What changed in this filing

/stocks — the workspaceLOADING

Item 9A. Controls and Procedures

2022-02-23 compared with 2021-02-24 · 938 added, 922 removed, 2400 unchanged (44% of the section changed)

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Other information

Disclosure regarding foreign jurisdiction that prevents inspections

Not applicable.

Directors, executive officers and corporate governance

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Each of the seven individuals listed in the section entitled “Nominees for director” on pages 112 to 115 of this report have been nominated for election at the annual meeting of shareholders to be held May 3, 2022.

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

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

Brownell is a current director and has chosen not to stand for re-election.

All of the nominees are now directors and have been since the dates indicated.

Reference is made to the section under “Nominees for director”:

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

Brownell is deemed a non-independent

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.

As an employee of Exxon Mobil Corporation, D.C.

Brownell is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.

As an employee of Exxon Mobil Corporation, M.R.

Crocker is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.

Principal accountant fees and services

Auditor information

The audit committee of the board of directors recommends that PwC be reappointed as the auditor of the company until the close of the next annual meeting.

The audit committee of the board of directors recommends that PricewaterhouseCoopers LLP (PwC) be reappointed as the auditor of the company until the close of the next annual meeting.

PwC has been the auditor of the company for more than five years and are located in Calgary, Alberta.

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Exhibits, financial statement schedules

Reference is made to the table of contents in the “Financial section” on page 41 of this report.

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.

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.

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.

Description of capital stock.

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for the year ended December 31, 2019 (File No.

(1) Syncrude Ownership and Management Agreement, dated February 4, 1975 (Incorporated herein by reference to Exhibit 13(b) of the company’s Registration Statement on Form S-1, as filed with the Securities and Exchange Commission on August 21, 1979 (File No.

(2) Letter Agreement, dated February 8, 1982, between the Government of Canada and Esso Resources Canada Limited, amending Schedule “C” to the Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to Exhibit (20) of the company’s Annual Report on Form 10-K

for the year ended December 31, 1981 (File No.

(3) Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the company’s Annual Report on Form 10-K for the year ended December 31, 1989 (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.

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for the year ended December 31, 2001 (File No.

(5) Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.

(6) Amendment to Syncrude Ownership and Management Agreement effective September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No.

(7) Syncrude Bitumen Royalty Option Agreement, dated November 18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January 1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Form 8-K

filed on November 19, 2008 (File No.

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

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filed on October 31, 2016 (File No.

(6) Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2020 and subsequent years, as amended effective November 24, 2020.

Imperial Oil Resources Limited is incorporated in Canada, and is a wholly-owned subsidiary of the company.

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.

Imperial Oil Resources Limited is incorporated in Alberta, Canada and Canada Imperial Oil Limited is incorporated in Canada, and both are wholly-owned subsidiaries of the company.

The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2021.

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accounting officer)

/s/ Matthew R.

/s/ Krystyna T.

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Management’s discussion and analysis of financial condition and results of operations

Business environment and risk assessment

Results of operations

Business environment

Business results

Liquidity and capital resources

Capital and exploration expenditures

Market risks and other uncertainties

Critical accounting estimates

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Summary of significant accounting policies

Accounting changes

Business segments

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

Quarterly financial data

Financial information (U.S.

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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.

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.

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 measure 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.

When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity.

The most directly comparable financial measure that is disclosed in the financial statements is total assets within the company’s Consolidated balance sheet.

Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed.

Reconciliation of capital employed

millions of Canadian dollars

From the Consolidated balance sheet

Business uses:

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Return on average capital employed (ROCE)

ROCE is a financial performance ratio.

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

Segment net income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing.

Capital employed is a non-GAAP

financial measure and is disclosed and reconciled above.

The company’s total ROCE is net income excluding the after-tax

cost of financing divided by total average capital employed.

The company has consistently applied its ROCE definition for many years and views it as the best measure of historical capital productivity in a capital-intensive, long-term industry.

The company has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in a capital-intensive, long-term industry.

Additional measures, which are more cash flow based, are used to make investment decisions.

Components of return on average capital employed

millions of Canadian dollars

From the Consolidated statement of income

Net income (loss)

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Average capital employed

Return on average capital employed (percent) – corporate total

Return on average capital employed (percent)

– corporate total

Cash flows from operating activities and asset sales

Cash flows from operating activities and asset sales 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.

The most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company’s Consolidated statement of cash flows.

The company employs a long-standing and regular disciplined review process to ensure that assets are contributing to the company’s strategic objectives.

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Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.

Reconciliation of cash flows from (used in) operating activities and asset sales

millions of Canadian dollars

From the Consolidated statement of cash flows

Cash flows from operating activities

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Operating costs

Operating costs 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.

They exclude 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

The most directly comparable financial measure that is disclosed in the financial statements is total expenses within the company’s Consolidated statement of income.

While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.

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millions of Canadian dollars

From Imperial’s Consolidated statement of income

From the Consolidated statement of income

Total expenses

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millions of Canadian dollars

From Imperial’s Consolidated statement of income

From the Consolidated statement of income

Production and manufacturing

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Total operating costs

Net income (loss) excluding identified items

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

financial measure that is total net income (loss) excluding individually significant non-operational

events with an absolute corporate total earnings impact of at least $100 million in a given quarter.

The net income (loss) impact of an identified item for an individual segment in a given quarter may be less than $100 million when the item impacts several segments or several periods.

The most directly comparable financial measure that is disclosed in the financial statements is net income (loss) within the company’s Consolidated statement of income.

Management uses these figures to improve comparability of the underlying business across multiple periods by isolating and removing significant non-operational

events from business results.

The company believes this view provides investors increased transparency into business results and trends, and provides investors with a view of the business as seen through the eyes of management.

Net income (loss) excluding identified items is not meant to be viewed in isolation or as a substitute for net income (loss) as prepared in accordance with U.S.

All identified items are presented on an after-tax

Reconciliation of net income (loss) excluding identified items

millions of Canadian dollars

From the Consolidated statement of income

Net income (loss) (U.S.

Less identified items included in Net income (loss)

Tax adjustments

Subtotal of identified items

Net income (loss) excluding identified items

Management’s discussion and analysis of financial condition and results of operations

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 and 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 business model involving exploration for, and production of, crude oil and natural gas, manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products.

Imperial, with its resource base, financial strength, disciplined investment approach and technology portfolio, is well-positioned to participate in substantial investments to develop new Canadian energy supplies.

The company’s integrated business model, with significant investments in Upstream, Downstream and Chemical segments, generally reduces the company’s risk from changes in commodity prices.

The company’s operating segments are Upstream, Downstream, Chemicals and Corporate and other.

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

While commodity prices depend on supply and demand and may be volatile on a short-term basis, Imperial’s investment decisions are grounded on fundamentals reflected in its long-term business outlook, and use a disciplined approach in selecting and pursuing the most attractive investment opportunities.

