imo-20221231
UNITED STATES SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549
FORM 10-K
☑ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the fiscal year ended December 31, 2022
or
☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF
THE SECURITIES EXCHANGE ACT OF 1934
For the transition period from to
Commission file number 0-12014
IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)
505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1
(Address of principal executive offices) (Postal Code)
1-800-567-3776
(Registrant’s telephone number, including area code)
Securities registered pursuant to Section 12(b) of the Act:
Title of each class Trading symbol Name of each exchange onwhich registered
None None
Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)
(Title of Class)
Indicate by check mark if the registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Act).
Yes ✓ No......
Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes...... No ✓
Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ✓ No......
Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes ✓ No......
Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer”, “accelerated filer”, “smaller reporting company” and “emerging growth company” in Rule 12b-2 of the Securities Exchange Act of 1934.
Large accelerated filer ✓ Smaller reporting company......
Accelerated filer..... Emerging growth company......
Non-accelerated filer.....
If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act......
Indicate by check mark whether the registrant has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report. ✓
Indicate by check mark whether the registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934). Yes..... No ✓
As of the last business day of the 2022 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $11,744,615,092 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.
The number of common shares outstanding, as of February 8, 2023, was 584,152,718.
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Table of contents Page
PART I 5
Item 1. Business 5
Upstream 6
Disclosure of reserves 6
Proved undeveloped reserves 7
Oil and gas production, production prices and production costs 8
Drilling and other exploratory and development activities 10
Present activities 12
Delivery commitments 12
Oil and gas properties, wells, operations and acreage 13
Downstream 15
Supply and trading 15
Transportation 15
Refining 15
Distribution 15
Marketing 16
Chemical 16
Human capital resources 17
Competition 17
Government regulations 18
The company online 20
Item 1A. Risk factors 21
Item 1B. Unresolved staff comments 30
Item 2. Properties 30
Item 3. Legal proceedings 30
Item 4. Mine safety disclosures 30
Item 7A. Quantitative and qualitative disclosures about market risk 32
Item 8. Financial statements and supplementary data 33
Item 9A. Controls and procedures 33
Item 9B. Other information 33
Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections 33
PART III 34
Item 10. Directors, executive officers and corporate governance 34
Item 11. Executive compensation 34
Item 14. Principal accountant fees and services 37
Item 15. Exhibits, financial statement schedules 38
SIGNATURES 40
Financial section 41
Proxy information section 111
All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated. Note that numbers may not add due to rounding.
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Forward-looking statements
Statements of future events or conditions in this report, including projections, targets, expectations, estimates, and business plans are forward-looking statements. Similarly, discussion of emission-reduction roadmaps or future plans related to carbon capture, biofuel, hydrogen, plastics recycling and other plans to drive towards net -zero emissions are dependent on future market factors, such as continued technological progress and policy support, and represent forward-looking statements. Forward-looking statements can be identified by words such as believe, anticipate, intend, propose, plan, goal, seek, project, predict, target, estimate, expect, strategy, outlook, schedule, future, continue, likely, may, should, will and similar references to future periods. Forward-looking statements in this report include, but are not limited to, references to estimates, development, timing and recovery of reserves; the improvement of recovery through experimental operations; the infill development drilling program at Cold Lake; the timing, cost, efficiency and production of the Leming and SAGD Grand Rapids Phase 1 and LASER projects at Cold Lake and the Aspen project; the continued evaluation of other oil sands leases and unconventional assets; the upstream focus on key oil sands assets; future activities with respect to Beaufort Sea licences; the impact of the Kearl Boiler Flue Gas heat recovery unit, and progressing plans for application to up to four additional boilers by year end 2023; the ability of rail infrastructure to mitigate pipeline capacity constraints; human capital resources strategy and impact; anticipated capital and operating expenditures, including with respect to environmental protection; continued evaluation of the company’s share purchase program; being well positioned to participate in future investments and reduce commodity price risk; the company’s long-term business outlook including demand, supply and energy mix and pathways related to greenhouse gas emissions; the impact of participation in the Pathways alliance; Imperial’s company-wide net-zero goal by 2050 (Scope 1 and 2) and the company’s greenhouse gas emissions intensity goal for 2030 for its oil sands operations; the extent of ongoing effects of current global economic uncertainty and geopolitical events affecting supply and demand, including inflation, and the company’s ability to mitigate cost impacts and offset inflationary pressure; segment growth, competitive strategies and benefits from an integrated business model; the ability of the company’s current investment strategy of value and select volume growth to deliver robust returns and support long term growth; continued evaluation of opportunities such as rail shipments and pace of the Aspen project; the impact of Downstream strategies and competitive position and the expected volatility of refining margins; potential impacts from environmental risks, carbon policy, climate related regulations and biofuels mandates; the timing and production from the renewable diesel facility at Strathcona; the benefits to the Chemical business from integration with the Sarnia refinery and relationship with ExxonMobil; capital structure and financial strength as a competitive advantage, for risk mitigation and meeting funding requirements; expected full year capital expenditures of about $1.7 billion for 2023; earnings sensitivities; risks associated with use of derivative instruments; the impact of any pending litigation, accounting standards and unrecognized tax benefits; standardized measures of discounted future cash flows; the effectiveness of the company’s compensation plan in long term performance and mitigating risk; the progress and impact of various initiatives including with E3 Lithium, Air Products, FLO and Atura Power; and the impact of the Sarnia products pipeline.
Forward-looking statements are based on the company’s current expectations, estimates, projections and assumptions at the time the statements are made. Actual future financial and operating results, including expectations and assumptions concerning future energy demand, supply and mix; commodity prices and foreign exchange rates; production rates, growth and mix across various assets; production life, resource recoveries and reservoir performance; project plans, timing, costs, technical evaluations and capacities, and the company’s ability to effectively execute on these plans and operate its assets, including its investment in the renewable diesel complex at Strathcona and the Leming, Grand Rapids and LASER projects at Cold Lake; the adoption and impact of new facilities or technologies on reductions to GHG emissions intensity, including technologies using solvents to replace energy intensive steam at Cold Lake, boiler flue gas technology at Kearl, Strathcona renewable diesel, carbon capture and storage including in connection with hydrogen for the renewable diesel project, recovery technologies and efficiency projects and any changes in the scope, terms, or costs of such projects; that any required support from policymakers and other stakeholders for various new technologies such as carbon capture and storage will be provided; for renewable diesel, the availability and cost of locally-sourced and grown feedstock and the supply of renewable diesel to British Columbia in connection with its low-carbon fuel legislation; the amount and timing of emissions reductions, including the impact of lower carbon fuels; performance of third party service providers; receipt of regulatory and third party approvals in a timely manner; applicable laws and government policies, including with respect to climate change, GHG emissions reductions and low carbon fuels; refinery utilization and product sales; the ability to offset any ongoing inflationary pressures; cash generation, financing sources and capital structure, such as dividends and shareholder returns, including the timing and amounts of share repurchases; progression of COVID-19 and its impacts on Imperial’s ability to operate its assets; capital and environmental expenditures; the capture of
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efficiencies within and between business lines and the ability to maintain near-term cost reductions as ongoing efficiencies; and general market conditions could differ materially depending on a number of factors.
These factors include global, regional or local changes in supply and demand for oil, natural gas, petroleum and petrochemical products, feedstocks and other market factors, economic conditions or seasonal fluctuations and resulting demand, price, differential and margin impacts; transportation for accessing markets; political or regulatory events, including changes in law or government policy, applicable royalty rates, tax laws including taxes on share buybacks, and actions in response to COVID-19; environmental risks inherent in oil and gas activities; environmental regulation, including climate change and greenhouse gas regulation and changes to such regulation; government policies supporting lower carbon investment opportunities; failure or delay of supportive policy and market development for emerging lower-emission energy technologies; the receipt, in a timely manner, of regulatory and third-party approvals; third-party opposition to company and service provider operations, projects and infrastructure; availability and allocation of capital; availability and performance of third-party service providers; unanticipated technical or operational difficulties; management effectiveness and disaster response preparedness; commercial negotiations; project management and schedules and timely completion of projects; unexpected technological developments; the results of research programs and new technologies, including with respect to greenhouse gas emissions, and the ability to bring new technologies to commercial scale on a cost-competitive basis; reservoir analysis and performance; the ability to develop or acquire additional reserves; operational hazards and risks; cybersecurity incidents; currency exchange rates; the impacts of COVID-19 or other public health crises, including the effects of government responses on people and economies; general economic conditions, including the occurrence and duration of economic recessions or downturns; and other factors discussed in Item 1A Risk factors and Item 7 Management’s discussion and analysis of financial condition and results of operations in this annual report on Form 10-K.
Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Imperial Oil Limited. Imperial’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them. Imperial undertakes no obligation to update any forward-looking statements contained herein, except as required by applicable law.
Forward-looking and other statements regarding Imperial's environmental, social and other sustainability efforts and aspirations are not an indication that these statements are necessarily material to investors or requiring disclosure in the company's filings with securities regulators. In addition, historical, current and forward-looking environmental, social and sustainability-related statements may be based on standards for measuring progress that are still developing, internal controls and processes that continue to evolve, and assumptions that are subject to change in the future, including future rule-making.
