IMPERIAL OIL LTD 10-K

Item 1. Business Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the company is located at 505 Quarry Park Boulevard S.E., Calgary, Alberta, Canada T2C 5N1. Exxon Mobil Corporation (“ExxonMobil”) owns approximately 69.6 percent of the outstanding shares of the company. In this report, unless the context otherwise indicates, reference to the “company” or “Imperial” includes Imperial Oil Limited and its subsidiaries, and reference to ExxonMobil includes Exxon Mobil Corporation and its affiliates, as appropriate. The company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is a major producer of crude oil, the largest petroleum refiner, a leading marketer of petroleum products, and a major producer of petrochemicals. The company also pursues lower-emission business opportunities including carbon capture and storage, hydrogen and lower-emission fuels. The company’s operations are conducted in three main segments: Upstream, Downstream and Chemical. Upstream operations include the exploration for, and production of, crude oil, natural gas, synthetic crude oil and bitumen. Downstream operations consist of the transportation and refining of crude oil, blending of refined products and the distribution and marketing of those products. Chemical operations consist of the manufacturing and marketing of various petrochemicals. Operating data and financial information about the company’s business segments are contained in this report under the following: “Management’s discussion and analysis of financial condition and results of operations” and the “Financial section” under note 2 to the consolidated financial statements: “Business segments”. 5 Upstream Disclosure of reserves Summary of oil and gas reserves at year-end The table below summarizes the net proved reserves for the company, as at December 31, 2022, as detailed in the “Supplemental information on oil and gas exploration and production activities” part of the “Financial section”, starting on page 41 of this report. All of the company’s reported reserves are located in Canada. The company has reported proved reserves based on the average of the first-day-of-the-month price for each month during the last 12-month period ending December 31. Natural gas is converted to an oil-equivalent basis at six million cubic feet per one thousand barrels. No major discovery or other favourable or adverse event has occurred since December 31, 2022 that would cause a significant change in the estimated proved reserves as of that date. Liquids (a) Natural gas Synthetic crude oil Bitumen Total oil-equivalent basis millions of barrels billions of cubic feet millions of barrels millions of barrels millions of barrels Net proved reserves: Developed 4 60 248 1,691 1,953 Undeveloped — 12 105 133 240 Total net proved 4 72 353 1,824 2,193 (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 well information such as flow rates and reservoir pressures, and development and production costs, and other factors. Furthermore, the company only records proved reserves for projects which have received significant funding commitments by management made toward the development of the reserves. Although the company is reasonably certain that proved reserves will be produced, the timing and amount recovered can be affected by a number of factors, including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. In addition, proved reserves could be affected by an extended period of low prices which could reduce the level of the company’s capital spending and also impact its partners’ capacity to fund their share of joint projects. Technologies used in establishing proved reserves estimates Imperial’s proved reserves in 2022 were based on estimates generated through the integration of available and appropriate geological, engineering and production data, utilizing well established technologies that have been demonstrated in the field to yield repeatable and consistent results. Data used in these integrated assessments included information obtained directly from the subsurface via wellbores, such as well logs, reservoir core samples, fluid samples, static and dynamic pressure information, production test data, and surveillance and performance information. The data utilized also included subsurface information obtained through indirect measurements, including seismic data, calibrated with available well control information. The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages. In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates. 6 Preparation of reserves estimates Imperial has a dedicated reserves management group that is separate from the base operating organization. Primary responsibilities of this group include oversight of the reserves estimation process for compliance with the U.S. Securities and Exchange Commission rules and regulations, review of annual changes in reserves estimates and the reporting of Imperial’s proved reserves. This group also maintains the official reserves estimates for Imperial’s proved reserves. In addition, this group provides training to personnel involved in the reserve estimation and reporting processes within Imperial. The reserves management