EDGAR 10-K Filing

Company CIK: 49938
Filing Year: 2025
Filename: 49938_10-K_2025_0000049938-25-000015.json

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ITEM 1. BUSINESS
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, lower-emission fuels, and lithium.
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".
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, 2024, as detailed in the "Supplemental information on oil and gas exploration and production activities" in the "Financial section" 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 ended 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, 2024 that would cause a significant change in the estimated proved reserves as of that date.
Liquids (a)
Natural gas
Synthetic
crude oil
Bitumen
Total
oil-equivalent
basis
millions of
barrels
billions of
cubic feet
millions of
barrels
millions of
barrels
millions of
barrels
Net proved reserves:
Developed - 41 190 1,697 1,894
Undeveloped - 12 106 119 227
Total net proved - 53 296 1,816 2,121
(a)Liquids include crude oil, condensate and natural gas liquids (NGLs). NGL proved reserves are not material and are therefore included under liquids.
The estimation of proved reserve volumes, which is based on the requirement of reasonable certainty, is an ongoing process based on rigorous technical evaluations, commercial and market assessments, detailed analysis of reservoir and well performance, 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 2024 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.
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 the company’s proved reserves. This group also maintains the official reserves estimates for the company’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 22 years of petroleum industry experience, including 13 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 22 persons with an average of 12 years of relevant technical experience in evaluating reserves, of whom 21 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 10 years of relevant experience in evaluating and managing the evaluation of reserves.
Proved undeveloped reserves
As at December 31, 2024, approximately 11 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 227 million oil-equivalent barrels. Proved undeveloped reserves are associated with Syncrude, Kearl and Cold Lake. This compared to 218 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2023. The increase of 9 million oil-equivalent barrels of proved undeveloped reserves is mainly attributed to full funding of Cold Lake infill drilling, partially offset by Cold Lake infill start-ups.
As at December 31, 2024 there were no proved undeveloped reserves that have remained undeveloped for five years or more.
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 $260 million during the year to progress the development of proved undeveloped reserves at Cold Lake, Kearl and Syncrude. These investments represented about 24 percent of the $1,078 million in total reported Upstream capital and exploration expenditures.
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" 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, 2024 was as follows. All reported production volumes were from Canada.
thousands of barrels per day (a) 2024 2023 2022
Bitumen:
Kearl: - gross (b)
200 191 172
- net (c)
186 177 157
Cold Lake: - gross (b)
148 135 144
- net (c)
113 106 106
Total bitumen: - gross (b)
348 326 316
- net (c)
299 283 263
Synthetic crude oil (d):
- gross (b)
75 76 77
- net (c)
62 67 63
Liquids (e):
- gross (b)
5 5 9
- net (c)
5 5 9
Total: - gross (b)
428 407 402
- net (c)
366 355 335
(a)Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.
(b)Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.
(c)Net production is gross production less the mineral owners’ or governments’ share or both.
(d)The company’s synthetic crude oil production volumes were from the company’s share of production volumes in the Syncrude joint venture and include immaterial amounts of bitumen and other products exported to the operator's facilities using an existing interconnect pipeline.
(e)Liquids include crude oil, condensate and NGLs.
Average daily production and production available for sale of natural gas
The company’s average daily production and production available for sale of natural gas during the three years ended December 31, 2024 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.
millions of cubic feet per day (a) 2024 2023 2022
Gross production (b) (c)
30 33 85
Net production (c) (d) (e)
30 32 83
Net production available for sale (f)
9 11 50
(a)Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.
(b)Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.
(c)Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.
(d)Net production is gross production less the mineral owners’ or governments’ share or both.
(e)Net production reported in the above table is consistent with production quantities in the net proved reserves disclosure.
(f)Includes sales of the company’s share of net production and excludes amounts used for internal consumption.
Total average daily oil-equivalent basis production
The company’s total average daily production expressed in an oil-equivalent basis is set forth below, with natural gas converted to an oil-equivalent basis at six million cubic feet per one thousand barrels.
thousands of barrels per day (a) 2024 2023 2022
Total production oil-equivalent basis:
-gross (b)
433 413 416
-net (c)
371 360 349
(a)Volume per day metrics are calculated by dividing the volume for the period by the number of calendar days in the period.
(b)Gross production is the company’s share of production (excluding purchases) before deduction of the mineral owners’ or governments’ share or both.
(c)Net production is gross production less the mineral owners’ or governments’ share or both.
Average unit sales price
The company’s average unit sales price and average unit production costs by product type for the three years ended December 31, 2024 were as follows.
Canadian dollars per barrel 2024 2023 2022
Bitumen 74.53 67.42 84.67
Synthetic crude oil 101.91 105.57 125.46
Liquids (a)
55.63 59.30 93.77
Canadian dollars per thousand cubic feet
Natural gas 0.69 2.58 5.69
(a)Liquids include crude oil, condensate and NGLs.
In 2024, Imperial's average Canadian dollar realization for bitumen increased, primarily driven by the narrowing of the Western Texas Intermediate (WTI)/Western Canada Select (WCS) spread and lower diluent costs, partially offset by lower WTI. The company's average Canadian dollar realizations for synthetic crude oil decreased, primarily driven by a weaker Synthetic/WTI spread and lower WTI.
In 2023, Imperial’s average Canadian dollar realization for bitumen decreased generally in line with Western Canada Select (WCS). The company's average Canadian dollar realizations for synthetic crude oil decreased 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.
Average unit production costs
Canadian dollars per barrel 2024 2023 2022
Bitumen 29.42 32.41 39.05
Synthetic crude oil 61.84 62.57 68.00
Total oil-equivalent basis (a)
35.48 38.51 44.02
(a)Includes liquids, bitumen, synthetic crude oil and natural gas.
In 2024, bitumen unit production costs decreased, primarily driven by lower energy costs, higher Cold Lake production due to Grand Rapids, and higher Kearl production due to improved mine fleet productivity and optimized turnaround.
In 2024, synthetic crude oil unit production costs decreased, primarily driven by lower upgrading costs and lower energy costs.
In 2023, bitumen unit production costs decreased, primarily driven by lower energy costs and higher Kearl production due to improved reliability, plant capacity utilization, and mine equipment productivity.
In 2023, synthetic crude oil unit production costs decreased, primarily driven by higher net production.
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, 2024.
wells 2024 2023 2022
Net productive exploratory - - -
Net dry exploratory - - -
Net productive development 14 32 24
Net dry development - - -
Total 14 32 24
In 2024, wells drilled to add productive capacity include 14 development wells at Cold Lake.
In 2023, wells drilled to add productive capacity include 32 development wells at Cold Lake.
Wells drilling
At December 31, 2024, the company was drilling the following development wells to add productive capacity at Cold Lake. All wells were located in Canada.
wells Gross Net
Total 2 2
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 2024, additional development wells were drilled to add productive capacity. In 2025, a development drilling program is planned within the approved development area to add productive capacity.
