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ADVISORIES

In this Annual Information Form (AIF), references to “Suncor” or “the company” mean Suncor Energy Inc., its subsidiaries, partnerships and joint arrangements (including those identified in Note 29 of the company’s 2021 audited Consolidated Financial Statements), unless the context otherwise requires. Suncor Energy Inc. has numerous direct and indirect subsidiaries, partnerships and joint arrangements (“affiliates”), which own and operate assets and conduct activities in different jurisdictions. The terms “Suncor” or “the company” in this AIF are used herein for simplicity of communication and only mean that there is an affiliation with Suncor Energy Inc., without necessarily identifying the specific nature of the affiliation. The use of such terms in any statement herein does not mean that they apply to Suncor Energy Inc. or any particular affiliate, and does not waive the corporate separateness of any affiliate. For further clarity, Suncor Energy Inc. does not directly operate or own assets in the U.S. References to the “Board of Directors” or the “Board” mean the Board of Directors of Suncor Energy Inc.

All financial information is reported in Canadian dollars, unless otherwise noted. Production volumes are presented on a working-interest basis, before royalties, unless otherwise noted. Libyan production volumes are presented on an economic basis.

References to the 2021 audited Consolidated Financial Statements mean Suncor’s audited Consolidated Financial Statements prepared in accordance with Canadian generally accepted accounting principles (GAAP), which is within the framework of International Financial Reporting Standards (IFRS), the notes thereto and the auditor’s report thereon, as at and for each year in the two-year period ended December 31, 2021. References to the MD&A mean Suncor’s Management’s Discussion and Analysis, dated February 23, 2022.

This AIF contains forward-looking statements based on Suncor’s current plans, expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, including those discussed in this document in the Risk Factors section, many of which are beyond the company’s control. Users of this information are cautioned that actual results may differ materially. Refer to the Advisory – Forward-Looking Information and Non-GAAP Financial Measures section of this AIF for information regarding risk factors and material assumptions underlying the forward-looking statements.

Information contained in or otherwise accessible through Suncor’s website www.suncor.com does not form a part of this AIF and is not incorporated into this AIF by reference.

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GLOSSARY OF TERMS AND ABBREVIATIONS

Common Industry Terms

Products

Crude oil is a mixture, consisting mainly of pentanes and heavier hydrocarbons, that exists in the liquid phase in reservoirs and remains liquid at atmospheric pressure and temperature. Crude oil may contain small amounts of sulphur and other non-hydrocarbons, but does not include liquids obtained in the processing of natural gas.

Bitumen is a naturally occurring solid or semi-solid hydrocarbon, consisting mainly of heavier hydrocarbons that are too heavy or thick to flow or be pumped without being diluted or heated, and that is not primarily recoverable at economic rates through a well without the implementation of enhanced recovery methods. After it is extracted, bitumen may be upgraded into crude oil and other petroleum products.

Light crude oil is crude oil with a relative density greater than 31.1 degrees API gravity.

Medium crude oil is crude oil with a relative density greater than 22.3 degrees API gravity and less than or equal to 31.1 degrees API gravity.

Heavy crude oil is crude oil with a relative density greater than 10.0 degrees API gravity and less than or equal to 22.3 degrees API gravity.

Synthetic crude oil (SCO) is a mixture of liquid hydrocarbons derived by upgrading bitumen and may contain sulphur or other non-hydrogen compounds. SCO with a lower sulphur content is referred to as sweet synthetic crude oil, while SCO with a higher sulphur content is referred to as sour synthetic crude oil.

Natural gas is a mixture of lighter hydrocarbons that exist either in the gaseous phase or in solution in crude oil in reservoirs but are gaseous at atmospheric conditions. Natural gas may contain sulphur or other non-hydrocarbon compounds.

Conventional natural gas is natural gas that occurs in a normal, porous, permeable reservoir rock and that, at a particular time, can be technically and economically produced using normal production practices.

Natural gas liquids (NGLs) are hydrocarbon components that can be recovered from natural gas as liquids, including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons. Liquefied petroleum gas (LPG) consists predominantly of propane and/or butane and, in Canada, it frequently includes ethane.

Oil and gas exploration and development terms

Development costs are costs incurred to obtain access to reserves and to provide facilities for extracting, treating, gathering and storing oil and gas from reserves.

Exploration costs are costs incurred in identifying areas that may warrant examination and in examining specific areas that are considered to have prospects that may contain oil and gas reserves, including costs of drilling exploratory wells and exploratory-type stratigraphic test wells.

Field is a defined geographical area consisting of one or more pools containing hydrocarbons.

Oil sands are deposits of sand, sandstone or other sedimentary rocks that contain crude bitumen.

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Reservoir is a subsurface rock unit that contains a potentially recoverable accumulation of petroleum.

Wells

Appraisal wells are drilled into a discovered hydrocarbon accumulation to further understand the extent and size of the accumulation.

Cuttings reinjection wells are drilled for the safe disposal of drilling waste, including drill cuttings, mud slurry, old drilling fluids and waste water, in order to minimize the environmental impact.

Delineation wells are drilled to define the extent of known accumulations of petroleum for the assignment of reserves. This includes wells drilled for the purpose of assessing the stratigraphy, structure and bitumen saturation of an oil sands lease.

Development wells are drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

Disposal wells are drilled in areas where excess fluids from operations can be safely injected for safe disposal. The fluid is pumped into a subsurface formation sealed off from other formations by impervious strata of rock. These wells are operated within limits approved by the appropriate regulatory bodies.

Dry holes are exploratory or development wells found to be incapable of producing either oil or gas in sufficient quantities to justify their completion as an oil or gas well.

Exploratory wells are drilled with the intention of discovering commercial reservoirs or deposits of crude oil and/or natural gas.

Infill wells are drilled within a known accumulation of petroleum, between existing development wells, to target regions of the reservoir containing bypassed hydrocarbons or to accelerate production.

Observation wells are used to monitor changes in a producing field. Parameters being monitored may include fluid saturations, temperature or reservoir pressure.

Service wells are development wells drilled or completed to support production in an existing field, such as observation wells or wells drilled for the purpose of injecting gas, steam or water.

Sidetrack wells are drilled from existing wells. Operations start first by abandoning the lateral section of an existing well and subsequently drilling and completing a new lateral section. The sidetracked well is then tied it to the existing wellhead and uses the existing surface facilities.

Stratigraphic test wells are usually drilled without the intention of being completed for production and are geologically directed to obtain information pertaining to a specific geologic condition, such as core hole drilling or delineation wells on oil sands leases, or to measure the commercial potential (i.e., size and quality) of a discovery, such as appraisal wells for offshore discoveries.

Production terms

Crude feedstock generally refers either to (i) the bitumen required in the production of SCO for the company’s oil sands operations, or (ii) crude oil and/or other components required in the production of refined petroleum products for the company’s downstream operations.

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Diluent is a light hydrocarbon mixture blended with bitumen or heavy crude oil to reduce its viscosity so that it can be transported by pipeline.

Downstream refers to the refining of crude oil and the distribution and selling of refined products in retail and wholesale channels.

Extraction refers to the process of separating bitumen from oil sands.

Froth treatment refers to the process of adding a light hydrocarbon to bitumen froth produced in the extraction process to separate the bitumen from the water and fine solids in the bitumen froth.

In situ refers to methods of extracting bitumen from oil sands other than by surface mining.

Midstream refers to transportation, storage and wholesale marketing of crude or refined petroleum products.

Overburden is the material overlying oil sands that must be removed before mining. Overburden is removed on an ongoing basis to continually expose the ore.

Paraffinic froth treatment refers to a froth treatment process whereby a lighter diluent or solvent that contains paraffin is used to selectively remove some of the asphaltenes (the highest carbon component of the barrel) from the final product. This results in a lower carbon, higher quality bitumen that can be sold directly to market without further upgrading.

Production sharing contracts are a common type of contract, outside North America, signed between a government and a resource extraction company that states how much of the resource produced each party will receive and which parties are responsible for the development of the resource and operation of associated facilities. The resource extraction company does not obtain title to the product; however, the company is subject to the upstream risks and rewards. An exploration and production sharing agreement (EPSA) is a form of production sharing contract, which also states which parties are responsible for exploration activities.

Steam-assisted gravity drainage (SAGD) is an enhanced oil recovery technology for producing bitumen. It requires drilling pairs of horizontal wells with one located above the other. To help reduce land disturbance and improve cost efficiency, well pairs are drilled from multi-well pads. Steam is injected into the upper wellbore to heat the bitumen. This process reduces the viscosity of the bitumen, allowing heated bitumen and condensed steam to drain into the lower wellbore and flow up to the surface aided by subsurface pumps or circulating gas.

Steam-to-oil ratio is a metric used to quantify the cubic metres of water (converted to steam) required to produce one cubic metre of oil. Different reservoirs have different steam-to-oil ratios primarily due to differences in reservoir characteristics like oil viscosity, thickness, and permeability, but within similar reservoir characteristics, the ratio is a good measure of thermal efficiency. A lower ratio indicates more efficient use of steam.

Upgrading is the two-stage process by which bitumen is converted into SCO.

Primary upgrading, also referred to as coking or thermal cracking, heats the bitumen in coke drums to remove excess carbon. The superheated hydrocarbon vapours are sent to fractionators where they condense into naphtha, kerosene and gas oil. Carbon residue, or coke, is removed from the coke drums periodically and later sold as a byproduct.

Secondary upgrading, a purification process also referred to as hydrotreating, adds hydrogen to, and reduces the sulphur and nitrogen content of, primary upgrading output to create sweet SCO and diesel.