group maintains a central database containing the company’s official reserves estimates. Appropriate controls, including limitations on database access and update capabilities, are in place to ensure data integrity within this central database. An annual review of the system’s controls is performed by internal audit. Key components of the reserves estimation process include technical evaluations, commercial and market assessments, analysis of well and field performance, and long standing approval guidelines. No changes may be made to reserves estimates in the central database, including the addition of any new initial reserves estimates or subsequent revisions, unless those changes have been thoroughly reviewed and evaluated by duly authorized personnel within the base operating organization. In addition, changes to reserves estimates that exceed certain thresholds require further review and endorsement by the operating organization and the reserves management group, culminating in reviews with and approval by senior management and the company’s board of directors. The internal qualified reserves evaluator is a professional geoscientist registered in Alberta, Canada and has 20 years of petroleum industry experience, including 11 years of reserves related experience. The position provides leadership to the internal reserves management group and is responsible for filing a reserves report with the Canadian securities regulatory authorities. The company’s internal reserves evaluation staff consists of 20 persons with an average of 14 years of relevant technical experience in evaluating reserves, of whom 18 persons are qualified reserves evaluators for purposes of Canadian securities regulatory requirements. The company’s internal reserves evaluation management team is made up of 15 persons with an average of 11 years of relevant experience in evaluating and managing the evaluation of reserves. Proved undeveloped reserves As at December 31, 2022, approximately 11 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 240 million oil-equivalent barrels. Proved undeveloped reserves are associated with Syncrude and Cold Lake. This compared to 386 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2021. The decrease of 146 million oil-equivalent barrels of proved undeveloped reserves includes a decrease of 133 million oil-equivalent barrels at Cold Lake associated with a shift of future development from the traditional Cyclic Steam Stimulation (CSS) to lower emissions intensity, solvent based technologies, a decrease of 7 million oil-equivalent barrels at Syncrude, and a decrease of 6 million oil-equivalent barrels due to the Montney and Duvernay unconventional assets sale. No proved undeveloped reserves were converted into proved developed reserves during 2022. Proved undeveloped reserves that have remained undeveloped for five years or more represent about 6 percent (14 million oil-equivalent barrels) of proved undeveloped reserves and are associated with ongoing development programs at Cold Lake. These undeveloped reserves are planned to be developed in a staged approach to align with operational capacity and efficient capital spending commitment over the life of the asset. The company is reasonably certain that these proved reserves will be produced; however the timing and amount recovered can be affected by a number of factors including completion and optimization of development projects, reservoir performance, regulatory approvals, government policies, consumer preferences, changes in the amount and timing of capital investments, royalty frameworks and significant changes in oil and gas price levels. One of the company’s requirements to report resources as proved reserves is that management has made significant funding commitments towards the development of the reserves. The company has a disciplined investment strategy and many major fields require a long lead-time in order to be developed. The company made investments of about $167 million during the year to progress the development of proved undeveloped reserves at Cold Lake and Syncrude. These investments represented about 15 percent of the $1,128 million in total reported Upstream capital and exploration expenditures. 7 Oil and gas production, production prices and production costs Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 47 of this report for a narrative discussion on the material changes. Average daily production of oil The company’s average daily oil production by final products sold during the three years ended December 31, 2022 was as follows. All reported production volumes were from Canada. thousands of barrels per day (a) 2022 2021 2020 Bitumen: Kearl: - gross (b) 172 186 158 - net (c) 157 178 155 Cold Lake: - gross (b) 144 140 132 - net (c) 106 114 124 Total bitumen: - gross (b) 316 326 290 - net (c) 263 292 279 Synthetic crude oil (d) : - gross (b) 77 71 69 - net (c) 63 62 68 Liquids (e) : - gross (b) 9 11 13 - net (c) 9 10 12 Total: - gross (b) 402 408 372 - net (c) 335 364 359 (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, 2022 are set forth below. All reported production volumes were from Canada and are calculated at a pressure base of 14.73 pounds per square inch absolute at 60 degrees Fahrenheit. Reference is made to the portion of the “Financial section” entitled “Management’s discussion and analysis of financial condition and results of operations” on page 47 of this report for a narrative discussion on the material changes. millions of cubic feet per day (a) 2022 2021 2020 Gross production (b) (c) 85 120 154 Net production (c) (d) (e) 83 115 150 Net production available for sale (f) 50 81 115 (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. 