In August 2018, Imperial received regulatory approval from the Alberta Energy Regulator (AER) for an expansion project at Cold Lake to develop the Grand Rapids interval using Solvent Assisted - Steam Assisted Gravity Drainage (SA-SAGD) technology, capable of producing 50,000 barrels per day before royalties. The company is developing 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. The initial steam injection phase at Grand Rapids started in December 2023 and first oil production was achieved in May 2024.
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 having commenced in 2023 and start-up planned in 2025.
The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques.
Aspen and other in-situ oil sands activities
In October 2018, the company received regulatory approval for the Aspen SA-SAGD project from the AER. 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 due to continued market uncertainty. Aspen’s project pace will continue to be evaluated and remains an important opportunity for Imperial. The Enhanced Bitumen Recovery Technology (EBRT) field pilot on the Aspen lease received funding approval in 2023, with development work underway for pilot start-up anticipated by 2027. The pilot will test technology that has the potential to deliver higher bitumen production rates compared to industry average SAGD operations.
Work progresses on technical and technology evaluations to support potential future 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.
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. In 2023, the Western Arctic - Tariuq (Offshore) Accord was signed and prohibition was extended to December 31, 2028. The Federal Government plans to co-develop a climate and marine science-based review of the moratorium. The company continues to hold the licences while maintaining community engagement and participation in the 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.
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.
During 2024, the company’s share of Kearl’s net bitumen production was about 186,000 barrels per day and gross production was about 200,000 barrels per day.
Total gross production for Kearl was about 281,000 barrels per day (200,000 barrels Imperial’s share), which is an increase of about 11,000 barrels per day (9,000 barrels Imperial's share) compared to 2023, as a result of improved mine fleet productivity and optimized turnaround.
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.
In 2024, net bitumen production at Cold Lake was about 113,000 barrels per day. The gross production was about 148,000 barrels per day, which is an increase of about 13,000 barrels per day compared to 2023, primarily driven by Grand Rapids.
Cold Lake continues to utilize its commercial application of Liquid Addition to Steam for Enhanced Recovery (LASER), with the technology being applied to approximately 15 percent of production.
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 2024, the company’s share of Syncrude’s net production was about 62,000 barrels per day. The gross production was about 75,000 barrels per day, which is a decrease of about 1,000 barrels per day compared to 2023.
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.
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, 2024 and December 31, 2023, is disclosed 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 2024 primarily due to the shut-in of multiple non-economical wells.
Year ended December 31, 2024
Year ended December 31, 2023
Crude oil Natural gas Crude oil Natural gas
wells Gross (a)
Net (b)
Gross (a)
Net (b)
Gross (a)
Net (b)
Gross (a)
Net (b)
Total (c)
3,991 3,987 2,387 763 4,084 4,080 2,411 770
(a)Gross wells are wells in which the company owns a working interest.
(b)Net wells are the sum of the fractional working interest owned by the company in gross wells, rounded to the nearest whole number.
(c)Multiple completion wells are permanently equipped to produce separately from two or more distinctly different geological formations. At year-end 2024, the company had an interest in 12 gross wells with multiple completions (2023 - 12 gross wells).
Land holdings
At December 31, 2024 and December 31, 2023, the company held the following oil and gas rights, and bitumen and synthetic crude oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore.
Developed Undeveloped Total
thousands of acres 2024 2023 2024 2023 2024 2023
Western provinces (a):
Liquids and gas - gross (b)
413 422 185 185 598 607
- net (c)
251 253 135 135 386 388
Bitumen - gross (b)
196 196 578 584 774 780
- net (c)
182 182 253 255 435 437
Synthetic crude oil - gross (b)
119 119 100 100 219 219
- net (c)
30 30 25 25 55 55
Canada lands (d):
Liquids and gas - gross (b)
2 2 1,803 1,803 1,805 1,805
- net (c)
2 2 495 496 497 498
Atlantic offshore:
Liquids and gas - gross (b)
23 65 146 146 169 211
- net (c)
2 6 22 22 24 28
Total (e):
- gross (b)
753 804 2,812 2,818 3,565 3,622
- net (c)
467 473 930 933 1,397 1,406
(a)Western provinces include British Columbia and Alberta.
(b)Gross acres include the interests of others.
(c)Net acres exclude the interests of others.
(d)Canada lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and other Northwest Territories.
(e)Certain land holdings are subject to modification under agreements whereby others may earn interests in the company’s holdings by performing certain exploratory work (farm-out) and whereby the company may earn interests in others’ holdings by performing certain exploratory work (farm-in).
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 171,000 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 29,000 net acres in the Clarke Creek area, about 28,000 net acres of oil sands leases in the Corner area, and about 18,000 net acres in the Chard area. The 171,000 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 386,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas.
Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from 2 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.
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
The company currently transports its crude oil production and third-party crude oil required to supply refineries by contracted or common carrier pipelines.
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, 2024, and the daily rated capacities of the refineries as at December 31, 2024, were as follows.
Refinery throughput (a)
Rated capacities (b)
Year ended December 31
at December 31
thousands of barrels per day 2024 2023 2022 2024
Strathcona, Alberta 187 186 195 197
Sarnia, Ontario 110 110 113 124
Nanticoke, Ontario 102 111 110 113
Total 399 407 418 434
Utilization of refinery capacity (percent)
92 94 98
(a)Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.
(b)Refining capacity data is based on 100 percent of rated refinery process unit stream-day capacities to process inputs to atmospheric distillation units under normal operating conditions, less the impact of shutdowns for regular repair and maintenance activities, averaged over an extended period of time.
Lower refinery throughput in 2024 reflected the impact of planned turnaround activities at Nanticoke, Sarnia and Strathcona refineries.
Lower refinery throughput in 2023 primarily reflected the impact of planned turnaround activities at Strathcona and Sarnia refineries.
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.
Marketing
The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers.
The company supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2024, there were about 2,600 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby the company supplies fuel to independent third parties.
The company 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, 2024, are set out in the following table.
thousands of barrels per day 2024 2023 2022
Gasolines 223 228 229
Heating, diesel and jet fuels 175 176 176
Lube oils and other products (a)
46 43 47
Heavy fuel oils 22 24 23
Net petroleum product sales 466 471 475
(a)In 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast.
Chemical
The company’s Chemical operations manufacture and market 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, 2024, were as follows.
thousands of tonnes 2024 2023 2022
Total petrochemical sales (a)
684 820 842
(a)In 2024, benzene and aromatic solvent sales are reported under Petroleum product sales - Lube oils and other products, whereas in 2023, they were reported under Petrochemical sales. The company has determined that the impact of this change is not material; therefore, the comparative periods have not been recast.
In 2024, sales volumes decreased primarily due to the reclassification of benzene and aromatic solvent sales.
In 2023, sales volumes decreased primarily due to planned maintenance activities.
Delivery commitments
The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements.