The corporate plan is a fundamental annual management process that is the basis for setting operating and capital objectives, in addition to providing the economic assumptions used for investment evaluation purposes.

Volume projections are based on individual field production profiles, which are also updated annually.

Price ranges for crude oil, natural gas, refined products and chemical products are based on corporate plan assumptions developed annually and are utilized 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.

Major investment opportunities are evaluated over a range of potential market conditions.

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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.

Business environment and risk assessment

Business environment

Long-term business outlook

Given the uncertainty around the near-term impacts of COVID-19

on economic growth, energy demand and energy supply, and lack of precedent, the company is considering a range of recovery pathways to guide near-term plans.

These pathways expect that energy demand will grow beyond 2019 levels as early as 2022 reflecting the phase out of COVID-19

impacts and re-establishment of long-term supply / demand fundamentals.

The “Long-term business outlook” is based on Exxon Mobil Corporation’s Outlook for Energy

, which combined with the near-term pathways is used to help inform the company’s long-term business strategies and investment plans.

(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

greenhouse gas emission-reduction technologies;

and supportive government policies.

The Outlook considers these fundamentals to form the basis for the company’s long-term business planning, investment decisions, and research programs.

The Outlook reflects the company’s view of global energy demand and supply through 2050.

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

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.

By 2050, the world’s population is projected at around 9.7 billion people, or about 2 billion more than in 2019.

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 75 percent by 2040.

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.

As economies and populations grow, and as living standards improve for billions of people, the need for energy is expected to continue to rise.

Even with significant efficiency gains, global energy demand is projected to rise by more than 10 percent from 2018 to 2040.

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)).

Canada is expected to see flat to modest local energy demand growth through to 2040 and will continue to be a large supplier of energy exports to help meet rising global energy needs.

As expanding prosperity helps drive 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.

Even with significant efficiency gains, global energy demand is projected to rise by almost 15 percent from 2019 to 2050.

This increase in energy demand is expected to be driven by developing countries (i.e., those that are not member nations of the Organization for Economic Co-operation and Development (OECD)).

As expanding prosperity drives global energy demand higher, increasing use of energy-efficient technologies and practices, as well as lower-emission products will continue to help significantly reduce energy consumption and 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.

Global electricity demand is expected to increase approximately 50 percent from 2018 to 2040, with developing countries likely to account for about 85 percent of the increase.

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.

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 likely to decline substantially and approach 20 percent of the world’s electricity in 2040, versus nearly 40 percent in 2018, in part as a result of policies to improve air quality as well as reduce greenhouse gas emissions to address the risks related to climate change.

From 2018 to 2040, the amount of electricity supplied using natural gas, nuclear power, and renewables is likely to nearly double, accounting for the entire growth in electricity supplies and offsetting the reduction of coal.

Electricity from wind and solar is likely to increase about 400 percent, helping total renewables (including other sources, i.e., hydropower) to account for about 80 percent of the increase in electricity supplies worldwide through 2040.

Total renewables will likely reach about 50 percent of global electricity supplies by 2040.

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.

Supplies of electricity by energy type will reflect significant differences across regions reflecting a wide range of factors including the cost and availability of various energy supplies and policy developments.

Energy for transportation – including cars, trucks, ships, trains and airplanes – is expected to increase by about 20 percent from 2018 to 2040.

Transportation energy demand is likely to account for over 60 percent of the growth in liquid fuels demand worldwide over this period.

Light-duty vehicle demand for liquid fuels is projected to peak prior to 2025 and then decline to levels seen in the early-2010s by 2040 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 60 percent.

By 2040, light-duty vehicles are expected to account for about 20 percent of global liquid fuels demand.

During the same time period, nearly all the world’s commercial transportation fleets are likely to continue to run on liquid fuels, which are widely available and offer practical advantages in providing a large quantity of energy in small volumes.

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.

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.

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.

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

share of global liquid fuels demand is expected to increase to about 65 percent by 2040, as liquid fuels demand in the OECD is likely to decline by close to 15 percent.

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;

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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 2018 to 2040, meeting about 50 percent of global energy demand growth.

Global natural gas demand is expected to rise about 25 percent from 2018 to 2040, with about half of that increase coming from the Asia Pacific region.

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 2019 to 2050, meeting about 55 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.

Significant growth in supplies of unconventional gas – the natural gas found in shale and other tight rock formations – will help meet these needs.

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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 likely 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 2040, while the share of coal falls to about two thirds of the natural gas share.

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 likely to exceed 15 percent of global energy by 2040, 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 350 percent from 2018 to 2040, when they will likely be just over 6 percent of the world energy mix.

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.

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.

Technology will underpin these increases.

The investments to develop and supply resources to meet global demand through 2040 will be significant – even if demand remains flat.

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

According to the IEA’s Stated Energy Policies Scenario, the investment required to meet oil and natural gas supply requirements worldwide over the period 2019 to 2040 will be about US$17 trillion (measured in 2019 dollars).

In the IEA’s Sustainable Development Scenario, which is in line with the objectives of the Paris Agreement on climate change, the investment need would still accumulate to US$12 trillion.

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.

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The Outlook for Energy

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

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, application of a proxy cost of carbon or assessment of targeted policies (i.e., automotive fuel economy standards).

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).

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 are expected to provide in preparation for 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 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

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.

Business results

millions of Canadian dollars

Net income (loss) (U.S.

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

Tax adjustments

Subtotal of identified items

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)

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

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

Imperial’s Upstream business strategies guide the company’s exploration, development, production, research and gas marketing activities.

These strategies include maximizing asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness.

These strategies include improving asset reliability, accelerating development and application of high impact technologies, maximizing value by capturing new business opportunities and managing the existing portfolio, as well as pursuing sustainable improvements in organizational efficiency and effectiveness.

These strategies are underpinned by a relentless focus on operations integrity, commitment to innovative technologies, disciplined approach to investing and cost management, development of employees and investment in the communities within which the company operates.

Imperial has a significant oil and gas resource base and a large inventory of potential projects.

The company continues to evaluate opportunities to support long-term growth.

As future development projects bring new production online, Imperial expects growth from oil sands in-situ

and mining, as well as unconventional resources, with the largest growth potential related to in-situ.

Actual volumes will vary from year to year due to the factors described in Item 1A.

The company’s current investment strategy is to invest for value and select volume growth, with focus on optimization within existing assets, cost reduction opportunities and productivity enhancements that aim to deliver robust returns at a wide range of prices.

The company also continues to evaluate opportunities to support long-term growth.

Although actual volumes will vary from year to year, the focus is on value-add,

long-term growth opportunities within the context of the factors described in Item 1A.

“Risk factors”.

Imperial continually evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen in-situ

oil sands project, as economically justified.

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 the year as supply and demand began to rebalance.

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

Prices for most of the company’s crude oil sold are referenced to Western Canada Select (WCS) and West Texas Intermediate (WTI) oil markets.

