40-F 1 a2240152z40-f.htm 40-F
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UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

FORM 40-F

(Check One)

o |  | Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934
|  | or
ý |  | Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

| For fiscal year ended: Commission File Number: |  | December 31, 2019 No. 1-12384

SUNCOR ENERGY INC.
(Exact name of registrant as specified in its charter)

Canada (Province or other jurisdiction of incorporation or organization) |  | 1311,1321,2911, 4613,5171,5172 (Primary standard industrial classification code number, if applicable) |  | 98-0343201 (I.R.S. employer identification number, if applicable)

150 - 6th Avenue S.W.
P.O. Box 2844
Calgary, Alberta, Canada T2P 3E3
(403) 296-8000

(Address and telephone number of registrant's principal executive office)

CT Corporation System
28 Liberty St.
New York, New York 10005
(212) 894-8940

(Name, address and telephone number of agent for service in the United States)

Securities registered pursuant to Section 12(b) of the Act:

Title of each class: |  | Trading Symbol(s): |  | Name of each exchange on which registered:
Common shares |  | SU |  | New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act:

None

Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act:

None

For annual reports, indicate by check mark the information filed with this form:

ý |  | Annual Information Form |  | ý |  | Annual Audited Financial Statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report:

Common Shares |  | As of December 31, 2019 there were 1,531,873,743 Common Shares issued and outstanding

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the preceding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements for the past 90 days.

Yes |  | ý |  | No |  | o

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).

Yes |  | ý |  | No |  | o

Indicate by check mark whether the registrant is an emerging growth company as defined in Rule 12b-2 of the Exchange Act.

Emerging growth company o

If an emerging growth company that prepares its financial statements in accordance with U.S. GAAP, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. o

INCORPORATION BY REFERENCE

This annual report on Form 40-F is incorporated by reference into and as an exhibit to, as applicable, each of the following Registration Statements of the Registrant under the Securities Act of 1933: Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form S-8 (File No. 333-161021) and Form S-8 (File No. 333-161029). The Registrant's Annual Information Form dated February 26, 2020, included in this annual report on Form 40-F, and Audited Consolidated Financial Statements and Management's Discussion and Analysis for the year ended December 31, 2019, included as Exhibit 99-1 and Exhibit 99-2, respectively, to this annual report on Form 40-F, are incorporated by reference into and as an exhibit to, as applicable, the Registrant's Registration Statement on Form F-10 (File No. 333- 225338).

ANNUAL INFORMATION FORM

ANNUAL INFORMATION FORM DATED FEBRUARY 26, 2020

TABLE OF CONTENTS

1 |  | Advisories
2 |  | Glossary of Terms and Abbreviations
2 |  | Common Industry Terms
4 |  | Common Abbreviations
4 |  | Conversion Table
5 |  | Corporate Structure
5 |  | Name, Address and Incorporation
5 |  | Intercorporate Relationships
6 |  | General Development of the Business
6 |  | Overview
7 |  | Three-Year History
10 |  | Narrative Description of Suncor's Businesses
10 |  | Oil Sands
15 |  | Exploration and Production
19 |  | Refining and Marketing
23 |  | Other Suncor Businesses
24 |  | Suncor Employees
24 |  | Ethics, Social and Environmental Policies
26 |  | Statement of Reserves Data and Other Oil and Gas Information
28 |  | Oil and Gas Reserves Tables and Notes
33 |  | Future Net Revenues Tables and Notes
39 |  | Additional Information Relating to Reserves Data
51 |  | Industry Conditions
59 |  | Risk Factors
70 |  | Dividends
71 |  | Description of Capital Structure
73 |  | Market for Securities
74 |  | Directors and Executive Officers
80 |  | Audit Committee Information
82 |  | Legal Proceedings and Regulatory Actions
82 |  | Interests of Management and Others in Material Transactions
82 |  | Transfer Agent and Registrar
82 |  | Material Contracts
82 |  | Interests of Experts
83 |  | Disclosure Pursuant to the Requirements of the NYSE
83 |  | Additional Information
84 |  | Advisory – Forward-Looking Information and Non-GAAP Financial Measures
|  | Schedules
A-1 |  | SCHEDULE "A" – AUDIT COMMITTEE MANDATE
B-1 |  | SCHEDULE "B" – SUNCOR ENERGY INC. POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES
C-1 |  | SCHEDULE "C" – FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
D-1 |  | SCHEDULE "D" – FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR
E-1 |  | SCHEDULE "E" – FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

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 27 of the company's 2019 audited Consolidated Financial Statements), unless the context otherwise requires. 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 2019 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, 2019. References to the MD&A mean Suncor's Management's Discussion and Analysis, dated February 26, 2020.