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 the company's 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. The company’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 5,100 at the end of 2024 (2023 - 5,300, 2022 - 5,300). Regular employees are defined as active executive, management, professional, technical, administrative, 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.
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, economic 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. In October 2023, the Supreme Court of Canada ruled that the new federal assessment scheme was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. 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.
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 operational measurements and sampling to confirm that 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 fuels, continued evaluation and implementation of technologies and products 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 $6.9 billion on environmental protection and facilities. In 2024, the company’s environmental capital and operating expenditures totalled approximately $2.1 billion, which was spent primarily on activities to protect the water, air and land, including remediation projects. Environmental expenditures are expected to increase to approximately $2.6 billion in 2025, with capital expenditures expected
to account for approximately 54 percent of the total. Costs for 2026 are anticipated to be approximately $2.6 billion, with capital expenditures expected to account for approximately 53 percent of the total.
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 2024 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.
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.
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 Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act.
The Act also provides that a dominant firm (or a firm that is jointly dominant with others) can face possible prohibition orders if it engages in conduct that is intentionally anti-competitive, or if its conduct has prevented or lessened competition substantially (or is likely to do so) in a market in which it has an interest. If such a firm engaged in intentionally anti-competitive acts that resulted in a substantial prevention or lessening of competition, then the firm may be subject to administrative monetary penalties and monetary awards to persons affected, and if a prohibition order is not likely to restore competition in that market the firm may be subject to an alternative or additional remedial order to overcome the effects of the practice, including the divestiture of assets or shares.
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
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 during the lifespan of its major assets. Any material decline in crude oil prices could have a material adverse effect on the company’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 the company'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, lower-emission fuels, and lithium also depends on the growth and development of markets for those products and services, including implementation of supportive and stable 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 economic downturns, 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, national or regional trade tariffs, trade sanctions or trade controls, international monetary and currency exchange rate fluctuations, decoupling of economies, disruptions in trade alliances or military alliances, or a broader breakdown in global trade, security or public health issues and responses, extended government shutdowns, the inability to access debt markets due to rating, banking, or legal constraints, liquidity crises, de-dollarization in global trade or the growth or use of alternative common currencies, and other events or conditions that impair the functioning of financial markets and institutions, also pose risks to the company.
Other demand-related factors
Factors that may affect the demand for crude oil, gas, fuels and petrochemicals, and therefore could impact the company’s results, include technological improvements in energy efficiency; seasonal weather patterns, which affect the demand for the company's products, including lower demand for gasoline, impacting Downstream results in the winter; increased competitiveness of, or government policy support for, alternative energy sources or potential substitutes for the company's products; new product quality regulations; technological changes or consumer preferences that alter fuel choices, such as technological advances in energy storage or other critical areas that make wind, solar, nuclear or other alternatives more competitive for power generation; changes in consumer preferences for the company’s products, including consumer demand for alternative fuel 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" in this Item 1A below.
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 (or may have a consequence of restricting) oil and gas production or exports, or increase associated production, reporting or compliance costs, including actions intended to reduce greenhouse gas emissions as described under “Climate change, energy transition and greenhouse gas restrictions” in this Item 1A, and previous Government of Alberta curtailment regulations; collective actions by non-governmental organizations and financial institutions to withhold funding or support from oil and gas producers; the occurrence of wars or hostile actions, including disruption of land or sea transportation routes; natural disasters; trade tariffs, sanctions or broader breakdowns in global trade; disruptions in competitors’ operations; and unexpected pipeline or rail constraints that may disrupt and have in the past disrupted supplies. For example, Russia's military action in Ukraine impacted global crude oil and gas supply levels and prices, and contributed to a volatile commodity environment; and the potential for trade tariffs by the United States on Canadian goods and potential retaliatory actions by Canadian or provincial governments could impact market prices and demand for, and export volumes of, Canadian goods. 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. In the past, increased differentials have 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, may also be affected by the occurrence, severity, pace and rate of recovery of future public health epidemics or pandemics, 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 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 the company’s existing operations and planned projects. This includes actions by policy makers, regulators or other actors to delay or deny necessary licences and permits, reduce or retract government incentives for emissions reductions, or 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 (including but not limited to in respect of climate change and greenhouse gas emissions and company communications relating thereto), regulatory interpretations that exclude or disfavour the company's products under government policies or programs intended to support new or developing markets or technologies or that are otherwise not technology-neutral, and increasing and expanding consultation with stakeholders and Indigenous communities,
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 or changes in taxes or government royalty rates (including retroactive claims or punitive taxes on oil, gas and petrochemical operations) and changes in trade policies and agreements (including those potential tariffs and retaliatory actions discussed above in this Item 1A under “Other supply-related factors”). Changes in taxation policy, such as the Government of Canada's tax on repurchases of equity that became effective from January 1, 2024, could impact the company’s financial results and ability to return surplus cash to shareholders. Further, the adoption of regulations mandating efficiency standards, emission standards or 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. Governments are also introducing bans on certain technologies that could impact demand for products, such as the Government of Canada’s regulations to gradually reduce the proportion of permitted sales of new internal combustion engine cars and light trucks from 2026-2034 and ban such sales 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 negatively impact the company’s ability to operate its projects and facilities (including but not limited to resulting in mandatory facility shutdowns or suspensions) 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. Of note, there are currently a number of court actions against the government by Indigenous groups regarding the assessment of cumulative impacts and infringement on exercise of treaty rights. These cases may inform future government decisions and policies regarding land use planning and resource development, and could impact the requirements or willingness to grant regulatory licenses or approvals. 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, regional drought, 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 or have been implemented at the federal and provincial levels, including sulphur dioxide limits for refineries in Ontario, and volatile organic compounds (VOC) and benzene controls required for petroleum liquid storage tanks and loading operations at refining and terminal locations, 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.