8 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) 2022 2021 2020 Total production oil-equivalent basis: - gross (b) 416 428 398 - net (c) 349 383 384 (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, 2022 were as follows. Canadian dollars per barrel 2022 2021 2020 Bitumen 84.67 57.91 25.69 Synthetic crude oil 125.46 81.61 49.76 Liquids (a) 93.77 59.41 27.40 Canadian dollars per thousand cubic feet Natural gas 5.69 3.83 1.90 (a) Liquids include crude oil, condensate and NGLs. In 2022, Imperial's average Canadian dollar realization for bitumen increased generally in line with Western Canada Select (WCS). The company's average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs and reflect a premium over WTI driven by supply and demand. In 2021, Imperial’s average Canadian dollar realizations for bitumen increased generally in line with Western Canada Select (WCS). The company’s average Canadian dollar realizations for synthetic crude oil increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs. Average unit production costs Canadian dollars per barrel 2022 2021 2020 Bitumen 39.05 29.06 25.73 Synthetic crude oil 68.00 61.97 45.51 Total oil-equivalent basis (a) 44.02 34.32 28.73 (a) Includes liquids, bitumen, synthetic crude oil and natural gas. In 2022, bitumen unit production costs increased, primarily driven by higher energy costs. In 2022, synthetic crude oil unit production costs increased, primarily driven by higher energy costs. In 2021, bitumen unit production costs increased, primarily driven by higher energy costs. In 2021, synthetic crude oil unit production costs increased, primarily driven by higher maintenance costs and mine tailings spend. 9 Drilling and other exploratory and development activities The company has been involved in the exploration for and development of crude oil and natural gas in Canada only. Wells drilled The following table sets forth the net exploratory and development wells that were drilled or participated in by the company during the three years ended December 31, 2022. wells 2022 2021 2020 Net productive exploratory — — — Net dry exploratory — — — Net productive development 24 13 29 Net dry development — — — Total 24 13 29 In 2022, wells drilled to add productive capacity include 24 development wells at Cold Lake. In 2021, wells drilled to add productive capacity include 12 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets. In 2020, wells drilled to add productive capacity include 28 development wells at Cold Lake and 1 well associated with the Montney and Duvernay unconventional assets. Wells drilling At December 31, 2022, the company was drilling the following development wells to add productive capacity at Cold Lake. All wells were located in Canada. 2022 Wells Gross Net Total 21 21 Exploratory and development activities regarding oil and gas resources Cold Lake To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities are required periodically. In 2022, additional wells were drilled on existing phases. In 2023, an infill development drilling program is planned within the approved development area to add productive capacity. Additionally, in 2022, the company approved the budget for the Leming steam-assisted gravity drainage (SAGD) project that will re-develop the original pilot area of the Cold Lake field, with development activities to commence in 2023 and start-up planned in 2024. The company also conducts experimental pilot operations to improve recovery of bitumen from wells by means of new drilling, production or recovery techniques. Aspen, Cold Lake expansion and other oil sands activities In October 2018, the company received regulatory approval for the Aspen solvent-assisted, steam-assisted gravity drainage (SA-SAGD) project from the Alberta Energy Regulator. Development was proposed to occur in two phases, each producing about 75,000 barrels per day, before royalties. The first phase of the project was approved by the company’s board, and appropriated for $2.6 billion. Construction began late in the fourth quarter of 2018. In March 2019, the company slowed the pace of development given market uncertainty stemming from the Government of Alberta’s temporary mandatory production curtailment regulations and other industry competitiveness challenges. Although the Government of Alberta repealed the regulatory authority for imposing temporary production curtailments at the end of 2021, major investment remains on hold. Aspen’s project pace will continue to be evaluated and remains an important opportunity for Imperial. 