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.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 1

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 lower sulphur content is referred to as sweet synthetic crude oil, while SCO with 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, 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.

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 the 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.

2 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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 for the purpose of supporting production in an existing field, such as wells drilled for the purpose of injecting gas, steam or water, or observation wells.

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.

Diluent is a light hydrocarbon mixture used to blend 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 in order 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 (PFT) refers to a froth treatment process whereby a lighter diluent or solvent that contains paraffin is used, which provides the capability to selectively remove some of the asphaltines (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 (PSCs) 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 PSC, 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. Low pressure 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 (SOR) is a metric used to quantify the efficiency of an in situ oil recovery process, which measures the cubic metres of water (converted to steam) required to produce one cubic metre of oil. 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 of, primary upgrading output to create sweet SCO and diesel.

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.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 3

Common Abbreviations

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

Measurement
bbl(s) |  | barrel(s)
bbls/d |  | barrels per day
mbbls |  | thousands of barrels
mbbls/d |  | thousands of barrels per day
mmbbls |  | millions of barrels
mmbbls/d |  | millions of barrels per day
boe |  | barrels of oil equivalent
boe/d |  | barrels of oil equivalent per day
mboe |  | thousands of barrels of oil equivalent
mboe/d |  | thousands of barrels of oil equivalent per day
mmboe |  | millions of barrels of oil equivalent
mmboe/d |  | millions of barrels of oil equivalent per day
mcf |  | thousands of cubic feet of natural gas
mcf/d |  | thousands of cubic feet of natural gas per day
mcfe |  | thousands of cubic feet of natural gas equivalent
mmcf |  | millions of cubic feet of natural gas
mmcf/d |  | millions of cubic feet of natural gas per day
mmcfe |  | millions of cubic feet of natural gas equivalent
mmcfe/d |  | millions of cubic feet of natural gas equivalent per day
bcf |  | billions of cubic feet of natural gas
bcfe |  | billions of cubic feet of natural gas equivalent
GJ |  | gigajoules
mmbtu |  | millions of British thermal units
API |  | American Petroleum Institute
CO2 |  | carbon dioxide
CO2e |  | carbon dioxide equivalent
m3 |  | cubic metres
m3/d |  | cubic metres per day
m3/s |  | cubic metres per second
km |  | kilometres
MW |  | Megawatts
GWh |  | Gigawatt hours
Mt |  | Megatonnes
Places and Currencies
U.S. |  | United States
U.K. |  | United Kingdom
B.C. |  | British Columbia
$ or Cdn$ |  | Canadian dollars
US$ |  | United States dollars
£ |  | Pounds sterling
€ |  | Euros
Products, Markets and Processes
WTI |  | West Texas Intermediate
WCS |  | Western Canadian Select
NGL(s) |  | natural gas liquid(s)
LPG |  | liquefied petroleum gas
SCO |  | synthetic crude oil
NYMEX |  | New York Mercantile Exchange
TSX |  | Toronto Stock Exchange
NYSE |  | New York Stock Exchange

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)

1 m3 liquids = 6.29 barrels |  | 1 tonne = 0.984 tons (long)
1 m3 natural gas = 35.49 cubic feet |  | 1 tonne = 1.102 tons (short)
1 m3 overburden = 1.31 cubic yards |  | 1 kilometre = 0.62 miles
|  | 1 hectare = 2.5 acres

(1)
  Conversion using the above factors on rounded numbers appearing in this AIF may produce small differences from reported amounts as a result of rounding.
(2)
  Some information in this AIF is set forth in metric units and some in imperial units.

4 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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 – 6th Avenue S.W., Calgary, Alberta, T2P 3E3.