Regulation of oil sands
The company’s mining operations are, among other regulations, subject to tailings management regulations that establish approval, monitoring, reporting and performance criteria for tailings ponds and management plans. A failure or perceived failure to satisfy the requirements or if the company’s tailings management operations do not operate in the manner anticipated by the company or third parties could materially impact the company's ability to operate its assets. 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 and delicensing 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 mandated under both federal and provincial regulations. 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. In October 2023, the Supreme Court of Canada ruled that the new federal assessment scheme was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. 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, as well as laws and regulations affecting production of the company's products, trading, carbon capture and storage, hydrogen, lower-emission fuels or lithium) or other laws that penalize the company for past or current production of legal and/or permitted products and operations may increase the cost of operation or 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 and risks, including severe weather, drought, forest fires and geological events, may impact the company’s operational performance. For example, the company's oil sands operations were particularly affected by extreme cold weather in 2022 and wildfires in 2016. 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. See also “Safety, business controls and environmental risk management” under “Operational and other factors” in this Item 1A below.
Climate change, energy transition and greenhouse gas restrictions
Greenhouse gas emissions reductions
Driven by concern over the risks of climate change, the provinces and the Government of Canada have adopted or have revised regulatory frameworks to report on or reduce greenhouse gas emissions including emissions from the production and use of oil and gas and their products, as well as increase the use of or support for different emission-reduction technologies. 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 carbon dioxide (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 (including supportive policy and technology advancements) and reflect substantial uncertainties. The company’s actions with respect to the energy transition carry risks that the transition, including underlying technologies, government policies, and markets as discussed in more detail below, will not be available or 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 changes 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. Imperial’s results may be impacted if the implementation pace and uncertainty of policy reduces the global competitiveness of the Canadian oil and gas industry and the company’s crude oil and refined products. Political government changes may create further policy uncertainty resulting in greater investment uncertainty and industry competitiveness concerns.
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, restrictions on sales of gasoline-only vehicles, and other incentives or mandates designed to support certain technologies for transitioning to lower-emission energy sources. 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 45 to 50 percent below 2005 levels by 2035, a substantial increase in ambition beyond its original and most recent 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, and additional sector specific regulations may be developed to achieve this target.
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 percentage of priced emissions increased nominally to 11 percent in 2021 and 12 percent in 2022, with the oil sands mining and upgrading facilities increasing to 17 percent in 2021, 18 percent
in 2022 and 20 percent in 2023. These percentages increase by 2 percent per year for 2024 to 2028 (inclusive), 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 put a price on 8 percent of a facility’s emissions in 2022. The price increased by 2.4 percent in 2023 and 1.5 percent in 2024, and will increase by 1.5 percent per year thereafter. British Columbia has carbon pricing in place for all industrial emissions, with pricing that matches the federal carbon pricing schedule since 2022. 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.
There are also various renewable and low carbon fuel standards being developed or already applicable to the company’s products. In 2022, the Government of Canada finalized the Clean Fuel Regulations, which require the reduction in carbon intensity of liquid transportation fuels supplied in Canada starting in July 2023. The regulations require fuel suppliers to reduce the carbon intensity of gasoline and diesel by reducing the GHG emissions within the fossil fuel life cycle, blending in low carbon intensity renewables or fuel switching away from fossil fuels. 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. Uncertainty exists regarding federal overreach into provincial jurisdiction to implement such changes and policies. In October 2023, the Supreme Court of Canada ruled that the Impact Assessment Act was unconstitutional in part. In November 2024, Alberta referred the constitutionality of the amended Impact Assessment Act to the Court of Appeal of Alberta. The impact of this legislation is not fully apparent.
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 costs (such as complying with increased or mandatory disclosure or due diligence requirements and government mandated energy transition plans), increase 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 the company's 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 and electricity to the extent they view such measures as a viable approach for pursuing national and global energy and climate policies. For example, following the publication of a regulatory framework in December 2023, in November 2024 the Government of Canada released proposed regulations that will impose a cap on greenhouse gas emissions from upstream oil and gas activities by 2030, and in December 2024 the Government of Canada released final Clean Electricity Regulations that will require reductions in the carbon intensity of electricity provided to the grid between 2035 and 2050. 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 collectively 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. These actions include delaying or blocking needed infrastructure, utilizing shareholder governance mechanisms against companies or their shareholders or financial institutions in an effort to deter investments in oil and gas activities, and taking other 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 emissions will require new technologies and added infrastructure to reduce the cost and increase the scalability of
alternative energy sources. The company is continuing research and collaboration efforts to advance the development and deployment of carbon capture and storage, hydrogen, lower-emission fuels and lithium. 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 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, any successful energy transition will require appropriate support from governments and private participants throughout the global economy. Ultimately, market solutions with sound business fundamentals are necessary to incentivize and sustain wide-spread solutions that drive emissions reductions. The company’s ability to develop and deploy carbon capture and storage, hydrogen, lower-emission fuels, lithium, and other new energy technologies at commercial scale will depend in part on the continued development of stable and supportive government policies and markets. Failure or delay of these policies or markets to materialize or be maintained, or the development of these policies or markets in a manner that differs from the company’s expectations, could adversely impact these investments. Policy and other actions that result in restricting the availability of hydrocarbon products without a 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. The company's operations and planned projects that have been developed with regard to current or anticipated policies, including but not limited to policies relating to carbon emission credits, may become uneconomic or otherwise adversely impacted if such policies change or are not adopted as anticipated. See also the discussion of "Supply and demand", "Government and political factors", and "Project management" in this Item 1A.