In January 2019, the Government of Alberta’s temporary mandatory production curtailment regulations came into effect.

Although the mandatory production curtailment decreased throughout 2019 and 2020, and was eliminated in December 2020, the regulatory authority to impose curtailment remains in place and there is the potential for curtailment to be re-imposed

and increased.

The duration of these regulations is uncertain.

Imperial continually monitors the effects of these regulations and evaluates opportunities, including crude shipments by rail and the pace of the development of its Aspen in-situ

oil sands project, as economically justified.

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 activities, levels of prosperity, technology advances, consumer preference and government policies.

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.

To manage the risks associated with price, Imperial evaluates annual plans and all major investments across a range of price scenarios.

In 2020, Imperial re-assessed

the long-term development plans of its unconventional portfolio in Alberta and no longer plans to further develop a significant portion of this portfolio.

The decision resulted in a non-cash,

impairment charge of $1,171 million in 2020, thereby reducing the carrying value of those assets to fair value.

The company retains its interest in these resources.

These non-core

assets are non-producing,

undeveloped assets and the company does not expect any material future cash expenditures related to this impairment.

This decision is consistent with Imperial’s strategy of focusing its upstream resources and efforts on its key oil sands assets as well as on only the most attractive portions of its unconventional portfolio.

Imperial continues to produce from its developed acreage.

Kearl’s supplemental crushing facilities started operations in late 2019, with ramp-up

of all units through early 2020.

These facilities have further improved reliability, reduced planned downtime, lowered unit costs and enabled the asset to achieve higher volumes.

As disclosed in the company’s 2019 Form 10-K,

the original production target in 2020 for Kearl was 240,000 barrels per day (about 170,000 barrels Imperial’s share).

As a result of market conditions, the company adjusted planned maintenance and turnaround activity, and revised its full-year guidance for Kearl total gross production to 220,000 barrels per day (about 156,000 barrels Imperial’s share).

In 2020, Kearl achieved record annual total gross production of 222,000 barrels per day (158,000 barrels Imperial’s share).

Imperial continues to progress initiatives to enable the asset to achieve 255,000 barrels per day of total gross production in 2021 (about 181,000 barrels Imperial’s share).

In 2020, gross bitumen production at Cold Lake was impacted by ongoing steam management.

The company plans to focus on base performance in the near-term and expects gross bitumen production at Cold Lake to average approximately 130,000 barrels per day in 2021.

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.

As described in more detail in Item 1A.

1 unchanged sentence

could have negative impacts on the upstream business.

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

Imperial’s Downstream business strategies competitively position the company across a range of market conditions.

These strategies include targeting industry leading performance in reliability, safety and operations integrity, as well as maximizing value from advanced technologies, capitalizing on integration across Imperial’s businesses, selectively investing for resilient and advantaged returns, operating efficiently and effectively, and providing quality, valued and differentiated products and services to customers.

Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 428,000 barrels per day.

Refining margins are largely driven by differences in commodity prices and are a function of the difference between what a refinery pays for its raw materials (primarily crude oil) and the market prices for the range of products produced (primarily gasoline, heating oil, diesel oil, jet fuel, fuel oil and asphalt).

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

Prices for these commodities are determined by the global and regional marketplaces and are influenced by many factors, including global and regional supply / demand balances, inventory levels, industry refinery operations, import / export balances, currency fluctuations, seasonal demand, weather and political climate.

Imperial’s integration across the value chain, from refining to marketing, enhances overall value across the fuels business.

In 2020, demand for petroleum products was significantly impacted by the COVID-19

pandemic, starting in the first half of the year.

While there was some demand improvement in the second half of 2020, demand remained below 2019 levels.

This unprecedented demand impact also adversely affected Imperial’s margins.

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 2020, 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.

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 2020, margins were adversely impacted by continued industry capacity additions and effects related to COVID-19.

Imperial maintains a competitive advantage through continued operational excellence, consistent product quality, investment and cost discipline, and integration of its chemical plant in Sarnia with the refinery.

The company also benefits from its relationship with ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.

Results of operations

In 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 across Canada and the world resulting in substantial reductions in consumer and business activity and significantly reduced local and global 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.

Market conditions continued to reflect considerable uncertainty throughout 2020 as consumer and business activity has exhibited some degree of recovery, but remained lower when compared to prior periods as a result of the pandemic.

Despite actions taken by key oil-producing

countries to reduce oversupply, and improved credit market conditions providing sufficient liquidity to credit-worthy companies, the unfavourable economic impacts appear increasingly likely to persist to some extent well into 2021.

In late March, the company announced significant reductions in 2020 capital and operating expense spending plans.

Capital and exploration expenditures for 2020 were $874 million, in line with the company’s most recent guidance of $900 million, and less than half of 2019 expenditures.

Capital expenditures in 2021 are expected to be approximately $1.2 billion.

In addition, full-year production and manufacturing expenses were $985 million lower than the prior year.

This decrease enabled the company to surpass its $500 million expense reduction commitment made in 2020 by nearly double.

The effect of COVID-19

and the current business environment on supply and demand patterns negatively impacted Imperial’s financial and operating results in 2020.

Industry conditions seen in 2020 have led to lower realized prices for the company’s products and have resulted in substantially lower earnings and operating cash flow throughout 2020 in comparison to 2019.

In response to these conditions, the company operated certain assets at reduced rates and adjusted planned maintenance and turnaround activities throughout the second and third quarters in an effort to reduce on-site

staffing levels and to better balance production with demand.

Refinery utilization rates and petroleum product sales were reduced through the second quarter of 2020, but saw some improvement in product demands in the second half of the year.

The length and severity of COVID-19

impacts to demand and the current business environment are highly uncertain, with the future supply and demand patterns inherently difficult to predict.

In the second quarter of 2020, Canadian federal and provincial governments introduced plans and programs to support business and economic activities in response to the disruptive impacts from the COVID-19

The Government of Canada implemented the Canada Emergency Wage Subsidy (CEWS) as part of its COVID-19

Economic Response Plan, and has extended the CEWS until June 2021.

The company received wage subsidies under this program and, if eligible, intends to continue to apply for these wage subsidies.

Additionally, in the fourth quarter, the Alberta government enacted an accelerated reduction in the corporate income tax rate to eight percent beginning July 1, 2020, compared with a previously legislated reduction to eight percent beginning January 1, 2022.

The corporate income tax rate change did not have a significant impact on the company’s financial statements.

The company has taken steps, in line with federal and provincial guidelines and restrictions, to limit the spread of COVID-19

among employees, contractors and the broader community, while also maintaining operations to ensure reliable supply of products to customers as a provider of essential services.

The company maintains robust business continuity plans, which have been activated to minimize the impact of COVID-19

on workforce productivity.

2021 Net income (loss) factor analysis

millions of Canadian dollars

Net income (loss)

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, and a favourable impact of about $115 million after-tax,

associated with the Canada Emergency Wage Subsidy (CEWS), which includes Imperial’s proportionate share of a joint venture.

