What changed in this filing

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Item 1. Business

2022-02-23 compared with 2021-02-24 · 84 added, 107 removed, 334 unchanged (36% of the section changed)

6 unchanged sentences

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 and a leading marketer of petroleum products.

It is also a major producer of petrochemicals.

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 and biofuels.

The company’s operations are conducted in three main segments:

3 unchanged sentences

Chemical operations consist of the manufacturing and marketing of various petrochemicals.

Financial information about segments and geographic areas for the company is contained in the “Financial section” of this report under note 3 to the consolidated financial statements:

Operating data and financial information about the company’s business segments are contained in this report under the following:

“Management’s discussion and analysis of financial condition and results of operations” and the “Financial section” under note 2 to the consolidated financial statements:

“Business segments”.

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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, among 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.

1 unchanged sentence

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.

As a result of low prices during 2020, under the U.S.

Securities and Exchange Commission definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves at year-end

Amounts no longer qualifying as proved reserves include 2.2 billion barrels of bitumen at Kearl and 0.6 billion barrels of bitumen at Cold Lake.

Among the factors that could result in portions of these amounts being recognized again as proved reserves at some point in the future are a recovery in the SEC price basis, a further decline in costs, and / or operating efficiencies.

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

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

Securities and Exchange Commission (SEC) definition.

As a result of improved prices in 2021, under the U.S.

Securities and Exchange Commission definition of proved reserves, an additional 1.7 billion barrels of bitumen at Kearl and 0.5 billion barrels of bitumen at Cold Lake qualified as proved reserves at year-end

Technologies used in establishing proved reserves estimates

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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 proprietary seismic processing software, proprietary reservoir modeling and simulation software, and commercially available data analysis packages.

The tools used to interpret the data included seismic processing software, reservoir modeling and simulation software, and data analysis packages.

In some circumstances, where appropriate analog reservoirs were available, reservoir parameters from these analogs were used to increase the quality of and confidence in the reserves estimates.

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As at December 31, 2021, approximately 14 percent of the company’s proved reserves were proved undeveloped reflecting volumes of 386 million oil-equivalent

Proved undeveloped reserves are associated with Syncrude and Cold Lake.

Proved undeveloped reserves are associated with Syncrude, Cold Lake, and the Montney and Duvernay unconventional assets.

This compared to 138 million oil-equivalent

barrels of proved undeveloped reserves reported at the end of 2020.

The decrease of 259 million oil-equivalent

barrels of proved undeveloped reserves includes a decrease of 335 million oil-equivalent

barrels at Cold Lake and a decrease of 57 million oil-equivalent

barrels at the Montney and Duvernay unconventional assets, partially offset by an increase of 133 million oil-equivalent

The increase of 248 million oil-equivalent

barrels of proved undeveloped reserves includes an increase of 262 million oil-equivalent barrels at Cold Lake, an increase of 6 million oil-equivalent

barrels at the Montney and Duvernay unconventional assets, partially offset by a decrease of 20 million oil-equivalent

barrels at Syncrude.

Conversion of proved undeveloped reserves into proved developed was 34 million oil-equivalent

barrels in 2020, associated with Cold Lake and the Montney and Duvernay unconventional assets.

barrels during 2021, associated with Cold Lake and the Montney and Duvernay unconventional assets.

Proved undeveloped reserves that have remained undeveloped for five years or more represent about 53 percent (204 million oil-equivalent

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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 $209 million during the year to progress the development of proved undeveloped reserves at Cold Lake, the Montney and Duvernay unconventional assets and at Syncrude.

The company made investments of about $124 million during the year to progress the development of proved undeveloped reserves at Cold Lake, Syncrude and the Montney and Duvernay unconventional assets.

These investments represented about 20 percent of the $632 million in total reported Upstream capital and exploration expenditures.

Investments made by the company to develop quantities which no longer meet the SEC definition of proved reserves as a result of low prices during 2020 are included in these capital and exploration expenditures.

Oil and gas production, production prices and production costs

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Liquids include crude oil, condensate and NGLs.

In 2020, Imperial’s average Canadian dollar realizations for bitumen decreased primarily due to a decrease in Western Canada Select.

