta has 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, increasing by 1 percent per year. Further, the Alberta 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, with Ontario cancelling the cap and trade program in 2018, the company’s operations in Ontario were subject to the federal carbon levy and output based pricing system through 2021. Starting in 2022, Ontario has received equivalency for its Emissions Performance System, which puts a price on 8 percent of a facility’s emissions. British Columbia has carbon pricing in place for all emissions, with pricing expected to align with federal pricing in 2022. Increases in carbon pricing could adversely impact the company’s operations and financial results unless the company can adapt its operations.

In 2019, the Government of Canada enacted the , which 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.

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 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.

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 or cause unscheduled downtime.

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: measures such as threat information sharing with governmental and industry groups; internal training and awareness campaigns including routine testing of employee awareness via mock threats; and an emphasis on resiliency including business response and recovery.

As a result of governments in many countries, including Canada, have mandated quarantines, closures, orders and travel restrictions that have had a significant impact on demand for the company’s products. While these effects are expected to be temporary, the resurgence of cases of has led to a highly uncertain business environment. Although there has been some movement toward activity levels, the duration of the business disruptions and related financial impact cannot be reasonably estimated at this time and continued or new restrictions could continue to impact the demand for petroleum products.

The company has had positive cases, but these cases have not had a material impact on its operations or business. The company has initiated numerous emergency response and business continuity plans, and a substantial portion of the company’s workforce has implemented remote working arrangements. However, if the company’s mitigation and response efforts prove insufficient, then large outbreaks of epidemics, pandemics or other health crises such as 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.

The pandemic continues to evolve, with changing case numbers and the potential for additional public health restrictions. The impact of the pandemic remains difficult to predict.

As of February 15, 2022 there were

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian withholding tax of 15 percent, but may vary from one tax convention to another.

There is no Canadian tax on gains from selling shares or debt instruments owned by 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 (“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.

Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 149 of this report.

M.R. Crocker is deemed a member of the board of directors and the executive resources committee, public policy and corporate responsibility 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.

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 services to be performed by the external auditor after considering the effect of such services on their independence.

Reference is made to the tableof contents in the “Financial section” on page 42 of this report.

The following exhibits, numbered in accordance with Item 601 of Regulation 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 (File No. 0-12014)).
(iii)(A)				(1)		Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)).
				(2)		Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
				(3)		Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 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)).
(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, 2021.
(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).

		Imperial Oil Limited
by /s/ Bradley W. Corson
		(Bradley W. Corson)
		Chairman, president and chief executive officer

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. These measures are not prescribed by U.S. Generally Accepted Accounting Principles (GAAP). These measures constitute financial measures” under Securities and Exchange Commission Regulation G, and “specified financial measures” under National Instrument and Other Financial Measures Disclosure of the Canadian Securities Administrators.

Reconciliation of these financial measures to the most comparable GAAP financial measure, and other information required by these regulations have been provided. 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 is a 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.

ROCE is a 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 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 financial measure and is disclosed and reconciled above. The company’s total ROCE is net income excluding the 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.