Energy demand models are forward-looking by nature and aim to replicate system dynamics of the global energy system, requiring simplifications. The reference to any scenario in this report, including any potential net-zero scenarios, does not imply Imperial views any particular scenario as likely to occur. In addition, energy demand scenarios require assumptions on a variety of parameters. As such, the outcome of any given scenario using an energy demand model comes with a high degree of uncertainty. For example, the International Energy Agency (IEA) describes its Net Zero Emissions (NZE) by 2050 scenario as extremely challenging, requiring unprecedented innovation, unprecedented international cooperation and sustained support and participation from consumers. Third-party scenarios discussed in this report reflect the modeling assumptions and outputs of their respective authors, not Imperial, and their use by Imperial is not an endorsement by the company of their underlying assumptions, likelihood or probability. Investment decisions are made on the basis of Imperial’s separate planning process. Any use of the modeling of a third-party organization within this report does not constitute or imply an endorsement by Imperial of any or all of the positions or activities of such organization.
The term “project” as used in this report can refer to a variety of different activities and does not necessarily have the same meaning as in any government payment transparency reports.
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PART I
Item 1. Business
Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1. Exxon Mobil Corporation (“ExxonMobil”) owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to the “company” or “Imperial” includes Imperial Oil Limited and its subsidiaries, and reference to ExxonMobil includes Exxon Mobil Corporation and its affiliates, as appropriate.
The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner, a leading marketer of petroleum products, and a major producer of petrochemicals. The company also pursues lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels.
The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic crude oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals.
Operating data and financial information about the company’s business segments are contained in this report under the following: “Management’s discussion and analysis of financial condition and results of operations” and the “Financial section” under note 2 to the consolidated financial statements: “Business segments”.
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Upstream
Disclosure of reserves
Summary of oil and gas reserves at year-end
The table below summarizes the net proved reserves for the company, as at December 31, 2022, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 41 of this report.
All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the first-day-of-the-month price for each month during the last 12-month period ending December 31. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2022 that would cause a significant change in the estimated proved reserves as of that date.
Liquids (a) Natural gas Synthetic crude oil Bitumen Totaloil-equivalentbasis
Net proved reserves:
The estimation of proved reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of well information such as flow rates and reservoir pressures, and development and production costs, and other factors. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects.
Technologies used in establishing proved reserves estimates
Imperial’s proved reserves in 2022 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results.
Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages.
In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.
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Preparation of reserves estimates
Imperial has a dedicated reserves management group that is separate from the base operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with the U.S. Securities and Exchange Commission rules and regulations, review of annual changes in reserves estimates and the reporting of Imperial’s proved reserves. This group also maintains the official reserves estimates for Imperial’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial.
The reserves management group maintains a central database containing the company’s official reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long standing approval guidelines. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors.
The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has 20 years of petroleum industry experience, including 11 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 20 persons with an average of 14 years of relevant technical experience in evaluating reserves, of whom 18 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 15 persons with an average of 11 years of relevant experience in evaluating and managing the evaluation of reserves.
Proved undeveloped reserves
As at December 31, 2022, approximately 11 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 240 million oil-equivalent barrels. Proved undeveloped reserves are associated with Syncrude and Cold Lake. This compared to 386 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2021. The decrease of 146 million oil-equivalent barrels of proved undeveloped reserves includes a decrease of 133 million oil-equivalent barrels at Cold Lake associated with a shift of future development from the traditional Cyclic Steam Stimulation (CSS) to lower emissions intensity, solvent based technologies, a decrease of 7 million oil-equivalent barrels at Syncrude, and a decrease of 6 million oil-equivalent barrels due to the Montney and Duvernay unconventional assets sale. No proved undeveloped reserves were converted into proved developed reserves during 2022.
Proved undeveloped reserves that have remained undeveloped for five years or more represent about 6 percent (14 million oil-equivalent barrels) of proved undeveloped reserves and are associated with ongoing development programs at Cold Lake. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the asset. The company is reasonably certain that these proved reserves will be produced; however the timing and amount recovered can be affected by a number of factors including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels.
One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $167 million during the year to progress the development of proved undeveloped reserves at Cold Lake and Syncrude. These investments represented about 15 percent of the $1,128 million in total reported Upstream capital and exploration expenditures.
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Oil and gas production, production prices and production costs
Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 47 of this report for a narrative discussion on the material changes.
Average daily production of oil
The company’s average daily oil production by final products sold during the three years ended
December 31, 2022 was as follows. All reported production volumes were from Canada.
Bitumen:
Synthetic crude oil (d): - gross (b) 77 71 69
Liquids (e): - gross (b) 9 11 13
Average daily production and production available for sale of natural gas
The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2022 are set forth below. All reported production volumes were from Canada and are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 47 of this report for a narrative discussion on the material changes.
Net production available for sale (f) 50 81 115
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Total average daily oil-equivalent basis production
The company’s total average daily production expressed in an oil-equivalent basis is set forth below, with natural gas converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
Total production oil-equivalent basis:
Average unit sales price
The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2022 were as follows.
Canadian dollars per thousand cubic feet
(a)Liquids include crude oil, condensate and NGLs.
In 2022, Imperial's average Canadian dollar realization for bitumen increased generally in line with Western Canada Select (WCS). The company's average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs and reflect a premium over WTI driven by supply and demand.
In 2021, Imperial’s average Canadian dollar realizations for bitumen increased generally in line with Western Canada Select (WCS). The company’s average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs.
Average unit production costs
(a)Includes liquids, bitumen, synthetic crude oil and natural gas.
In 2022, bitumen unit production costs increased, primarily driven by higher energy costs.
In 2022, synthetic crude oil unit production costs increased, primarily driven by higher energy costs.
In 2021, bitumen unit production costs increased, primarily driven by higher energy costs.
In 2021, synthetic crude oil unit production costs increased, primarily driven by higher maintenance costs and mine tailings spend.
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Drilling and other exploratory and development activities
The company has been involved in the exploration for and development of crude oil and natural gas in Canada only.
Wells drilled
The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2022.
Net productive exploratory — — —
Net dry exploratory — — —
Net productive development 24 13 29
Net dry development — — —
In 2022, wells drilled to add productive capacity include 24 development wells at Cold Lake.
In 2021, wells drilled to add productive capacity include 12 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets.
In 2020, wells drilled to add productive capacity include 28 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets.
Wells drilling
At December 31, 2022, the company was drilling the following development wells to add productive capacity at Cold Lake. All wells were located in Canada.
Wells Gross Net
Exploratory and development activities regarding oil and gas resources
Cold Lake
To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. In 2022, additional wells were drilled on existing phases. In 2023, an infill development drilling program is planned within the approved development area to add productive capacity. Additionally, in 2022, the company approved the budget for the Leming steam-assisted gravity drainage (SAGD) project that will re-develop the original pilot area of the Cold Lake field, with development activities to commence in 2023 and start-up planned in 2024.
The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.
Aspen, Cold Lake expansion and other oil sands activities
In October 2018, the company received regulatory approval for the Aspen solvent-assisted, steam-assisted gravity drainage (SA-SAGD) project from the Alberta Energy Regulator. Development was proposed to occur in two phases, each producing about 75,000 barrels per day, before royalties. The first phase of the project was approved by the company’s board, and appropriated for $2.6 billion. Construction began late in the fourth quarter of 2018. In March 2019, the company slowed the pace of development given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. Although the Government of Alberta repealed the regulatory authority for imposing temporary production curtailments at the end of 2021, major investment remains on hold. Aspen’s project pace will continue to be evaluated and remains an important opportunity for Imperial.
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In August 2018, Imperial received regulatory approval from the Alberta Energy Regulator for an expansion project at Cold Lake to develop the Grand Rapids interval using SA-SAGD technology, capable of producing 50,000 barrels per day before royalties. Imperial intends to develop the Grand Rapids reservoir through capital-efficient investments that make use of available steam capacity from existing plants, with the initial phase of Grand Rapids development planned as an extension from the Nabiye plant. In April 2022, the Grand Rapids Phase 1 (GRP1) project was approved by the company's board with a forecasted average production of 15,000 barrels per day before royalties. Development activities are planned to be completed by year-end 2023.
Work progresses on technical and technology evaluations to support potential Clarke Creek, Corner, Clyden and Chard in-situ development regulatory applications.
The company also has interests in other oil sands leases in the Athabasca region of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development.
Montney and Duvernay
The company owned a 50 percent interest in XTO Energy Canada, which included Montney and Duvernay unconventional assets located in central Alberta. On August 31, 2022, jointly with ExxonMobil Canada, Imperial sold its interests in XTO Energy Canada to Whitecap Resources Inc. The sale completed the marketing effort announced in January 2022, and is consistent with Imperial’s strategy to focus upstream resources on key oil sands assets and its commitment to deliver long-term value to shareholders. The assets included 567,000 net acres in the Montney shale, 72,000 net acres in the Duvernay shale and additional acreage in other areas of Alberta. Net production from these assets was about 140 million cubic feet of natural gas per day and about 9,000 barrels of crude, condensate and natural gas liquids per day.
The sale of the assets followed the company's ramp down of drilling activity and adjustment of long-term development plans in 2020 and 2021.