Intercorporate Relationships

Material subsidiaries, each of which is wholly owned, either directly or indirectly, by the company as at December 31, 2019, are shown below:

Name |  | Jurisdiction Where Organized |  | Description |
Canadian operations |  |  |  |  |
Suncor Energy Oil Sands Limited Partnership |  | Alberta |  | This partnership holds most of the company's Oil Sands operations assets. |
Suncor Energy Products Partnership |  | Alberta |  | This partnership holds substantially all of the company's Canadian refining and marketing assets. |
Suncor Energy Marketing Inc. |  | Alberta |  | Through this subsidiary, production from the upstream Canadian businesses is marketed. This subsidiary also administers Suncor's energy trading activities and power business, markets certain third-party products, procures crude oil feedstock and natural gas for its downstream business, and procures and markets natural gas liquids (NGLs) and liquefied petroleum gas (LPG) for its downstream business. |
Suncor Energy Ventures Corporation |  | Alberta |  | A subsidiary which indirectly owns a 36.74% ownership in the Syncrude joint operation. |
Suncor Energy Ventures Partnership |  | Alberta |  | A subsidiary which owns a 22% ownership in the Syncrude joint operation. |
U.S. operations |  |  |  |  |
Suncor Energy (U.S.A.) Marketing Inc. |  | Delaware |  | A subsidiary that procures and markets third-party crude oil, in addition to procuring crude oil feedstock for the company's refining operations. |
Suncor Energy (U.S.A.) Inc. |  | Delaware |  | A subsidiary through which the company's U.S. refining and marketing operations are conducted. |
International operations |  |  |  |  |
Suncor Energy UK Limited |  | U.K. |  | A subsidiary through which the majority of the company's North Sea operations are conducted. |

The company's remaining subsidiaries each accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2019, and (ii) less than 10% of the company's consolidated operating revenues for the fiscal year ended December 31, 2019. In aggregate, the remaining subsidiaries accounted for less than 20% of the company's consolidated assets as at December 31, 2019, and less than 20% of the company's consolidated operating revenues for the fiscal year ended December 31, 2019.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 5

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is an integrated energy company headquartered in Calgary, Alberta, Canada. The company is strategically focused on developing one of the world's largest petroleum resource basins – Canada's Athabasca oil sands. In addition, Suncor explores for, acquires, develops, produces and markets crude oil in Canada and internationally; the company transports and refines crude oil, and markets petroleum and petrochemical products primarily in Canada. Suncor also operates a renewable energy business and conducts energy trading activities focused principally on the marketing and trading of crude oil, natural gas, byproducts, refined products, and power.

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, recovers bitumen from mining and in situ operations. Bitumen is either upgraded into SCO for refinery feedstock and diesel fuel, or blended with diluent for direct sale to market through the company's midstream infrastructure and its marketing activities. The Oil Sands segment includes:

•
  Oil Sands operations refer to Suncor's owned and operated mining, extraction, upgrading, in situ and related logistics, blending and storage assets in the Athabasca oil sands region. Oil Sands operations consist of:
  •
    Oil Sands Base operations include the Millennium and North Steepbank mining and extraction operations, integrated upgrading facilities known as Upgrader 1 and Upgrader 2, and the associated infrastructure for these assets – including utilities, energy, reclamation and storage facilities.
  •
    In Situ operations include oil sands bitumen production from Firebag and MacKay River and supporting infrastructure, including central processing facilities, cogeneration units, product transportation infrastructure, diluent import capabilities, storage assets and a cooling and blending facility. In Situ also includes development opportunities which may support future in situ production, including Meadow Creek (75%), Lewis (100%), OSLO (77.78%), various interests in Chard (25% to 50%), and a non-operated interest in Kirby (10%). In Situ production is either upgraded by Oil Sands Base, or blended with diluent and marketed directly to customers.
•
  Fort Hills includes Suncor's 54.11% interest in Fort Hills, which the company operates, and the East Tank Farm Development (ETFD) in which Suncor holds a 51% interest and operates.
•
  Syncrude refers to Suncor's 58.74% non-operated interest in the oil sands mining and upgrading operation.

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, and onshore assets in Libya and Syria.