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Upstream refers to the exploration, development and production of crude oil, bitumen or natural gas.

Reserves

Please refer to the Definitions for Reserves Data Tables section of the Statement of Reserves Data and Other Oil and Gas Information in this AIF.

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Common Abbreviations

The following is a list of abbreviations that may be used in this AIF:

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Suncor converts certain natural gas volumes to boe, boe/d, mboe, mboe/d and mmboe on the basis of six mcf to one boe. Any figure presented in boe, boe/d, mboe, mboe/d or mmboe may be misleading, particularly if used in isolation. A conversion ratio of six mcf of natural gas to one bbl of crude oil or NGLs is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not necessarily represent value equivalency at the wellhead. Given that the value ratio based on the current price of crude oil as compared to natural gas is significantly different from the energy equivalency of 6:1, conversion on a 6:1 basis may be misleading as an indication of value.

Conversion Table⁽¹⁾⁽²⁾

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CORPORATE STRUCTURE

Name, Address and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act (the CBCA) on August 22, 1979, of Sun Oil Company Limited, incorporated in 1923, and Great Canadian Oil Sands Limited, incorporated in 1953. On January 1, 1989, the company further amalgamated with a wholly owned subsidiary under the CBCA. The company amended its Articles in 1995 to move its registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997 to adopt the name, “Suncor Energy Inc.” In April 1997, May 2000, May 2002, and May 2008 the company amended its Articles to divide its issued and outstanding shares on a two-for-one basis.

Pursuant to an arrangement under the CBCA, which was completed effective August 1, 2009, Suncor amalgamated with Petro-Canada to form a single corporation continuing under the name “Suncor Energy Inc.” On January 1, 2017, Suncor amalgamated with certain of its wholly owned subsidiaries under the CBCA.

Suncor’s registered and head office is located at 150 – 6^th Avenue S.W., Calgary, Alberta, T2P 3E3.

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The company’s remaining subsidiaries each accounted for (i) less than 10% of the company’s consolidated assets as at December 31, 2021, and (ii) less than 10% of the company’s consolidated revenues for the fiscal year ended December 31, 2021. In aggregate, the remaining subsidiaries accounted for less than 20% of the company’s consolidated assets as at December 31, 2021, and less than 20% of the company’s consolidated revenues for the fiscal year ended December 31, 2021.

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GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. Suncor’s operations include oil sands development, production and upgrading; offshore oil and gas; petroleum refining in Canada and the U.S.; and the company’s Petro-Canada retail and wholesale distribution networks (including Canada’s Electric Highway™, a coast-to-coast network of fast-charging electric vehicle stations). Suncor is developing petroleum resources while advancing the transition to a low-emissions future through investment in power, renewable fuels and hydrogen. Suncor also conducts energy trading activities focused principally on the marketing and trading of crude oil, natural gas, byproducts, refined products and power. Suncor has been recognized for its performance and transparent reporting on the Dow Jones Sustainability index, FTSE4Good and CDP. Suncor is also listed on the UN Global Compact 100 stock index. Suncor’s common shares (symbol: SU) are listed on the TSX and NYSE.

Suncor has classified its operations into the following segments:

OIL SANDS

Suncor’s Oil Sands segment, with assets located in the Athabasca oil sands of northeast Alberta, produces bitumen from mining and in situ operations. Bitumen is either upgraded into SCO for refinery feedstock and diesel fuel, or blended with diluent for refinery feedstock or direct sale to market through the company’s midstream infrastructure and its marketing activities. The segment includes the marketing, supply, transportation and risk management of crude oil, natural gas, power and byproducts. The Oil Sands segment includes:

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EXPLORATION AND PRODUCTION

Suncor’s Exploration and Production (E&P) segment consists of offshore operations off the east coast of Canada and in the North Sea, the Norwegian Sea and the Norwegian North Sea, and onshore assets in Libya and Syria. This segment also includes the marketing and risk management of crude oil and natural gas.

REFINING AND MARKETING

Suncor’s Refining and Marketing segment consists of two primary operations: the Refining and Supply and Marketing operations discussed below, as well as the infrastructure supporting the marketing, supply and risk management of refined products, crude oil, natural gas, power and byproducts. This segment also includes the trading of crude oil, refined products, natural gas and power.

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CORPORATE AND ELIMINATIONS

The Corporate and Eliminations segment includes the company’s investments in renewable energy projects and other activities not directly attributable to any other operating segment.

Three-Year History

Over the last three years, several events have influenced the general development of Suncor’s business.

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NARRATIVE DESCRIPTION OF SUNCOR’S BUSINESSES

For a discussion of the environmental and other regulatory conditions, and competitive conditions and seasonal impacts affecting Suncor’s segments, refer to the Industry Conditions and Risk Factors sections of this AIF.

Oil Sands

Oil Sands Operations – Assets and Operations

Oil Sands Base Operations

Suncor’s integrated Oil Sands Base operations, located in the Athabasca oil sands region of northeast Alberta, involve numerous activities:

After overburden is removed, open-pit mining operations use shovels to excavate oil sands bitumen ore, which is trucked to sizers and breaker units that reduce the size of the ore. Next, a slurry of hot water, sand and bitumen is created and delivered via a pipeline to extraction plants. The raw bitumen is separated from the slurry using a hot water process that creates a bitumen froth. Naphtha is added to the bitumen froth to form a diluted bitumen, which is subsequently sent to a centrifuge plant that removes most of the remaining impurities and minerals. Coarse tailings produced in this process are placed directly into sand placement areas.

Suncor has regional pipelines which connect the company’s mining, in situ, upgrading and storage assets, providing optionality and improving upgrader utilization and optimization of bitumen value for Suncor.

Additionally, interconnecting pipelines connect Syncrude’s Mildred Lake site and Suncor’s Oil Sands Base operations. The pipelines provide increased operational flexibility through the ability to transfer bitumen and sour SCO between the two plants, enabling higher upgrader utilization. The pipelines create flexibility for Syncrude to sell intermediate products to Suncor, which include bitumen and sour SCO.

After the diluted bitumen is transferred to upgrading facilities, the naphtha is removed and recycled to be used again as diluent in the extraction processes. Bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour SCO, is either sold to market or upgraded further into sweet SCO by removing sulphur and nitrogen using a hydrotreating process. In addition to sweet and sour SCO, upgrading processes also produce ultra-low sulphur diesel fuel and other byproducts.

To generate steam for the mining and extraction process, the company uses either a cogeneration unit or coke-fired boilers. Electricity is generated by turbine generators, most of which are part of the Oil Sands Base cogeneration unit, or provided by cogeneration units at Firebag. Process water is used in extraction processes and then recycled.

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Suncor regularly conducts planned maintenance events at its facilities. Large planned maintenance events that require units to be taken offline to be completed are often referred to as turnarounds. Turnaround maintenance provides opportunities for both preventive maintenance and capital replacement, which are expected to improve reliability and operational efficiency. Planned maintenance events generally occur on routine cycles, determined by historical operating performance, recommended usage factors or regulatory requirements. A turnaround typically involves shutting down the unit, inspecting it for wear or other damage, repairing or replacing components, and then restarting the unit. Production levels and product mix are typically impacted during these activities.

Mining processes disturb areas of land that must be reclaimed. Land reclamation activities involve soil salvage and replacement, wetlands research, the protection of fish, waterfowl and other wildlife, and revegetation.

Oil sands tailings are the remaining sand, water, clay, silt and residual hydrocarbons left after most hydrocarbons are extracted from the ore during the water-based bitumen extraction process. Suncor’s updated and approved tailings management plan involves an increase in treatment capacity using accelerated dewatering and treatment of mature fine tailings at Oil Sands Base, including the construction of a permanent aquatic storage structure. This approach is supported by the construction, operation and ongoing monitoring of a demonstration pit lake, and aligns with the Government of Alberta’s Tailings Management Framework (TMF) and the Alberta Energy Regulator’s (AER) Directive 085 – Fluid Tailings Management for Oil Sands Mining Projects (the Tailings Directive).

Oil Sands Base Assets

Millennium and North Steepbank

Suncor pioneered the commercial development of the Athabasca oil sands beginning in 1962, achieving first production in 1967. Bitumen is currently mined from the Millennium area, which began production in 2001, and the North Steepbank area, which began production in 2011. During 2021, the company mined approximately 150.8 million tonnes of bitumen ore (2020 – 145.9 million tonnes) and processed an average of 276.2 mbbls/d of mined bitumen in its extraction facilities (2020 – 262.2 mbbls/d).

The company filed a regulatory application in the first quarter of 2020 to potentially replace Suncor’s Millennium and North Steepbank mines as they reach the end of their useful lives after 2030. The application does not represent a project sanction and a final sanctioning is expected later in the decade.

Upgrading Facilities

Suncor’s upgrading facilities consist of two upgraders: Upgrader 1, which has a capacity of approximately 110 mbbls/d of SCO, and Upgrader 2, which has a capacity of approximately 240 mbbls/d of SCO. Suncor’s secondary upgrading facilities consist of three hydrogen plants, three naphtha hydrotreaters, two gas oil hydrotreaters, one diesel hydrotreater and one kerosene hydrotreater.