Beaufort Sea
The company holds a 25 percent interest in two exploration licences in the Beaufort Sea. In 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences were not impacted. In June 2019, the Federal Government approved selective changes to the Canada Petroleum Resources Act to prohibit and freeze the existing licences through the completion of the Beaufort Regional Strategic Environmental Assessment (BR-SEA) review. In 2022, the prohibition was extended to December 31, 2023 with a second one-year extension. During this time, the Federal Government plans to finalize the BR-SEA for public release which will be subject to a stakeholder review period that will aim to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic. The company continues to hold the licences while maintaining community engagement and participation in the BR-SEA process.
Exploratory and development activities regarding oil and gas resources extracted by mining methods
The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region.
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Present activities
Review of principal ongoing activities
Kearl
Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail.
During 2022, the company’s share of Kearl’s net bitumen production was about 157,000 barrels per day and gross production was about 172,000 barrels per day.
Total gross production for Kearl was about 242,000 barrels per day (172,000 barrels Imperial’s share), down 21,000 barrels per day (14,000 barrels Imperial's share) compared to 2021, as a result of extreme cold weather impacts in the first quarter of 2022.
In 2022, the company successfully completed the startup of the second Boiler Flue Gas Unit, incorporating learnings from the first unit's startup in 2021. This technology recovers waste heat from a boiler’s combustion exhaust to pre-heat process water. Each unit has the potential to reduce operating costs and emissions. Imperial is currently progressing plans to apply this innovative technology on up to four additional boilers by year-end 2023.
Cold Lake
Cold Lake is an in-situ heavy oil bitumen operation. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.
During 2022, net bitumen production at Cold Lake was about 106,000 barrels per day and gross production was about 144,000 barrels per day. Gross production increased about 4,000 barrels per day compared to 2021 as a result of improved reliability, production optimizations, and recent capital-efficient infill drilling.
Cold Lake has expanded its commercial application of Liquid Addition to Steam for Enhanced Recovery (LASER), with the technology now being applied to approximately 10 per cent of production, resulting in reduced greenhouse gas emissions compared to traditional CSS technology.
Syncrude
Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties.
In 2022, the company’s share of Syncrude’s net production was about 63,000 barrels per day. The gross production was about 77,000 barrels per day, which is an increase of about 6,000 barrels per day compared to 2021, supported by the interconnect pipeline.
The Province of Alberta, in its capacity as lessor of Kearl, Cold Lake, and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil.
Delivery commitments
The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.
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Oil and gas properties, wells, operations and acreage
Production wells
The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2022 and December 31, 2021, is set forth in the following table. The statistics in the table are determined in part from information received from other operators. The total number of wells decreased in 2022 primarily due to divestment activities and the shut-in of multiple non-economical wells.
Crude oil Natural gas Crude oil Natural gas
wells Gross (a) Net (b) Gross (a) Net (b) Gross (a) Net (b) Gross (a) Net (b)
Land holdings
At December 31, 2022 and December 31, 2021, the company held the following oil and gas rights, and bitumen and synthetic crude oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.
Developed Undeveloped Total
Western provinces (a):
Canada lands (d):
Atlantic offshore:
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Western provinces
The company’s bitumen leases include about 161,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 68,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 173,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area, about 30,000 net acres of oil sands leases in the Corner area, about 29,000 net acres in the Clarke Creek area and about 18,000 net acres in the Chard area. The 173,000 net acres are suitable for in-situ recovery techniques.
The company’s share of Syncrude joint venture leases covering about 55,000 net acres accounts for the entire synthetic crude oil acreage.
Oil sands leases have an exploration period of 15 years and are continued beyond that point by payment of escalating rentals or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production.
The company holds interests in an additional 395,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2022, the company divested its interest in Horn River totalling about 103,000 net acres and its interest in XTO Energy Canada totalling about 365,000 net acres.
Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability.
Canada lands
Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres.
Exploration licences on Canada lands have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions.
The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs.
Atlantic offshore
Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production licences or held by SDLs.
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Downstream
Supply and trading
The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices, in addition to undertaking trading activities. Purchases and sales are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.
Transportation
Imperial currently transports the company’s crude oil production and third-party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal has total capacity to ship up to 210,000 barrels per day of crude oil.
Refining
The company owns and operates three refineries, which process predominantly Canadian crude oil. The company purchases finished products to supplement its refinery production.
The approximate average daily volumes of refinery throughput and utilization during the three years ended December 31, 2022, and the daily rated capacities of the refineries as at December 31, 2022, were as follows.
Refinery throughput (a) Rated capacities (b)
Year ended December 31 at December 31
Utilization of refinery capacity (percent) 98 89 80
2022
Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity.
2021
Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partially offset by a planned turnaround at Strathcona.
Distribution
The company maintains a nationwide distribution system to move petroleum products to market by pipeline, tanker, rail and road transport. The company owns and operates fuel terminals across the country, as well as natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products pipeline companies.
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Marketing
The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.
Imperial supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2022, there were about 2,400 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby Imperial supplies fuel to independent third parties.
Imperial also sells petroleum products, including fuel, asphalt and lubricants, to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded fuel and lubricant resellers.
The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2022, are set out in the following table.
Lube oils and other products 47 45 40
In 2022, improved petroleum product sales primarily reflects increased demand.
In 2021, improved petroleum product sales primarily reflects reduced impacts associated with the COVID-19 pandemic.
Chemical
The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates, polyethylene resin, and markets refinery grade propylene. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery.
The company’s total petrochemical sales volumes during the three years ended December 31, 2022, were as follows.
In 2022, sales volumes increased primarily due to higher sales of propylene and polyethylene, partially offset by lower intermediates.
In 2021, sales volumes increased primarily due to higher sales of intermediates and aromatics.
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Human capital resources
Imperial operates in a complex, competitive and changing business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the company’s philosophy on talent development.
Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of our business across the business cycle. The company’s compensation is market competitive, long-term oriented, and highly differentiated by individual performance. In addition, benefits and workplace programs support the company’s talent management approach, and are designed to attract and retain employees for a long-term career. Overall, this multifaceted approach has resulted in strong employee retention.
Imperial views diversity as an opportunity. The company encourages and respects diversity of thought, ideas, and perspective in its workforce. The company considers diversity through all stages of employment including recruitment, training and development of its employees. Imperial’s goal is to reflect the mix and diversity of the communities where it operates, and it continues to focus on diverse representation at all levels of the organization.
The number of regular employees was about 5,300 at the end of 2022 (2021 - 5,400, 2020 - 5,800). Regular employees are defined as active executive, management, professional, technical and wage employees who work full-time or part-time for the company and are covered by the company’s benefit plans and programs.
Competition
The Canadian energy and petrochemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The energy and petrochemical industries also compete with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. Certain industry participants, including Imperial, are expanding investments in lower-emission energy and emission-reduction services and technologies.
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Government regulations
Petroleum, natural gas and oil sands rights
Most of the company’s petroleum, natural gas and oil sands rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum, natural gas and / or oil sands on the leased lands for a specified period.
In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production.
The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land.
Project approval
Approvals and licences from relevant provincial or federal governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes.
Approval of large energy projects may be impacted by the environmental assessment framework under Canada's Impact Assessment Act (IAA). The IAA includes broader consideration for social, health, and gender-based impacts, the impact on Canada’s climate change commitments (including a requirement under the Strategic Assessment for Climate Change to provide a credible plan for the project to deliver net-zero greenhouse gas emissions by 2050), reliance on strategic and regional assessments and adjusted regulatory review timelines.
Environmental protection
The company regards protecting the environment in connection with its various operations as a priority. The company is subject to extensive environmental regulations in Canada that apply to all phases of exploration, development, operation, and final closure. These requirements cover the management and monitoring of potential environmental impacts during active operations, including practices for land disturbance, wildlife protection, specifications for equipment operation and material storage and limitations on discharges to the environment. It also includes conducting environmental surveys and collecting continuous operational measurements and sampling to confirm that environmental practices are adequately protecting the environment. These regulations also specify the actions and requirements for final reclamation, abandonment and closure of facilities. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. The company also maintains extensive operating procedures, processes and emergency response plans to address environmental risks at its operations.
As discussed in Item 1A. “Risk factors” in this report, compliance with existing and potential future government regulations, including environmental regulations, may have material effects on the capital expenditures, earnings, and competitive position of the company. Imperial takes new and ongoing measures throughout its operations each year to prevent and minimize the impact of its operations on air, land and water. These include significant investments in refining infrastructure and technology to manufacture clean fuels, continued evaluation and implementation of new technologies to reduce greenhouse gas emissions, adherence to federal and provincial greenhouse gas emissions reduction and reporting programs, enhanced water and land management, and expenditures for asset retirement obligations. In the past five years, the company has made capital and operating expenditures of about $4.5 billion on environmental protection and facilities. In 2022, the company’s environmental capital and operating expenditures totalled approximately $1.4 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Environmental expenditures are expected to increase to approximately $1.8 billion in 2023, with capital expenditures expected to account for approximately 65 percent of the total. Costs for 2024 are anticipated to increase to approximately $2.2 billion, with capital expenditures expected to account for approximately 69 percent of the total.
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Crude oil
Production
The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles.
Additionally, the Government of Alberta has in the past used temporary mandatory production curtailment regulations to impose production limits on large producers in Alberta, such as those implemented in 2019 and repealed in 2021.
Exports
Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the Canada Energy Regulator (CER) and the Government of Canada. Export contracts of less than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require an order from the CER.
Natural gas
Production
The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2022 gas production rates.
