What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2023-02-22 compared with 2022-02-23 · 1728 added, 1200 removed, 2138 unchanged (58% of the section changed)

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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 are now directors and have been since the dates indicated.

All of the nominees, with the exception of S.R.

Floren and G.J.

Goldberg, are now directors and have been since the dates indicated.

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.

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”:

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Reference is made to the following sections under “Company executives and executive compensation”:

“Letter to shareholders from the executive resources committee on executive compensation”, starting on page 154 of this report;

• “Letter to shareholders from the executive resources committee on executive compensation”, on page 155 of this report;

• “Compensation discussion and analysis”, on pages 156 to 178 of this report.

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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

Imperial Oil Limited Exxon Mobil Corporation

Named executive officer Common

stock units (b)

Corson — 323,600 120,676 73,850

Lyons — 94,800 10,419 9,600

Younger — 54,400 8,796 13,600

Jolly 12,506 73,800 — —

Wetmore 15,990 60,400 — —

Incumbent directors and executive

officers as a group (16 people)

No common shares are beneficially owned by reason of exercisable options.

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.

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Information not being within the knowledge of the company has been provided by the directors and the executive officers individually.

Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards.

(b) Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards.

Certain relationships and related transactions, and director independence

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Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 151 of this report.

Crocker is deemed a non-independent

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.

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.

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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.

PwC is a participating audit firm with the Canadian Public Accountability Board and the Public Company Accounting Oversight Board (United States) (PCAOB).

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

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.

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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.

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

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 continually 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 Public Company Accounting Oversight Board (United States) (PCAOB) and the rules of the U.S.

Securities and Exchange Commission.

The audit committee periodically discusses with PwC their independence from the company and from management.

The company has concluded that the auditor’s independence has been maintained.

Exhibits, financial statement schedules

Reference is made to the table

of contents in the “Financial section” on page 42 of this report.

The following exhibits, numbered in accordance with Item 601 of Regulation S-K,

are filed as part of this report:

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.

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.

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:

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.

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.

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.

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.

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

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.

(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.

(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.

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.

(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) 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.

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.

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.

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.

(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.

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.

Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2022 and subsequent years, as amended effective November 29, 2022.

(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.

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Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).

Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b)

and 18 U.S.C.

Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C.

Section 1350.

Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b)

and 18 U.S.C.

Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C.

Section 1350.

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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.

Form 10-K summary

Not applicable.

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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.

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finance and administration, and controller

(Principal financial officer and principal

accounting officer)

(Principal financial officer and principal accounting officer)

/s/ Matthew R.

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Financial section

Table of contents Page

Financial information (U.S.

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Other comprehensive income (loss) information

Divestment activities

Supplemental information on oil and gas exploration and production activities (unaudited)

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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)

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The definitions are provided to facilitate understanding of the terms and how they are calculated.

These measures are not prescribed by U.S.

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 “specified financial measures” under National Instrument 52-112

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.

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.

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.

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asset and liability perspective

Total assets 43,524 40,782 38,031

Total current liabilities excluding notes and loans payable (8,776) (5,432) (3,153)

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Return on average capital employed (ROCE)

ROCE is a non-GAAP

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

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.

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.

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Net income (loss) 7,340 2,479 (1,857)

Financing (after-tax)

including Imperial’s share of equity companies

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

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.

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.

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From the Consolidated statement of cash flows

Cash flows from operating activities

Cash flows from (used in) operating activities 10,482 5,476 798

Proceeds from asset sales 904 81 82

Total cash flows from operating activities and asset sales

Total cash flows from (used in) operating activities and asset sales 11,386 5,557 880

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

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.

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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

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Depreciation and depletion (includes impairments) 1,897 1,977 3,293

pension and postretirement benefit

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

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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.

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.

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.

All identified items are presented on an after-tax

All identified items are presented on an after-tax basis.

Reconciliation of net income (loss) excluding identified items

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Net income (loss) (U.S.

GAAP) 7,340 2,479 (1,857)

Less identified items included in Net income (loss)

Tax adjustments

Gain/(loss) on sale of assets 208 — —

Impairments — — (1,171)

Subtotal of identified items 208 — (1,171)

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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 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.

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.

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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 energy supply and demand assumptions supporting the corporate plan is ExxonMobil’s Outlook

, 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 emission prices and foreign currency exchange rates are based on corporate plan assumptions developed annually and are utilized 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 major investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

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.

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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 energy fundamentals.

These fundamentals include energy supply and demand trends;

the scale and variety of energy needs worldwide;

capability, practicality and affordability of energy alternatives including low-carbon

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;

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It is a projection based on current trends in technology, government policies, consumer preferences, geopolitics, and economic development.

In addition, the Outlook considers a range of scenarios - including remote scenarios - to help inform perspective of the future and enhance strategic thinking over time.