Suncor is proceeding with its project to replace the existing coke-fired boilers at Oil Sands Base with a new 800 MW cogeneration facility. The project is expected to provide reliable steam generation required for Suncor’s extraction and upgrading operations and is expected to reduce the GHG emissions intensity associated with steam production at Oil Sands Base by approximately 25%. In addition, the excess electricity produced will be transmitted to Alberta’s power grid, providing reliable, baseload, low-carbon electricity, equivalent to approximately 8% of Alberta’s current electricity demand. In total, this project will

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reduce GHG emissions in the province of Alberta by approximately 5.1 Mt per year. The project is estimated to cost approximately $1.4 billion with an expected in-service date between 2024 and 2025.

During 2021, Suncor’s Oil Sands Base assets averaged 313.7 mbbls/d of upgraded (SCO and diesel) production, mainly sourced from bitumen provided by both Oil Sands Base and In Situ operations, including the company’s internal consumption and transfers through the interconnecting pipelines (2020 –311.8 mbbls/d). In the 2021 AIF, the company revised the presentation of current and prior year upgraded Oil Sands Base production to include internally consumed diesel volumes and transfers through the interconnecting pipelines with Syncrude.

Other Mining Leases

Suncor, directly and indirectly, owns interests in several other mineable oil sands leases, including Base Mine Extension and Audet. Suncor undertakes exploratory drilling programs on such leases from time to time as part of its mine replacement projects. Suncor holds a 100% working interest in both Base Mine Extension and Audet.

In Situ Operations

Suncor’s In Situ operations at Firebag and MacKay River use SAGD technology to produce bitumen from oil sands deposits that are too deep to be mined.

SAGD is an enhanced oil recovery technology for producing bitumen. It requires drilling pairs of horizontal wells with one located above the other. To help reduce land disturbance and improve cost efficiency, well pairs are drilled from multi-well pads. Low pressure steam is injected into the upper wellbore to create a high-temperature steam chamber underground. This process reduces the viscosity of the bitumen, allowing the heated bitumen and condensed steam to drain into the lower wellbore and flow up to the surface aided by subsurface pumps or circulating gas.

The bitumen and water mixture is pumped to separation units at central processing facilities, where the water is removed from the bitumen, treated and recycled for use in steam generation. To facilitate shipment, In Situ operations blend diluent with the bitumen, or transport it through an insulated pipeline as hot bitumen.

To generate steam for operations, the company uses Once Through Steam Generators (OTSGs) or cogeneration units. OTSGs are fuelled by both purchased natural gas and produced natural gas recovered at central processing facilities. Cogeneration units are energy-efficient systems, that use natural gas combustion to power turbines that generate electricity and steam used in SAGD operations. Excess electricity generation from cogeneration units is used at Oil Sands Base facilities or sold to the Alberta power grid.

Central processing facilities, steam generation units and well pads are all subject to routine inspection and maintenance cycles.

SAGD production volumes are impacted by reservoir characteristics and the capacity of central processing facilities and steam generation units to process liquids and generate steam. As with conventional oil and gas properties, SAGD wells experience natural production declines after

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several years. In an effort to maintain bitumen supply, Suncor drills new well pairs from existing well pads or constructs new well pads to facilitate future well pair drilling and production.

In Situ Assets

Firebag

Production from Suncor’s Firebag operations commenced in 2004. The Firebag complex has central processing facilities with a total capacity of 215 mbbls/d of bitumen. Actual production from Firebag varies based on steaming and ramp-up periods for new wells, planned and unplanned maintenance, reservoir conditions and other factors.

As at December 31, 2021, Firebag had 20 well pads in operation, with 265 SAGD well pairs and 52 infill wells either producing or on initial steam injection. Central processing facilities have been designed to provide some flexibility as to which well pads supply bitumen. Steam generated at the various facilities can be used at multiple well pads. In addition, Firebag includes five cogeneration units that generate steam, which are capable of producing approximately 474 MW of electricity. The Firebag site power load requirements are approximately 122 MW and, in 2021, Firebag exported approximately 271 MW of electricity to the Alberta power grid and Oil Sands Base. There are also 13 OTSGs at the site for additional steam generation.

During 2021, Firebag production averaged 206.4 mbbls/d of bitumen (2020 – 182.4 mbbls/d) with a steam-to-oil ratio of 2.6 (2020 – 2.7). After completing maintenance and debottlenecking activities to expand the capacity of the facility in late 2020, Firebag operated near nameplate capacity of 215 mbbls/d in 2021.

Suncor is working on developing incremental debottlenecks to maximize the value of the Firebag asset. Debottlenecking capacity and timing will depend on economic conditions, and can be supported by integrated well pad development and solvent SAGD technologies.

MacKay River

Production from Suncor’s MacKay River operations commenced in 2002. The MacKay River central processing facilities have a bitumen processing capacity of 38 mbbls/d. As at December 31, 2021, MacKay River included nine well pads with 131 well pairs either producing or on initial steam injection. A third party owns the on-site cogeneration unit, which Suncor operates under a commercial agreement that generates steam and electricity. There are also four OTSGs at the site for additional steam generation.

During 2021, MacKay River production averaged 35.9 mbbls/d of bitumen (2020 – 16.7 mbbls/d) with a steam-to-oil ratio of 2.8 (2020 – 3.6). MacKay River operated at near nameplate capacity of 38 mbbls/d throughout 2021.

Other In Situ Leases

Suncor owns and operates several other oil sands leases that may support future in situ production, including Lewis, Meadow Creek, Gregoire, OSLO, Chard and Kirby. Suncor holds a 100% working interest in Lewis and Gregoire, a 75% working interest in Meadow Creek, a 77.78% working interest in OSLO, interests varying from 25% to 50% in Chard, and a 10% non-operated interest in Kirby.

Suncor is the operator of Meadow Creek, which is located approximately 40 kilometres south of Fort McMurray. Meadow Creek consists of two In Situ projects: Meadow Creek East and Meadow Creek West. In early 2017, Suncor received AER approval for the Meadow Creek East Project. In early 2020, Suncor received regulatory approval of an amendment to the capacity of the project. The project is expected to be developed in two stages with anticipated gross production capacity up to 80 mbbls/d. In early 2020, Suncor received AER approval for the Meadow Creek West project. Meadow Creek West is expected to be developed in a single stage and has an anticipated gross production capacity of 40 mbbls/d of

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bitumen. The timing of the project sanction for Meadow Creek East and Meadow Creek West has been deferred and will depend on future market conditions.

In February 2018, Suncor submitted an application for the Lewis Project to the AER, which received regulatory approval in March 2021. The project is located approximately 25 kilometres northeast of Fort McMurray and is expected to be developed in stages, with anticipated peak production of 160 mbbls/d of bitumen. The timing of the project sanction for Lewis will depend on future market conditions.

Fort Hills

Fort Hills is an oil sands mining area comprising leases on the east side of the Athabasca River, north of Oil Sands Base operations. Fort Hills operations are substantially similar to those of Suncor’s Oil Sands Base mining and extraction assets; however, Fort Hills uses a paraffinic froth treatment process to produce a marketable bitumen product that is partially decarbonized, resulting in a higher-quality bitumen requiring less diluent and eliminating the need for on-site upgrading facilities.

Suncor holds a 54.11% working interest in Fort Hills and is the operator of the asset. Fort Hills began producing paraffinic froth treated bitumen from secondary extraction in early 2018. Fort Hills has a nameplate capacity of 194 mbbls/d (gross) of bitumen (105 mbbls/d, net to Suncor). During 2021, Suncor’s share of Fort Hills production averaged 50.7 mbbls/d of bitumen (2020 – 58.1 mbbls/d) from approximately 32.6 million tonnes of bitumen ore mined (2020 – 37.7 million tonnes). Fort Hills transitioned to a one-train operation in the second quarter of 2020 in response to the COVID-19 pandemic’s impact on oil prices. Production in 2021 was via one-train until Fort Hills resumed a two-train operation in December.

Due to a decline in forecast heavy crude oil prices as a result of decreased global demand due to the impacts of the COVID-19 pandemic and changes to its capital, operating and production plans, the company recorded an after-tax impairment charge of $1.376 billion on its share of Fort Hills in the first quarter of 2020.

Syncrude

Suncor holds a 58.74% interest in the Syncrude joint operation, which has gross bitumen conversion to SCO capacity of 350 mbbls/d (206 mbbls/d, net to Suncor). Syncrude began producing in 1978 and is located near Fort McMurray, and it includes mining operations at Mildred Lake and Aurora North. On September 30, 2021, the operatorship of Syncrude was formally transferred to Suncor concurrent with the ratification of the Joint Venture Operating Agreement, and the previous Management Services Agreement with Imperial Oil was cancelled.

In 2012, the Syncrude joint venture owners announced a plan to develop two mining areas adjacent to the current mine, the Mildred Lake West Extension (MLX-W) and the Mildred Lake East Extension (MLX-E), which are collectively expected to extend the life of Mildred Lake by a minimum of 10 years. In 2015, a decision was made by the joint venture owners to progress with the MLX-W program. The MLX-E program is expected to follow MLX-W development if economic conditions prove suitable. The MLX-W program is expected to sustain bitumen production levels at the Mildred Lake site after resource depletion at the North Mine. The plan proposes to use existing mining and extraction facilities. The Syncrude MLX-W mining area received AER approval in 2019 and additional approvals in 2020. MLX-W was put on hold in 2020 due to the COVID-19 pandemic; however, construction activities were restarted in 2021, with first oil expected in late 2025.

Syncrude mining operations use truck, shovel and pipeline systems, similar to those at Oil Sands Base. Extraction and upgrading technologies at Syncrude are similar to those used at Oil Sands Base, with the exception that Syncrude uses a fluid coking process that involves the continuous thermal cracking of the heaviest hydrocarbons. At Mildred Lake, electricity is provided by a utility plant fuelled by natural gas and rich fuel gas from upgrading operations. At Aurora North, Syncrude operates two cogeneration units that provide heat and electricity.