Exports
The Government of Canada has the authority to regulate the export price for natural gas. Exports of natural gas from Canada require approval by the CER and the Government of Canada. The Government of Canada allows the export of natural gas by CER order without volume limitation for terms not exceeding 24 months.
Royalties
The Government of Canada and the provinces in which the company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.
Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Kearl, Cold Lake and Syncrude, see “Upstream” section entitled “Present activities” under Item 1 on page 12.
Investment Canada Act
The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.
The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada.
By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians.
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Competition Act
The Competition Bureau seeks to ensure that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the Competition Act (the Act). A merger transaction, whether or not notifiable, is subject to examination by the Commissioner of the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act.
An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. An ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau.
The company online
The company’s website www.imperialoil.ca contains a variety of corporate and investor information free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC. The SEC’s website, www.sec.gov, contains reports, proxy and information statements, interactive data files, and other information regarding issuers that are submitted and posted electronically with the SEC.
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Item 1A. Risk factors
Imperial’s financial and operating results are subject to a variety of risks inherent in oil, gas and petrochemical businesses, and the pursuit of lower-emission business opportunities. Many of these risk factors are not within Imperial’s control and could adversely affect Imperial’s business, financial and operating results, or financial position. These risk factors include:
Supply and demand
The oil, gas, fuels and petrochemical businesses are fundamentally commodity businesses. This means the company’s operations and earnings may be significantly affected by changes in oil, natural gas and petrochemical prices, and by changes in margins on refined products and petrochemicals. Crude oil, natural gas, petrochemical and petroleum product prices and margins depend on local, regional, and global events or conditions that affect supply and demand for the relevant commodity or product. Commodity prices have been volatile, and the company expects that volatility to continue. Any material decline in crude oil prices could have a material adverse effect on Imperial’s Upstream operations, financial position, proved reserves and the amount spent to develop reserves. On the other hand, a material increase in crude oil prices could have a material adverse effect on Imperial’s Downstream margins, depending on the market conditions for refined products. The company's pursuit of lower-emission business opportunities including carbon capture and storage, hydrogen, and lower-emission fuels also depends on the growth and development of markets for those products and services, including implementation of supportive government policies and developments in technology to enable those products and services to be provided on a cost-effective basis at commercial scale. See "Climate change, energy transition and greenhouse gas restrictions" in this Item 1A. The company may also be impacted by changes in other commodities the company utilizes, such as prices and availability of feedstocks for lower-emission fuels including renewable diesel.
Economic conditions
The demand for energy and petrochemicals is generally linked closely with broad-based economic activities and levels of prosperity. The occurrence of recessions or other periods of low or negative economic growth will typically have a direct adverse impact on the company’s results. Other factors that affect general economic conditions such as changes in population growth rates, government regulation or austerity programs, trade tariffs or broader breakdowns in global trade, security or public health issues and responses, the inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, other events or conditions that impair the functioning of financial markets and institutions also pose risks to Imperial.
Other demand-related factors
Factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact Imperial’s results include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for our products, including lower demand for gasoline, impacting Downstream results in the winter; increased competitiveness of, or government policy support for, alternative energy sources; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage that make wind and solar more competitive for power generation; changes in consumer preferences for the company’s products, including consumer demand for alternative fueled or electric transportation or alternatives to plastic products; broad-based changes in personal income levels, interest rates and inflation; and security or public health issues and responses such as epidemics and pandemics. See also “Climate change, energy transition and greenhouse gas restrictions” below.
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Other supply-related factors
Commodity prices and margins also vary depending on a number of factors affecting supply. For example, increased supply from the development of new oil and gas supply sources and technologies to enhance recovery from existing sources tends to reduce commodity prices to the extent such supply increases are not offset by commensurate growth in demand. Similarly, increases in industry refining or petrochemical manufacturing capacity relative to demand tend to reduce margins on affected products. Crude oil, gas and petrochemical supply levels can also be affected by factors that reduce available supplies, such as the level of and adherence by participating countries or others to production quotas established by OPEC or “OPEC+” and other agreements among sovereigns, government policies that restrict oil and gas production or increase associated costs, including actions intended to reduce greenhouse gas emissions and previous Government of Alberta curtailment regulations, the occurrence of wars, hostile actions, natural disasters, trade tariffs or broader breakdowns in global trade, disruptions in competitors’ operations, or unexpected pipeline or rail constraints that may disrupt and have in the past disrupted supplies. For example, Russia's military action in Ukraine has impacted global crude oil and gas supply levels and prices, and continues to contribute to a volatile commodity environment, the duration of which is uncertain. Technological change can also alter the relative costs for competitors to find, produce, and refine oil and gas and to manufacture petrochemicals.
Canadian-specific market factors
The market price for western Canadian heavy crude oil is typically lower than light and medium grades of oil, principally due to the higher transportation and refining costs. Western Canadian crude oil may also be subject to limits on transportation capacity to markets. Future crude price differentials between western Canadian crude oil relative to prices in the U.S. Gulf Coast are uncertain and changes in the heavy or light crude oil differentials could have a material adverse effect on the company’s business. Increased differentials, have in the past, led the Government of Alberta to enact temporary mandatory production curtailment regulations that imposed production limits on large producers in Alberta such as Imperial. Although the regulatory authority to impose curtailments was repealed at the end of 2021, the use of similar curtailment regulations in the future could have an adverse effect on the company’s business. A significant portion of the company’s production is bitumen, which is blended with diluent for transportation and marketability of heavy crude oil. Increases to diluent prices, relative to heavy crude oil prices, could also have an adverse effect on the company’s business.
Other market factors
Market factors may also result in losses from commodity derivatives and other instruments used to hedge price exposures or for trading purposes. Imperial’s future business results, including cash flows and financing needs, will also be affected by the rate of recovery from the COVID-19 pandemic, as well as the occurrence and severity of future outbreaks, the responsive actions taken by governments and others, and the resulting effects on regional and global markets and economies. If the company’s mitigation and response efforts prove insufficient, then large outbreaks of epidemics, pandemics or other health crises such as COVID-19 at operating sites, particularly in remote locations and where work camps are utilized, could materially impact the company’s personnel and its operations, reducing productivity and increasing costs.
Government and political factors
Imperial’s results can be adversely impacted by political, legal or regulatory developments affecting operations and markets. Changes in government policy or regulations, changes in law or interpretation of settled law, challenges to legislative jurisdiction between different levels of government, third-party opposition to company or infrastructure projects, and duration of regulatory reviews could impact Imperial’s existing operations and planned projects. This includes actions by policy-makers, regulators or other actors to delay or deny necessary licences and permits, restrict the availability of oil and gas leases or the operation of third-party infrastructure that the company relies on, such as pipelines to transport the company’s upstream production to market or that supply feedstock to the company’s refineries. Additionally, changes in environmental regulations, assessment processes or other laws and increasing and expanding stakeholder consultation (including Indigenous stakeholders), may increase the cost of compliance or reduce or delay available business opportunities and adversely impact the company’s results.
Other government and political factors that could adversely affect the company’s financial results include increases in taxes or government royalty rates (including retroactive claims) and changes in trade policies and agreements. Changes in taxation policy, such as the Government of Canada announcement in 2022 of a tax on share buybacks, could impact the company’s results and ability to return surplus cash to shareholders. Further, the adoption of regulations mandating efficiency standards, and the use of alternative fuels or uncompetitive fuel components could affect the company’s operations. Many governments are providing tax advantages and other subsidies to support alternative energy sources or are mandating the use of specific fuels or technologies.
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Governments are also introducing bans on certain technologies that could impact demand for products, such as the Government of Canada’s intention to ban the sale of new internal combustion engine cars and light trucks beginning in 2035. Governments and others are also promoting research into new technologies to reduce the cost and increase the scalability of alternative energy sources, and the success of these initiatives may decrease demand for the company’s products. Actions by policy makers, regulators or others may require changes in the company’s business or strategy that could result in reduced returns.
Governments may establish regulations with respect to the control of the company’s production, such as the Government of Alberta's temporary mandatory production curtailment regulations that were in effect from 2019 through 2021, as discussed in the “Supply and demand” section above. Government intervention in free markets may introduce unintended consequences such as market volatility and uncertainty, misallocation of resources, and erosion of investor confidence.
Environmental risks
All phases of the Upstream, Downstream and Chemical businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial, territorial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).
Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances into the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported, and include those aimed at reducing consumption or addressing environmental concerns with certain end products. Changes to these requirements could adversely affect the company’s results by impacting commodity prices, increasing costs and reducing revenues.
Environmental legislation also requires that wells, facility sites and other properties associated with the company’s operations be operated, maintained, monitored, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. This includes the requirement for specific approvals for many areas of interaction with the environment, such as land use, air quality, water use, biodiversity protection and waste, including mine tailings management. The failure to operate as anticipated and adhere to conditions, the delay or denial of approvals and changes to conditions or regulations could impact the company’s ability to operate its projects and facilities and adversely affect the company’s results.