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 the company’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 and other 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, including with counterparties located outside of Canada. The company’s operations, market position and financial condition may be adversely impacted if these counterparties fail to fulfil their obligations. For counterparties located outside of Canada, the risk of such failure may be enhanced and the company’s ability to mitigate against such failure may be reduced as a result of a lack of physical proximity, foreign government actions or other geopolitical factors.
The company may also be adversely affected by the outcome of litigation or arbitration resulting from its operations, including but not limited to proceedings in respect of greenhouse gas emissions and the promotion of the company’s products, or by government enforcement proceedings alleging non-compliance with applicable
laws or regulations. Such proceedings are subject to uncertainty and success is not guaranteed, and the company may incur significant expenses and devote significant resources in defending such proceedings.
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, although inflationary pressures declined in Canada and other countries during 2024, moderate inflation levels have persisted and governments generally maintained elevated interest rates which may further impact the company through the availability of financing, cost of debt, and exchange rate fluctuations. In addition, potential tariffs and retaliatory actions discussed above in this Item 1A under “Other supply-related factors” could have further inflationary impacts. Additional information regarding the potential future impact of market factors on the company's 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 successfully manage those factors that are at least in part within its control, including its capital allocation into existing and new businesses. The extent to which the company 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 protect and enforce the company’s contractual and legal rights (including with joint venture partners); 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 ability to qualify for certain incentives available under supportive government policies for emerging markets and technologies; the impact of general economic, business and market conditions; and the company’s ability to prevent, to the extent possible, and respond effectively to unforeseen technical difficulties that could delay project start-up or cause unscheduled downtime.
Operational efficiency
An important component of Imperial’s competitive performance, especially given the commodity-based nature of the company’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 integration and 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, the dynamic and rapidly evolving technological landscape, and the need for continuous efficiency improvement.
The company’s research and development organizations must be able to adapt to a changing market, regulatory and policy environment, including developing or deploying 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 (including but not limited to artificial intelligence technologies) to gain new business insights and support business operations.
There are risks associated with existing and new operations and 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 those relating to environmental sustainability and reduction of greenhouse gas emissions), and financial results.
In 2023, the company’s Kearl site completed its multiyear program to convert its 81 haul trucks to autonomous operation. The autonomous system is composed of perception systems, sensors and mechanical components on each truck, which feed information to a number of onboard computer systems. These onboard computer systems send real time information over a wireless network to a central server and database that displays real time information to central control room operators who manage the overall fleet’s operation. Computer automation systems are used to both maneuver the individual trucks and in an overarching truck assignment application which manages truck routing patterns. The use of the autonomous system helps the company to capture productivity improvements while also reducing costs and further enhancing operational safety. Failure of the autonomous system to operate as intended could result in material adverse impacts to production at the Kearl site and the company’s financial results, physical harm to people or the environment, damage or destruction of company assets, and negative reputational consequences. The company applies risk management, internal controls and controls management systems in respect of these risks relating to autonomous haul trucks, as described in “Safety, business controls and environmental risk management” in this Item 1A below. See also “Cybersecurity” and “Reputation” in this Item 1A below.
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), drought, forest fires 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. The company 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.
Preparedness
The company’s operations have been and in the future may be disrupted by severe weather events, natural disasters, human error, and similar events. The company's 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. The company's 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.
Cybersecurity
The company is regularly subject to attempted cybersecurity disruptions from a variety of sources, including state-sponsored actors and actors potentially employing emerging technologies such as artificial intelligence technologies. The company’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. See "Item 1C. Cybersecurity" for information on the company's program for managing cybersecurity risks.
The company has limited ability to influence third parties, including the company's partners, suppliers, service providers (including providers of cloud-based services for the company's data or applications) and customers, to implement strong cybersecurity controls, and the company is exposed to potential harm from cybersecurity
events that may affect their operations. During 2024, the company responded to several cyber-attacks on suppliers and joint venture partners, none of which caused a material impact to Imperial. The company’s response included giving technical assistance, loaning equipment, and taking additional defensive measures.
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. 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. The company 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.
Competition
As noted in Item 1 above, the Canadian energy and petrochemical industries are highly competitive. Technology and expertise provided by industry service companies may enhance the competitiveness of firms that may not have the internal resources and capabilities of Imperial. As described in more detail above, the company’s hydrocarbon-based energy products are also subject to growing and, in many cases, government-supported competition from alternative energy sources. In addition, as the company enters new markets in pursuit of lower-emission business opportunities, the company will need to compete effectively with established competitors in these markets, as well as with new market entrants seeking to capitalize on these opportunities, while successfully navigating changing market conditions or technologies.
Reputation
Imperial’s reputation is an important corporate asset. Factors that could have an impact on the company’s reputation include an operating incident or significant cybersecurity disruption; changes in consumer views concerning the company’s products; changes in consumer media preferences from traditional mainstream media to decentralized and personalized media; a perception by the public that the company is not being fully transparent in the sharing of information regarding its operations that is or may be relevant to community decision-making; actions taken by the company's business partners; 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, Indigenous rights 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
Item 1B. Unresolved staff comments
None.