10 In August 2018, Imperial received regulatory approval from the Alberta Energy Regulator for an expansion project at Cold Lake to develop the Grand Rapids interval using SA-SAGD technology, capable of producing 50,000 barrels per day before royalties. Imperial intends to develop the Grand Rapids reservoir through capital-efficient investments that make use of available steam capacity from existing plants, with the initial phase of Grand Rapids development planned as an extension from the Nabiye plant. In April 2022, the Grand Rapids Phase 1 (GRP1) project was approved by the company's board with a forecasted average production of 15,000 barrels per day before royalties. Development activities are planned to be completed by year-end 2023. Work progresses on technical and technology evaluations to support potential Clarke Creek, Corner, Clyden and Chard in-situ development regulatory applications. The company also has interests in other oil sands leases in the Athabasca region of northern Alberta. Evaluation wells completed on these leased areas established the presence of bitumen. The company continues to evaluate these leases to determine their potential for future development. Montney and Duvernay The company owned a 50 percent interest in XTO Energy Canada, which included Montney and Duvernay unconventional assets located in central Alberta. On August 31, 2022, jointly with ExxonMobil Canada, Imperial sold its interests in XTO Energy Canada to Whitecap Resources Inc. The sale completed the marketing effort announced in January 2022, and is consistent with Imperial’s strategy to focus upstream resources on key oil sands assets and its commitment to deliver long-term value to shareholders. The assets included 567,000 net acres in the Montney shale, 72,000 net acres in the Duvernay shale and additional acreage in other areas of Alberta. Net production from these assets was about 140 million cubic feet of natural gas per day and about 9,000 barrels of crude, condensate and natural gas liquids per day. The sale of the assets followed the company's ramp down of drilling activity and adjustment of long-term development plans in 2020 and 2021. Beaufort Sea The company holds a 25 percent interest in two exploration licences in the Beaufort Sea. In 2016, the Federal Government of Canada declared Arctic waters off limits to new offshore oil and gas licences for five years subject to review at the end of that period. Existing licences were not impacted. In June 2019, the Federal Government approved selective changes to the Canada Petroleum Resources Act to prohibit and freeze the existing licences through the completion of the Beaufort Regional Strategic Environmental Assessment (BR-SEA) review. In 2022, the prohibition was extended to December 31, 2023 with a second one-year extension. During this time, the Federal Government plans to finalize the BR-SEA for public release which will be subject to a stakeholder review period that will aim to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic. The company continues to hold the licences while maintaining community engagement and participation in the BR-SEA process. Exploratory and development activities regarding oil and gas resources extracted by mining methods The company continues to evaluate other undeveloped, mineable oil sands acreage in the Athabasca region. 11 Present activities Review of principal ongoing activities Kearl Kearl is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract the crude bitumen, which is processed through extraction and froth treatment trains. The company holds a 70.96 percent participating interest in the joint venture and ExxonMobil Canada Properties holds the other 29.04 percent. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. Diluent is natural gas condensate or other light hydrocarbons added to the crude bitumen to facilitate transportation by pipeline and rail. During 2022, the company’s share of Kearl’s net bitumen production was about 157,000 barrels per day and gross production was about 172,000 barrels per day. Total gross production for Kearl was about 242,000 barrels per day (172,000 barrels Imperial’s share), down 21,000 barrels per day (14,000 barrels Imperial's share) compared to 2021, as a result of extreme cold weather impacts in the first quarter of 2022. In 2022, the company successfully completed the startup of the second Boiler Flue Gas Unit, incorporating learnings from the first unit's startup in 2021. This technology recovers waste heat from a boiler’s combustion exhaust to pre-heat process water. Each unit has the potential to reduce operating costs and emissions. Imperial is currently progressing plans to apply this innovative technology on up to four additional boilers by year-end 2023. Cold Lake Cold Lake is an in-situ heavy oil bitumen operation. The product, a blend of bitumen and diluent, is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. During 2022, net bitumen production at Cold Lake was about 106,000 barrels per day and gross production was about 144,000 barrels per day. Gross production increased about 4,000 barrels per day compared to 2021 as a result of improved reliability, production optimizations, and recent capital-efficient infill drilling. Cold Lake has expanded its commercial application of Liquid Addition to Steam