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Syncrude produces a single sweet SCO product; individual joint venture owners are responsible for marketing this product. In addition, interconnecting pipelines between Syncrude’s Mildred Lake site and Suncor’s Oil Sands Base operations create flexibility for Syncrude to sell intermediate products to Suncor, which include bitumen and sour SCO.

Land reclamation activities at Syncrude are similar to those at Oil Sands Base; however, certain aspects of the tailings management processes at Syncrude are different. Syncrude’s tailings plan uses freshwater capping, a composite tails mixture of fine tails and gypsum, and centrifuge technology that separates water from tailings. The updated tailings management plans for Syncrude Aurora North and Syncrude Mildred Lake were approved by the AER in June 2018 and June 2019, respectively.

In 2021, Suncor’s share of Syncrude production, including internal consumption and transfers through the interconnecting pipelines, averaged 172.4 mbbls/d of SCO and bitumen (2020 – 165.7 mbbls/d). Production in 2021 was impacted by maintenance activities. In the 2021 AIF, the company revised the presentation of current and prior year Syncrude production to include internally consumed diesel volumes and transfers through the interconnecting pipelines with Oil Sands Base.

Other Oil Sands Leases

Suncor indirectly owns interests in other mineable oil sands leases, including Mildred Lake West, Mildred Lake East, Lease 29, Lease 30 and Lease 31, through the company’s 58.74% working interest in the Syncrude joint operation.

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New Technology

Technology is a fundamental component of Suncor’s business. Suncor pioneered commercial oil sands development and continues to advance technology through innovation and collaboration to improve efficiencies, lower costs and increase environmental performance. Development of new technology can take extended periods of time, first to demonstrate technical feasibility and then to demonstrate commercial viability. The necessary validation typically occurs through a series of progressive steps that allow results to be reliably scaled and assessed for implementation.

Following a successful commercial-scale evaluation in 2018, the company began a phased implementation of autonomous haulage systems at its operated mine sites. Autonomous haulage systems were deployed at the North Steepbank mine in 2018 and at Fort Hills in 2020. Full implementation at the Oil Sands Base Millennium mine is expected to be completed over the next four years. Autonomous haul trucks, which operate using GPS, wireless communication and perceptive technologies, have demonstrated an ability to maneuver safely, effectively and efficiently in Suncor’s operating environment and offer a number of advantages over existing truck and shovel operations, including enhanced safety performance, better operating efficiency and lower operating costs. During 2021, the company moved a total of 85.3 million gross tonnes of ore and overburden (2020 – 73.5 million gross tonnes) with autonomous haulage systems, which includes volumes from North Steepbank and Fort Hills. In 2021, Fort Hills temporarily returned to a staffed fleet to better manage congestion and interactions between staffed and autonomous operations, as Suncor ramped up mine operations to support a return to two trains.

Building upon the process used in Suncor’s Tailings Reduction Operations (TRO™), Suncor has developed the permanent aquatic storage structure (PASS) fluid tailings treatment process to significantly increase the amount of fluid tailings it can treat in a more sustainable manner. PASS combines the TRO™ process with the addition of a coagulant to improve the quality of the water expressed from the treated fluid tailings. Since 2010, fluid tailings volumes at Oil Sands Base operations have remained steady, and with the implementation of PASS technology, has allowed for a greater than 5% reduction in untreated fluid tailings inventory as of the fall of 2020. Suncor is working to reduce the number of active tailings ponds overall. Even with the start of a new mining operation (Fort Hills), the total number of active

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tailings ponds has been reduced since 2010, with one being surface reclaimed and three more advancing to closure.

Suncor is also working on, or has completed, several new technology projects that are proceeding with the next phase of field testing. Examples of Suncor’s new technology projects include:

Sales of Principal Products

Primary markets for SCO and bitumen production from Suncor’s Oil Sands segment, including paraffinic froth treated bitumen from Fort Hills, include refining operations in Alberta, Ontario, Quebec, the U.S. Midwest and the U.S. Rocky Mountain regions, and markets on the U.S. Gulf Coast. Diesel production from upgrading operations is sold primarily in Western Canada and the United States.

For bitumen production from In Situ operations, Suncor’s marketing strategy allows it to take advantage of changes in market conditions by either upgrading the bitumen at the company’s Oil Sands Base facilities, refining diluted bitumen at the company’s Edmonton refinery or selling diluted bitumen to third parties. Increased bitumen sales may also be required during upgrading facility outages. In Situ bitumen production processed by Oil Sands Base upgrading facilities in 2021 decreased to 116.8 mbbls/d or 48% (2020 – 130.1 mbbls/d or 65%) of total In Situ bitumen production as less In Situ bitumen feedstock was

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required due to higher mined bitumen feedstock and imports of bitumen from Syncrude on the interconnecting pipelines.

In the normal course of business, Suncor processes its proprietary sour SCO at the company’s refineries or enters into long-term sales agreements, which contain varying terms with respect to pricing, volume, expiry and termination.

Distribution of Products

Production from Oil Sands operations and Fort Hills is gathered into Suncor’s Fort McMurray facilities at the Athabasca Terminal, which is operated by Enbridge Inc., or the East Tank Farm, which is operated by Suncor and connected to the Athabasca Terminal. Suncor has arrangements with Enbridge to store SCO, diluted bitumen and diesel at the Athabasca Terminal. Product moves from the Athabasca Terminal in the following ways:

From Edmonton and Hardisty, where Suncor has both owned storage capacity and additional capacity under contract, the company has various options for delivering product to customers:

Production from Syncrude is moved to market via the Pembina Athabasca Oil Sands Pipeline.

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Royalties

Oil Sands Royalties

Oil sands projects are subject to the royalty framework issued by the Government of Alberta (the Royalty Framework), and regulated by the Oil Sands Royalty Regulation 2009 (OSRR 2009) and supporting regulations, which were sanctioned in 2008. Under the Royalty Framework, royalties for oil sands projects are based on a sliding-scale rate of 25% to 40% of net revenue (net revenue royalty or NRR), subject to a minimum royalty within a range of 1% to 9% of gross revenue (gross revenue royalty or GRR). Revenues used in royalty formulas are driven primarily by benchmark prices for WCS, while sliding-scale percentages in royalty formulas depend on prices for WTI from Cdn$55/bbl for the minimum rate to the maximum rate at a WTI price of Cdn$120/bbl. A royalty project remains subject to the minimum royalty (the pre-payout phase) until the project’s cumulative gross revenue exceeds its cumulative costs, including an annual investment allowance (the post-payout phase). During the post-payout phase, the annual royalty paid to the province is the greater of the GRR and NRR.

In 2021, Suncor incurred royalties at an average rate of 2% of gross revenue for Oil Sands Base (2020 –0%), and at an average rate of 13% of gross revenue for Syncrude operations (2020 – 3%) due to higher prices. Oil Sands Base and the Syncrude project are both in the post-payout phase, with assessment for the year for Oil Sands Base at GRR due to a carry-forward costs balance, and for Syncrude at NRR.

Fort Hills is subject to the same Royalty Framework as Oil Sands Base and Syncrude; however, Fort Hills is in the pre-payout phase. In 2021, Fort Hills incurred royalties at an average rate of 2% of gross revenue (2020 – 1%) due to higher prices.

In 2021, Suncor incurred royalties for MacKay River, which is in the post-payout phase, at an average rate of 10% of gross revenue due to higher prices (2020 – 2%), and royalties at an average rate of 12% of gross revenue for Firebag (2020 – 1%), due to higher prices and reaching the post-payout phase in 2021.

Exploration and Production

E&P Canada – Assets and Operations

Based in St. John’s, Newfoundland and Labrador, this business includes interests in four producing fields and future developments and extensions. Suncor is also involved in exploration drilling for new opportunities. Suncor is the only company in this region with interests in every field currently in production.

Terra Nova

The Terra Nova oilfield is approximately 350 kilometres southeast of St. John’s. Terra Nova was discovered in 1984 and was the second oilfield to be developed offshore Newfoundland and Labrador. Operated by Suncor, the production system uses a Floating Production, Storage and Offloading (FPSO) vessel that is moored on location, and has gross production capacity of 180 mbbls/d (86 mbbls/d, net to Suncor) of crude oil and an oil storage capacity of 960 mbbls. Terra Nova was the first harsh environment development in North America to use an FPSO vessel. The Terra Nova oilfield is divided into three distinct areas, known as the Graben, the East Flank and the Far East. Production from Terra Nova began in January 2002.

Terra Nova has been offline since the fourth quarter of 2019. In 2020, the company safely preserved the FPSO quayside and deferred the previously announced Terra Nova ALE Project until an economically viable path forward with a safe and reliable return to operations could be determined. During the third quarter of 2021, Suncor and the co-owners of the Terra Nova project finalized an agreement to restructure the project ownership and move forward with the ALE Project. The agreement increased the company’s working interest to 48% from approximately 38% in exchange for a cash payment from the

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exiting owners, and includes royalty and financial support from the Government of Newfoundland and Labrador.

The ALE Project is expected to extend production life by approximately 10 years, providing an additional 70 million barrels of resource for the partnership and providing many benefits to the Newfoundland and Labrador and Canadian economies in the form of taxes, royalties and employment. As part of the project, the FPSO will undergo maintenance work and a safe return to operations is anticipated before the end of 2022.