Included in the range of these scenarios are the Intergovernmental Panel on Climate Change Lower 2°C and the International Energy Agency’s Net Zero Emissions (IEA NZE) by 2050 scenario.

To effectively evaluate the pace of change, ExxonMobil uses many scenarios to help identify signposts to provide leading indicators of future developments and allow for timely adjustments to the Outlook.

The IEA describes the IEA NZE as extremely challenging, requiring all stakeholders – governments, businesses, investors and citizens – to take action this year and every year after so that the goal does not slip out of reach.

The scenario assumes unprecedented and sustained energy efficiency gains, innovation and technology transfer, lower-emission investments, and globally coordinated greenhouse gas reduction policy.

The IEA acknowledges that society is not on the IEA NZE pathway.

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 company expects worldwide economic growth to average close to 2.5 percent per year, with economic output growing by around 125 percent by 2050 compared to 2019.

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.

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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 emissions per unit of economic output over time.

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 almost 75 percent from 2019 to 2050, with developing countries likely to account for about 80 percent of the increase.

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 2019, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address risks related to climate change.

From 2019 to 2050, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely 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 600 percent, helping total renewables (including other sources, i.e., hydropower) to account for about 80 percent of the increase in electricity supplies worldwide through 2050.

Total renewables are expected reach about 50 percent of global electricity supplies by 2050.

Natural gas and nuclear are also expected to increase shares over the period to 2050, reaching more than 25 percent and about 10 percent of global electricity supplies, respectively, by 2050.

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.

Under the Outlook, energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by almost 25 percent from 2019 to 2050.

Transportation energy demand is expected to account for over 40 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 about 75 percent.

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 widely available and offer practical advantages in providing a large quantity of energy in small volumes.

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 114 million oil-equivalent

barrels per day, an increase of about 14 percent from 2019.

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 more than 20 percent.

Much of the global liquid fuels demand today is met by crude production from traditional conventional sources;

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 economic and lower-carbon supply options.

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 35 percent from 2019 to 2050, with more than half of that increase coming from the Asia Pacific region.

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 more than two-thirds

of worldwide demand in 2050.

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.

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Oil is expected to remain the largest source of energy with its share remaining close to 30 percent in 2050.

Coal is currently the second largest source of energy, but it is expected to lose that position to natural gas in the next few years.

The share of natural gas is expected to reach more than 25 percent by 2050, while the share of coal falls to about half that.

Nuclear power is projected to grow significantly, 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 biomass, hydro and geothermal contributing a combined share of more than 10 percent.

Total energy supplied from wind, solar and biofuels is expected to increase rapidly, growing over 420 percent from 2019 to 2050, when they are projected to be about 10 percent of the world energy mix.

To meet this projected demand under the Outlook, 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.

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.

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.

This reflects a fundamental aspect of the oil and natural gas business as the International Energy Agency (IEA) describes in its World Energy Outlook 2021

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 ExxonMobil’s Outlook for Energy

as a foundation for estimating energy supply and demand requirements from various energy sources and uses, and the Outlook for Energy

takes into account policies established to reduce energy related greenhouse gas emissions.

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 for Energy

reflects an environment with increasingly stringent climate policies and is consistent with the global aggregation of Nationally Determined Contributions (NDCs), as available at the end of 2020, which were submitted by signatories to the United Nations Framework Convention on Climate Change (UNFCCC) 2015 Paris Agreement.

The Outlook for Energy

seeks to identify potential impacts of climate related policies, which often target specific sectors.

It estimates potential impacts of these policies on consumer energy demand by using various assumptions and tools – including, depending on the sector, and as applicable, use of a proxy cost of carbon or assessment of targeted policies (i.e., automotive fuel economy standards).

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 have provided around COP 26 in Glasgow in November 2021 as well as other policy developments in light of net zero ambitions recently formulated by some nations, including Canada.

The information provided in the “Long-term business outlook” includes internal estimates and projections based upon ExxonMobil’s internal data and analyses, as well as publicly available information from external sources including the International Energy Agency.

Advancing climate solutions

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.

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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 has a goal to achieve net zero Scope 1 and 2 greenhouse gas emissions in the company’s oil sands operations by 2050 in support of Canada’s commitment to move towards net zero emissions.

To support this net-zero

ambition, by the end of 2030 Imperial anticipates to reduce Scope 1 and 2 greenhouse gas emissions intensity of its operated oil sands facilities by 30 percent, compared with 2016 levels.

The company plans to achieve this through implementation of lower greenhouse gas next generation technologies at its Cold Lake operation, efficiency improvements at its facilities, and the use of carbon capture and storage.

In the near term, the company remains on track to meet its previous Scope 1 and Scope 2 greenhouse gas emissions intensity goal of a 10 percent reduction for operated oil sands facilities by the end of 2023, compared to 2016 levels.

In June, Imperial and its industry peers announced the launch of the Oil Sands Pathways to Net Zero alliance.