•
  E&P Canada operations include Suncor's 37.675% working interest in Terra Nova, which Suncor operates. Suncor also holds non-operated interests in Hibernia (20% in the base project and 19.190% in the Hibernia Southern Extension Unit (HSEU)), White Rose (27.5% in the base project and 26.125% in the extensions), and Hebron (21.034%). In addition, the company holds interests in several exploration licences and significant discovery licences offshore Newfoundland and Labrador. Previously, E&P Canada also included Suncor's 37% equity interest in Canbriam Energy Inc. (Canbriam) which was sold during the second quarter of 2019.
•
  E&P International operations include Suncor's non-operated interests in Buzzard (29.89%), the Golden Eagle Area Development (GEAD) (26.69%), Oda (30%), the Fenja project (17.5%), and the Rosebank future development project (40%). Buzzard, Golden Eagle, and Rosebank are located in the U.K. sector of the North Sea, while Oda and the Fenja project are located in the Norwegian North Sea and the Norwegian Sea, respectively. In addition, Suncor owns, pursuant to EPSAs, working interests in the exploration and development of oilfields in the Sirte Basin in Libya, although production in Libya remained partially shut in throughout 2019 due to continued political unrest. The timing of a return to normal operations in Libya remains uncertain. Suncor also owns, pursuant to a PSC, an interest in the Ebla gas development in Syria, which has been suspended, indefinitely, since 2011 due to political unrest in the country.

6 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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 and supply of refined products, crude oil, natural gas, power and byproducts.

•
  Refining and Supply operations refine crude oil and intermediate feedstock into a wide range of petroleum and petrochemical products. Refining and Supply consists of:
  •
    Eastern North America operations include a 137,000 bbls/d refinery located in Montreal, Quebec and an 85,000 bbls/d refinery located in Sarnia, Ontario.
  •
    Western North America operations include a 142,000 bbls/d refinery located in Edmonton, Alberta and a 98,000 bbls/d refinery in Commerce City, Colorado.
  •
    Other Refining and Supply assets include interests in a petrochemical plant and a sulphur recovery facility in Montreal, Quebec, product pipelines and terminals throughout Canada and the U.S., and the St. Clair ethanol plant in Ontario.
•
  Marketing operations sell refined petroleum products to retail, commercial and industrial customers through a combination of company-owned Petro-Canada™ and Sunoco™ locations and branded-dealers in Canada and other non-branded retail stations in the U.S., a nationwide commercial road transportation network in Canada, and a bulk sales channel in Canada.

(1)
  Petro-Canada™ is a registered trademark of Suncor Energy Inc. used under license.

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. Beginning in the first quarter of 2019, results from the company's Energy Trading business have been included within each of the respective reporting business segments to which the respective trading activity relates. The Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.

•
  Renewable Energy includes interests in four wind farm operations in Ontario and Western Canada, being Adelaide, Chin Chute, Magrath and Sunbridge as well as the Forty Mile Wind Power project currently under construction.
•
  Corporate activities include stewardship of Suncor's debt and borrowing costs, expenses not allocated to the company's businesses, the company's captive insurance activities that insure a portion of the company's asset base and investments in clean technology.
•
  Intersegment revenues and expenses are removed from consolidated results in Eliminations. Intersegment activity includes the sale of product between the company's segments and insurance for a portion of the company's operations by the Corporate captive insurance entity. The sale of product between the company's segments is primarily related to crude refining feedstock sold from Oil Sands to Refining and Marketing.