In 2021, Terra Nova production remained offline; therefore, Suncor’s share of Terra Nova production averaged nil mbbls/d of crude oil (2020 – nil mbbls/d).

In the first quarter of 2020, due to a decline in forecast crude oil prices as a result of decreased global demand due to the COVID-19 pandemic as well as changes to capital, operating and production plans, the company recorded an after-tax impairment charge of $285 million on its share of the Terra Nova assets. Subsequently, in the third quarter of 2021, the company recorded a non-cash after-tax impairment reversal of $168 million on its share of the Terra Nova assets, as a result of the ALE Project moving forward and the benefit of royalty and financial support from the Government of Newfoundland and Labrador.

Hibernia and the Hibernia Southern Extension Unit

The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 kilometres southeast of St. John’s and was the first field to be developed in the Jeanne d’Arc Basin. Operated by Hibernia Management and Development Company Ltd., the production system is a fixed Gravity Based Structure (GBS) that sits on the ocean floor and has gross production capacity of 230 mbbls/d (46 mbbls/d, net to Suncor) of crude oil, and an oil storage capacity of 1,300 mbbls. Actual production levels are lower, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Hibernia commenced production in November 1997. As at December 31, 2021, there were 74 wells: 41 oil production wells, 27 water injection wells, five gas injection wells and one water-alternating-gas injection well.

In 2010, final agreements were signed between the Hibernia co-venturers and the Government of Newfoundland and Labrador that established the fiscal, equity and operational principles for the development of the Hibernia Southern Extension Unit (HSEU). At the end of 2021, there were eight oil production wells and nine water injection wells in the HSEU. The production wells were drilled from the GBS platform and are included in the Hibernia well count above. All nine of the water injection wells were drilled using a mobile offshore drill rig. Water for injection purposes is supplied from the GBS platform via a subsea flowline.

In 2021, Suncor’s share of Hibernia production averaged 19.8 mbbls/d of crude oil (2020 – 23.2 mbbls/d).

White Rose and the White Rose Extensions

White Rose is approximately 350 kilometres southeast of St. John’s. Operated by Cenovus Energy Inc. (previously Husky Oil Operations Limited), White Rose uses an FPSO vessel and has gross production capacity of 140 mbbls/d (39 mbbls/d, net to Suncor) of crude oil and oil storage capacity of 940 mbbls. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, gas and water injection and production limits, and asset and facility reliability. Production from White Rose began in November 2005. As at December 31, 2021, there were 44 wells: 23 oil production wells, 15 water injection wells, three gas storage wells, and three gas injection wells.

In 2007, the White Rose co-venturers signed an agreement with the Government of Newfoundland and Labrador for the development of the White Rose Extensions, which includes the North Amethyst, South White Rose Extension, and West White Rose satellite fields. First oil was achieved at North Amethyst in

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May 2010. Development of the South White Rose Extension began in 2013, with first oil achieved in June 2015.

Development of the West White Rose field has been divided into two stages. The first stage was approved in 2010 and first oil was achieved in September 2011. The second stage, West White Rose Project, was sanctioned during the second quarter of 2017. The project was expected to extend the life of the existing White Rose assets, with Suncor’s share of peak oil production estimated to be 20 mbbls/d of crude oil. Major development activity began in 2018. However, in 2020, the operator announced a full project review given the continued market uncertainty caused by the COVID-19 pandemic along with the cancellation of the 2021 construction season and has moved the project into safekeeping mode. At West White Rose, in 2021, Suncor entered into a conditional agreement to increase its interest in the White Rose assets subject to a number of conditions including an economic restart decision for the West White Rose Project by mid-2022. Should the conditions be met, Suncor has agreed to increase its ownership interest in the White Rose assets by 12.5% to approximately 40% in exchange for a cash payment by the operator to Suncor.

Due to a decline in forecast crude oil prices as a result of decreased global demand due to the COVID-19 pandemic, as well as changes to capital, operating and production plans, the company recorded an after-tax impairment charge of $137 million on its share of the White Rose assets in the first quarter of 2020. Subsequently, in the fourth quarter of 2020, the company recorded an after-tax impairment charge of $423 million on its share of the White Rose assets as a result of the significant uncertainty surrounding the future of the West White Rose Project. The book value as of December 31, 2020, was impaired to zero.

In 2021, Suncor’s share of White Rose production averaged 5.4 mbbls/d of crude oil (2020 – 6.7 mbbls/d).

Hebron

The Hebron oilfield is located approximately 340 kilometres southeast of St. John’s and is operated by ExxonMobil Canada Properties. The development includes a concrete GBS that sits on the ocean floor and supports an integrated topsides deck used for production, drilling and accommodations. At peak, the Hebron Project is expected to produce 31.6 mbbls/d of crude oil, net to Suncor, ramping up over several years. Hebron has a gross oil storage capacity of 1,200 mbbls and 52 well slots. First oil was achieved in November 2017.

During 2021, drilling activities continued at Hebron and are expected to continue throughout 2022. As at December 31, 2021, there were 27 wells: 18 oil production wells, four water injection wells, one gas injection well, one cuttings reinjection well and three water alternating gas injection wells. In 2021, Suncor’s share of production averaged 29.2 mbbls/d of crude oil (2020 – 29.7 mbbls/d).

Other Assets

Suncor continues to pursue opportunities offshore Newfoundland and Labrador. In 2019, Suncor and Cenovus were announced as the successful bidders on exploration licence No. 1164, which is located north of White Rose. This licence carries work commitments from 2020 to 2026. In total, the company holds interests in 48 significant discovery licences and four exploration licences offshore in this area.

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E&P International – Assets and Operations

Offshore U.K. & Norway

Buzzard

The Buzzard oilfield is located in the Outer Moray Firth, 95 kilometres northeast of Aberdeen, Scotland. Operated by CNOOC Petroleum Europe Limited, a subsidiary of China National Offshore Oil Corporation Limited, the Buzzard facilities have gross installed production capacity of approximately 220 mbbls/d (66 mbbls/d, net to Suncor) of crude oil and 80 mmcf/d (24 mmcf/d, net to Suncor) of natural gas. Actual annual production levels are lower than production capacity, reflecting current reservoir capability, including natural declines, water injection limits, gas and water production limits, and asset and infrastructure reliability. Buzzard commenced production in January 2007 and consists of four bridge-linked platforms supporting wellhead facilities, production facilities, living quarters and utilities, as well as sulphur handling. As at December 31, 2021, there were 51 wells: 34 oil and gas production wells and 17 water injection wells. Buzzard Phase 2 was sanctioned in 2018 and project execution, although adversely impacted by the COVID-19 pandemic, has progressed throughout 2021 with first oil achieved in November 2021. In 2021, Suncor’s share of Buzzard production averaged 18.7 mboe/d of crude oil and natural gas (2020 – 25.9 mboe/d).

Golden Eagle Area Development

On October 22, 2021, the company completed the sale of its 26.69% working interest in the Golden Eagle Area Development for gross proceeds of US$250 million net of closing adjustments and other closing costs, resulting in an after-tax gain on sale of approximately $227 million, in addition to future contingent consideration of up to US$50 million. The effective date of the sale was January 1, 2021. In 2021, Suncor’s share of Golden Eagle Area Development production averaged 8.3 mboe/d of crude oil and natural gas (2020 – 7.8 mboe/d).

Rosebank

The Rosebank future development project, in which Suncor has a 40% working interest, was discovered in December 2004 and is operated by Equinor U.K. Limited. It is located approximately 130 kilometres northwest of the Shetland Islands, in the U.K. North Sea. The project is currently in the pre-sanction phase.

Oda

The Oda field (PL405 licence) was discovered in 2011 and is located 13 kilometres east of the producing Ula field in the southern part of the Norwegian North Sea. Spirit Energy is the operator and Suncor has a 30% working interest. Oda was sanctioned in November 2016. The field is a subsea tie-back to the Ula platform. Drilling activities were completed in 2018, and first oil was achieved in March 2019. As at December 31, 2021, there were three wells: two production wells and one water injection well. In 2021, Suncor’s share of Oda production averaged 2.7 mboe/d of crude oil and natural gas (2020 – 7.5 mboe/d).

Fenja

In 2018, Suncor acquired a 17.5% participating interest in the Fenja development project (PL586 licence). The Fenja field, which was discovered in 2014 and is operated by Neptune Energy, is located approximately 30 kilometres southwest of the Equinor-operated Njord field in the Norwegian Sea. The project was sanctioned by the owners in late 2017, and the plan for development and operation was approved by the Norwegian Ministry of Petroleum and Energy in the first half of 2018. The field will be developed with two subsea templates, each with up to four wells, tied back to the Equinor-operated Njord platform. First oil is planned for 2023, with peak production expected to reach 29 mboe/d (5.1 mboe/d, net to Suncor) of crude oil and natural gas in 2024.

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Other Assets

Suncor continues to pursue other opportunities offshore of the U.K. and Norway. The company holds interests in 15 exploration licences in these areas.

Other International

Libya

In Libya, Suncor is a signatory to seven EPSAs with the National Oil Corporation (NOC). Five of the seven EPSAs relate to fields with developed production and exploration prospects; the remaining two are exploration EPSAs related to properties that do not contain reserves, one of which is to be relinquished following an unsuccessful exploration program. Under the EPSAs, Suncor pays 100% of the exploration costs, 50% of the development costs and 12% of the operating costs. The development, operating and eligible exploration costs are recovered through a 12% share of production (Cost Recovery oil). Any Cost Recovery oil remaining after Suncor’s costs have been recovered is referred to as excess petroleum, and is shared between Suncor and the NOC based on several factors. The total oil Suncor receives for cost recovery and its share of excess petroleum is referred to as entitlement volumes. The EPSAs expire on December 31, 2032, but include an initial five-year extension through the end of 2037. Libya is a member of the Organization of Petroleum Exporting Countries (OPEC) and is subject to quotas that can affect the company’s production in Libya.