Regulation of air, water and land
The implementation of, and compliance with, policies and regulations related to air, water and land, such as Alberta’s Lower Athabasca Regional Plan and Wetland Policy applicable to the company’s oil sands assets, could restrict development in current and future areas of operation. The company also depends on water obtained under licences for withdrawal, storage, reuse and discharge in both its Upstream and Downstream businesses, including future projects and expansions. Water use may be limited by regulatory requirements, seasonal fluctuations, competing demands, environmental sensitivities, increasingly stringent water management standards, and changes to conditions or availability of licences, which may restrict and adversely affect the company’s operations. Additionally, a number of air quality regulations and frameworks are being developed and implemented at the federal and provincial levels, including sulphur dioxide limits for refineries in Ontario, and could impact existing and planned operations and projects through increased capital and operating expenses including retrofits to existing equipment, and could adversely impact the company’s operations and financial results.
Regulation of wildlife
Federal and provincial legislation aimed at protecting sensitive, threatened or endangered wildlife, such as woodland caribou and species of migratory birds, may also increase restoration and offset costs and impact the company’s projects. If it is determined that such wildlife and their habitat are not sufficiently protected, governments or other parties may take actions to limit the pace or ability to develop in areas of Imperial’s current and future projects.
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Regulation of oil sands
The company’s mining operations are subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. Further, the absence or evolving nature of policies and regulations for the timing and closure of tailings ponds, including the approved technologies and methods for closure (such as the use of end pit lakes and water capped tailings), and dam safety directives, regulations, guides and abandonment requirements could have a material impact on conditions for approvals and ultimate mine closure costs. Additionally, successful management and closure requires the release of water to the environment, and although an Alberta water release policy and federal oil sands effluent regulations are being developed, the timing and impact of these regulations is uncertain and the absence of effective regulation could negatively impact the company’s operations and financial results.
Environmental assessments
In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. The Government of Canada's environmental assessment framework under the Impact Assessment Act expands assessment considerations beyond the environment to include social, health, economic, and gender-based impacts and the impact on Canada’s climate change commitments (including a requirement under the Strategic Assessment for Climate Change to provide a credible plan for the project to deliver net-zero greenhouse gas emissions by 2050). It also includes a reliance on strategic and regional assessments and adjusted regulatory review timelines. The impact of this legislation is not fully apparent, but it may impact the cost, manner, duration and ability to advance large energy projects and project expansions.
Compliance costs
Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the cessation of operations, imposition of fines and penalties, and liability for clean-up costs and damages.
The costs of complying with environmental legislation in the future could have a material adverse effect on the company’s financial condition or results of operations. The company anticipates that changes in environmental legislation may require, among other things, reductions in emissions from its operations to the air and water and may result in increased capital expenditures. Changes in environmental legislation (including, but not limited to, application of regulations related to air, water, land, biodiversity and waste, such as mine tailings and the production or use of new or recycled plastics) may increase the cost of compliance or reduce or delay available business opportunities. Future changes in environmental legislation and the enforcement of regulations could occur and result in stricter standards and enforcement, larger fines, penalties and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the company’s financial condition or results of operations.
Risk Management
There are operational risks inherent in oil and gas exploration and production activities, as well as the potential to incur substantial financial liabilities, if the company does not manage those risks effectively. Environmental hazards including severe weather events may impact the company’s operational performance, such as extreme cold weather that makes mining operations more difficult. The ability to insure risks is limited by the capacity of the applicable insurance markets, which may not be sufficient to cover the likely cost of a major adverse operating event. Accordingly, the company’s primary focus is on prevention, including through its rigorous operations integrity management system. The company’s future results will depend on the continued effectiveness of these efforts.
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Climate change, energy transition and greenhouse gas restrictions
Net-zero scenarios
Driven by concern over the risks of climate change, the provinces and the Government of Canada have adopted or have revised regulatory frameworks to reduce greenhouse gas emissions including emissions from the production and use of oil and gas, and their products. These actions are being taken both independently by national and regional governments and within the framework of United Nations Conference of the Parties’ summits under which Canada has endorsed objectives to reduce the atmospheric concentration of CO2 over the coming decades, with an ambition ultimately to achieve “net zero”. Net zero means that emissions of greenhouse gases from human activities would be balanced by actions that remove such gases from the atmosphere. Expectations for transition of the world’s energy system to lower-emission sources, and ultimately net zero, derive from hypothetical scenarios that reflect many assumptions about the future and reflect substantial uncertainties. The company’s actions with respect to the energy transition, including its announced goal, ultimately, to achieve company-wide net-zero emissions (Scope 1 and 2) from its operated assets, carries risks that the transition, including underlying technologies, policies, and markets as discussed in more detail below, will not develop at the pace or in the manner estimated by current net-zero scenarios. The success of Imperial's strategy for the energy transition will also depend on its ability to recognize key signposts of change in the global energy system on a timely basis, and the corresponding ability to direct investment to the technologies and businesses, at the appropriate stage of development, to best capitalize on the company's competitive strengths.
Greenhouse gas restrictions
Government actions intended to reduce greenhouse gas emissions include adoption of carbon emissions pricing, cap and trade regimes, carbon taxes, emissions limits, increased mileage and other efficiency standards, low carbon fuels standards, mandates for sales of electrical vehicles and incentives or mandates for renewable energy. The Government of Canada has updated its nationally determined contribution (NDC) under the Paris Agreement on climate change, to reduce greenhouse gas emissions economy-wide by 40 to 45 percent below 2005 levels by 2030, a substantial increase in ambition beyond its original NDC. To implement these goals, the Government of Canada uses a number of policy tools including the Greenhouse Gas Pollution Pricing Act (GGPPA), which sets a federal backstop carbon price Canada-wide through a carbon levy applied to fossil fuels ($50 per tonne CO2 equivalent emissions starting in 2022 and increasing by $15 per tonne annually to $170 per tonne in 2030), and an output-based pricing system for large industrial emitters. Under the GGPPA, provinces are required to either adopt the GGPPA, or obtain equivalency by adopting a price-based system (with a minimum of the federal carbon pricing) or a cap and trade system. Further, in 2021 the Government of Canada enacted legislation to formalize Canada’s target to achieve net-zero emissions by 2050 and establish interim emissions reductions targets at five year intervals. Under the Canadian Net-Zero Emissions Accountability Act, the Government of Canada is required to develop an emissions reduction plan for 2030 consistent with achieving net-zero emissions by 2050.
The Government of Alberta obtained federal equivalency for its Technology Innovation and Emissions Reduction Regulation (TIER) that came into effect in 2020 and applies to facilities with CO2 emissions in excess of 100,000 tonnes per year. TIER is designed to reduce emissions by putting a price on nominally 10 percent of a facility’s emissions in 2020. This price increased to 11 percent in 2021 and 12 percent in 2022, with the oil sands mining and upgrading facilities increasing to 17 percent in 2021 and 18 percent in 2022, and these percentages are anticipated to increase by 2 percent per year starting in 2023, followed by an increase of 4 percent in 2029 and 2030 for the oil sands sector. Further, the Alberta Oil Sands Emissions Limit Act sets a limit of 100 megatonnes of CO2 per year of emissions in the oil sands sector, but oil sands emissions remain below the limit and it is not yet possible to predict the impact of this act on the company’s future oil sands operations in Alberta. With respect to other provinces, Ontario obtained federal equivalency for its Emissions Performance System, which puts a price on 8 percent of a facility’s emissions, increasing by 2.4 percent in 2023 followed by 1.5 percent in 2024. British Columbia has carbon pricing in place for all emissions, with pricing expected to meet or exceed the federal carbon pricing schedule in 2023. Increases in carbon pricing could adversely impact the company’s operations and financial results unless the company can adapt its operations through technological innovation and investment in a cost-effective manner or meet compliance through offset credits or other mechanisms.
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There are also various low carbon fuel standards being developed or already applicable to the company’s products. In 2022, the Government of Canada finalized draft regulations for the Clean Fuel Regulations, which will require the reduction in carbon intensity of liquid transportation fuels supplied in Canada starting in July 2023. The regulations build upon the existing federal renewable fuels regulations that require fuel producers and importers to have a specified amount of renewable fuel in gasoline and diesel. Similarly, British Columbia introduced a Low Carbon Fuel Standard in 2013, which increased to a 10 percent carbon intensity reduction requirement in 2020. Beginning in 2023, the British Columbia government has further increased the carbon intensity reductions to a total of 30 percent by 2030 (compared to the 2010 baseline). Compliance can be achieved by either blending renewable fuels with low carbon intensity or by purchasing credits.
The Government of Canada's Impact Assessment Act links environmental assessment approvals to climate change-related goals, and has also discussed a goal of establishing legally-binding policies for being carbon-neutral by 2050. Changes and policies related to this act could adversely impact the company’s ability to progress new oil sands projects.
International accords and underlying regional and national regulations covering climate change and greenhouse gas emissions continue to evolve with uncertain timing and outcome, making it difficult to predict their business impact. Such laws and policies could make Imperial’s products more expensive and less competitive, reduce or delay available business opportunities, reduce demand for hydrocarbons, and shift hydrocarbon demand toward lower greenhouse gas emission energy sources. Current and pending greenhouse gas regulations or policies may also increase compliance and abatement costs including taxes and levies, increase abandonment and reclamation obligations and impact decommissioning timelines, lengthen project evaluation and implementation times, impact reserves evaluations and affect operations. Increased costs may not be recoverable in the market place, could negatively affect our returns and could reduce the global competitiveness of the company’s crude oil, natural gas and refined products. Governments may also impose restrictions on production of, or emissions from, oil and gas to the extent they view such measures as a viable approach for pursuing national and global energy and climate policies. For example, the Government of Canada announced its intention to pursue a cap on greenhouse gas emission from oil and gas activities by 2030. Concern over the risks of climate change may lead governments to make laws applicable to the energy industry progressively more stringent over time. Political and other actors and their agents are also increasingly seeking to advance climate change objectives indirectly, such as by seeking to reduce the availability or increase the cost of financing and investment in the oil and gas sector and taking actions intended to promote changes in business strategy for oil and gas companies.