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

Net income in 2019 was $2,200 million, or $2.88 per share on a diluted basis, compared to net income of $2,314 million or $2.86 per share in 2018.

2019 results include a favourable impact, largely non-cash,

of $662 million associated with the Alberta corporate income tax rate decrease.

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.

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.

2020 Net income (loss) factor analysis

millions of Canadian dollars

Net income (loss)

Upstream recorded a net loss of $2,318 million for the year, compared to net income of $1,348 million in 2019.

Results were negatively impacted by lower realizations of about $2,620 million, a non-cash

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, and lower volumes of about $130 million.

These items were partially offset by lower royalties of about $540 million, lower operating expenses of about $250 million, favourable foreign exchange impacts of about $100 million, and about $70 million associated with the CEWS received by the company which includes Imperial’s proportionate share of a joint venture.

Upstream net income was $1,348 million for the year, reflecting the favourable impact associated with the decreased Alberta corporate income tax rate of $689 million.

Excluding this impact, 2019 net income was $659 million, up $797 million compared to a net loss of $138 million in 2018.

Improved results reflect higher crude oil realizations of about $1,000 million, as well as higher volumes of about $350 million primarily at Syncrude and Norman Wells.

Results were negatively impacted by higher royalties of about $230 million, higher operating expenses of about $190 million and lower Cold Lake volumes of about $120 million.

Average realizations

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

Marker prices and average realizations

Canadian dollars, unless otherwise noted

West Texas Intermediate (US$) (per barrel)

Western Canada Select (US$) (per barrel)

WTI/WCS Spread (US$) (per barrel)

Bitumen (per barrel)

3 unchanged sentences

Natural gas (per thousand cubic feet)

WTI averaged US$39.26 per barrel in 2020, down from US$57.03 per barrel in 2019.

WCS averaged US$26.87 per barrel and US$44.29 per barrel for the same periods.

The WTI / WCS differential narrowed to approximately US$12 per barrel in 2020, from around US$13 per barrel in 2019.

The Canadian dollar averaged US$0.75 in 2020, essentially unchanged from 2019.

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.

Bitumen realizations averaged $25.69 per barrel, compared to $50.02 per barrel in 2019.

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.

Synthetic crude realizations averaged $49.76 per barrel, compared to $74.47 per barrel in 2019.

WTI averaged US$57.03 per barrel in 2019, down from US$65.03 per barrel in 2018.

WCS averaged US$44.29 per barrel and US$38.71 per barrel for the same periods.

The WTI / WCS differential narrowed to average approximately US$13 per barrel in 2019, from around US$26 per barrel in 2018.

The Canadian dollar averaged US$0.75 in 2019, a decrease of US$0.02 from 2018.

Imperial’s average Canadian dollar realizations for bitumen increased in 2019, supported primarily by an increase in WCS and lower diluent costs.

Bitumen realizations averaged $50.02 per barrel, up from $37.56 per barrel in 2018.

The company’s average Canadian dollar realizations for synthetic crude increased relative to WTI, primarily due to the narrowing of the western Canadian light crude differential.

Synthetic crude realizations averaged $74.47 per barrel, up from $70.66 per barrel in 2018.

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

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Bitumen sales, including diluent (c)

NGL sales (d)

Natural gas - production and production available for sale

millions of cubic feet per day

Production (d) (e)

Production available for sale (f)

Production (e) (f)

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.

Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.

Net production excludes those shares.

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.

2 unchanged sentences

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

Total gross production of Kearl bitumen averaged 222,000 barrels per day in 2020 (158,000 barrels Imperial’s share), the highest annual production in the asset’s history, up from 205,000 barrels per day (145,000 barrels Imperial’s share) in 2019.

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.

Gross production of Cold Lake bitumen averaged 132,000 barrels per day in 2020, compared to 140,000 barrels per day in 2019.

During 2020, the company’s share of gross production from Syncrude averaged 69,000 barrels per day, compared to 73,000 barrels per day in 2019.

Total gross production of Kearl bitumen averaged 205,000 barrels per day in 2019 (145,000 barrels Imperial’s share), compared to 206,000 barrels per day (146,000 barrels Imperial’s share) in 2018.

Gross production of Cold Lake bitumen averaged 140,000 barrels per day in 2019, compared to 147,000 barrels per day in 2018.

During 2019, the company’s share of gross production from Syncrude averaged 73,000 barrels per day, up from 62,000 barrels per day in 2018.

Higher production was mainly due to the absence of production impacts from the 2018 power disruption.

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

Imperial’s Downstream business strategies competitively position the company across a range of market conditions.

Imperial owns and operates three refineries in Canada, with aggregate distillation capacity of 428,000 barrels per day.

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

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

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.

Results of operations

2021 Net income (loss) factor analysis

millions of Canadian dollars

Net income (loss)

Downstream net income was $553 million, compared to $961 million in 2019.

Results were negatively impacted by lower margins of about $710 million, and lower sales volumes of about $290 million.

These items were offset 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.

Downstream net income was $961 million, compared to $2,366 million in 2018.

Earnings were negatively impacted by lower margins of about $1,130 million, reliability events of about $150 million, including the fractionation tower incident at Sarnia, higher net planned turnaround impacts of about $140 million, and lower sales volumes of about $130 million.

These factors were partially offset by favourable foreign exchange impacts of about $90 million.

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.

2020 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.

Refinery utilization

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Total refinery throughput (b)

Refinery capacity at December 31

Rated capacity at December 31 (c)

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.

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.

Petroleum product sales

thousands of barrels per day (a)

3 unchanged sentences

Net petroleum product sales

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

Crude oil and feedstocks sent directly to atmospheric distillation units.

Refinery throughput averaged 340,000 barrels per day in 2020, compared to 353,000 barrels per day in 2019.

Capacity utilization was 80 percent, compared to 83 percent in 2019.

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.

Petroleum product sales were 421,000 barrels per day in 2020, compared to 475,000 barrels per day in 2019.

(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

Refinery throughput averaged 353,000 barrels per day in 2019, compared to 392,000 barrels per day in 2018.

Capacity utilization was 83 percent, compared to 93 percent in 2018.

Reduced throughput was mainly due to higher planned turnaround activities and impacts from the Sarnia fractionation tower incident.

Petroleum product sales were 475,000 barrels per day in 2019, compared to 504,000 barrels per day in 2018.

Lower petroleum product sales were mainly due to lower refinery throughput.

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.

The company also benefits from its relationship with ExxonMobil’s North American chemical businesses, enabling Imperial to maintain a leadership position in its key market segments.

Results of operations

2021 Net income (loss) factor analysis

millions of Canadian dollars

Net income (loss)

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

2020 Net income (loss) factor analysis

millions of Canadian dollars

Margins – Lower earnings primarily reflect lower margins.

thousands of tonnes

2 unchanged sentences

Total petrochemical sales

Chemical net income was $78 million in 2020, compared to $108 million in 2019, primarily reflecting lower margins.