for Enhanced Recovery (LASER), with the technology now being applied to approximately 10 per cent of production, resulting in reduced greenhouse gas emissions compared to traditional CSS technology. Syncrude Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit mining methods to extract crude bitumen, and then upgrade it to produce a high-quality, light (32 degrees API), sweet, synthetic crude oil. The company holds a 25 percent participating interest in the joint venture. The produced synthetic crude oil is typically shipped to the company’s refineries, Exxon Mobil Corporation refineries and to other third parties. In 2022, the company’s share of Syncrude’s net production was about 63,000 barrels per day. The gross production was about 77,000 barrels per day, which is an increase of about 6,000 barrels per day compared to 2021, supported by the interconnect pipeline. The Province of Alberta, in its capacity as lessor of Kearl, Cold Lake, and Syncrude oil sands leases, is entitled to a royalty on production. Royalties are subject to the oil sands royalty regulations which are based upon a sliding scale determined largely by the price of crude oil. Delivery commitments The company has no material commitments to provide a fixed and determinable quantity of oil or gas under existing contracts and agreements. 12 Oil and gas properties, wells, operations and acreage Production wells The company’s production of liquids, bitumen and natural gas is derived from wells located exclusively in Canada. The total number of wells capable of production, in which the company had interests at December 31, 2022 and December 31, 2021, is set forth in the following table. The statistics in the table are determined in part from information received from other operators. The total number of wells decreased in 2022 primarily due to divestment activities and the shut-in of multiple non-economical wells. Year ended December 31, 2022 Year ended December 31, 2021 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) 4,277 4,264 2,419 774 4,557 4,509 2,729 885 (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 2022, the company had an interest in 12 gross wells with multiple completions (2021 - 12 gross wells). Land holdings At December 31, 2022 and December 31, 2021, the company held the following oil and gas rights, and bitumen and synthetic crude oil leases, all of which are located in Canada, specifically in the western provinces, in the Canada lands and in the Atlantic offshore. Developed Undeveloped Total thousands of acres 2022 2021 2022 2021 2022 2021 Western provinces (a): Liquids and gas - gross (b) 441 1,059 185 621 626 1,680 - net (c) 260 517 135 350 395 867 Bitumen - gross (b) 196 196 584 584 780 780 - net (c) 182 182 255 255 437 437 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 2 495 495 497 497 Atlantic offshore: Liquids and gas - gross (b) 65 65 146 267 211 332 - net (c) 6 6 22 36 28 42 Total (e) : - gross (b) 823 1,441 2,818 3,375 3,641 4,816 - net (c) 480 737 932 1,161 1,412 1,898 (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). 13 Western provinces The company’s bitumen leases include about 161,000 net acres of oil sands leases near Cold Lake and an area of about 34,000 net acres at Kearl. The company also has about 68,000 net acres of undeveloped, mineable oil sands acreage in the Athabasca region. In addition, the company has interests in other bitumen oil sands leases in the Athabasca areas totalling about 173,000 net acres, which include about 62,000 net acres of oil sands leases in the Clyden area, about 34,000 net acres of oil sands leases in the Aspen area, about 30,000 net acres of oil sands leases in the Corner area, about 29,000 net acres in the Clarke Creek area and about 18,000 net acres in the Chard area. The 173,000 net acres are suitable for in-situ recovery techniques. The company’s share of Syncrude joint venture leases covering about 55,000 net acres accounts for the entire synthetic crude oil acreage. Oil sands leases have an exploration period of 15 years and are continued beyond that point by payment of escalating rentals or by production. The majority of the acreage in Cold Lake, Kearl and Syncrude is continued by production. The company holds interests in an additional 395,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas. In 2022, the company divested its interest in Horn River totalling about 103,000 net acres and its interest in XTO Energy Canada totalling about 365,000 net acres. Crude oil and natural gas leases and licences from the western provinces have exploration periods ranging from two to 15 years and are continued beyond that point by proven production capability. Canada lands Land holdings in Canada lands primarily include exploration licence (EL) acreage in the Beaufort Sea of about 252,000 net acres and significant discovery licence (SDL) acreage in the Mackenzie Delta and Beaufort Sea areas of about 183,000 net acres. Exploration licences on Canada lands have a finite term. If a significant discovery is made, a SDL may be granted that holds the acreage under the SDL indefinitely, subject to certain conditions. The company’s net acreage in Canada lands is either continued