Three-Year History

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

2017

•
  Sale of Suncor's interest in the Cedar Point wind facility. On January 24, 2017, the company closed the sale of its 50% share of Cedar Point for gross proceeds of $291 million.
•
  Sale of Petro-Canada Lubricants Inc. (PCLI) business. On February 1, 2017, the company completed the sale of PCLI, including the production and manufacturing facilities in Mississauga, Ontario as well as the global marketing and distribution assets held by PCLI, for gross proceeds of $1.125 billion to a subsidiary of HollyFrontier Corporation (HollyFrontier).
•
  Suncor commenced a normal course issuer bid (NCIB). Suncor filed its notice of intention to commence a new NCIB to purchase and cancel up to $2.0 billion of the company's common shares, beginning on May 2, 2017 and ending on May 1, 2018, through the facilities of the TSX, NYSE and/or alternative trading platforms. As at December 31, 2017, the company had repurchased 33.2 million common shares for cancellation at an average price of $42.61 per common share, for a total repurchase cost of $1.413 billion.
•
  West White Rose Project sanctioned. Suncor is a non-operating partner with a blended working interest of approximately 26%. The company's share of peak oil production is estimated to be 20 mbbls/d.
•
  Sale of Suncor's interest in the Ripley wind facility. On July 10, 2017, the company closed the sale of its 50% share of Ripley for gross proceeds of $48 million.
•
  Sale of 49% equity interest in Suncor's ETFD. On November 22, 2017, the company closed the sale to Fort McKay First Nation and Mikisew Cree First Nation of a 49% equity interest in Suncor's ETFD for gross proceeds of $503 million. The deal represents the largest business investment to date by First Nations in Canada.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 7

•
  US$750 million notes offering. On November 15, 2017, the company issued US$750 million of 4.00% senior unsecured notes due in 2047.
•
  First oil from Hebron. Hebron commenced production of oil on November 27, 2017.
•
  Repayment of debt. The company repaid US$1.25 billion 6.10% notes, US$600 million 6.05% notes and $700 million 5.80% notes all originally scheduled to mature in the first half of 2018. The reduction in outstanding debt reduced financing costs and has provided ongoing balance sheet flexibility.
•
  Fort Hills commercial dispute resolution. On December 21, 2017, the Fort Hills partners resolved their commercial dispute with respect to funding of project capital and reached an agreement pursuant to which Suncor acquired an additional 2.26% interest in the project for consideration of $308 million, bringing Suncor's ownership interest in the project at that time to 53.06%.

2018

•
  First oil from Fort Hills. On January 27, 2018, the Fort Hills project began producing paraffinic froth-treated bitumen from secondary extraction and production successfully ramped up and averaged 94% of the project's nameplate capacity of 194 mbbls/d (105 mbbls/d, net to Suncor) in the fourth quarter of 2018.
•
  Renewal of NCIB and increase in share repurchases. In May 2018, Suncor renewed its NCIB to continue to repurchase its common shares through the facilities of the TSX, NYSE and/or alternative trading platforms. On November 14, 2018, the TSX accepted a notice filed by the company of its intention to amend the NCIB effective November 19, 2018 to increase the maximum number of common shares that may be repurchased from 52,285,330 to 81,695,830 common shares between May 4, 2018 and May 3, 2019. In 2018, the company repurchased 64.4 million common shares for cancellation at an average price of $47.38 per share, for a total repurchase cost of $3.053 billion.
•
  Acquisition of additional 5% interest in Syncrude. On February 23, 2018, Suncor acquired an additional 5% interest in Syncrude from Mocal Energy Ltd. for $923 million, adding a further 17,500 bbls/d of SCO capacity and increasing the company's ownership interest to 58.74%.
•
  Purchased 17.5% participating interest in the Fenja development project. On May 31, 2018, the company acquired a 17.5% non-operated interest in the Fenja development project located offshore Norway from Faroe Petroleum Norge AS (Faroe) for acquisition costs of $70 million, plus interim settlement costs of $22 million. This project was sanctioned by its owners in December 2017, with first oil anticipated in 2021, with peak production expected to reach 34 mbbls/d (6 mbbls/d, net to Suncor) between 2021 and 2022.
•
  Acquisition of additional 1.05% interest in Fort Hills. During the first quarter of 2018, Suncor acquired an additional 1.05% interest in the Fort Hills operation for consideration of $145 million, bringing Suncor's ownership interest in the project to 54.11%. The additional interest is an outcome of the commercial settlement agreement reached among the Fort Hills partners in December 2017.
•
  Disposition of Joslyn Oil Sands Mining Project (Joslyn). On September 29, 2018, Suncor along with the other working-interest partners in Joslyn, agreed to sell 100% of their respective working interests to Canadian Natural Resources Limited (CNRL) for gross proceeds of $225 million, $82.7 million, net to Suncor. Suncor held a 36.75% working interest in Joslyn prior to the transaction.
•
  Production ramp up at Hebron. Drilling activity at Hebron was ongoing throughout 2018, with the third and fourth production wells coming online in April and October 2018, respectively. Production continued to ramp up ahead of expectations, averaging 13 mbbls/d during 2018.
•
  Buzzard Phase 2 sanctioned. During 2018, Buzzard Phase 2 was sanctioned by Suncor and the other project partners and the plan for development was approved by the U.K. Oil and Gas Authority. Suncor holds a 29.89% non-operated interest in the project. First oil is anticipated in early 2021.
•
  Repayment of debt. The company completed an early retirement of US$83 million of subsidiary debt acquired through the acquisition of Canadian Oil Sands Limited (COS) with a coupon of 7.75%, originally scheduled to mature on May 15, 2019.
•
  Syncrude bi-directional pipelines. During the fourth quarter of 2018, Suncor and its joint operating partners reached an agreement to build bi-directional interconnecting pipelines, which will connect Syncrude's Mildred Lake site and Suncor's Oil Sands Base operations. The pipelines will provide increased operational flexibility through the ability to transfer bitumen and gas oils between the two plants, enabling higher reliability and utilization. The pipelines are expected to be in-service by the second half of 2020.
•
  Full implementation of autonomous haulage systems (AHS) at North Steepbank. During 2018, the company completed the implementation of AHS at its North Steepbank mine. Autonomous haul trucks, which operate using GPS, wireless communication and perceptive