The company’s average Canadian dollar realizations for synthetic crude decreased generally in line with West Texas Intermediate, adjusted for changes in exchange rates and transportation costs.

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

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

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 increased generally in line with West Texas Intermediate (WTI), adjusted for changes in exchange rates and transportation costs.

In 2020, Imperial’s average Canadian dollar realizations for bitumen decreased primarily due to a decrease in WCS.

The company’s average Canadian dollar realizations for synthetic crude decreased generally in line with WTI, adjusted for changes in exchange rates and transportation costs.

Average unit production costs

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Includes liquids, bitumen, synthetic oil and natural gas.

In 2021, bitumen unit production costs were higher, primarily driven by higher energy costs.

In 2021, synthetic oil unit production costs were higher, primarily driven by higher maintenance costs and mine tailings spend.

In 2020, bitumen unit production costs were lower, primarily driven by higher Kearl production due to improved reliability and reduced downtime related to the addition of supplemental crushing facilities in 2020, and cost saving activities in response to market conditions.

In 2020, synthetic oil unit production costs were lower, primarily driven by cost saving activities in response to market conditions.

In 2019, bitumen unit production costs were higher, primarily driven by Kearl costs associated with improving reliability and mine performance, and increased mine material movement.

In 2019, synthetic oil unit production costs were lower, primarily driven by higher production due to the absence of the site-wide power disruption at Syncrude in 2018 and lower maintenance costs.

In 2020, synthetic oil unit production costs were lower, primarily driven by cost saving activities in response to

market conditions.

Drilling and other exploratory and development activities

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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 2019, wells drilled to add productive capacity include 14 development wells at Cold Lake and 14 wells 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 2019, wells drilled to add productive capacity include 14 development wells at Cold Lake and 14 wells associated with the Montney and Duvernay unconventional assets.

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Aspen, Cold Lake expansion and other oil sands activities

The company filed a regulatory application for a new in-situ

oil sands project at Aspen in December 2013, using steam-assisted gravity drainage (SAGD) technology to develop the project in three phases producing about 45,000 barrels per day before royalties, per phase.

In 2015, the company amended the regulatory application to develop the Aspen project using solvent-assisted, steam-assisted gravity drainage (SA-SAGD)

The technology significantly improves capital efficiency and lowers greenhouse gas intensity versus the existing SAGD technologies.

The project is proposed to be executed in two phases producing about 75,000 barrels per day before royalties, per phase.

In October 2018, regulatory approval for the Aspen in-situ

project was received from the Alberta Energy Regulator.

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.

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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.

Aspen’s project pace will be continuously evaluated, although major investment remains on hold.

Aspen remains an important development project for Imperial.

In March 2016, Imperial filed a regulatory application for an expansion project at Cold Lake to develop the Grand Rapids interval using SA-SAGD

The project is proposed to produce 50,000 barrels per day, before royalties.

In August 2018, regulatory approval for the expansion project at Cold Lake was received from the Alberta Energy Regulator.

The company continues to progress the project with a slower pace.

Work progresses on technical evaluations to support potential Clarke Creek, Corner, Clyden and Chard in-situ

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.

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.

Imperial continues to progress this opportunity.

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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Montney and Duvernay

The company has ramped down development drilling in its Montney and Duvernay unconventional assets in the western provinces.

Imperial has re-assessed

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

The assets that will not be developed are non-core,

The company owns a 50 percent interest in XTO Energy Canada which includes the Montney and Duvernay unconventional assets located in central Alberta.

In 2020, the company ramped down development drilling and revised long-term development plans to exclude a significant portion of the non-core,

non-producing

undeveloped assets.

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

The decision resulted in a non-cash,

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

The company retains its interest in these resources.

Imperial continues to produce from its developed acreage.

In 2007, the company acquired a 50 percent interest in an exploration licence in the Beaufort Sea.

As part of the evaluation, a 3-D

seismic survey was conducted in 2008 and the company has since carried out data collection programs to support environmental studies and safe exploration drilling operations.

In 2010, the company executed an agreement to cross-convey interests with another company to acquire a 25 percent interest in an additional Beaufort Sea exploration licence.