by production or held through ELs and SDLs. Atlantic offshore Exploration licences on Atlantic offshore have a finite term. The Atlantic offshore acreage is continued by production licences or held by SDLs. 14 Downstream Supply and trading The company supplements its own production of crude oil, condensate and petroleum products with substantial purchases from a number of other sources at negotiated market prices, in addition to undertaking trading activities. Purchases and sales are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil. Transportation Imperial currently transports the company’s crude oil production and third-party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail. To mitigate pipeline capacity constraints, the company has developed rail infrastructure. The Edmonton rail terminal has total capacity to ship up to 210,000 barrels per day of crude oil. Refining The company owns and operates three refineries, which process predominantly Canadian crude oil. The company purchases finished products to supplement its refinery production. The approximate average daily volumes of refinery throughput and utilization during the three years ended December 31, 2022, and the daily rated capacities of the refineries as at December 31, 2022, were as follows. Refinery throughput (a) Rated capacities (b) Year ended December 31 at December 31 thousands of barrels per day 2022 2021 2020 2022 Strathcona, Alberta 195 172 170 197 Sarnia, Ontario 113 106 86 123 Nanticoke, Ontario 110 101 84 113 Total 418 379 340 433 Utilization of refinery capacity (percent) 98 89 80 (a) Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units. (b) Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing. 2022 Improved refinery throughput in 2022 was primarily driven by increased demand and reduced turnaround activity. 2021 Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partially offset by a planned turnaround at Strathcona. Distribution The company maintains a nationwide distribution system to move petroleum products to market by pipeline, tanker, rail and road transport. The company owns and operates fuel terminals across the country, as well as natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products pipeline companies. 15 Marketing The company markets petroleum products throughout Canada under well-known brand names, most notably Esso and Mobil, to all types of customers. Imperial supplies petroleum products through Esso and Mobil-branded sites and independent marketers. At the end of 2022, there were about 2,400 sites operating under a branded wholesaler model, in alignment with Esso and Mobil brand standards, whereby Imperial supplies fuel to independent third parties. Imperial also sells petroleum products, including fuel, asphalt and lubricants, to large industrial and transportation customers, independent marketers, resellers, as well as other refiners. The company serves agriculture, residential heating and commercial markets through branded fuel and lubricant resellers. The approximate daily volumes of net petroleum products (excluding purchases / sales contracts with the same counterparty) sold during the three years ended December 31, 2022, are set out in the following table. thousands of barrels per day 2022 2021 2020 Gasolines 229 224 215 Heating, diesel and jet fuels 176 160 146 Lube oils and other products 47 45 40 Heavy fuel oils 23 27 20 Net petroleum product sales 475 456 421 In 2022, improved petroleum product sales primarily reflects increased demand. In 2021, improved petroleum product sales primarily reflects reduced impacts associated with the COVID-19 pandemic. Chemical The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates, polyethylene resin, and markets refinery grade propylene. Its petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the company’s petroleum refinery. The company’s total petrochemical sales volumes during the three years ended December 31, 2022, were as follows. thousands of tonnes 2022 2021 2020 Total petrochemical sales 842 831 749 In 2022, sales volumes increased primarily due to higher sales of propylene and polyethylene, partially offset by lower intermediates. In 2021, sales volumes increased primarily due to higher sales of intermediates and aromatics. 16 Human capital resources Imperial operates in a complex, competitive and changing business environment where decisions and risks play out over time horizons that are often decades in length. This long-term orientation underpins the company’s philosophy on talent development. Talent development begins with recruiting exceptional candidates and continues with individually planned experiences and training designed to facilitate broad development and a deep understanding of our business across the business cycle. The company’s compensation is market competitive, long-term oriented, and highly differentiated by individual performance. In addition, benefits and workplace programs support the company’s talent management approach, and are designed to attract and retain employees for a long-term career. Overall, this multifaceted approach has resulted in strong employee retention. Imperial views diversity as an opportunity. The