8 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

technologies, offer a number of advantages over existing truck and shovel operations, including enhanced safety performance, better operating efficiency and lower operating costs. Full implementation at Fort Hills and Millennium is expected to be completed in 2020 and 2023, respectively.

2019

•
  Government of Alberta Mandatory Production Curtailment. The Government of Alberta's mandatory production curtailment program began on January 1, 2019 and was in effect for the duration of 2019 and has been extended into 2020. Production curtailment primarily affected the company's non-upgraded bitumen production as the company maximized the production of higher value SCO barrels during the year.
•
  First oil from Oda. First oil was achieved ahead of schedule at Oda on March 16, 2019. At peak, Oda is expected to produce 35 mbbls/d (11 mbbls/d, net to Suncor).
•
  Mark Little appointed President and Chief Executive Officer. Mr. Little replaced Mr. Steve Williams who retired as Chief Executive Officer at the conclusion of the company's annual general meeting of shareholders on May 2, 2019.
•
  Sanction of Terra Nova asset life extension (ALE) project. On May 3, 2019, the company sanctioned the Terra Nova ALE project which is expected to extend the life of Terra Nova by approximately a decade and is planned for execution by the end of 2020.
•
  Sale of equity interest in Canbriam. In June 2019, Suncor completed the sale of its 37% equity interest in Canbriam for gross proceeds of $151 million. Suncor originally acquired the equity interest in Canbriam in 2018 in exchange for its northeast B.C. mineral landholdings, including associated production, along with additional cash consideration of $52 million in 2018.
•
  Debt issuance and repayment. During 2019, the company issued $750 million of 3.10% senior unsecured medium term notes and repaid US$140 million of maturing higher interest long-term debt.
•
  Investment in low-carbon power cogeneration. In the third quarter of 2019, Suncor announced that it is replacing its coke-fired boilers with a new cogeneration facility at its Oil Sands Base operations. The project is expected to provide reliable steam generation required for Suncor's extraction and upgrading operations and is expected to reduce the greenhouse gas (GHG) emissions intensity associated with steam production at Oil Sands Base operations by approximately 25%. In addition, the 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 reduce the GHG emissions in the province of Alberta by approximately 2.5 Mt per year. The project is estimated to cost approximately $1.4 billion with an expected in-service date in the second half of 2023.
•
  Continued investment in clean energy. In the fourth quarter of 2019, Suncor sanctioned the Forty Mile Wind Power Project in southern Alberta. This estimated $300 million renewable power project is expected to drive value through low-carbon power generation and the retention of generated carbon credits. The company also invested $73 million in Enerkem Inc., a producer of advanced biofuels and renewable chemicals from waste.
•
  Production ramp up at Hebron. Hebron reached nameplate production of 31.6 mbbls/d, net to Suncor ahead of schedule in 2019, with six new production wells coming online throughout the year. During 2019, production at Hebron averaged 23.5 mbbls/d, net to Suncor.
•
  Multi-year strategic alliance with Microsoft. To accelerate its digital transformation, Suncor has entered into a strategic alliance with Microsoft. This alliance enables Suncor to utilize Microsoft's full range of cloud solutions to empower a connected and collaborative workforce, build an agile data platform to increase analytics capabilities and partner with experts while gaining access to leading edge technologies.
•
  Completion of cross-Canada network of Petro-Canada™ electric vehicle (EV) stations. Suncor advanced its sustainability and technology initiatives by completing its coast-to-coast Electric Highway™ network of fast-charging EV stations across Canada during the fourth quarter of 2019.
•
  Continuation of NCIB. In May 2019, Suncor renewed its NCIB to continue to repurchase its common shares through the facilities of the TSX, NYSE and/or alternative trading platforms. On December 23, 2019, the TSX accepted a notice filed by the company to increase the maximum number of common shares that may be repurchased from 50,252,231 shares, or approximately 3% of Suncor's issued and outstanding common shares as at April 30, 2019, to 78,549,178 common shares, or 5% of Suncor's issued and outstanding common shares as at April 30, 2019. In 2019, the company repurchased 55.3 million common shares for cancellation at an average price of $41.12 per common share, for a total repurchase cost of $2.274 billion. Subsequent to the end of the year, Suncor's Board of Directors approved the renewal of its share repurchase program of up to $2.0 billion beginning on March 1, 2020.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 9