Technology and lower-emission solutions
Achieving societal ambitions to reduce greenhouse gas emissions and ultimately achieve net-zero will require new technologies to reduce the cost and increase the scalability of alternative energy sources as well as technologies such as carbon capture and storage (CCS). CCS technologies, focused initially on capturing and sequestering CO2 emissions from high-intensity industrial activities, can assist in meeting society’s objective to mitigate atmospheric greenhouse gas levels while also helping ensure the availability of the reliable and affordable energy the world requires. The company’s future results and ability to succeed through the energy transition while helping meet Canada's emission-reduction goals and meet its own net-zero and emission reduction goals will depend in part on the success of these research and collaboration efforts. It will also rely on the company’s ability to adapt and apply the strengths of its current business model to providing the energy products of the future in a cost-competitive manner.
Policy and market development
The scale of the world’s energy system means that, in addition to developments in technology discussed above, a successful energy transition will require appropriate support from governments and private participants throughout the global economy. The company’s ability to develop and deploy CCS and other lower-emission energy technologies at commercial scale will depend in part on the continued development of supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained could adversely impact these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without commensurate reduction in demand may have unpredictable adverse effects, including increased commodity price volatility; periods of significantly higher commodity prices and resulting inflationary pressures; and local or regional energy shortages. Such effects in turn may depress economic growth or lead to rapid or conflicting shifts in policy by different actors, with resulting adverse effects on the company’s business.
In addition, the existence of supportive policies in any jurisdiction is not a guarantee that those policies will continue in the future. See also the discussion of “Supply and demand”, “Government and political factors”, and “Management effectiveness” in this Item 1A.
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Currency
Prices for commodities produced by the company are commonly benchmarked in U.S. dollars. The majority of Imperial’s sales and purchases are related to these industry U.S. dollar benchmarks. As the company records and reports its financial results in Canadian dollars, to the extent that the value of the Canadian dollar strengthens, the company’s reported earnings will be negatively affected. The company does not currently make use of derivative instruments to offset exposures associated with foreign currency.
Other business risks
Imperial is reliant on a number of key chemicals, catalysts and third-party service providers, including input and output commodity transportation (pipelines, rail, trucking, marine) and utilities providing services, including electricity and water, to various company operations. The lack of availability, capacity or proximity, with respect to pipeline facilities and railcars, could negatively impact Imperial’s ability to produce at capacity levels. Transportation disruptions, including those caused by events unrelated to the company’s operations, could adversely affect the company’s price realizations, refining operations and sales volumes. This includes outages of key third-party infrastructure, such as pipelines servicing the company’s oil sands assets or pipelines supplying feedstock to its refineries, which could impact the company’s ability to operate its assets or limit the ability to deliver production and products to market. A third-party utilities outage could have an adverse impact on the company’s operations and ability to produce.
The company also enters into contractual relationships with suppliers, partners and other counterparties to procure and sell goods and services, and the company’s operations, market position and financial condition may be adversely impacted if these counterparties do not fulfil their obligations. Imperial may also be adversely affected by the outcome of litigation resulting from its operations or by government enforcement proceedings alleging non-compliance with applicable laws or regulations. Litigation is subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending litigation.
Current and future increases in operating costs such as energy, transportation and materials, including through shipping, supply chain disruptions and inflationary cost pressures, could adversely affect the company’s financial results if it is unable to control or offset these costs. In addition to direct potential impacts on the company's costs and revenues, market factors such as rates of inflation may indirectly impact results to the extent such factors reduce general rates of economic growth and therefore energy demand, as discussed under “Supply and demand". Further, with inflation rising in Canada and other countries throughout 2022, governments have increased interest rates which may further impact the company through the availability of financing, cost of debt, and exchange rate fluctuations. Additional information regarding the potential future impact of market factors on our businesses is included or incorporated by reference under Item 7A Quantitative and qualitative disclosures about market risk in this report.
Operational and other factors
In addition to external economic and political factors, Imperial’s future business results also depend on the company’s ability to manage successfully those factors that are at least in part within its control. The extent to which Imperial manages these factors will impact its performance relative to competition. For projects in which the company is not the operator such as Syncrude, Imperial depends on the management effectiveness of one or more co-venturers whom the company does not control.
Project management
The nature of the company’s Upstream, Downstream and Chemical businesses depend on complex, long-term, and capital intensive projects that require a high degree of project management expertise to maximize efficiency. This includes development, engineering, construction, commissioning and ongoing operational activities and expertise. The company’s results are affected by its ability to develop and operate projects and facilities as planned, and by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the company’s ability to obtain the necessary environmental and other regulatory approvals; changes in regulations; the ability to negotiate successfully with joint venturers, partners, governments, suppliers, customers and others; the ability to model and optimize reservoir performance; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and the company’s ability to respond effectively to unforeseen technical difficulties that could delay project start-up or cause unscheduled downtime.
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Operational efficiency
An important component of Imperial’s competitive performance, especially given the commodity based nature of Imperial’s business, is the ability to operate efficiently, including the company’s ability to manage expenses and improve production yields on an ongoing basis. This requires continuous management focus, including technological improvements, cost control, productivity enhancements and regular reappraisal of the company’s asset portfolio. The company’s operations and results also depend on key personnel and subject matter expertise, the recruitment, development and retention of high caliber employees, and the availability of skilled labour.
Research and development and technical change
Imperial relies upon the research and development organizations of the company and ExxonMobil, with whom the company conducts shared research. Innovation and technology are important to maintain the company’s competitive position, especially in light of the technological nature of Imperial’s business and the need for continuous efficiency improvement.
The company’s research and development organizations must be able to adapt to a changing market and policy environment, including developing technologies to help reduce greenhouse gas emissions intensity. To remain competitive, the company must also continuously adapt and capture the benefits of new technologies including growing the company’s capabilities to utilize digital data technologies to gain new business insights. There are risks associated with projects that rely on new technology, including that the results of implementing the new technology may differ from simulated, piloted or expected results. The failure to develop and adopt new technology may have an adverse impact on the company’s operations, ability to meet regulatory requirements and operational commitments and targets (including environmental sustainability and reduction of greenhouse gas emissions), and financial results.
Safety, business controls and environmental risk management
The scope and nature of the company’s operations present a variety of significant hazards and risks, including operational hazards and risks such as explosions, fires, pipeline ruptures and crude oil spills. Imperial’s operations are also subject to the additional hazards of pollution, releases of toxic gas and environmental hazards and risks, including severe weather (such as extreme cold weather events that impacted the company's oil sands operations in early 2022) and geological events. The company’s results depend on management’s ability to minimize these inherent risks, to effectively control business activities and to minimize the potential for human error. Imperial applies rigorous management systems, including a combined program of effective operations integrity management, ongoing upgrades, key equipment replacements, and comprehensive inspection and surveillance. The company also maintains a disciplined framework of internal controls and applies a controls management system for monitoring compliance with this framework. The company’s upstream and downstream operations may experience loss of production, slowdowns or shutdowns and increased costs due to the failure of interdependent systems, and substantial liabilities and other adverse impacts could result if the company’s management systems and controls do not function as intended.
Cybersecurity
Imperial is regularly subject to attempted cybersecurity disruptions from a variety of sources, including state-sponsored actors. Imperial’s defensive preparedness includes multi-layered technological capabilities for prevention and detection of cybersecurity disruptions: non-technological measures such as threat information sharing with governmental and industry groups; annual internal training and awareness campaigns including routine testing of employee awareness via mock threats; and an emphasis on resiliency including business response and recovery.
If the measures the company is taking to protect against cybersecurity disruptions prove to be insufficient or if the company’s proprietary data is otherwise not protected, the company, as well as its customers, employees or third parties, could be adversely affected. The company is exposed to potential harm from cybersecurity events that may affect the operations of third parties, including our partners, suppliers, service providers (including providers of cloud-based services for our data or applications), and customers. Cybersecurity disruptions could cause physical harm to people or the environment; damage or destroy assets; compromise business systems; result in proprietary information being altered, lost or stolen; result in employee, customer or third-party information being compromised; or otherwise disrupt the company’s business operations. Imperial could incur significant costs to remedy the effects of a major cybersecurity disruption, in addition to costs in connection with resulting regulatory actions, litigation or reputational harm.
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Preparedness
The company’s operations may be disrupted by severe weather events, natural disasters, human error, and similar events. Our facilities are designed, engineered, constructed, and operated to withstand a variety of extreme climatic and other conditions, with safety factors built in to cover a number of uncertainties, including those associated with permafrost stability, temperature extremes, extreme rainfall events, earthquakes and other events. Our consideration of changing weather conditions and inclusion of safety factors in design covers the engineering uncertainties that climate change and other events may potentially introduce. Imperial’s ability to mitigate the adverse impacts of these events depends in part upon the effectiveness of its robust facility engineering, rigorous disaster preparedness and response, and business continuity planning.