company encourages and respects diversity of thought, ideas, and perspective in its workforce. The company considers diversity through all stages of employment including recruitment, training and development of its employees. Imperial’s goal is to reflect the mix and diversity of the communities where it operates, and it continues to focus on diverse representation at all levels of the organization. The number of regular employees was about 5,300 at the end of 2022 (2021 - 5,400, 2020 - 5,800). Regular employees are defined as active executive, management, professional, technical and wage employees who work full-time or part-time for the company and are covered by the company’s benefit plans and programs. Competition The Canadian energy and petrochemical industries are highly competitive. Competition exists in the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The energy and petrochemical industries also compete with other industries in supplying the energy, fuel and chemical needs of both industrial and individual consumers. Certain industry participants, including Imperial, are expanding investments in lower-emission energy and emission-reduction services and technologies. 17 Government regulations Petroleum, natural gas and oil sands rights Most of the company’s petroleum, natural gas and oil sands rights were acquired from governments, either federal or provincial. These rights, in the form of leases or licences, are generally acquired for cash or work commitments. A lease or licence entitles the holder to explore for petroleum, natural gas and / or oil sands on the leased lands for a specified period. In western provinces, the lease holder can produce the petroleum or natural gas discovered on the leased lands and retains the rights based on continued production. Oil sands leases are retained by meeting the minimum level of evaluation, payment of rentals, or by production. The holder of a licence relating to Canada lands and the Atlantic offshore can apply for a SDL if a discovery is made. If granted, the SDL holds the lands indefinitely subject to certain conditions. The holder may then apply for a production licence in order to produce petroleum or natural gas from the licenced land. Project approval Approvals and licences from relevant provincial or federal governmental or regulatory bodies are required for the company to carry out, or make modifications to, its oil and gas activities. The project approval process for major projects can involve, among other things, environmental assessments (including relevant mitigation measures), stakeholder and Indigenous consultation and input regarding project concerns, and public hearings. Approval may be subject to various conditions and commitments arising through these processes. Approval of large energy projects may be impacted by the environmental assessment framework under Canada's Impact Assessment Act (IAA). The IAA includes broader consideration for social, health, and gender-based impacts, the impact on Canada’s climate change commitments (including a requirement under the Strategic Assessment for Climate Change to provide a credible plan for the project to deliver net-zero greenhouse gas emissions by 2050), reliance on strategic and regional assessments and adjusted regulatory review timelines. Environmental protection The company regards protecting the environment in connection with its various operations as a priority. The company is subject to extensive environmental regulations in Canada that apply to all phases of exploration, development, operation, and final closure. These requirements cover the management and monitoring of potential environmental impacts during active operations, including practices for land disturbance, wildlife protection, specifications for equipment operation and material storage and limitations on discharges to the environment. It also includes conducting environmental surveys and collecting continuous operational measurements and sampling to confirm that environmental practices are adequately protecting the environment. These regulations also specify the actions and requirements for final reclamation, abandonment and closure of facilities. The company works in cooperation with government agencies, industry associations and communities to address existing, and to anticipate potential, environmental protection issues. The company also maintains extensive operating procedures, processes and emergency response plans to address environmental risks at its operations. As discussed in Item 1A. “Risk factors” in this report, compliance with existing and potential future government regulations, including environmental regulations, may have material effects on the capital expenditures, earnings, and competitive position of the company. Imperial takes new and ongoing measures throughout its operations each year to prevent and minimize the impact of its operations on air, land and water. These include significant investments in refining infrastructure and technology to manufacture clean fuels, continued evaluation and implementation of new technologies to reduce greenhouse gas emissions, adherence to federal and provincial greenhouse gas