The goal of this unique alliance, working collectively with the federal and Alberta governments, is to achieve net zero greenhouse gas emissions from oil sands operations by 2050 to help Canada meet its climate goals.

Current business environment

In early 2020, the balance of supply and demand for petroleum and petrochemical products experienced two significant disruptive effects.

On the demand side, the COVID-19

pandemic spread rapidly through most areas of the world resulting in substantial reductions in consumer and business activity and significantly reduced demand for crude oil, natural gas and petroleum products.

This reduction in demand coincided with announcements of increased production in certain key oil-producing

countries which led to increases in inventory levels and sharp declines in prices for crude oil, natural gas and petroleum products.

Through 2021, demand for petroleum and petrochemical products has continued to recover, with the company’s financial results benefiting from stronger prices and margins, notably prices for crude oil and natural gas as well as Chemical product margins.

The company continues to closely monitor industry and global economic conditions amid this uneven global recovery from the COVID-19

pandemic which has brought unprecedented uncertainties to near-term economic outlooks, including recovery from the COVID-19

The general rate of inflation in Canada and many other countries experienced a brief decline in the initial stage of the COVID-19

However inflation rates increased in 2021 across major economies, with some regions experiencing multi-decade highs, largely reflecting overall imbalances between supply and demand recoveries from the pandemic.

The underlying factors include, but are not limited to, global supply chain disruptions, shipping bottlenecks, labor market constraints and side effects from monetary and fiscal expansions.

The global economic recovery remains uneven with significant uncertainty.

Prices for services and materials continue to evolve in response to fast-changing commodity markets, industry activities, as well as government policies, impacting operating and capital costs.

The company closely monitors market trends and works to mitigate cost impacts in all price environments through its economies of scale in global procurement, efficient project management practices, and general productivity improvements.

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.

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.

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

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Net income (loss) (U.S.

Identified items included in Net income (loss) (a)

Tax adjustments

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

Net income (loss) excluding identified items (a)

(a) Net income (loss) excluding identified items is a non-GAAP

financial measure - see “Frequently used terms” section (page 44)

208 — (1,171)

Net income (loss) excluding identified items 1

7,132 2,479 (686)

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.

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.

Net loss in 2020 was $1,857 million, or $2.53 per share on a diluted basis, compared to net income of $2,200 million or $2.88 per share in 2019.

Current year results reflect a non-cash

impairment charge of $1,171 million after tax, related to the company’s decision to no longer develop a significant portion of its unconventional portfolio.

Full-year 2019 results included a favourable impact of $662 million associated with the Alberta corporate income tax rate decrease.

financial measure – see “Frequently used terms” section on page 44 for definition and reconciliation

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.

Imperial produces crude oil and natural gas for sale predominantly into North American markets.

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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.

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.

The upstream industry environment has a history of significant price volatility.

Market demand and prices experienced a sharp decline in the first half of 2020 largely driven by the COVID-19

Following this decline, prices improved in the second half of 2020 and throughout 2021, as supply and demand began to rebalance.

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.

Volatility in differentials can lead to government action, such as in 2019 when the Government of Alberta imposed temporary mandatory production curtailment regulations on large producers.

Mandatory curtailment was eliminated in December 2020 and the regulatory authority to impose curtailment was repealed at the end of 2021.

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 and other factors.

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.

In 2021, demand for petroleum and petrochemical products continued to recover, with the company’s financial results benefiting from stronger prices compared to the prior year.

The company continues to closely monitor industry and global economic conditions, including recovery from the COVID-19

Upstream asset performance met or exceeded expectations in 2021.

The company continued to benefit from its actions implemented in 2020 to reduce the cost structure and improve reliability of its assets, enabling the Upstream to capture significant value and take advantage of the improving business environment throughout 2021.

Upstream delivered its highest production in over 30 years, supported by Kearl achieving record annual total gross production of about 263,000 barrels per day (186,000 barrels Imperial’s share).

The company adjusted its planned maintenance and turnaround activity at Kearl, eliminating its fall turnaround and transitioned to a single annual turnaround, one year ahead of schedule.

During 2021, Cold Lake gross production was about 140,000 barrels per day, driven by continued focus on production optimization and reliability enhancements.

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, and COVID-19

could have negative impacts on the upstream business.

“Risk factors”, environmental risks and climate related regulations could have negative impacts on the upstream business.

Results of operations

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millions of Canadian dollars

Identified items are a non-GAAP

financial measure – see “Frequently used terms” section (page 44)

Price – Higher realizations increased net income by about $3,640 million, primarily driven by average bitumen realizations increasing by $32.22 per barrel and synthetic realizations increasing by $31.85 per barrel.

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 decreased net income by about $680 million, primarily driven by higher commodity prices.

Identified items 1

– Prior year results included unfavourable identified items

of $1,171 million related to the company’s decision to no longer develop a significant portion of its unconventional portfolio.