Reputation
Imperial’s reputation is an important corporate asset. Factors that could have an impact on the company’s reputation including an operating incident or significant cybersecurity disruption; changes in consumer views concerning the company’s products; a perception by investors or others that insufficient progress is being made with respect to the company’s ambition in the energy transition, or that pursuit of this ambition may result in allocation of capital to investments with reduced returns; and other adverse events such as those described in this Item 1A. Negative impacts on Imperial’s reputation could, in turn, make it more difficult for the company to compete successfully for new opportunities, obtain necessary regulatory approvals, obtain financing, and attract talent, or they could reduce consumer demand for the company’s branded products. Imperial’s reputation may also be harmed by events which negatively affect the image of the industry as a whole, including public and investor perception of Alberta oil sands in relation to greenhouse gas emissions and environmental impact.
Reserves
The company’s future production and cash flows from bitumen, synthetic crude oil, liquids and natural gas reserves are highly dependent upon the company’s success in exploiting its current reserves. To maintain production and cash flows over the long term, the company must replace produced reserves, which can be accomplished through exploration discovery of new resources, appraisal and investments in developing discovered resources, or acquisition of reserves. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the company’s ability to make the necessary capital investments to maintain and grow oil and natural gas reserves will be adversely impacted. In addition, the company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.
Estimates of economically recoverable oil and natural gas reserves and future net cash flows involve many uncertainties, including factors beyond the company’s control. Key factors with uncertainty include: geological and engineering estimates, including that additional information obtained through seismic and drilling programs, reservoir analysis and production and operational history may result in revisions to reserves; the assumed effects of regulation or changes to regulation by government agencies, including royalty frameworks and environmental regulations (such as the regulation of greenhouse gas emissions, including accelerated timelines and emission reduction stringency to meet government goals, which could impose significant compliance costs on the company, require new technology, or impact the economic viability of certain projects); future commodity prices, where low commodity prices may affect reserves development; abandonment and reclamation costs, including reclamation and tailings requirements for mining operations; and operating costs. Actual production, revenues, taxes and royalties, development costs, abandonment and reclamation costs, and operating expenditures, with respect to reserves, will likely vary from such estimates, and such variances could be material.
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Item 1B. Unresolved staff comments
None.
Item 2. Properties
Reference is made to Item 1 above.
Item 3. Legal proceedings
Refer to the relevant portions of note 9. "Litigation and other contingencies" of the “Financial section” of this report for additional information on legal proceedings.
Imperial has elected to use a US $1 million threshold for disclosing environmental proceedings.
Item 4. Mine safety disclosures
Not applicable.
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PART II
Item 5. Market for registrant’s common equity, related stockholder matters and issuer purchases of equity securities
Market information
The company’s common shares are listed and trade on the Toronto Stock Exchange in Canada, and have unlisted trading privileges and trade on the NYSE American LLC in the United States. The symbol for the company’s common shares on these exchanges is IMO.
As of February 8, 2023 there were 9,342holders of record of common shares of the company.
Information for security holders outside Canada
Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian non-resident withholding tax of 15 percent, but may vary from one tax convention to another.
The withholding tax is reduced to 5 percent on dividends paid to a corporation resident in the U.S. that owns at least 10 percent of the voting shares of the company.
The company is a qualified foreign corporation for purposes of the reduced U.S. capital gains tax rates, which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.
There is no Canadian tax on gains from selling shares or debt instruments owned by non-residents not carrying on business in Canada, as long as the shareholder does not, in any given 60 month period, own 25 percent or more of the shares of the company.
Canada has approved several positions with respect to the Multilateral Convention to Implement Tax Treaty Related Measures to Prevent Base Erosion and Profit Shifting (“MLI”), which may impact the taxability of dividends and capital gains in Canada if the shareholder’s country of residence has also approved these same positions of the MLI.
During the fourth quarter, the company did not issue or sell any unregistered equity securities.
Securities authorized for issuance under equity compensation plans
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under the “Company executives and executive compensation”:
•Entitled “Performance graph” within the “Compensation discussion and analysis” section on page 170 of this report; and
•Entitled “Equity compensation plan information”, within the “Compensation discussion and analysis”, on page 176 of this report.
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Issuer purchases of equity securities
(November 1 - November 30) — — — —
The company will continue to evaluate the renewal of its normal course issuer bid share purchase program in June 2023 in the context of its overall capital activities.
Purchase plans may be modified at any time without prior notice.
Item 7. Management’s discussion and analysis of financial condition and results of operations
Reference is made to the section entitled “Management’s discussion and analysis of financial condition and results of operations” in the “Financial section”, starting on page 47 of this report.
Item 7A. Quantitative and qualitative disclosures about market risk
Reference is made to the section entitled “Market risks” in the “Financial section”, starting on page 63 of this report. All statements other than historical information incorporated in this Item 7A are forward-looking statements. The actual impact of future market changes could differ materially due to, among other things, factors discussed in this report.
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Item 8. Financial statements and supplementary data
Reference is made to the table of contents in the “Financial section” on page 41 of this report:
•Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PCAOB ID: 271), Calgary, Canada dated February 22, 2023, beginning with the section entitled “Report of Independent Registered Public Accounting Firm” on page 71 and continuing through note 18, “Divestment activities” on page 106;
•“Supplemental information on oil and gas exploration and production activities” (unaudited) starting on page 107.
Item 9. Changes in and disagreements with accountants on accounting and financial disclosure
None.
Item 9A. Controls and procedures
As indicated in the certifications in Exhibit 31 of this report, the company’s principal executive officer and principal financial officer have evaluated the company’s disclosure controls and procedures as of December 31, 2022. Based on that evaluation, these officers have concluded that the company’s disclosure controls and procedures are effective in ensuring that information required to be disclosed by the company in the reports that it files or submits under the Securities Exchange Act of 1934, as amended, is accumulated and communicated to them in a manner that allows for timely decisions regarding required disclosures and are effective in ensuring that such information is recorded, processed, summarized and reported within the time periods specified in the SEC’s rules and forms.
Reference is made to page 70 of this report for “Management’s report on internal control over financial reporting” and page 71 for the “Report of Independent Registered Public Accounting Firm” on the company’s internal control over financial reporting as of December 31, 2022.
There has not been any change in the company’s internal control over financial reporting during the last fiscal quarter that has materially affected, or is reasonably likely to materially affect, the company’s internal control over financial reporting.
Item 9B. Other information
None.
Item 9C. Disclosure regarding foreign jurisdiction that prevents inspections
Not applicable.
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PART III
Item 10. Directors, executive officers and corporate governance
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
The company currently has seven directors. The articles of the company require that the board have between five and fifteen directors. Each director is elected to hold office until the close of the next annual meeting. Each of the seven individuals listed in the section entitled “Nominees for director” on pages 112 to 116 of this report have been nominated for election at the annual meeting of shareholders to be held May 2, 2023. All of the nominees, with the exception of S.R. Driscoll, J. Floren and G.J. Goldberg, are now directors and have been since the dates indicated. Ms. Driscoll, Mr. Floren and Mr. Goldberg are not currently directors and are being nominated for election as directors at the annual meeting of shareholders for the first time. K.T. Hoeg, J.M. Mintz and D.S. Sutherland are currently directors and are not standing for re-election in 2023 as they have reached the company's mandatory retirement age for directors.
Reference is made to the section under “Nominees for director”:
•“Director nominee tables”, on pages 112 to 116 of this report;
Reference is made to the sections under “Corporate governance disclosure”:
•“Skills and experience of our board members and nominees”, on page 121 of this report.
•“Other public company directorships of our board members and nominees”, on page 125 of this report.
•The table entitled “Audit committee” under “Board and committee structure”, on page 134 of this report;
•“Ethical business conduct”, starting on page 147 of this report; and
•“Largest shareholder”, on page 151 of this report.
Reference is made to the sections under “Company executives and executive compensation”:
•“Named executive officers of the company” and “Other executive officers of the company”, on pages 153 to 154 of this report.
Item 11. Executive compensation
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the sections under “Corporate governance disclosure”:
•“Director compensation”, on pages 139 to 146 of this report; and
•“Share ownership guidelines of independent directors and chairman, president and chief executive officer”, on page 146 of this report.
Reference is made to the following sections under “Company executives and executive compensation”:
•“Letter to shareholders from the executive resources committee on executive compensation”, on page 155 of this report; and
•“Compensation discussion and analysis”, on pages 156 to 178 of this report.
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Item 12. Security ownership of certain beneficial owners and management and related stockholder matters
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Company executives and executive compensation” entitled “Equity compensation plan information”, within the “Compensation discussion and analysis” section, on page 176 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Largest shareholder”, on page 151 of this report.
Reference is also made to the security ownership information for directors and executive officers of the company under the preceding Items 10 and 11. The compensation of the directors and executive officers of the company for the year-ended December 31, 2022 is described in the sections under “Nominees for director” starting on page 112, “Director compensation” starting on page 139 and “Company executives and executive compensation” starting on page 153. The following table shows the number of Imperial Oil Limited and Exxon Mobil Corporation common shares owned and restricted stock units held by each named executive officer, and the incumbent directors and executive officers as a group, as of February 8, 2023.