As a result of that agreement, the company operates both licences and its interest in the original licence was reduced to 25 percent.

In 2013, the company and its joint venture partners filed a project description, initiating the formal regulatory review of the project.

and undeveloped areas of the Montney and Duvernay unconventional assets.

In 2021, the company resumed limited drilling activity to develop select portions of the acreage with other operators.

In January 2022, Imperial announced its intention to market its interest in XTO Energy Canada jointly with ExxonMobil Canada, consistent with Imperial’s strategy to focus its upstream resources and efforts on its key oil sands assets.

A definitive decision to sell the Montney and Duvernay unconventional assets has not been made.

Operations will continue as normal throughout the marketing process and should the process not result in a sale.

XTO Energy Canada net production from these assets is about 140 million cubic feet of natural gas per day and about 9,000 barrels per day of crude, condensate and natural gas liquids.

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.

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In June 2019, the Federal Government approved selective changes to the Canada Petroleum Resources Act

to provide an indefinite prohibition and freeze of the existing licences through the completion of the Beaufort Sea Regional Environmental Assessment (BR-SEA)

The Federal Government continues to consult with stakeholders as part of the BR-SEA

to address regional social, environmental, economic and spill response impacts of natural resource development in the Arctic.

to prohibit and freeze the existing licences through the completion of the Beaufort Sea Regional Environmental Assessment (BR-SEA)

In 2021, the prohibition was extended until December 31, 2022, during which time the Federal Government will continue to consult with stakeholders as part of the BR-SEA

review 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

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During 2021, the company’s share of Kearl’s net bitumen production was about 178,000 barrels per day and gross production was about 186,000 barrels per day.

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

of all units through early 2020.

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

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

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

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

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

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

As a result of low prices during 2020, under the SEC definition of proved reserves, certain quantities of bitumen that qualified as proved reserves in prior years did not qualify as proved reserves at year-end

Amounts no longer qualifying as proved reserves include 2.2 billion barrels of bitumen at Kearl.

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

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

SEC definition.

Total gross production for Kearl was about 263,000 barrels per day (186,000 barrels Imperial’s share), setting a new record for Kearl and continuing multi-year improvements in reliability, costs and performance.

Total gross production increased about 41,000 barrels per day (28,000 barrels Imperial’s share) compared to 2020, which was the asset’s previous annual production record.

Increased production was primarily driven by the absence of prior year production balancing with market demands, supported by the supplemental crushers and other reliability improvements.

Kearl also eliminated its fall turnaround and transitioned to a single annual turnaround, one year ahead of schedule.

Kearl successfully started up the first Kearl Boiler Flue Gas heat recovery unit in 2021.

This technology recovers waste heat from a boiler’s combustion exhaust to pre-heat

process water.

This not only has the potential to reduce operating costs, but also emissions by up to 30,000 tonnes / year of carbon dioxide equivalent.

Imperial is currently progressing plans to apply this innovative technology on up to five additional boilers.

Cold Lake is an in-situ

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During 2021, net bitumen production at Cold Lake was about 114,000 barrels per day and gross production was about 140,000 barrels per day.

Amounts no longer qualifying as proved reserves include 0.6 billion barrels of bitumen at Cold Lake.

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

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

SEC definition.

Gross production increased about 8,000 barrels per day compared to 2020 as a result of improved reliability, production optimizations, and recent capital-efficient infill drilling.

Syncrude is a joint venture established to recover shallow deposits of oil sands using open-pit

3 unchanged sentences

In 2021, the company’s share of Syncrude’s net production of synthetic crude oil was about 62,000 barrels per day and gross production was about 71,000 barrels per day.

On September 30, 2021, operatorship successfully transferred from Syncrude Canada to Suncor.

With the transition complete, additional synergies are expected to be captured, in an effort to maximize profitability and improve reliability.

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.

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Net acres exclude the interests of others.

Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories and Yukon regions (Yukon - 2019 only).

Canada lands include the Arctic Islands, Beaufort Sea / Mackenzie Delta, and other Northwest Territories.

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)

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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 174,000 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 18,000 net acres in the Chard area and about 29,000 net acres in the Clarke Creek area.