Chemical net income was $108 million in 2019, compared to $275 million in 2018, primarily due to lower margins.

Corporate and other

1 unchanged sentence

Net income (loss)

Corporate and other expenses were $170 million in 2020, compared to $217 million in 2019.

Corporate and other expenses were $217 million in 2019, compared to $189 million in 2018.

Liquidity and capital resources

Sources and uses of cash

millions of Canadian dollars

Cash provided by (used in)

Operating activities

Investing activities

Financing activities

Increase (decrease) in cash and cash equivalents

Cash and cash equivalents at end of year

The company issues long-term debt from time to time and maintains a commercial paper program.

10 unchanged sentences

Future funding requirements are not expected to affect the company’s existing capital investment plans or its ability to pursue new investment opportunities.

millions of Canadian dollars

Cash provided by (used in)

Operating activities

Investing activities

Financing activities

Increase (decrease) in cash and cash equivalents

Cash and cash equivalents at end of year

Cash flow from operating activities

Cash flow generated from operating activities was $798 million in 2020, compared to $4,429 million in 2019, primarily reflecting lower realizations in the Upstream and unfavourable working capital impacts.

Cash flow generated from operating activities was $4,429 million in 2019, up from $3,922 million in 2018, primarily reflecting favourable working capital effects, partially offset by lower earnings excluding the impact associated with the Alberta corporate income tax rate decrease.

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.

Investing activities used net cash of $1,704 million in 2019, compared with $1,559 million used in 2018, primarily reflecting higher additions to property, plant and equipment.

Cash flow from financing activities

Cash used in financing activities was $943 million in 2020, compared to $1,995 million used in 2019.

At the end of 2021, total debt outstanding was $5,176 million, compared with $5,184 million at the end of 2020.

During the second quarter of 2021, the company extended the maturity date of two of its short-term lines of credit, totalling $750 million, to May 2023, these facilities are now long-term.

The company also extended its $300 million committed short-term line of credit to June 2022.

In November 2021, the company extended the maturity date of an existing $250 million committed short-term line of credit to November 2022.

The company has not drawn on these facilities.

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.

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The company has not drawn on the facility.

During 2020, the company, under its share purchase program, purchased about 9.8 million shares for $274 million.

Share repurchases

millions of Canadian dollars, unless noted

Share repurchases

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.

On April 30, 2021, the company announced an amendment to its normal course issuer bid to increase the number of common shares that were available to be purchased.

Under the amendment, the number of common shares available for purchase increased to a maximum of 29,363,070 common shares during the period June 29, 2020 to June 28, 2021.

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

On June 23, 2021 the company announced that it 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.

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.

Dividends paid in 2020 were $649 million.

The per share dividend paid in 2020 was $0.88, up from $0.82 in 2019.

Cash used in financing activities was $1,995 million in 2019, compared with $2,570 million used in 2018.

At the end of 2019, total debt outstanding was $5,190 million, compared with $5,180 million at the end of 2018.

In September 2019, the company extended the maturity date of its existing long-term, variable-rate, Canadian dollar loan from ExxonMobil to June 30, 2025.

All other terms and conditions remained unchanged.

In November 2019, the company increased the capacity of its non-interest

bearing, revolving demand loan with ExxonMobil from $75 million to $150 million.

The loan represents ExxonMobil’s share of a working capital facility required to support purchasing, marketing, transportation and derivative arrangements for crude oil and diluent products undertaken by Imperial on behalf of ExxonMobil.

At December 31, 2019 the company had borrowed $111 million under this arrangement.

In November 2019, the company extended the maturity date of its existing $250 million committed long-term line of credit to November 2021.

The company has not drawn on the facility.

In December 2019, the company extended the maturity date of its existing $250 million committed short-term line of credit to December 2020.

The company has not drawn on the facility.

During 2019, the company, under its share purchase program, purchased about 38.7 million shares for $1,373 million, including shares purchased from Exxon Mobil Corporation.

Dividends paid in 2019 were $631 million.

The per share dividend paid in 2019 was $0.82, up from $0.70 in 2018.

millions of Canadian dollars, unless noted

Dividends paid

Per share dividend paid (dollars)

Financial strength

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

The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets under the full range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

The following table shows the company’s commitments outstanding at December 31, 2020.

It combines data from the Consolidated balance sheet and from individual notes to the consolidated financial statements, where appropriate.

Payment due by period

millions of Canadian dollars

Long-term debt excluding finance lease obligations (a)

Operating and finance leases (b)

Firm capital commitments (c)

Pension and other postretirement obligations (d)

Asset retirement obligations (e)

Other long-term purchase agreements (f)

Long-term debt includes a loan from an affiliated company of ExxonMobil of $4,447 million.

The payment by period for the related party long-term loan is estimated based on the right of the related party to cancel the loan on at least 370 days advance written notice.

Minimum commitments for finance and operating leases, both commenced and non-commenced,

are shown on an undiscounted basis.

Leases are primarily associated with storage tanks, rail cars, marine vessels, transportation facilities and service agreements.

Firm capital commitments represent legally-binding payment obligations to third parties where agreements specifying all significant terms have been executed for the construction and purchase of fixed assets and other permanent investments.

In certain cases where the company executes contracts requiring commitments to a work scope, those commitments have been included to the extent that the amounts and timing of payments can be reliably estimated.

Firm capital commitments related to capital projects are shown on an undiscounted basis.

The amount by which the benefit obligations exceeded the fair value of fund assets for pension and other postretirement plans at year end.

The payments by period include expected contributions to funded pension plans in 2021 and estimated benefit payments for unfunded plans in all years.

Asset retirement obligations represent the fair value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.

Other long-term purchase agreements are non-cancelable,

or cancelable only under certain conditions and long-term commitments other than unconditional purchase obligations.

The company’s financial strength represents a competitive advantage of strategic importance providing it the opportunity to readily access capital markets across a range of market conditions and enables the company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

Contractual obligations

The company has contractual obligations involving commitments to third parties that impact its liquidity and capital resource needs.

These contractual obligations are primarily for leases, debt, asset retirement obligations, pension and other postretirement benefits, other long-term obligations, and firm capital commitments.

Further information on this topic can be found in notes 4, 5, 13 and 14 to the consolidated financial statements.

Other long-term purchase agreements are commitments that are non-cancelable,

or cancelable only under certain conditions, as well as long-term commitments, other than unconditional purchase obligations.

They include primarily transportation services agreements, raw material supply and community benefits agreements.

Unrecognized tax benefits totalling $36 million have not been included in the company’s commitments table because the company does not expect there will be any cash impact from the final settlements as sufficient funds have been deposited with the Canada Revenue Agency.

Further details on the unrecognized tax benefits can be found in note 4 to the financial statements on page 88.

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.

Litigation and other contingencies

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Capital and exploration expenditures

Capital and exploration expenditures represent the combined total of additions at cost to property, plant and equipment;

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

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Corporate and other

(a) Exploration expenses included.