Other – All other items decreased net income by $968 million, primarily driven by 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.

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

Identified items are a non-GAAP

financial measure – see “Frequently used terms” section (page 44)

Price – Lower realizations decreased net income by about $2,620 million.

Volumes – Lower volumes decreased net income by about $130 million.

Royalty – Lower royalties increased net income by about $540 million.

Identified items 1

impairment charge of $1,171 million, related to the company’s decision to no longer develop a significant portion of its unconventional portfolio.

Absence of a favourable impact of $689 million associated with the Alberta corporate income tax rate decrease in 2019.

Other – All other items increased net income by $404 million, primarily driven by lower operating expenses of about $250 million, favourable foreign exchange impacts of about $100 million, and about $70 million associated with the Canada Emergency Wage Subsidy received by the company which includes Imperial’s proportionate share of a joint venture.

financial measure – see “Frequently used terms” section on page 44 for definition and reconciliation

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.

Marker prices and average realizations

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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)

Synthetic oil (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$)

Imperial’s average Canadian dollar realizations for bitumen increased in 2021, generally in line with Western Canada Select.

The company’s average Canadian dollar realizations for synthetic crude increase generally in line with West Texas Intermediate, adjusted for changes in exchange rates and transportation costs.

Imperial’s average Canadian dollar realizations for bitumen decreased in 2020 primarily due to a decrease in WCS.

The company’s average Canadian dollar realizations for synthetic crude decreased generally in line with WTI, adjusted for changes in exchange rates and transportation costs.

Crude oil and natural gas liquids (NGL) - production and sales

0.77 0.80 0.75

Crude oil and natural gas liquids (NGL) - production and sales (a)

thousands of barrels per day 2022

Synthetic oil (b)

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

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NGL sales (d)

Natural gas - production and production available for sale

Natural gas - production and production available for sale (a)

millions of cubic feet per day 2022

gross net gross net gross net

Production (e) (f)

85 83 120 115 154 150

Production available for sale (g)

Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

(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.

The company’s synthetic oil production volumes were from the company’s share of production volumes in the Syncrude joint venture.

Diluent is natural gas condensate or other light hydrocarbons added to crude bitumen to facilitate transportation to market by pipeline and rail.

2021 NGL sales round to 0.

Gross production of natural gas includes amounts used for internal consumption with the exception of the amounts re-injected.

Net production is gross production less 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.

Includes sales of the company’s share of net production and excludes amounts used for internal consumption.

Higher production at Kearl was primarily driven by the absence of prior year production balancing with market demands.

Kearl achieved the highest annual production in the asset’s history.

Improved production was mainly due to the addition of supplemental crushing facilities in 2020, partially offset by the balancing of near term production with demand through the advancement and extension of planned turnaround activities.

(g) Includes sales of the company’s share of net production and excludes amounts used for internal consumption.

Lower production at Kearl was primarily a result of downtime in the first half of the year.

Higher production at Kearl was primarily driven by the absence of prior year production balancing with market

Imperial’s Downstream serves predominantly Canadian markets with refining, trading, logistics and marketing activities.

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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 at 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 climate.

Crude oil and many products are widely traded with published prices, including those quoted on the New York Mercantile Exchange.

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.

Through 2021, demand for petroleum products continued to recover, with the Downstream financial results benefiting from stronger margins.

The company continues to closely monitor industry and global economic conditions, including recovery from the COVID-19

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 to the motoring public through Esso and Mobil-branded sites and independent marketers.

At the end of 2021, there were about 2,400 sites operating under a branded wholesaler model whereby Imperial supplies fuel to independent third parties who own and operate sites in alignment with Esso and Mobil brand standards.

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

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millions of Canadian dollars

Margins – Higher margins increased net income by about $600 million, reflecting improved product demand.

Other – All other items decreased net income by $258 million, primarily driven by unfavourable foreign exchange impacts of about $150 million and an unfavourable inventory adjustment of $74 million 2

, partially offset by lower operating expenses of about $50 million.

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.

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.

2021 Net income (loss) factor analysis

millions of Canadian dollars

Margins – Results were negatively impacted by lower margins of about $710 million.

Other – All other items increased net income by $302 million, primarily driven by lower operating expenses of about $190 million, lower turnaround impacts of about $190 million primarily related to reduced turnaround activity in the current year and improved reliability of about $180 million primarily due to the absence of the Sarnia fractionation tower incident which occurred in April 2019.

These items were partially offset by lower sales volumes of about $290 million.

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

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Utilization of total refinery capacity (percent)

Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.

Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.

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.

(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.

Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19

pandemic, partially offset by a planned turnaround at Strathcona.

Lower throughput was driven by reduced demand due to the COVID-19

pandemic, partially offset by lower refinery turnaround activity and reliability events, including impacts from the Sarnia fractionation tower incident which occurred in April 2019.

Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity.

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

Heavy fuel oils

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.