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

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The company holds interests in an additional 867,000 net acres of developed and undeveloped land in the western provinces related to crude oil and natural gas, including about 369,000 net acres associated with the company’s unconventional portfolio in Alberta.

Imperial has re-assessed

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

These interests include lands that are part of Imperial’s recent announcement to market its interest in XTO Energy Canada jointly with ExxonMobil Canada.

XTO Energy Canada assets include 568,000 net acres in the Montney shale, 85,000 net acres in the Duvernay shale and additional acreage in other areas of Alberta;

Imperial owns a 50 percent interest in XTO Energy Canada.

This is consistent with Imperial’s strategy to focus its upstream resources and efforts on its key oil sands assets.

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.

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.

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The Atlantic offshore acreage is continued by production licences or held by SDLs.

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.

Purchases are made under both spot and term contracts from domestic and foreign sources, including ExxonMobil.

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 uncertainty associated with the timing of industry pipeline projects and pipeline capacity constraints, the company has developed rail infrastructure.

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.

1 unchanged sentence

The company purchases finished products to supplement its refinery production.

The approximate average daily volumes of refinery throughput during the three years ended December 31, 2020, and the daily rated capacities of the refineries as at December 31, 2020, were as follows.

The approximate average daily volumes of refinery throughput and utilization during the three years ended December 31, 2021, and the daily rated capacities of the refineries as at December 31, 2021, were as follows.

Refinery throughput (a)

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Nanticoke, Ontario

Utilization of refinery capacity (percent)

Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.

1 unchanged sentence

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.

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

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

Improved refinery throughput in 2021 primarily reflects reduced impacts associated with the COVID-19

pandemic, partially offset by a planned turnaround at Strathcona.

Lower throughput was driven by reduced demand due to the COVID-19

pandemic, partially offset by lower refinery turnaround activity and reliability events, including impacts from the Sarnia fractionation tower incident which occurred in April 2019.

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

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

Reduced throughput was mainly due to higher planned turnaround activities and impacts from the Sarnia fractionation tower incident which occurred in April 2019.

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

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Net petroleum product sales

In 2021, improved petroleum product sales primarily reflects reduced impacts associated with the COVID-19

In 2020, lower sales were primarily driven by reduced demand due to the COVID-19

In 2019, lower sales volumes were mainly due to lower refinery throughput.

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

3 unchanged sentences

Total petrochemical sales

In 2021, sales volumes increased primarily due to higher sales of intermediates and aromatics.

In 2020, sales volumes increased primarily due to higher sales of intermediates.

In 2019, sales volumes decreased primarily due to lower aromatics and intermediates sales.

Human capital resources

7 unchanged sentences

The company encourages and respects diversity of thought, ideas, and perspective in its workforce.

The company considers diversity though all stages of employment including recruitment, training and development of its employees.

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 5,400 at the end of 2021 (2020 - 5,800, 2019 - 6,000).

Regular employees are defined as 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 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.

1 unchanged sentence

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

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In 2019, the Canadian government implemented a new environmental assessment framework in Canada under the Impact Assessment Act

, which may impact the manner in which large energy projects are approved.

Changes from the previous environmental assessment legislation include broader consideration for social, health, and gender-based impacts, the impact on Canada’s climate change commitments, reliance on strategic and regional assessments and adjusted regulatory review timelines.

(IAA), which may impact the manner in which large energy projects are approved.

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

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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, in December 2018, the Government of Alberta introduced temporary mandatory production curtailment regulations, which took effect on January 1, 2019.

These regulations enable the government to impose production limits on large producers in Alberta.

Mandatory production curtailments were eliminated effective December 2020, but the regulatory authority to impose curtailments remains in place.

The duration of these regulations is uncertain.

Additionally, the Government of Alberta has in the past used temporary mandatory production curtailment regulations to impose production limits on large producers in Alberta.

Mandatory production curtailments were implemented in January 2019 and eliminated in December 2020.

By the end of 2021, the regulatory authority to impose curtailments was repealed.

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.

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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.

Section 102 of the Act provides that 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.

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.

9 unchanged sentences

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