Total capital and exploration expenditures were $874 million in 2020, a decrease of $940 million from 2019.

In response to the challenges presented by the COVID-19

pandemic and decreases in commodity prices, in the first quarter of 2020 the company provided an updated capital outlook of $1.1 billion to $1.2 billion (from original guidance of $1.6 billion to $1.7 billion).

In the third quarter of 2020, the company further updated this capital outlook to about $900 million.

For the Upstream segment, capital and exploration expenditures were $561 million in 2020, compared with $1,248 million in 2019.

Investments were primarily related to sustaining activity in support of the company’s in-situ

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 $251 million in 2020, compared with $484 million in 2019.

Investments were primarily for enhancing the company’s distribution network as well as refinery projects to improve reliability, feedstock flexibility, energy efficiency and environmental performance.

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 capital and exploration expenditures are expected to be approximately $1.4 billion in 2022.

Expected capital and exploration expenditures for 2022 includes firm capital commitments of $290 million for the construction and purchase of fixed assets and other permanent investments.

An additional $354 million of firm capital commitments have been made for years 2023 and beyond.

Actual spending could vary depending on the progress of individual projects.

Market risks and other uncertainties

Crude oil, natural gas, petroleum product and chemical prices have fluctuated in response to changing market forces.

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

Each sensitivity calculation shows the impact on net income resulting from a change in one factor, after-tax

and royalties and holding all other factors constant.

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.

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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.

In addition, the company may use commodity-based contracts, including derivatives, to manage commodity price risk and for trading purposes.

In addition, the company may use commodity-based contracts, including derivatives, to manage commodity price risk and to generate returns from trading.

The company’s derivatives are not accounted for under hedge accounting.

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GAAP requires management to make estimates and judgments that affect the reported amounts of assets, liabilities, revenues and expenses, and the disclosure of contingent assets and liabilities.

The company’s accounting and financial reporting fairly reflect its business model involving exploration for, and production of, crude oil and natural gas;

manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products;

and pursuit of lower-emission business opportunities, including carbon capture and storage, and biofuels.

Imperial does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet.

The company’s significant accounting policies are summarized in note 1 to the consolidated financial statements on page 80.

Oil and gas reserves

Oil and natural gas reserves

Evaluations of oil and natural gas reserves are important to the effective management of upstream assets.

They are an integral part of investment decisions about oil and gas properties such as whether development should proceed.

The estimation of proved reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of well information such as flow rates and reservoir pressures, and development and production costs, among other factors.

The estimation of proved reserves is controlled by the company through long-standing approval guidelines.

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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.

The percentage of proved developed reserves was 75 percent of total proved reserves at year-end

2020, a reduction from 89 percent in 2019.

Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, royalty frameworks and significant changes in oil and gas price levels.

The company is reasonably certain that proved reserves will be produced.

However, the timing and amount recovered can be affected by a number of factors including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, royalty frameworks and significant changes in oil and natural gas price levels.

Unproved reserves are quantities of oil and natural gas with less than reasonable certainty of recoverability and include probable reserves.

Probable reserves are reserves that, together with proved reserves, are as likely as not to be recovered.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or re-evaluation

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;

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Revisions can also result from significant changes in either development strategy or production equipment / facility capacity.

2016, downward revisions of proved developed and undeveloped bitumen reserves were a result of low prices.

The entire 2.5 billion barrels of bitumen at Kearl and approximately 0.2 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.

2017, an additional 0.3 billion barrels of bitumen at Kearl and Cold Lake qualified as proved reserves resulting from improved prices in the year.

As a result of improved prices in 2018, an additional 2.3 billion barrels of bitumen at Kearl qualified as proved reserves at year-end

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.

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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.

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.

Under the terms of certain contractual arrangements or government royalty regimes, lower prices can also increase proved reserves attributable to Imperial.

The company does not expect its operations to be affected by the downward revision of reported proved reserves as disclosed under the U.S.

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

The calculation of unit-of-production

depreciation is a critical accounting estimate that measures the depreciation of upstream assets.

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 the actual cost of production.

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.

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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 2017 and 2018, with the corresponding effect on depreciation expense being immaterial when compared to prior periods.

This approach will also be applied in 2021 and the effect of this approach is anticipated to be immaterial compared to 2020.

For 2019 and 2020, all properties had sufficient reserves at their relevant SEC prices which enabled equitable allocation of cost over the economic lives of the Upstream assets.

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.

Impact of oil and gas reserves and prices and margins on testing for impairment

The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable.

Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

A significant decrease in the market price of a long-lived asset;

A significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in the company’s current and projected reserve volumes;

A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator;

An accumulation of project costs significantly in excess of the amount originally expected;

A current-period operating loss combined with a history and forecast of operating or cash flow losses;

A current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

Asset valuation analysis, profitability reviews and other periodic control processes assist Imperial in assessing whether events or changes in circumstances indicate the carrying amounts of any of its assets may not be recoverable.

The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.

This process is aligned with the requirements of ASC 360

and 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.

In general, Imperial does not view temporarily low prices or margins as an indication of impairment.

Management believes prices over the long term must be sufficient to generate investments in energy supply to meet global demand.

Management believes that prices over the long term must be sufficient to generate investments in energy supply to meet global demand.

Although prices will occasionally drop significantly, industry prices over the long term will continue to be driven by market supply and demand fundamentals.

On the supply side, industry production from mature fields is declining.

This is being offset by investments to generate production from new discoveries, field developments and technological and efficiency advancements.

This is being offset by investments to generate production from new discoveries, field developments, and technology and efficiency advancements.

OPEC investment activities and production policies also have an impact on world oil supplies.

The demand side is largely a function of general economic activities and levels of prosperity.

Because the lifespans of the company’s major assets are measured in decades, the value of these assets is predominantly based on long-term views of future commodity prices and development and production costs.

During the lifespan of these major assets, the company expects that oil and gas prices will experience significant volatility, and 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.

While near-term prices are subject to wide fluctuations, longer-term price views are more stable and meaningful for purposes of assessing future cash flows.

When the industry experiences a prolonged and deep reduction in commodity prices, the market supply and demand conditions may result in changes to the company’s price or margin assumptions it uses for its capital investment decisions.

To the extent those changes result in a significant reduction to its oil prices or natural gas prices or margin ranges, the company may consider that situation, in conjunction with other events or changes in circumstances such as a history of operating losses, as an indicator of potential impairment for certain assets.

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 yearly average of first-day-of-the-month

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.

The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.

This process is aligned with the requirements of ASC 360 and ASC 932

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

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.

Energy Outlook and cash flow assessment

The annual planning and budgeting process, known as the company plan, is the mechanism by which resources (capital, operating expenses and people) are allocated across the company.

The foundation for the energy supply and demand assumptions supporting the company plan begins with Exxon Mobil Corporation’s 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.

