What changed in this filing

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Item 1. Business

2024-02-28 compared with 2023-02-22 · 69 added, 76 removed, 327 unchanged (31% of the section changed)

17 unchanged sentences

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.

The table below summarizes the net proved reserves for the company, as at December 31, 2023, 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 ending December 31.

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.

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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.

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 Imperial’s proved reserves.

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As at December 31, 2023, approximately 10 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 218 million oil-equivalent barrels.

Proved undeveloped reserves are associated with Syncrude and Cold Lake.

Proved undeveloped reserves are associated with Syncrude, Kearl and Cold Lake.

This compared to 240 million oil-equivalent barrels of proved undeveloped reserves reported at the end of 2022.

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.

The decrease of 22 million oil-equivalent barrels of proved undeveloped reserves is mainly attributed to the migration of Cold Lake proved undeveloped reserves to proved developed reserves following infill development drilling and the start-up of the Grand Rapids Phase 1 project.

As at December 31, 2023 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 $167 million during the year to progress the development of proved undeveloped reserves at Cold Lake and Syncrude.

The company made investments of about $391 million during the year to progress the development of proved undeveloped reserves at Cold Lake, Kearl and Syncrude.

These investments represented about 35 percent of the $1,108 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” on page 47 of this report for a narrative discussion on the material changes.

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, 2022 was as follows.

The company’s average daily oil production by final products sold during the three years ended December 31, 2023 was as follows.

All reported production volumes were from Canada.

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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) 2023 2022 2021

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(a) Liquids include crude oil, condensate and NGLs.

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.

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).

Average unit production costs

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(a) Includes liquids, bitumen, synthetic crude oil and natural gas.

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.

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.

Drilling and other exploratory and development activities

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In 2023, wells drilled to add productive capacity include 32 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.

In 2022, wells drilled to add productive capacity include 24 development wells at Cold Lake.

Wells drilling

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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.

In 2023, additional wells were drilled on existing phases, as well as development drilling to add productive capacity.

In 2024, a 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 having commenced in 2023 and start-up planned in 2025.

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 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 started in December 2023 and is expected to last until the end of the first quarter of 2024, with production ramping up over the following months.

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.

Aspen and other in-situ oil sands activities

In October 2018, the company received regulatory approval for the Aspen 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.

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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.

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.

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.

The Enhanced Bitumen Recovery Technology (EBRT) field pilot on the Aspen lease received funding approval in 2023, with development work underway for pilot startup by 2027.

The pilot will test technology that has the potential to deliver higher bitumen production rates and lower greenhouse gas emissions as compared to industry average SAGD operations.

Work progresses on technical and technology evaluations to support potential Clarke Creek, Corner, Clyden and Chard in-situ development regulatory applications.

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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.

The company holds a 25 percent interest in two exploration licences in the Beaufort Sea.

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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.

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

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During 2023, the company’s share of Kearl’s net bitumen production was about 177,000 barrels per day and gross production was about 191,000 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.

Total gross production for Kearl was about 270,000 barrels per day (191,000 barrels Imperial’s share), up 28,000 barrels per day (19,000 barrels Imperial's share) compared to 2022, as a result of improved reliability, plant capacity utilization, and mine equipment productivity.

In 2023, Kearl completed its multiyear program to convert its 81 haul trucks to autonomous operation.

Imperial is now one of the largest autonomous mine fleet operators in the world and continues to capture productivity improvements while also reducing costs and further enhancing operational safety.

In 2023, the company successfully completed its multiyear program to install six Boiler Flue Gas units.

This technology recovers waste heat from a boiler’s combustion exhaust to preheat process water and reduce greenhouse gas emissions.

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.

In 2023, net bitumen production at Cold Lake was about 106,000 barrels per day.

The gross production was about 135,000 barrels per day, which is a decrease of about 9,000 barrels per day compared to 2022.

Cold Lake continues to utilize its commercial application of Liquid Addition to Steam f or Enhanced Recovery (LASER), with the technology now being applied to approximately 15 percent of production, resulting in reduced greenhouse gas emissions compared to traditional Cyclic Steam Stimulation (CSS) technology.

Grand Rapids Phase 1 (GRP1) will be the first SA-SAGD project in the industry and is expected to reduce greenhouse gas emissions intensity by up to 40 percent compared to existing CSS technology.

The initial steam injection phase started in December 2023 and is expected to last until the end of the first quarter of 2024, with production ramping up over the following months.

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.

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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.

In 2023, the company’s share of Syncrude’s net productio n was about 67,000 barrels per day.

The gross production was about 76,000 barrels per day, which is a decrease of about 1,000 barrels per day compared to 2022.

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.

Oil and gas properties, wells, operations and acreage

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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 total number of wells capable of production, in which the company had interests at December 31, 2023 and December 31, 2022, 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 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

The total number of wells decreased in 2023 primarily due to the shut-in of multiple non-economical wells.

Year ended December 31, 2023

Year ended December 31, 2022

Crude oil Natural gas Crude oil Natural gas

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The company holds interests in an additional 388,000 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.

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.

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.

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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.

The company currently transports its crude oil production and third-party crude oil required to supply refineries by contracted pipelines, common carrier pipelines and rail.

The company has rail infrastructure to mitigate pipeline capacity constraints.

The company owns and operates three refineries, which process predominantly Canadian crude oil.

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(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.

(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 2023 primarily reflects the impact of planned turnaround activities at Strathcona and Sarnia refineries.

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

Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19 pandemic, partially offset by a planned turnaround at Strathcona.

The company maintains a nationwide distribution system to move petroleum products to market by pipeline, tanker, rail and road transport.

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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 supplies petroleum products through Esso and Mobil-branded sites and independent marketers.

At the end of 2023, there were about 2,500 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.

6 unchanged sentences

Net petroleum product sales 471 475 456

In 2023, lower petroleum product sales were primarily driven by lower wholesale customer volume.

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.

The company’s Chemical operations manufacture and market benzene, aromatic and aliphatic solvents, plasticizer intermediates, polyethylene resin, and markets refinery grade propylene.

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Total petrochemical sales 820 842 831

In 2023, sales volumes decreased primarily due to planned maintenance activities.

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.

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

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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.

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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 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 5,300 at the end of 2023 (2022 - 5,300, 2021 - 5,400).

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.

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.

The Canadian energy and petrochemical industries are highly competitive.

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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.

In October 2023, the Supreme Court of Canada ruled that the new federal assessment scheme was unconstitutional in part.

Legislative and regulatory amendments have yet to be made to address this decision.

The impact of this legislation and its expected amendments is not fully apparent, but it may impact the cost, manner, duration and ability to advance large energy projects and project expansions.

Environmental protection

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In 2023, the company’s environmental capital and operating expenditures totalled approximately $1.7 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.

Environmental expenditures are expected to increase to approximately $1.9 billion in 2024, with capital expenditures expected

to account for approximately 52 percent of the total.

Costs for 2025 are anticipated to be approximately $1.5 billion, with capital expenditures expected to account for approximately 43 percent of the total.

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.

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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 .

For information with respect to royalties for Kearl, Cold Lake and Syncrude, see "Upstream" section entitled "Present activities" under Item 1.

Investment Canada Act

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Compared sentence by sentence after normalising whitespace, quotation marks, case and digits, so re-formatting and restated figures do not read as changed language. Wording changes appear as one removal and one addition. The current filing and the prior one are authoritative.

What changed 10-K

Item 1. Business