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ITEM 2. PROPERTIES
Item 2. Properties
Reference is made to Item 1 above.

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ITEM 3. LEGAL PROCEEDINGS
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.

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ITEM 4. MINE SAFETY DISCLOSURE
Item 4. Mine safety disclosures
Not applicable.
PART II

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ITEM 5. MARKET FOR REGISTRANT'S COMMON EQUITY
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 14, 2025 there were 8,558 holders of record of common shares of the company.
Information for security holders outside Canada
Cash dividends paid to shareholders resident in the United States are, under the Canada-US income tax convention, subject to a Canadian non-resident withholding tax of 15 percent.
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 rate of withholding applicable to other jurisdictions may vary.
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 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.
The foregoing tax information is not intended to provide legal or tax advice, and shareholders are encouraged to consult a professional advisor with respect to all tax-related issues.
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 sections under the "Company executives and executive compensation":
•Entitled "Performance graph" within the "Compensation discussion and analysis" section on page 166 of this report; and
•Entitled "Equity compensation plan information", within the "Compensation discussion and analysis", on page 177 of this report.
Issuer purchases of equity securities
Total number of
shares purchased
Average price paid
per share
(Canadian dollars) (a)
Total number of
shares purchased
as part of publicly
announced plans
or programs
Maximum number
of shares that may
yet be purchased
under the plans or
programs (b)
October 2024
(October 1 - October 31)
5,541,599
104.65
5,541,599
8,815,978
November 2024
(November 1 - November 30)
5,289,708
103.34
5,289,708
3,526,270
December 2024
(December 1 - December 31)
3,526,270
98.88
3,526,270
-
(a)Excludes 2 percent tax on repurchases of equity.
(b)On June 24, 2024, the company announced by news release that it had received final approval from the Toronto Stock Exchange for a new normal course issuer bid to continue its then-existing share purchase program. The program enabled the company to purchase up to a maximum of 26,791,840 common shares during the period June 29, 2024 to June 28, 2025. This maximum included shares purchased under the normal course issuer bid from Exxon Mobil Corporation. As in the past, Exxon Mobil Corporation advised the company that it intended to participate to maintain its ownership percentage at approximately 69.6 percent. Imperial accelerated share purchases under the normal course issuer bid program, and the program completed on December 19, 2024 as a result of the company purchasing the maximum allowable number of shares under the program.
The company will continue to evaluate the renewal of its normal course issuer bid share purchase program in June 2025 in the context of its overall capital activities.
Purchase plans may be modified at any time without prior notice.