emissions reduction and reporting programs, enhanced water and land management, and expenditures for asset retirement obligations. In the past five years, the company has made capital and operating expenditures of about $4.5 billion on environmental protection and facilities. In 2022, the company’s environmental capital and operating expenditures totalled approximately $1.4 billion, which was spent primarily on activities to protect the air, land and water, including remediation projects. Environmental expenditures are expected to increase to approximately $1.8 billion in 2023, with capital expenditures expected to account for approximately 65 percent of the total. Costs for 2024 are anticipated to increase to approximately $2.2 billion, with capital expenditures expected to account for approximately 69 percent of the total. 18 Crude oil Production The maximum allowable gross production of crude oil from wells in Canada is subject to limitations by various regulatory authorities on the basis of engineering and conservation principles. Additionally, the Government of Alberta has in the past used temporary mandatory production curtailment regulations to impose production limits on large producers in Alberta, such as those implemented in 2019 and repealed in 2021. Exports Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require the prior approval of the Canada Energy Regulator (CER) and the Government of Canada. Export contracts of less than one year for light crude oil and petroleum products and two years for heavy crude oil (including bitumen) require an order from the CER. Natural gas Production The maximum allowable gross production of natural gas from wells in Canada is subject to limitations by various regulatory authorities. These limitations are to ensure oil recovery is not adversely impacted by accelerated gas production practices. These limitations do not impact gas reserves, only the timing of production of the reserves and did not have a significant impact on Imperial’s 2022 gas production rates. Exports The Government of Canada has the authority to regulate the export price for natural gas. Exports of natural gas from Canada require approval by the CER and the Government of Canada. The Government of Canada allows the export of natural gas by CER order without volume limitation for terms not exceeding 24 months. Royalties The Government of Canada and the provinces in which the company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights. Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed on crude oil, natural gas and natural gas liquids vary depending on a number of parameters, including well production volumes, selling prices and recovery methods. For information with respect to royalties for Kearl, Cold Lake and Syncrude, see “Upstream” section entitled “Present activities” under Item 1 on page 12 . Investment Canada Act The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. The acquisition of natural resource properties may, in certain circumstances, be considered a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval. The Act also requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. The Government of Canada is also authorized to take any measures that it considers advisable to protect national security, including the outright prohibition of a foreign investment in Canada. By virtue of the majority stock ownership of the company by ExxonMobil, the company is considered to be an entity which is not controlled by Canadians. 19 Competition Act The Competition Bureau seeks to ensure that Canadian businesses and consumers prosper in a competitive and innovative marketplace. The Competition Bureau is responsible for the administration and enforcement of the Competition Act (the Act). A merger transaction, whether or not notifiable, is subject to examination by the Commissioner of the Competition Bureau to determine whether the merger will have, or is likely to have, the effect of preventing or lessening substantially competition in a definable market. The assessment of the competitive effects of a merger is made with reference to the factors identified under the Act. An Advance Ruling Certificate (ARC) may be issued by the Commissioner to a party or parties to a proposed merger transaction who want to be assured that the transaction will not give rise to proceedings under section 92 of the Act. An ARC may be issued when the Commissioner is satisfied that there would not be sufficient grounds on which to apply to the Competition Tribunal for an order against a proposed merger. The issuance of an ARC is discretionary. An ARC cannot be issued for a transaction that has been completed, nor does an ARC ensure approval of the transaction by any agency other than the Competition Bureau. The company online The company’s website www.imperialoil.ca contains a variety of corporate and investor information free of charge, including the company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the SEC. The SEC’s website, www.sec.gov, contains reports, proxy and information statements, interactive data files, and other information regarding issuers that are submitted and posted electronically with the SEC. 20