Since 2013, production and liftings in Libya have been intermittent due to political unrest, and the remaining value of Suncor’s assets in Libya was impaired in 2015. Production in Libya was steady in 2021, albeit at reduced rates. The timing of a return to normal operations in Libya remains uncertain due to continued political unrest.

The estimated cost of Suncor’s remaining exploration work program commitment at December 31, 2021, is US$359 million. Suncor declared force majeure for all exploration commitments in Libya effective December 14, 2014, and this declaration remains in effect.

Suncor’s share of production in Libya on an economic basis averaged 3.4 mbbls/d in 2021 of crude oil (2020 – 0.8 mbbls/d).

Syria

In December 2011, amid continuing unrest in Syria, sanctions were imposed and Suncor declared force majeure under its contractual obligations, suspending its operations in the country. Consequently, the company has ceased recording all production and revenue associated with its Syrian assets. Since 2011, Suncor has not been able to monitor the status of any of its assets in the country, including whether certain facilities have suffered damage, although the company believes some assets have sustained significant damage. As a result of continued uncertainty about Suncor’s future in the country, the remaining value of the Suncor assets was impaired in 2013.

Sales of Principal Products

Oil and gas production from East Coast Canada and Offshore U.K. and Norway is either marketed by Suncor’s Energy Trading business acting as a marketing agent, or sold to the company’s Energy Trading business, which then markets the products to customers under direct sales arrangements. Suncor does not typically enter into long-term supply arrangements to sell its production from its Exploration and Production segment. Contracts for these direct sales arrangements are all made on a spot basis and incorporate pricing that is generally determined on a daily or monthly basis in relation to a specified market reference price.

In Libya, crude oil is marketed by the NOC on behalf of Suncor.

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Exploration and Production Sales Summary:

Distribution of Products

Royalties

East Coast Canada

Suncor’s East Coast projects are subject to royalty Agreements and regulations issued by the Government of Newfoundland and Labrador. To date, the royalty regime for each project has been negotiated on an individual basis. On November 1, 2017, the Province of Newfoundland and Labrador promulgated the Generic Offshore Royalty Regime for future projects. The current East Coast royalty regime has a tiered rate structure ranging from a minimum of 1% of gross revenue to a maximum of 42.5% of net revenue (gross revenue less eligible operating and capital costs). The tiered structure is based upon various profitability levels. An East Coast project will be subject to the minimum royalty (the pre-payout phase) until the project’s cumulative gross revenue exceeds its cumulative costs, including an annual investment allowance (the post-payout phase).

Terra Nova and the Newfoundland government finalized the Terra Nova Fiscal Agreement in 2021, which effected changes to the existing royalty structure. Royalties consist of an initial graduated-scale basic royalty, followed by a two-tiered royalty that will become payable upon the achievement of specified levels

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of profitability. The basic royalty starts at 1% of gross revenue, graduating to 10% depending on certain milestones. The Tier I royalty is equal to 20% of net revenue. The Tier II incremental royalty is on a stepped scale starting at 10% to 22.5% to reflect oil prices from US$65/bbl Brent to above US$80/bbl Brent. During 2021, Terra Nova did not pay royalties due to suspension of production (2020 – 2%).

Hibernia production from the original oilfields and the AA Block has reached the net royalty stage, consisting of a two-tier profit-sensitive royalty and an additional net profits interest of 10% of net revenue. Tier one is the greater of 5% of gross revenue or 30% of net revenue. Tier two is an additional 12.5% of net revenue; however, this has not yet been triggered. For the portion of the HSEU that is contained within the original Hibernia licence area, a tier three royalty ranges between 7.5% and 12.5% of net revenue, depending on the price of WTI.

The HSEU royalty structure is similar to the Hibernia arrangement, but is subject to an additional tier three royalty that ranges between 2.5% and 7.5% of net revenue, depending on the price of WTI. The HSEU tier three royalty was triggered in 2019.

Hibernia royalties (including the HSEU) and net profits interest combined to average 35% of gross revenue for 2021 (2020 – 23%), due to higher commodity prices.

The White Rose base project has reached the net royalty stage, consisting of a two-tier profit-sensitive royalty. Tier one is the greater of 7.5% of gross revenue or 20% of net revenue. Tier two is an additional 10% of net revenue. The White Rose Extension tier one and tier two royalty structures are the same as the base project, and there is an additional tier three royalty of 6.5% of net revenue, payable if WTI is greater than US$50/bbl. The White Rose Extension is currently paying tier one and tier three royalties, but has not yet triggered tier two. During 2021, total White Rose royalties averaged 6% of gross revenue (2020 – 6%).

The Hebron royalty consists of an initial sliding-scale basic royalty, followed by a three-tiered royalty that will become payable upon the achievement of specified levels of profitability. The basic royalty starts at 1% and increases to 7.5% of gross revenue depending on certain milestones. The tier one royalty is equal to 20% of net revenue. The tier two royalty is equal to an additional 10% of net revenue. The tier three royalty is equal to 6.5% of net revenue, payable if WTI is greater than US$50/bbl. During 2021, Hebron royalties averaged 1% of gross revenue (2020 – 1%).

E&P International

There are no royalties on oil and gas production from Offshore U.K. and Norway; however, oil and gas profits are subject to a 40% income tax rate and 78% income tax rate, respectively. For operations in Libya, all government interests, except for income taxes, are presented as royalties.

Refining and Marketing

Refining and Supply – Assets and Operations

Eastern North America

Montreal Refinery

The Montreal refinery has a crude oil capacity of 137 mbbls/d, with a flexible configuration that allows processing of sweet SCO from the company’s Oil Sands operations, WCS, conventional crude oil, and intermediate feedstock. Crude oil is procured at market prices on a spot basis or under contracts that can be terminated on short notice. Crude oil for the refinery can be supplied through several channels, including via Enbridge’s Line 9, the Portland-Montreal Pipeline, by marine transportation, and by rail for inland crudes.

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Production from the Montreal refinery includes gasoline, distillate, heavy fuel oil, solvents, asphalt and petrochemicals, which are distributed primarily across Quebec and Ontario. The Montreal refinery also continues to produce feedstock sold under a long-term supply contract with HollyFrontier, following the completion of the sale of Suncor’s Mississauga lubricants facility in early 2017. Refined products are delivered to distribution terminals and customers via the Trans-Northern Pipeline, truck, rail and marine vessel.

Sarnia Refinery

The Sarnia refinery has a crude oil capacity of 85 mbbls/d, processing both SCO from the company’s Oil Sands operations and conventional crude oil purchased from third parties on a spot basis or under contracts that can be terminated on short notice. Crude oil is supplied to the Sarnia refinery primarily via the Enbridge mainline and Lakehead pipeline systems. Suncor procures conventional crude oil feedstock primarily from Western Canada and has the ability to supplement supply with purchases from the U.S.

Production yield from the Sarnia refinery includes gasoline, kerosene, and jet and diesel fuels, which are primarily distributed in Ontario. Refined products are delivered to distribution terminals in Ontario via the Sun-Canadian Pipeline, or delivered to customers directly via marine vessel and rail. The Sarnia refinery also has limited access to pipelines delivering refined products into the U.S.

To meet the demands of Suncor’s marketing network in eastern North America, the company also purchases gasoline and distillate from other refiners. Suncor enters into reciprocal exchange arrangements with other refiners in Eastern North America, primarily for gasoline and distillate, as a means of minimizing transportation costs and balancing product availability. Specialty products, such as asphalt and petrochemicals, are also exported to customers in the U.S.

Other Facilities

Suncor holds a 51% interest in ParaChem Chemicals L.P., which owns and operates a petrochemicals plant located adjacent to the Montreal refinery. Feedstock for the plant includes xylene and toluene produced by the Montreal and Sarnia refineries. The plant primarily produces paraxylene, which is used by customers to manufacture polyester textiles and plastic bottles. Paraxylene production was approximately 358,000 metric tonnes in 2021 (2020 – 295,000 metric tonnes). ParaChem also produces benzene, hydrogen and heavy aromatics. Benzene production is delivered back to the Montreal refinery to be marketed with production from that facility.

Suncor operates Canada’s largest ethanol facility, the St. Clair ethanol plant in the Sarnia-Lambton region of Ontario, with a nameplate capacity of 396 million litres per year. In 2021, the plant produced 343 million litres of ethanol (2020 – 336 million litres).

Western North America

Edmonton Refinery

In the first quarter of 2021, the crude oil capacity of the Edmonton refinery increased to 146 mbbls/d (2020 – 142 mbbls/d) as a result of debottlenecking activities. The refinery has the capability to run a full slate of feedstock sourced from Suncor’s Oil Sands operations. Crude oil is supplied to the refinery via company-owned and third-party pipelines.

Feedstock is supplied from Suncor’s Oil Sands operations, Syncrude operations (including volumes purchased by Suncor from the other Syncrude joint venture owners’ share of production) and other producers from the Wood Buffalo and Cold Lake regions of Alberta. The refinery can process approximately 44 mbbls/d of blended heavy feedstock (comprised of 31 mbbls/d of bitumen and 13 mbbls/d of diluent) and process approximately 44 mbbls/d of sour SCO. The refinery can also process approximately 58 mbbls/d of sweet SCO through its synthetic crude train.