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 company’s assumptions which are developed in the annual planning and budgeting process, and are consistent with the criteria management uses to evaluate investment opportunities.

These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices, including price differentials, refining and chemical margins, volumes, development and operating costs, foreign currency exchange rates and inflation rates.

Cash flows used in recoverability assessments are based on the assumptions developed in the company plan, which is reviewed and approved by the board of directors, and are consistent with the criteria management uses to evaluate investment opportunities.

These evaluations make use of the company’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, refining and chemical margins, volumes, development and operating costs, including greenhouse gas emissions prices, and foreign currency exchange rates.

Volumes are based on projected field and facility production profiles, throughput, or sales.

Management’s estimate of upstream production volumes used for projected cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities.

Cash flow estimates for impairment testing exclude the effects of derivative instruments.

The greenhouse gas emission prices reflect existing or anticipated policy actions of applicable provincial and federal governments.

While third-party scenarios, such as the International Energy Agency Net Zero Emissions by 2050

, may be used to test the resiliency of company’s businesses or strategies, they are not used as a basis for developing future cash flows for impairment assessments.

Fair value of impaired assets

An asset group is impaired if its estimated future undiscounted cash flows are less than the asset group’s carrying value.

Impairments are measured by the amount by which the carrying value exceeds fair value.

The assessment of fair value may be based on market prices if an active market exists for the asset group or may require the use of Level 3 inputs and assumptions that are based upon the views of a likely market participant.

The principal parameters used to establish fair value can 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, commodity prices which are consistent with the average of third-party industry experts and government agencies, drilling and development costs, and discount rates.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs would be recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties.

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.

Other impairment estimates

Unproved properties are assessed periodically to determine whether they have been impaired.

Significant unproved properties are assessed for impairment individually, and valuation allowances against the capitalized costs are recorded based on the company’s future development plans, the estimated economic chance of success and the length of time that the company expects to hold the properties.

Properties that are not individually significant are aggregated by groups and amortized based on development risk and average holding period.

In 2020, events or changes in circumstances indicated that the carrying amount of certain of the company’s long-lived assets may not be recoverable.

Those situations primarily related to the annual review and approval of the company’s business and strategic plan.

As part of this process the company assessed its full portfolio of assets which included its unconventional assets.

Subsequently the company announced its decision to not further develop a significant portion of its unconventional portfolio in Alberta which resulted in a non-cash, after-tax impairment charge of $1,171 million in the company’s 2020 Upstream results, thereby reducing the carrying value of those assets to fair value.

For certain other upstream properties, the undiscounted cash flows were compared to the carrying values and no other adjustments were necessary.

Factors which could put further assets at risk of impairment in the future include reductions in the company’s price outlooks, changes in the allocation of capital, and operating cost increases which exceed the pace of efficiencies or the pace of oil and natural gas price increases.

However, due to the inherent difficulty in predicting future commodity prices, 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.

Long-lived assets that are held for sale are evaluated for possible impairment by comparing the carrying value of the asset with its fair value less the cost to sell.

If the net book value exceeds the fair value less cost to sell, the assets are considered impaired and adjusted to the lower value.

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

Investments 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.

Examples of key indicators include a history of operating losses, negative earnings and cash flow outlook, significant downward revisions to oil and gas reserves, and the financial condition and prospects for the investee’s business segment or geographic region.

If the decline in value of the investment is other than temporary, the carrying value of the investment is written down to fair value.

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

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.

However, due to the inherent difficulty in predicting future commodity prices or margins, and the relationship between industry prices and costs, it is not practicable to reasonably estimate the existence or range of any potential future impairment charges related to the company’s long-lived assets.

Supplemental information regarding oil and gas results of operations, capitalized costs and reserves is provided following the notes to consolidated financial statements.

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If different assumptions are used, the obligation and expense could increase or decrease as a result.

As an indication of the company’s potential exposure to changes in the critical assumptions such as the expected rate of return on plan assets and the discount rate for measuring the benefits obligation, a reduction of 1 percent in the discount rate would increase the plan benefits obligation by approximately $2.2 billion.

As an indication of the company’s potential exposure to changes in the critical assumptions such as the expected rate of return on plan assets and the discount rate for measuring the pension plan benefits obligation, a reduction of 1 percent in the discount rate would increase the benefits obligation by approximately $1.8 billion.

Similarly, a reduction of 1 percent in the long-term rate of return on plan assets would increase the annual pension expense by approximately $95 million before tax.

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Employee benefits expense represented about 1 percent of total expenses in 2021.

Asset retirement obligations and other environmental liabilities

Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed.

Asset retirement obligations

The company is subject to retirement obligations for certain assets.

The fair values of these obligations are recorded as liabilities on a discounted basis, which is typically at the time the assets are installed.

In the estimation of fair value, the company uses assumptions and judgments regarding such factors as the existence of a legal obligation for an asset retirement obligation;

technical assessments of the assets;

estimated amounts and timing of settlements;

discount rates;

and inflation rates.

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

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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 2020, the obligations were discounted at 6 percent and the accretion expense was $82 million, before-tax,

which was significantly less than 1 percent of total expenses in the year.

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.

Asset retirement obligations are not recognized for assets with an indeterminate useful life.

Asset retirement obligations for these facilities generally become firm at the time the facilities are permanently shut down and dismantled.

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

However, these sites 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.

For these and non-operating

assets, the company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.

Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location.

Since these estimates are specific to the locations involved, there are many individual assumptions underlying the company’s total asset retirement obligations and provision for other environmental liabilities.

While these individual assumptions can be subject to change, none of them is individually significant to the company’s reported financial results.

On page 94, note 5 to the consolidated financial statements provides a three year continuity table detailing the changes in asset retirement obligations.

Suspended exploratory well costs

The company continues capitalization of exploratory well costs when the well has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The company continues capitalization of exploratory well costs when it has found a sufficient quantity of reserves to justify its completion as a producing well and the company is making sufficient progress assessing the reserves and the economic and operating viability of the project.

Exploratory well costs not meeting these criteria are charged to expense.

Assessing whether the company is making sufficient progress on a project requires careful consideration of the facts and circumstances.

The facts and circumstances that support continued capitalization of suspended wells at year-end

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For a position that is likely to be sustained, the benefit recognized in the financial statements is measured at the largest amount that is greater than 50 percent likely of being realized.

A reserve is established for the difference between a position taken or expected to be taken in an income tax return and the amount recognized in the financial statements.

The company’s unrecognized tax benefits and a description of open tax years are summarized in note 4 to the consolidated financial statements starting on page 88.

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

The company’s unrecognized tax benefits and a description of open tax years are summarized in note 3 to the consolidated financial statements.

Management’s report on internal control over financial reporting

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PricewaterhouseCoopers LLP, an independent registered public accounting firm, audited the effectiveness of the company’s internal control over financial reporting as of December 31, 2021, as stated in their report which is included herein.

/s/ Bradley W.