Improved petroleum product sales in 2021 primarily reflects reduced impacts associated with the COVID-19

Lower petroleum product sales were primarily driven by reduced demand due to the COVID-19

Improved petroleum product sales in 2022 primarily reflects increased demand.

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.

North America continued to benefit from abundant supplies of natural gas and gas liquids, providing both low cost energy and feedstock for steam crackers.

In 2021, results benefited from robust industry demand and strong reliability.

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.

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millions of Canadian dollars

Margins – Improved margins increased net income by about $250 million, primarily due to stronger industry polyethylene margins.

Margins – Lower margins primarily reflect weaker industry polyethylene margins.

2021 Net income (loss) factor analysis

millions of Canadian dollars

Margins – Lower earnings primarily reflect lower margins.

Margins – Improved margins were primarily due to stronger industry polyethylene margins.

thousands of tonnes 2022 2021 2020

Polymers and basic chemicals 635 599 574

Intermediate and others

Intermediates 207 232 175

Total petrochemical sales 842 831 749

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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.

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Cash and cash equivalents at end of year

3,749 2,153 771

Cash flow from operating activities

Cash flow generated from operating activities primarily reflects higher Upstream realizations, improved Downstream margins, and favourable working capital impacts.

Cash flow generated from operating activities primarily reflects higher Upstream realizations and stronger Downstream margins.

Cash flow generated from operating activities primarily reflects lower realizations in the Upstream and unfavourable working capital impacts.

Cash flow from investing activities

Investing activities used net cash of $1,012 million in 2021, up from $802 million used in 2020, primarily reflecting higher additions to property, plant and equipment.

Investing activities used net cash of $802 million in 2020, compared to $1,704 million used in 2019, primarily reflecting lower additions to property, plant and equipment.

Cash flow from financing activities

Cash flow used in investing activities

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.

Cash flow used in investing activities primarily reflects higher additions to property, plant and equipment.

Cash flow used in financing activities

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.

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.

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The company has not drawn on these facilities.

At the end of 2020, total debt outstanding was $5,184 million, compared with $5,190 million at the end of 2019.

In response to market conditions, during the second quarter of 2020, the company entered into a $500 million committed short-term line of credit to May 2021, and a $300 million committed short-term line of credit to June 2021.

These facilities were in addition to existing credit facilities of $500 million.

The company has not drawn on these facilities.

In November 2020, the company extended the maturity date of one of its existing $250 million committed short-term line of credit to November 2021.

The company has not drawn on the facility.

The maturity date of the other existing $250 million credit facility remains unchanged at November 2021.

The company has not drawn on the facility.

Share repurchases

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Number of shares purchased (millions) (a)

(a) Share repurchases were made under the company’s normal course issuer bid program, and include shares purchased from Exxon Mobil Corporation concurrent with, but outside of the normal course issuer bid.

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.

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.

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.

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.

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In 2021, the company purchased 29,356,095 shares under this amended program.

On June 23, 2021 the company announced that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid and will continue its existing share purchase program.

The program enables the company to purchase up to a maximum of 35,583,671 common shares during the period June 29, 2021 to June 28, 2022.

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.

In response to market conditions, substantial purchases under the share purchase program were suspended on April 1, 2020.

millions of Canadian dollars, unless noted 2022 2021 2020

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Per share dividend paid (dollars)

1.29 0.98 0.88

Financial strength

The table below shows Imperial’s consolidated debt-to-capital

The table below shows Imperial’s consolidated debt-to-capital ratio.

The data demonstrates the company’s creditworthiness:

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Debt to capital (a)

Debt, defined as the sum of “Notes and loans payable” and “Long-term debt” (page 77), divided by capital, defined as the sum of debt and “Total shareholders’ equity” (page 77).

Debt-related interest incurred in 2021, before capitalization of interest, was $63 million, compared with $102 million in 2020.

The average effective interest rate on the company’s debt was 1.2 percent in 2021, compared with 2.0 percent in 2020.

(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.

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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.

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

2021 was $8.7 billion, of which $697 million is due in 2022, and $746 million is due in 2023.

At March 31, 2021, due to the termination of transportation services agreements related to a third-party pipeline project, other long-term purchase agreements decreased by approximately $2.9 billion.

The majority of these commitments related to years 2026 and beyond.

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.

Litigation and other contingencies

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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;

exploration expenses on a before-tax basis from the Consolidated statement of income;

and the company’s share of similar costs for equity companies.

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millions of Canadian dollars 2022 2021

Downstream 295 476

Chemical 10 8

Corporate and other 57 24

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 reliability, feedstock flexibility, energy efficiency and environmental performance.

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.

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Imperial’s integrated business model reduces the company’s risk from changes in commodity prices.

For instance, when light and heavy differentials between North American crude benchmarks and western Canadian prices widen together, 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.

As an example, the negative impact of a widening differential in the Upstream is more than offset by the benefit of lower feedstock costs in the Downstream.