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Production yield from the Edmonton refinery includes primarily gasoline, distillate and other light oils, which are delivered to distribution terminals across Western Canada via the Alberta Products Pipeline, the Trans Mountain Pipeline and the Enbridge pipeline system, as well as via truck and rail.

Commerce City Refinery

The Commerce City refinery, has a crude throughput capacity of 98 mbbls/d. The refinery processes primarily conventional crude oil, and has the capacity to process up to 16 mbbls/d of sour SCO and diluted bitumen from Suncor’s Oil Sands operations. A majority of crude feedstock is supplied from sources in the U.S., including the Rocky Mountain region, while the remainder is purchased from Canadian sources. Crude oil purchase contracts have terms ranging from month-to-month to multi-year. Crude oil is supplied to the Commerce City refinery primarily by pipeline, with the remainder transported via truck.

Production yield from the Commerce City refinery includes primarily gasoline, distillate and paving-grade asphalt.

The majority of the refined products are sold to commercial and wholesale customers in Colorado and Wyoming, and a retail network in Colorado and Wyoming. Refined products are distributed by truck, rail and pipeline.

Other Facilities

To support the supply and demand balance in the Vancouver area, Suncor imports and exports finished products through its Burrard distribution terminal located on the west coast of B.C. The Burrard distribution terminal was expanded by Suncor in 2020, which added an incremental 19 mbbls/d of export capacity, bringing the total export capacity of the terminal to 40 mbbls/d. Suncor also enters into reciprocal exchange arrangements with other refiners in western North America as a means of minimizing transportation costs and balancing product availability.

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Refinery Throughputs, Utilizations and Yields

The following tables summarize the crude feedstock, utilizations and production yield mix for Suncor’s refineries for the years ended December 31, 2021 and 2020.

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Distribution Terminals and Pipelines

Suncor owns and operates 13 major refined product terminals across Canada (including terminals adjacent to refineries) and three product terminals in Colorado. Combined with access to facilities under long-term contractual arrangements with other parties, Suncor’s North American assets are sufficient to meet the Refining and Marketing segment’s current storage and distribution needs.

As at December 31, 2021, Suncor’s ownership interests in certain pipelines were as follows:

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Marketing – Assets and Operations

Suncor’s retail service station network operates nationally in Canada primarily under the Petro-Canada^™ brand. As at December 31, 2021, this network consisted of 1,584 outlets across Canada, of which 786 locations are company-owned locations and 798 are branded-dealers. Selected locations along the Trans-Canada Highway contain Canada’s Electric Highway™, the coast-to-coast network of fast-charging electric vehicle stations. In addition, refined products are marketed through independent dealers and joint operations. Suncor’s Canadian retail network had sales of gasoline motor fuels averaging approximately 4.2 million litres per site in 2021 (2020 – 4.1 million litres).

Suncor’s Colorado retail network consists of 44 owned or leased Shell^™, Exxon^™ or Mobil^™ branded outlets. Suncor also has product supply agreements with 110 Shell-branded sites in both Colorado and Wyoming, and with 66 Exxon and Mobil-branded sites in Colorado.

Marketing activities from the retail network also generate non-petroleum revenues from convenience store sales and car washes.

Suncor’s wholesale operations sell refined products into farm, home heating, paving, small industrial, commercial and truck markets. Through its PETRO-PASS^™ network, Suncor is a national marketer to the commercial road transport segment in Canada. Suncor also sells refined products directly to large industrial and commercial customers and independent marketers.

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Sales volumes for specific products are moderately affected by seasonal cycles: gasoline sales are typically higher during the summer driving season; heating oil sales are typically higher during the winter season; diesel sales are typically higher during the drilling season at the beginning of the year in Western Canada and during agricultural planting and harvest seasons in early spring and late summer, respectively; and asphalt sales are typically higher during the summer construction paving period. Suncor has the flexibility to modify refinery inputs and outputs to match production yields with anticipated product demands. Suncor also has the flexibility to import and export refined products to optimize domestic seasonal cycles and to capture incremental margins from market dislocations as they arise.

Sales volumes can also be impacted when refineries undergo maintenance events, which reduce production. Suncor is able to partially mitigate this impact through its integrated facilities: the Edmonton refinery and Oil Sands Base upgrading facilities, and the Sarnia and Montreal refineries. In addition, Suncor may purchase refined products from third-party suppliers.

Other Suncor Businesses

Energy Trading

Suncor’s Energy Trading business is organized around five main commodity groups – crude oil, transportation fuels, specialty products and feedstock, natural gas, and electricity – and has trading offices in Canada, the U.K. and the U.S. Energy Trading manages open price exposure along the Suncor value chain and provides commodity supply, transportation and storage while optimizing price realizations for Suncor’s products. The company’s customers include mid- to large-sized commercial and industrial consumers, utility companies and energy producers.

The Energy Trading business supports the company’s Oil Sands and E&P production by optimizing price realizations, managing inventory levels and managing the impacts of external market factors, such as pipeline disruptions or outages at refining customers. The Energy Trading business has entered into contractual arrangements for other midstream infrastructure, such as pipeline, storage capacity and rail access, to optimize delivery of existing and future growth production, while generating earnings on select trading strategies and opportunities.

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The Energy Trading business supports the company’s Refining and Marketing business by optimizing the supply of crude and NGL feedstock to the company’s four refineries, managing crude inventory levels during refinery turnarounds and periods of unplanned maintenance, as well as managing external impacts from pipeline disruptions. Energy Trading also moves Suncor’s refinery production to market and ensures supply to Suncor’s branded retail and wholesale marketing channels. The business provides reliable natural gas supply to Suncor’s upstream and downstream operations and generates incremental revenue through trading and asset optimization.

Renewable Energy

Suncor’s renewable energy investment activities include development, construction and ownership of Suncor-operated and joint venture partner-operated renewable power assets across Canada. This currently includes a portfolio of four operating wind power facilities located in Alberta, Saskatchewan and Ontario with a gross installed capacity of 111 MW. In addition, Suncor has secured a number of sites for potential future wind and solar power projects that are in various stages of development, including the Forty Mile Wind Power Project in southeast Alberta. The sanctioned Forty Mile Wind Power Project is designed to provide 200 MW of generation capacity with an estimated total capital spend of $300 million. The project is currently planned for completion in late 2022.

Suncor’s wind power projects as at December 31, 2021:

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SUNCOR EMPLOYEES

The following table shows the distribution of full- and part-time employees among Suncor’s business units and corporate office.

(1)Includes employees related to the Fort Hills operations.

(2) Prior period information has been re-classified to conform to current period presentation.

(3) Includes employees from the company’s Projects group, which supports the business units.

In addition to Suncor’s employees, the company also uses independent contractors to supply a range of services.

Approximately 25% or 4,184 of the company’s employees were covered by collective agreements at the end of 2021. The company completed negotiations in 2021 in respect of the collective agreements relating to the Sarnia refinery and the Portland-Montreal Pipeline. Negotiations for four collective agreements will take place in 2022 representing approximately 317 employees and including the Commerce City refinery and B.C. terminals.

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ETHICS, SOCIAL AND ENVIRONMENTAL POLICIES

Suncor has adopted several policies focused on ethics, social and environmental matters.

Suncor’s standards for the ethical conduct of the company’s business are set forth in a Standards of Business Conduct Code (the Code), which applies to Suncor’s directors, officers, employees and independent contractors, and requires strict compliance with legal requirements and Suncor’s values. Topics addressed in the Code include competition, conflict of interest, the protection and proper use of corporate assets and opportunities, confidentiality, disclosure of material information, trading in shares and securities, communications to the public, improper payments, equal opportunity and discrimination, respectful workplace, fair dealing in trade relations, and accounting, reporting and business controls. The Code is supported by detailed policy guidance and standards and a Code compliance program, under which every Suncor director, officer, employee and independent contractor is required to annually complete a Code training course, read a summary of the Code, affirm that they understand the requirements of the Code, and provide confirmation of compliance with the Code since their last affirmation or confirmation that any instance of non-compliance has been discussed and resolved with the individual’s supervisor. Compliance is then reported to Suncor’s Governance Committee of the Board of Directors. A copy of the Code is available on Suncor’s website at www.suncor.com.

Suncor has a Supplier Code of Conduct that highlights the values that are important to Suncor and is a guide to the standard of behaviour required of all suppliers, contractors, consultants and other third parties with whom Suncor does business. The Supplier Code of Conduct addresses topics such as safety, human rights, harassment, bribery and corruption, and confidential information, among others. It

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also reinforces Suncor’s commitment to sustainable development and encourages Suncor’s business associates to work with the company to seek ways to reduce environmental impacts, support the communities in which Suncor works and collectively achieve economic growth. Compliance with the Supplier Code of Conduct is a standard requirement for all Suncor supply chain contracts.

Suncor has a Human Rights Policy, which affirms Suncor’s responsibility to respect human rights and is intended to ensure that Suncor is not complicit in human rights abuses. Suncor is subject to the laws of the countries in which it operates and is committed to complying with all such laws while honouring international human rights principles, such as those described in the Universal Declaration of Human Rights. The policy contains guiding principles, including the belief that a process for human rights impact assessment undertaken regularly is essential to identify, prevent, mitigate and remedy potential impacts on human rights; a commitment to providing a working environment that is free from harassment, violence, intimidation and other disruptive behaviours; a commitment to respecting the cultures, customs and values of the communities in which the company operates; the belief that security policies should be consistent with international human rights standards; and the belief that employees and stakeholders affected by the company’s activities should have access to grievance mechanisms that are legitimate, accessible, predictable, equitable and transparent. The policy makes clear that the scope of Suncor’s human rights due diligence should include its own operations and, where it can influence its third-party business relationships, the operations of others.