Chairman, president and

chief executive officer

/s/ Daniel E.

Chairman, president and chief executive officer

(Principal executive officer)

Senior vice-president,

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Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that (i) relate to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

The critical audit matter communicated below is a matter arising from the current period audit of the consolidated financial statements that was communicated or required to be communicated to the audit committee and that (i) relates to accounts or disclosures that are material to the consolidated financial statements and (ii) involved our especially challenging, subjective, or complex judgments.

The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

The Impact of Proved Oil and Natural Gas Reserves on Upstream Property, Plant and Equipment, Net

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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.

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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.

Impairment assessment of certain upstream property, plant and equipment, net

As described in Notes 1 and 3 to the consolidated financial statements, the Company’s upstream property, plant and equipment (PP&E), net balance was $28,907 million as of December 31, 2020.

If events or changes in circumstances indicate that the carrying value of an asset may not be recoverable, management 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 cash flows of other groups of assets.

These estimates of the future undiscounted cash flows make use of management’s assumptions of future capital allocations, crude oil and natural gas commodity prices including price differentials, upstream production volumes, development and operating costs, foreign currency exchange rates and inflation rates.

Management’s estimate of upstream production volumes used for undiscounted cash flows makes use of proved reserve quantities and may include risk-adjusted unproved reserve quantities.

As further disclosed by management, estimates of upstream production volumes 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).

An asset group is impaired if its estimated 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.

The principal considerations for our determination that performing procedures relating to the impairment assessment of certain 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 future undiscounted cash flows, which in turn led to (ii) a high degree of auditor judgment, subjectivity, and effort in performing procedures and evaluating management’s significant assumptions related to crude oil and natural gas commodity prices including price differentials, upstream production volumes, and development costs, as applicable.

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

These procedures included testing the effectiveness of controls relating to management’s upstream PP&E, net impairment assessment over proved properties.

These procedures also included, among others (i) testing management’s process for assessing the recoverability of carrying amounts of upstream PP&E, net;

(ii) evaluating the appropriateness of the undiscounted cash flow models;

(iii) testing the completeness and accuracy of underlying data used in the models;

and (iv) evaluating the reasonableness of significant assumptions used by management related to crude oil and natural gas commodity prices including price differentials, upstream production volumes, and development costs.

Evaluating the reasonableness of management’s assumptions related to future crude oil and natural gas commodity prices including price differentials involved comparing the assumption against observable market data.

Evaluating development costs involved evaluating the reasonableness of the assumptions as compared to the past performance of the Company and its business and strategic plan.

The work of management’s specialists was used in performing the procedures to evaluate the reasonableness of upstream production volumes.

As a basis for using this work, management’s specialists’ qualifications were understood and the Company’s relationship with management’s specialists was assessed.

The procedures performed also included evaluation of the methods and assumptions used by management’s specialists, tests of the data used by management’s specialists, and an evaluation of management’s specialists’ findings.

PricewaterhouseCoopers LLP

/s/ PricewaterhouseCoopers LLP

Chartered Professional Accountants

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Current assets

Accounts receivable - net (a) (note 2)

Accounts receivable - net (a)

Inventories of crude oil and products (note 11)

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Total current assets

Investments and long-term receivables (b) (note 2)

Investments and long-term receivables (b)

Property, plant and equipment,

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Total liabilities

Commitments and contingent liabilities

Commitments and contingent liabilities (note 9)

Shareholders’ equity

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Approved by the directors.

/s/ Bradley W.

Chairman, president and

chief executive officer

/s/ Daniel E.

Senior vice-president,

chief executive officer

finance and administration, and controller

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Dividends declared

Cumulative effect of accounting change (note 2)

Cumulative effect of accounting change

At end of year

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Investing activities

Additions to property, plant and equipmen t

Additions to property, plant and equipment

Proceeds from asset sales (note 8)

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Notes to consolidated financial statements

The accompanying consolidated financial statements and the supporting a

nd supplemental material are the responsibility of the management of Imperial Oil Limited.

The company’s principal business is energy, involving the exploration for, and production of, crude oil and natural gas and manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products.

The accompanying consolidated financial statements and the supporting and supplemental material are the responsibility of the management of Imperial Oil Limited.

The company’s principal business involves exploration for, and production of, crude oil and natural gas;

manufacture, trade, transport and sale of crude oil, natural gas, petroleum products, petrochemicals and a variety of specialty products;

and pursuit of lower-emission business opportunities including carbon capture and storage, and biofuels.

The consolidated financial statements have been prepared in accordance with United States Generally Accepted Accounting Principles (U.S.

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Actual results could differ from these estimates.

Prior years’ data has been reclassified in certain cases to conform to the 2020 presentation basis.

Prior years’ data have been reclassified in certain cases to conform to the 2021 presentation basis.

All amounts are in Canadian dollars unless otherwise indicated.

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Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies.

Imperial Oil Resources Limited is the only significant subsidiary included in the consolidated financial statements and is wholly owned by Imperial Oil Limited.

The consolidated financial statements also include the company’s share of the undivided interest in certain upstream assets, liabilities, revenues and expenses, including its 70.96 percent interest in the Kearl joint venture and its 25 percent interest in the Syncrude joint venture.

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.

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

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Development costs, including costs of productive wells and development dry holes, are capitalized.

Maintenance and repair costs, including planned major maintenance, are expensed as i n

Maintenance and repair costs, including planned major maintenance, are expensed as incurred.

Improvements that increase or prolong the service life or capacity of an asset are capitalized.

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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.

exploratory drilling and development costs associated with productive depletable extractive properties are amortized using the unit-of-production

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.

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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 2017 and 2018, with the corresponding effect on depreciation expense being immaterial when compared to prior periods.

This approach will also be applied in 2021 and the effect of this approach is anticipated to be immaterial compared to 2020.

For 2019 and 2020, all properties had sufficient reserves at their relevant SEC prices which enabled equitable allocation of cost over the economic lives of the Upstream assets.

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

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Impairment assessment

The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate the carrying amounts may not be recoverable.

The company tests assets or groups of assets for recoverability on an ongoing basis whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable.

Among the events or changes in circumstances which could indicate that the carrying value of an asset or asset group may not be recoverable are the following:

a significant decrease in the market price of a long-lived asset;

A significant adverse change in legal factors or in the business climate that could affect the value, including a significant adverse action or assessment by a regulator;

a significant adverse change in the extent or manner in which an asset is being used or in its physical condition including a significant decrease in current and projected reserve volumes;

a significant adverse change in legal factors or in the business climate that could affect the value, including an adverse action or assessment by a regulator;

an accumulation of project costs significantly in excess of the amount originally expected;

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a current expectation that, more likely than not, a long-lived asset will be sold or otherwise disposed of significantly before the end of its previously estimated useful life.

The company has a robust process to monitor for indicators of potential impairment across its asset groups throughout the year.

This process is aligned with the requirements of ASC 360

and 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.