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ITEM 6. SELECTED FINANCIAL DATA

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ITEM 7. MANAGEMENT'S DISCUSSION AND ANALYSIS
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 50 of this report.

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ITEM 7A. QUANTITATIVE AND QUALITATIVE DISCLOSURES ABOUT MARKET RISK
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 65 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
Item 8. Financial statements and supplementary data
Reference is made to the table of contents in the "Financial section" on page 44 of this report:
•Consolidated financial statements, together with the report thereon of PricewaterhouseCoopers LLP (PCAOB ID: 271), Calgary, Canada dated February 19, 2025, beginning with the section entitled "Report of Independent Registered Public Accounting Firm" on page 72 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.

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ITEM 9. CHANGES IN AND DISAGREEMENTS WITH ACCOUNTANTS
Item 9. Changes in and disagreements with accountants on accounting and financial disclosure
None.

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ITEM 9A. CONTROLS AND PROCEDURES
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, 2024. 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 71 of this report for "Management’s report on internal control over financial reporting" and page 72 for the "Report of Independent Registered Public Accounting Firm" on the company’s internal control over financial reporting as of December 31, 2024.
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.

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ITEM 9B. OTHER INFORMATION
Item 9B. Other information
During the three months ended December 31, 2024, none of the company's directors or officers adopted or terminated a "Rule 10b5-1 trading arrangement" or "non-Rule 10b5-1 trading arrangement," as each term is defined in Item 408(a) of Regulation S-K.

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ITEM 10. DIRECTORS, EXECUTIVE OFFICERS AND CORPORATE GOVERNANCE
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 8, 2025 (the "2025 Annual Meeting"). All of the nominees, with the exception of J.R. Whelan, are now directors and have been since the dates indicated.
B.W. Corson, current chairman, president and chief executive officer, is a current director and has chosen not to stand for re-election. On February 12, 2025, Mr. Corson announced his intention to retire at the conclusion of the 2025 Annual Meeting. Mr. Corson has resigned from his position as president effective April 1, 2025, and he has resigned from the chairman and chief executive officer positions effective at the conclusion of the 2025 Annual Meeting. On February 12, 2025, the board of directors appointed Mr. Whelan (i) as president of the company effective April 1, 2025, (ii) as chief executive officer of the company effective at the conclusion of the 2025 Annual Meeting, and (iii) provided that he is elected as a director at the 2025 Annual Meeting, as chairman of the board effective at the conclusion of such meeting.
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 126 of this report;
•The table entitled "Audit committee" under "Board and committee structure", on page 136 of this report;
•"Ethical business conduct", starting on page 148 of this report;
•"Restrictions on insider trading", starting on page 149 of this report; and
•"Largest shareholder", on page 152 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.

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ITEM 11. EXECUTIVE COMPENSATION
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 140 to 147 of this report; and
•"Share ownership guidelines of independent directors and chairman, president and chief executive officer", on page 147 of this report.
Reference is made to the following sections under "Company executives and executive compensation":
•"Letter to shareholders", on page 156 of this report; and
•"Compensation discussion and analysis", on pages 155 to 181 of this report.

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ITEM 12. SECURITY OWNERSHIP OF CERTAIN BENEFICIAL OWNERS
Item 12. Security ownership of certain beneficial owners and management and related stockholder matters
The following table sets forth, to the extent known by the company or ascertainable from public filings, each person, or group of affiliated persons, who is known by the company to beneficially own greater than 5.0% of the company's outstanding common shares as of December 31, 2024. Any fractional shares have been rounded to the nearest whole share.
Title of Class Name and Address of
Beneficial Owner Aggregate and Nature of Beneficial Ownership Percent of Class
Common Shares Exxon Mobil Corporation
22777 Springwoods Village Parkway
Spring, Texas 77389 (a)
354,294,928 69.6%
Common Shares FMR LLC
245 Summer Street
Boston, Massachusetts 02210 (b) (c)
43,014,477 (c)
8.5% (c)
(a)As of February 14, 2025, Exxon Mobil Corporation has sole voting and dispositive power with respect to 354,294,928 shares of the company's common shares.
(b)The company is permitted to rely on the information set forth in the referenced filings and has no reason to believe that the information is incomplete or inaccurate or that the beneficial owner should have filed an amended report and did not.
(c)Share ownership information is based solely on the Schedule 13G/A filed jointly by FMR LLC and Abigail P. Johnson with the SEC on February 12, 2025. As of December 31, 2024, (i) FMR LLC and Abigail P. Johnson each have beneficial ownership of the same 43,014,477 of the company's common shares, which shares are owned by FMR LLC, certain of its subsidiaries and affiliates, and other companies, (ii) FMR LLC has sole voting power with respect to 31,051,356 shares of those shares, and (iii) FMR LLC and Abigail P. Johnson each have sole dispositive power with respect to all such shares.
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 177 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, 2024 is described in the sections under "Nominees for director" starting on page 112, "Director compensation" starting on page 140 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 and restricted stock units beneficially owned by each named executive officer, and the incumbent directors and executive officers as a group, as of February 14, 2025.
Imperial Oil Limited Exxon Mobil Corporation
Named executive officer Common
shares (a)
Restricted
stock units (b)
Common
shares (a)
Restricted
stock units (b)
B.W. Corson 10,000 462,500 124,328 59,700
D.E. Lyons - 132,200 14,064 -
C.L. Gomez-Smith - 20,900 17,606 33,300
J.E. Burgess 106 61,950 - -
I.R. Laing 6,222 52,200 - -
Incumbent directors and executive
officers as a group (16 people)
33,600 884,400 161,644 283,060
(a)No common shares are beneficially owned by reason of exercisable options. None of these individuals owns 0.01 percent of the outstanding shares of Imperial Oil Limited or Exxon Mobil Corporation. The directors and officers as a group own 0.01 percent of the outstanding shares of Imperial Oil Limited, and 0.01 percent of the outstanding shares of Exxon Mobil Corporation. Information not being within the knowledge of the company has been provided by the directors and the executive officers individually.
(b)Restricted stock units do not carry voting rights prior to the issuance of shares on settlement of the awards.