Suncor has a Stakeholder Relations Policy that reflects Suncor’s values. The policy provides that Suncor is committed to developing and maintaining positive, meaningful relationships with stakeholders in all of its operating areas and provides Suncor’s principles for guiding the development of stakeholder relations (respect, responsibility, transparency, timeliness and mutual benefit). The policy states Suncor’s belief that successful stakeholder relations provide significant mutual benefits, including enabling informed decision-making, resolving issues with timely, cost-effective and mutually beneficial solutions, building stronger communities and supporting shared learning.

Suncor has a Canadian Indigenous Relations Policy, which affirms Suncor’s desire to work in collaboration with Indigenous Peoples to create shared value. The policy sets the foundation for a consistent approach to the company’s relationships with Indigenous Peoples and outlines Suncor’s responsibilities and commitments, and is intended to guide Suncor’s business decisions on a day-to-day basis. Suncor is committed to working closely with Indigenous Peoples and communities to build and maintain long-term and mutually beneficial relationships. The policy makes it clear that we strive for relationships that are based on transparency, mutual respect and trust.

Suncor has an Environment, Health and Safety (EH&S) policy, which affirms Suncor’s commitment to be a sustainable energy company by working to achieve or exceed levels of performance governed by legislation and by the evolving environmental, social and economic expectations of the company’s stakeholders. The policy reflects Suncor’s belief that the company’s EH&S efforts are complementary and interdependent with the company’s economic and social performance. The policy states that Suncor management is responsible for ensuring that employees and contractors under their direction are competent to manage their EH&S responsibilities and are knowledgeable of the hazards and risks associated with their jobs, and that all Suncor employees and contractors are accountable for compliance with relevant acts, codes, regulations, standards and procedures, and for their own personal safety and the safety of their co-workers.

The Environment, Health, Safety and Sustainable Development (EHS&SD) Committee of the Board of Directors meets quarterly to review Suncor’s effectiveness in meeting its EHS&SD obligations. The EHS&SD Committee also reviews the company’s strategies and policies, with respect to EHS&SD, given legal, industry and community standards. The EHS&SD Committee also monitors management’s performance and emerging trends and issues in these areas. The EHS&SD Committee reviews and makes recommendations to the Board (and to the Human Resources and Compensation Committee for the purposes of executive incentive plans) regarding the company’s safety and environment related performance goals and to assess whether such goals have been met. In addition, the EHS&SD Committee has oversight over Suncor’s performance with respect to the company’s social goal regarding

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building mutual trust and respect with the Indigenous Peoples of Canada, and reviews Suncor’s annual Report on Sustainability reporting on Suncor’s EHS&SD progress, plans and performance objectives, as well as disclosure on lobbying.

Suncor’s annual Excellence Awards program recognizes and celebrates employees and contractors who lead the way in strengthening Suncor’s culture, living Suncor’s purpose and values, and accelerating the Suncor transformational journey.

The aforementioned policies are reviewed regularly, and are accessible to employees and contractors on the company’s intranet. Additional workshops and targeted training sessions on various matters under the policies are also conducted as warranted throughout the year. The Canadian Indigenous Relations Policy is available in Cree and Dene audio translations.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Date of Statement

The Statement of Reserves Data and Other Oil and Gas Information outlined below is dated February 23, 2022, with an effective date of December 31, 2021. Reserves evaluations have not been updated since the effective date and, therefore, do not reflect changes in the company’s reserves since that date. The preparation date of the information is January 10, 2022.

Disclosure of Reserves Data

Suncor is subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of reserves data in accordance with National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (NI 51-101).

The reserves data included in this section of the AIF is based upon evaluations conducted by GLJ Ltd., contained in its report dated February 18, 2022 (the GLJ Report). GLJ is an independent qualified reserves evaluator as defined in NI 51-101.

The reserves data summarizes Suncor’s SCO, bitumen, light crude oil and medium crude oil (combined, including immaterial amounts of heavy crude oil) and conventional natural gas (including immaterial amounts of NGLs) reserves and the net present values of future net revenues for these reserves using forecast prices and costs prior to provision for interest and general and administrative expense.

Advisories – Reserves Data

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves. There is no assurance that the forecast prices and cost assumptions will be attained and variances could be material. There is no guarantee that the estimates for SCO, bitumen, light crude oil and medium crude oil, heavy crude oil, conventional natural gas and NGLs reserves provided herein will be recovered. Actual SCO, bitumen, light crude oil and medium crude oil, heavy crude oil, conventional natural gas and NGLs volumes recovered may be greater than or less than the estimates provided herein. Readers should review the Glossary of Terms and Abbreviations and the definitions and information contained in the Notes to Reserves Data Tables, Definitions for Reserves Data Tables and Notes to Future Net Revenues Tables in conjunction with the following notes and tables.

Significant Risk Factors and Uncertainties Affecting Reserves

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external influences. Revisions are often required as a result of newly acquired technical data, technology improvements or changes in performance, pricing, economic conditions, market availability or regulatory requirements. Additional technical information regarding geology, hydrogeology, reservoir properties and reservoir fluid properties is obtained through seismic programs, drilling programs, updated reservoir performance studies and analysis and production history, and may result in revisions to reserves. Pricing, market availability and economic conditions affect the profitability of reserves development. Royalty regimes and environmental regulations and other regulatory changes cannot be predicted but may have positive or negative effects on reserves. Future technology improvements would be expected to have a favourable impact on the economics of reserves development and exploitation, and therefore may result in an increase to reserves. Political unrest, such as is occurring in Syria and Libya, has resulted in volumes that would otherwise be classified as reserves being classified as contingent resources.

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While the above factors, and many others, are relevant to the evaluation of reserves, certain judgments and assumptions are always required. As new information becomes available, these areas are reviewed and revised accordingly.

The reserves included in this AIF represent estimates only. There are numerous uncertainties inherent in estimating quantities and quality of these reserves, including many factors beyond the company’s control. In general, estimates of reserves and the future net cash flows from these reserves are based upon a number of factors and assumptions – such as production forecasts, regulations, pricing, the timing and amount of capital expenditures, future royalties, future operating costs, yield rates for upgraded production of SCO from bitumen, and future abandonment and reclamation costs – all of which may vary considerably from actual results and may be affected by many of the factors identified under Industry Conditions and Risk Factors herein. The accuracy of any reserves estimate is a matter of interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. For these reasons, estimates of the reserves and categorization of such reserves based on the certainty of recovery, prepared by different engineers or by the same engineers at different times, may vary.

Reserves estimates are based upon geological assessment, including drilling and laboratory tests. Mining reserves estimates also consider production capacity and upgrading yields, mine plans, operating life and regulatory constraints. In Situ reserves estimates are also based upon the testing of core samples and seismic operations and demonstrated commercial success of in situ processes. Suncor’s actual production, revenues, royalties, taxes, and development and operating expenditures with respect to the company’s reserves will vary from such estimates, and such variances could be material. Production performance subsequent to the date of the estimate may justify future revision, either upward or downward, if material.

The reserves evaluations are based in part on the assumed success of activities the company intends to undertake in future years. The estimated reserves and associated cash flows may be increased or reduced to the extent that such activities do or do not achieve the level of success assumed in the reserves evaluations.

Specific significant risk factors and uncertainties affecting Suncor’s reserves include, among others:

Commodity pricing affects the profitability of reserves development. For example, low commodity prices could have a material adverse effect on Suncor’s reserves; conversely, higher commodity prices may result in higher reserves by making more projects economically viable or extending their economic life. Refer to the Risk Factors – Volatility of Commodity Prices section of this AIF.

Suncor operates in jurisdictions that have regulated, or have proposed to regulate, industrial GHG emissions, including the laws enacted by the Government of Alberta impacting Suncor’s current and future Oil Sands assets, a summary of which is set forth in the Industry Conditions – Environmental Regulation – Climate Change section of this AIF. Such laws could impose significant compliance costs on Suncor, which could potentially impact the economic viability of certain projects recorded as reserves, or could require that new technologies be developed. Future development could be adversely impacted if compliance costs result in projects not being economically viable or if required technologies are not developed. Refer to the Risk Factors – Carbon Risk section of this AIF.

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As a result of political unrest in Syria, Suncor reclassified all Syria reserves to contingent resources, effective December 31, 2012. Suncor also reclassified all Libya reserves to contingent resources, effective December 31, 2016, due to political unrest in Libya. All Syria and Libya volumes remain classified as contingent resources as at December 31, 2021. The criteria for the reclassification of the aforementioned volumes back to reserves include sustained periods of political stability, operational and production stability, and normalization of business relations including financial transactions. Refer to the Risk Factors – Foreign Operations section of this AIF.

Refer to the Additional Information Relating to Reserves Data – Abandonment and Reclamation Costs section of this AIF.

Government intervention, such as mandatory production curtailments, could create long-term market uncertainty, which could have a material adverse effect on Suncor’s reserves. Refer to the Risk Factors – Government/Regulatory Policy section of this AIF.

Refer to the Risk Factors section of this AIF for additional information on additional significant risk factors and uncertainties affecting Suncor’s reserves.

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Oil and Gas Reserves Tables and Notes

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Summary of Oil and Gas Reserves⁽¹⁾

as at December 31, 2021

(forecast prices and costs)⁽²⁾