Imperial Oil Limited Exxon Mobil Corporation
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Item 13. Certain relationships and related transactions, and director independence
Sections of the company’s management proxy circular are contained in the “Proxy information section”, starting on page 111. The company’s management proxy circular is prepared in accordance with Canadian securities regulations.
Reference is made to the section under “Corporate governance disclosure” entitled “Independence of our board members and nominees”, on page 122 of this report.
Reference is made to the section under “Corporate governance disclosure” entitled “Transactions with Exxon Mobil Corporation”, on page 151 of this report.
M.R. Crocker is deemed a non-independent member of the board of directors and the executive resources committee, safety and sustainability committee, nominations and corporate governance committee and community collaboration and engagement committee under the relevant standards. As an employee of Exxon Mobil Corporation, M.R. Crocker is independent of the company’s management and is able to assist these committees by reflecting the perspective of the company’s shareholders.
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Item 14. Principal accountant fees and services
Auditor information
The audit committee of the board of directors recommends that PricewaterhouseCoopers LLP (PwC) be reappointed as the auditor of the company until the close of the next annual meeting. PwC has been the auditor of the company for more than five years and are located in Calgary, Alberta. PwC is a participating audit firm with the Canadian Public Accountability Board and the Public Company Accounting Oversight Board (United States) (PCAOB).
Auditor fees
The aggregate fees of PwC for professional services rendered for the audit of the company’s financial statements and other services for the fiscal years ended December 31, 2022 and December 31, 2021 were as follows:
Audit-related fees 92 92
Tax fees — —
All other fees — —
Audit fees included the audit of the company’s annual financial statements, internal control over financial reporting, and a review of the first three quarterly financial statements in 2022. Audit-related fees consisted of other assurance services including the audit of the company’s retirement plan and royalty statement audits for oil and gas producing entities. The company did not engage the auditor for any other services.
The audit committee formally and annually evaluates the performance of the external auditor, recommends the external auditor to be appointed by the shareholders, recommends their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditor, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditor after considering the effect of such services on their independence.
All of the services rendered by the auditor to the company were approved by the audit committee.
Auditor independence
The audit committee periodically discusses with PwC their independence from the company and from management. PwC have confirmed that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta, the PCAOB and the rules of the SEC. The company has concluded that the auditor’s independence has been maintained.
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PART IV
Item 15. Exhibits, financial statement schedules
Reference is made to the table of contents in the “Financial section” on page 41 of this report.
The following exhibits, numbered in accordance with Item 601 of Regulation S-K, are filed as part of this report:
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(101) Interactive Data Files (formatted as Inline XBRL).
Copies of Exhibits may be acquired upon written request of any shareholder to the vice president, investor relations, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs.
Item 16. Form 10-K summary
Not applicable.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 22, 2023 by the undersigned, thereunto duly authorized.
Imperial Oil Limited
by /s/ Bradley W. Corson
(Bradley W. Corson)
Chairman, president and chief executive officer
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 22, 2023 by the following persons on behalf of the registrant and in the capacities indicated.
Signature Title
(Bradley W. Corson)
(Daniel E. Lyons)
/s/ David W. Cornhill Director
(David W. Cornhill)
/s/ Matthew R. Crocker Director
(Matthew R. Crocker)
/s/ Krystyna T. Hoeg Director
(Krystyna T. Hoeg)
/s/ Miranda C. Hubbs Director
(Miranda C. Hubbs)
/s/ Jack M. Mintz Director
(Jack M. Mintz)
/s/ David S. Sutherland Director
(David S. Sutherland)
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Financial section
Table of contents Page
Financial information (U.S. GAAP) 42
Frequently used terms 43
Overview 47
Business environment 48
Business results 52
Liquidity and capital resources 59
Capital and exploration expenditures 62
Market risks 63
Critical accounting estimates 65
Management’s report on internal control over financial reporting 70
Report of Independent Registered Public Accounting Firm 71
Consolidated statement of income (U.S. GAAP) 74
Consolidated statement of comprehensive income (U.S. GAAP) 75
Consolidated balance sheet (U.S. GAAP) 76
Consolidated statement of shareholders’ equity (U.S. GAAP) 77
Consolidated statement of cash flows (U.S. GAAP) 78
Notes to consolidated financial statements 79
1. Summary of significant accounting policies 79
2. Business segments 85
3. Income taxes 87
4. Employee retirement benefits 88
5. Other long-term obligations 93
6. Financial and derivative instruments 94
7. Share-based incentive compensation programs 96
8. Investment and other income 97
9. Litigation and other contingencies 97
11. Miscellaneous financial information 100
12. Financing and additional notes and loans payable information 101
15. Accounting for suspended exploratory well costs 104
16. Transactions with related parties 105
17. Other comprehensive income (loss) information 106
18. Divestment activities 106
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Financial information (U.S. GAAP)
Net income (loss):
Per share information (Canadian dollars)
Net income (loss) per common share - basic 11.47 3.48 (2.53)
Net income (loss) per common share - diluted 11.44 3.48 (2.53)
Dividends per common share - declared 1.46 1.03 0.88
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Frequently used terms
Listed below are definitions of several of Imperial’s key business and financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated. Certain measures included in this document are not prescribed by U.S. Generally Accepted Accounting Principles (GAAP). These measures constitute “non-GAAP financial measures” under Securities and Exchange Commission Regulation G and Item 10(e) of Regulation S-K, and “specified financial measures” under National Instrument 52-112 Non-GAAP and Other Financial Measures Disclosureof the Canadian Securities Administrators.
Reconciliation of these non-GAAP financial measures to the most comparable GAAP measure, and other information required by these regulations, have been provided. Non-GAAP financial measures and specified financial measures are not standardized financial measures under GAAP and do not have a standardized definition. As such, these measures may not be directly comparable to measures presented by other companies, and should not be considered a substitute for GAAP financial measures.
Capital employed
Capital employed is a non-GAAP financial measure that is a measurement of net investment. When viewed from the perspective of how capital is used by the business, it includes the company’s property, plant and equipment and other assets, less liabilities, excluding both short-term and long-term debt. When viewed from the perspective of the sources of capital employed in total for the company, it includes total debt and equity. The most directly comparable financial measure that is disclosed in the financial statements is total assets within the company’s Consolidated balance sheet. Both of these views include the company’s share of amounts applicable to equity companies, which the company believes should be included to provide a more comprehensive measurement of capital employed.
Reconciliation of capital employed
From the Consolidated balance sheet
Business uses: asset and liability perspective
Total long-term liabilities excluding long-term debt (8,180) (8,439) (8,276)
Add: Imperial’s share of equity company debt 25 20 26
Total company sources: Debt and equity perspective
Add: Imperial’s share of equity company debt 25 20 26
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Return on average capital employed (ROCE)
ROCE is a non-GAAP ratio. From the perspective of the business segments, ROCE is annual business segment net income divided by average business segment capital employed (an average of the beginning and end-of-year amounts). Segment net income includes Imperial’s share of segment net income of equity companies, consistent with the definition used for capital employed, and excludes the cost of financing. Capital employed is a non-GAAP financial measure and is disclosed and reconciled above. The company’s total ROCE is net income excluding the after-tax cost of financing divided by total average capital employed. The company has consistently applied its ROCE definition for many years and views it as one of the best measures of historical capital productivity in a capital-intensive, long-term industry. Additional measures, which are more cash flow based, are used to make investment decisions.
Components of return on average capital employed
From the Consolidated statement of income
Financing (after-tax) including Imperial’s share of equity companies 55 40 52
Return on average capital employed (percent) – corporate total 27.6 9.4 (6.4)
Cash flows from operating activities and asset sales
Cash flows from operating activities and asset sales is a non-GAAP financial measure that is the sum of the net cash provided by operating activities and proceeds from asset sales reported in the Consolidated statement of cash flows. This cash flow reflects the total sources of cash both from operating the company’s assets and from the divesting of assets. The most directly comparable financial measure that is disclosed in the financial statements is cash flows from (used in) operating activities within the company’s Consolidated statement of cash flows. The company employs a long-standing and regular disciplined review process to ensure that assets are contributing to the company’s strategic objectives. Assets are divested when they no longer meet these objectives or are worth considerably more to others. Because of the regular nature of this activity, the company believes it is useful for investors to consider sales proceeds together with cash provided by operating activities when evaluating cash available for investment in the business and financing activities, including shareholder distributions.
Reconciliation of cash flows from (used in) operating activities and asset sales
From the Consolidated statement of cash flows
Cash flows from (used in) operating activities 10,482 5,476 798
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Operating costs
Operating costs is a non-GAAP financial measure that are the costs during the period to produce, manufacture, and otherwise prepare the company’s products for sale – including energy costs, staffing and maintenance costs. It excludes the cost of raw materials, taxes and interest expense and are on a before-tax basis. The most directly comparable financial measure that is disclosed in the financial statements is total expenses within the company’s Consolidated statement of income. While the company is responsible for all revenue and expense elements of net income, operating costs represent the expenses most directly under the company’s control and therefore, are useful in evaluating the company’s performance.
Reconciliation of operating costs
From the Consolidated statement of income
Less:
Imperial's share of equity company expenses 71 61 64
Components of operating costs
From the Consolidated statement of income
Depreciation and depletion (includes impairments) 1,897 1,977 3,293
Non-service pension and postretirement benefit 17 42 121