At this time, Imperial is a net consumer of natural gas, used in Imperial’s Upstream operation and refineries.

A decrease in the value of natural gas reduces Imperial’s operating expenses, thereby increasing Imperial’s earnings.

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.

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These prices, in turn, depend on global and regional supply / demand balances, inventory levels, refinery operations, import / export balances and weather.

Industry crude oil and natural gas commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S.

Industry crude oil commodity prices and petroleum and chemical product prices are commonly benchmarked in U.S.

The majority of Imperial’s sales and purchases are related to these industry U.S.

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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

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

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 light and heavy crude price differentials (b)

Ten cents per thousand cubic feet decrease (increase) in natural gas prices

One dollar (U.S.) per barrel increase (decrease) in refining 2-1-1

One cent (U.S.) per pound increase (decrease) in sales margins for polyethylene

One dollar (U.S.) per barrel increase (decrease) in refining 2-1-1 margins (b)

One cent decrease (increase) in the value of the Canadian dollar versus the U.S.

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.

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.

Light and heavy crude differentials represent the difference between WTI benchmark prices and western Canadian prices for light and heavy crudes.

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, natural gas, 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, such as impacts due to the COVID-19

pandemic, will typically have a direct adverse impact on the company’s financial results.

Although price levels of crude oil and natural gas 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.

Accordingly, the company evaluates the viability of its major investments over a range of prices.

(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.

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.

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Refer to note 2 for additional information on intersegment revenue.

The company has an active asset management program in which underperforming assets are either improved to acceptable levels or considered for divestment.

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 the Upstream, Downstream and Chemical businesses reduce the company’s enterprise-wide risk from changes in commodity prices and currency exchange rates.

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.

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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, and biofuels.

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.

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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 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 and facilities with existing equipment and operating methods.

Proved undeveloped reserves include amounts expected to be recovered from new wells on undrilled proved acreage or from existing wells where a relatively major expenditure is required for completion.

Proved undeveloped reserves are recognized only if a development plan has been adopted indicating that the reserves are scheduled to be drilled within five years, unless specific circumstances support a longer period of time.

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.

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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;

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 / facility capacity.

In 2019, downward revisions to proved bitumen reserves were driven by technical and development plan updates at Kearl, resulting in a decrease of 0.2 billion barrels, partially offset by an increase of 0.1 billion barrels at Cold Lake associated with an end of field life change driven by pricing.

Downward revisions to proved synthetic oil reserves were a result of higher royalty obligations at Syncrude driven by pricing.

Changes to 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.

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 U.S.

Securities and Exchange Commission definition of proved reserves.

Downward revisions to proved synthetic oil reserves were a result of lower prices, offset by the addition of proved undeveloped reserves associated with future development at Syncrude.

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 U.S.

Securities and Exchange Commission definition of proved reserves.

Upward revisions to proved synthetic oil 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 U.S.

Securities and Exchange Commission (SEC) definition.

Unit-of-production

Oil and natural gas reserve volumes are used as the basis to calculate unit-of-production

depreciation rates for most upstream assets.

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.

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.

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, all properties have sufficient reserves at current SEC prices which will enable equitable allocation of cost over the economic lives of the Upstream assets.

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

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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 relies, in part, on the company’s planning and budgeting cycle.

This process is aligned with the requirements of ASC 360 and ASC 932 and relies, in part, on the company’s planning and budgeting cycle.

Because the lifespans of the vast majority of the company’s major assets are measured in decades, the future cash flows of these assets are predominantly based on long-term oil and natural gas commodity prices, 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.

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.

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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, and consequently, these assets will experience periods of higher earnings and periods of lower earnings, or even losses.

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.

Energy Outlook and cash flow assessment

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, and economic development.

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.

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.

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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.

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 amount by which the carrying value exceeds fair 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, drilling and development costs, operating costs, and discount rates which are reflective of the characteristics of the asset group.

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

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Judgment is required to determine if assets are held for sale, and to determine the fair value less cost to sell.

Investments in equity companies are assessed for possible impairment when events or changes in circumstances indicate that the carrying value of an investment may not be recoverable.

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.

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In the absence of market prices for the investment, discounted cash flows are used to assess fair value, which requires significant judgment.

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.

Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

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,

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.

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.

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.

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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 4.5 percent used in 2021, compares to actual returns of 8.5 percent and 7.3 percent achieved over the last 10-

periods respectively, ending December 31, 2021.

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.

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and inflation rates.

The obligations are initially measured at fair value and discounted to present value.

Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in production and manufacturing expenses.

As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook.

For 2021, the obligations were discounted at 6 percent and the accretion expense was $99 million, before tax, which was significantly less than 1 percent of total expenses in the year.

There would be no material impact on the company’s reported financial results if a different discount rate had been used.