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ITEM 13. CERTAIN RELATIONSHIPS AND RELATED TRANSACTIONS
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 152 of this report.
N.A. Hansen 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 finance committee under the relevant standards. As an employee of Exxon Mobil Corporation, N.A. Hansen 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 ACCOUNTING FEES AND SERVICES
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 is 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, 2024 and December 31, 2023 were as follows:
thousands of Canadian dollars 2024 2023
Audit fees 2,635 2,200
Audit-related fees 90 97
Tax fees - -
All other fees - -
Total fees 2,725 2,297
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 2024. 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.
PART IV

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ITEM 15. EXHIBITS, FINANCIAL STATEMENT SCHEDULES
Item 15. Exhibits, financial statement schedules
Reference is made to the table of contents in the "Financial section" on page 44 of this report.
The following exhibits, numbered in accordance with Item 601 of Regulation S-K, are filed as part of this report:
(3) (i)
Restated certificate and articles of incorporation of the company (Incorporated herein by reference to Exhibit (3.1) to the company’s Form 8-K filed on May 3, 2006 (File No. 0-12014)).
(ii)
Amended and Restated By-Law No. 1 of the company, dated September 17, 2024 (Incorporated herein by reference to Exhibit (3.1) to the company’s Quarterly Report on Form 10-Q for the quarter ended September 30, 2024 (File No. 0-12014)).
(4) (vi)
Description of capital stock. (Incorporated herein by reference to Exhibit (4)(vi) of the company’s Annual Report on Form 10-K for the year ended December 31, 2019 (File No. 0-12014)).
(10) (ii) (1) Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement dated June 25, 1984. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the company’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)).
(2)
Syncrude Bitumen Royalty Option Agreement, dated November 18, 2008, setting out the terms of the exercise by the Syncrude Joint Venture owners of the option contained in the existing Crown Agreement to convert to a royalty payable on the value of bitumen, effective January 1, 2009 (Incorporated herein by reference to Exhibit 1.01(10)(ii)(2) of the company’s Form 8-K filed on November 19, 2008 (File No. 0-12014)).
(iii)(A) (1) Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)).
(2) Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
(3)
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2016 and subsequent years, as amended effective October 26, 2016 (Incorporated herein by reference to Exhibit 9.01(c)[10(iii)(A)(1)] of the company’s Form 8-K filed on October 31, 2016 (File No. 0-12014)).
(4)
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2020 and subsequent years, as amended effective November 24, 2020 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company’s Annual Report on Form 10-K for the year ended December 31, 2020 (File No. 0-12014)).
(5)
Amended Restricted Stock Unit Plan with respect to Restricted Stock Units granted in 2022 and subsequent years, as amended effective November 29, 2022 (Incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the company's Annual Report on Form 10-K for the year ended December 31, 2022 (File No. 0-12014)).
(6)
Amended Short Term Incentive Program, as amended effective December 1, 2023 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the company's Annual Report on Form 10-K for the year ended December 31, 2023 (File No. 0-12014)).
(19)
Insider Trading and Blackout Guidelines
(21) Imperial Oil Resources Limited is incorporated in Alberta, Canada and Canada Imperial Oil Limited is incorporated in Canada, and both are wholly-owned subsidiaries of the company. The names of all other subsidiaries of the company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2024.
(31.1)
Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a).
(31.2)
Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).
(32.1)
Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
(32.2)
Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
(97)
SEC Rule 10D-1 Policy for the Recovery of Erroneously Awarded Compensation effective December 1, 2023 (Incorporated herein by reference to Exhibit (97) of the company's Annual Report on Form 10-K for the year ended December 31, 2023 (File No. 0-12014)).
(101) Interactive Data Files (formatted as Inline XBRL).
(104) Cover Page Interactive Data File (formatted as Inline XBRL and contained in Exhibit 101).
Copies of Exhibits may be acquired upon written request of any shareholder to the vice president, investor relations, Imperial Oil Limited, 505 Quarry Park Boulevard S.E., Calgary, Alberta T2C 5N1, and payment of processing and mailing costs.