On page 93 , note 5 to the consolidated financial statements provides a three-year continuity table detailing the changes in asset retirement obligations.

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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.

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.

Significant management judgment is required in the accounting for income tax contingencies and tax disputes because the outcomes are often difficult to predict.

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.

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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.

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.

Chairman, president and chief executive officer

(Principal executive officer)

/s/ Daniel E.

Senior vice-president,

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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, 2021, based on criteria established in Internal Control – Integrated Framework

(2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO).

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, 2021, based on criteria established in Internal Control – Integrated Framework

(2013) issued by the COSO.

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

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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.

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, 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 and the assumptions related to development and production costs, as applicable.

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.

Addressing the matter involved performing procedures and evaluating audit evidence in connection with forming our overall opinion on the consolidated financial statements.

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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.

These procedures also included, among others, testing the completeness and accuracy of the data related to future development and production costs.

Additionally, these procedures included evaluating whether the assumptions related to development and production costs were reasonable considering the past performance of the Company and its business and strategic plan, as applicable.

/s/ PricewaterhouseCoopers LLP

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Revenues and other income

59,413 37,508 22,284

Investment and other income (note 8, 18)

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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)

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Depreciation and depletion (includes impairments) (note 2, 11)

pension and postretirement benefit

1,897 1,977 3,293

Non-service pension and postretirement benefit 17 42 121

Financing (d) (note 12)

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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)

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)

Amounts from related parties included in revenues, (note 16).

Amounts to related parties included in purchases of crude oil and products, (note 16).

Amounts to related parties included in production and manufacturing, and selling and general expenses, (note 16).

Amounts to related parties included in financing, (note 16).

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,

3,795 2,737 2,484

and selling and general expenses, (note 16).

(d) Amounts to related parties included in financing, (note 16).

The information in the notes to consolidated financial statements is an integral part of these statements.

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Postretirement benefits liability adjustment (excluding amortization) 582 679 ( 212 )

Amortization of postretirement benefits liability adjustment included in net periodic benefit costs

Amortization of postretirement benefits liability adjustment included in net benefit costs

Total other comprehensive income (loss) 665 812 ( 78 )

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Current assets

Cash and cash equivalents 3,749 2,153

Accounts receivable - net (a)

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Property, plant and equipment,

less accumulated depreciation and depletion

Goodwill (note 11)

less accumulated depreciation and depletion (note 2, 18)

30,506 31,240

Other assets, including intangibles - net 1,223 806

Total assets 43,524 40,782

Current liabilities

Notes and loans payable (c) (note 12)

Notes and loans payable (note 12)

Accounts payable and accrued liabilities (a) (note 11)

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Total current liabilities 8,898 5,554

Long-term debt (d) (note 14)

Long-term debt (c) (note 14)

Other long-term obligations (note 5)

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Shareholders’ equity

Common shares at stated value (e) (note 10)

Common shares at stated value (d) (note 10)

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

Accounts receivable - net included net amounts receivable from related parties of $ 1,031 million (2020 – $ 384 million), (note 16).

Investments and long-term receivables included amounts from related parties of $ 298 million (2020 – $ 313 million), (note 16).

Notes and loans payable included amounts to related parties of $ 0 million (2020 – $ 111 million), (note 16).

Long-term debt included amounts to related parties of $ 4,447 million (2020 – $ 4,447 million), (note 16).

Number of common shares authorized and outstanding were 1,100 million and 678 million, respectively (2020 – 1,100 million and 734 million, respectively), (note 10).

(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).

(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.

Chairman, president and

Senior vice-president,

chief executive officer

finance and administration, and controller

/s/ Bradley W.

Corson /s/ Daniel E.

Corson Daniel E.

Chairman, president and Senior vice-president

chief executive officer finance and administration, and controller

Consolidated statement of shareholders’ equity (U.S.

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At December 31 2022 2021 2020

Common shares at stated value

Common shares at stated value (note 10)

At beginning of year 1,252 1,357 1,375

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At end of year 21,846 21,660 22,050

Accumulated other comprehensive income (loss)

Accumulated other comprehensive income (loss) (note 17)

At beginning of year ( 1,177 ) ( 1,989 ) ( 1,911 )

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millions of Canadian dollars

Inflow (outflow)

For the years ended December 31 2022 2021 2020

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Net income (loss) 7,340 2,479 ( 1,857 )

Adjustments for non-cash

Adjustments for non-cash items:

Depreciation and depletion (includes impairments) (note 2)

1,897 1,977 3,273

Impairment of intangible assets (note 11)

(Gain) loss on asset sales (note 8, 18)

( 158 ) ( 49 ) ( 35 )

Deferred income taxes and other ( 77 ) 91 ( 521 )

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All other items - net (b)

( 5 ) 615 253

Cash flows from (used in) operating activities 10,482 5,476 798

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Proceeds from asset sales (note 8, 18)

Additional investments ( 6 ) — —

Loans to equity companies - net 10 15 ( 16 )

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Short-term debt - net (note 12)

Reduction in finance lease obligations (note 14)

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 at beginning of year

Cash at end of year

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 when purchased.

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.

In 2019, the company removed $ 570 million of assets and corresponding liabilities associated with the Government of Ontario’s revocation of its cap and trade legislation.

The impact of this removal was not reflected in “Accounts payable and accrued liabilities” and “All other items - net” lines on the Consolidated statement of cash flows as it was not a cash transaction.

( 60 ) ( 43 ) ( 62 )

The information in the notes to consolidated financial statements is an integral part of these statements.

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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, and biofuels.

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.

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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 i

ts 70.96 percent interest in the Kearl joint venture and its 25 percent interest in the Syncrude joint venture.

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.

Imperial generally sells crude oil, natural gas and petroleum and chemical products under short-term agreements at prevailing market prices.

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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” primarily arise from contracts with customers.

Long-term receivables are primarily from non-customers.

“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, loyalty programs and accruals of expected volume discounts, and are not significant.

Contract liabilities are mainly customer prepayments and accruals of expected volume discounts, and are not significant.

Consumer taxes

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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,

(LIFO) method.

LIFO was selected over the alternative first-in,

and average cost methods because it provides a better matching of current costs with the revenues generated in the period.

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.

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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.

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 investment 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.

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.

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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

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.

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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.

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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, 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.

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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.

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.

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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

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, 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

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.

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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 relies, in part, on the company’s planning and budgeting cycle.

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.

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Other events or changes in circumstances, including indicators outlined in ASC 360

can be indicators of potential impairment as well.

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.

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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 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.

Energy Outlook and cash flow assessment

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, and economic development.

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.

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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.

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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 amount by which the carrying value exceeds fair 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.

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

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Losses on properties sold are recognized when incurred or when the properties are held for sale and the fair value of the properties is less than the carrying value.

Interest capitalization

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.

Asset retirement obligations and other environmental liabilities

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These obligations may include the costs of asset disposal and additional soil remediation.

However, these sites 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.

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.

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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 the summary of significant accounting policies.

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.

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Assets and liabilities that are not identifiable by segment are allocated.

Upstream Downstream Chemical

millions of Canadian dollars 2022 2021 2020 2022 2021 2020 2022 2021 2020

Revenues and other income

Intersegment sales (b)

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

Exploration (note 15)

Purchases of crude oil and products (b) (note 11)

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 (c) (note 11)

pension and postretirement benefit

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

Income tax expense (benefit)

Net income (loss)

Cash flows from (used in) operating activities

Capital and exploration expenditures

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

Corporate and other

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

Intersegment sales (b)

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

Exploration (note 15)

Purchases of crude oil and products (b) (note 11)

— — — — — — 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 (c) (note 11)

pension and postretirement benefit

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

Income tax expense (benefit)

Net income (loss)

Cash flows from (used in) operating activities

Capital and exploration expenditures

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

Includes export sales to the United States of $ 7,228 million (2020 - $ 4,614 million, 2019 - $ 7,190 million).

Export sales to the United States were recorded in all operating segments, with the largest effects in the Upstream segment.

In 2021, the Downstream segment acquired a portion of Upstream crude inventory for $ 444 million.

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

(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.

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

There was no earnings impact and the effects of this transaction have been eliminated for consolidation purposes.

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.

Segment results in 2019 include a largely non-cash

favourable impact of $ 662 million associated with the Alberta corporate income tax rate decrease, with the largest impact in the Upstream segment.

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.

(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.

Includes property, plant and equipment under construction of $ 2,348 million (2020 - $ 1,874 million, 2019 - $ 2,149 million).

Effective January 1, 2019, Imperial adopted the Financial Accounting Standards Board’s standard, Leases (Topic 842)

, as amended.

As at December 31, 2021, Total assets include operating lease right of use assets of $ 245 million (2020 - $ 188 million, 2019 - $ 260 million).

An election was made not to restate prior periods.

See note 13 for additional details.

In 2019, the company removed $ 570 million from Total assets and corresponding liabilities in the Downstream segment associated with the Government of Ontario’s revocation of its cap and trade legislation.

(f) Includes property, plant and equipment under construction of $ 2,676 million (2021 - $ 2,348 million, 2020 - $ 1,874 million).

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)

( 1.5 ) 0.5 ( 2.2 )

Effective income tax rate (percent)

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.

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 were immaterial.

Other primarily relates to prior year adjustments, re-assessments

and disposals.

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.

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:

7 unchanged sentences

Tax loss carryforwards ( 84 ) ( 42 ) ( 460 )

Valuation allowance 73 — —

Other ( 53 ) ( 101 ) ( 154 )

Net deferred income tax liabilities 4,599 4,458 4,101

33 unchanged sentences

What changed 10-K

Item 9A. Controls and Procedures