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:

•
  Mining and Extraction

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.

•
  Upgrading

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.

•
  Power and Steam Generation and Process Water Use

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.

•
  Maintenance

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.

•
  Reclamation

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 re-vegetation.

Oil sands tailings are the remaining sand, water, clay, silt and residual hydrocarbons left after the majority of 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 (PASS). 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 2019, the company mined approximately 159 million tonnes of bitumen ore (2018 – 138 million tonnes) and processed an average of 290 mbbls/d of mined bitumen in its extraction facilities (2018 – 259 mbbls/d).

The company expects to file a regulatory application within the first quarter of 2020 to potentially replace Suncor's Millennium and North Steepbank mines as they reach the end of their useful life in approximately 2035. The application is not a project sanction and a final sanctioning decision is not expected until 2030 at the earliest.

10 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Upgrading Facilities

Suncor's upgrading facilities consist of two upgraders: Upgrader 1, which has capacity of approximately 110 mbbls/d of SCO, and Upgrader 2, which has 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.

In the third quarter of 2019, Suncor announced that it is replacing its coke-fired boilers with a new 800 MW cogeneration facility at Oil Sands Base. 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 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 reduce the GHG emissions in the province of Alberta by approximately 2.5 Mt per year. The project is estimated to cost approximately $1.4 billion with an expected in-service date in the second half of 2023.

During 2019, Suncor averaged 313 mbbls/d of upgraded (SCO and diesel) production net of the company's internal consumption (2018 – 280 mbbls/d), mainly sourced from bitumen provided by both Oil Sands Base and In Situ operations.

Other Mining Leases

Suncor, directly and indirectly, owns interests in several other mineable oil sands leases, including Voyageur South 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 Voyageur South 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.

•
  The SAGD Process

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.

•
  Central Processing Facilities

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.

•
  Power and Steam Generation

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, which 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.

•
  Maintenance and Bitumen Supply

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 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 203 mbbls/d. 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, 2019, Firebag had 17 well pads in operation, with 242 SAGD well pairs and 52 infill wells either producing or on initial steam injection. Central processing facilities have been designed to be flexible 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 116 MW and, in 2019, Firebag exported approximately 285 MW of electricity to the Alberta power

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 11

grid and Oil Sands Base. There are also 13 OTSGs at the site for additional steam generation.

During 2019, Firebag production averaged 187 mbbls/d (2018 – 204 mbbls/d) with a SOR of 2.7 (2018 – 2.7). Production in 2019 was impacted by mandatory production curtailment.

Suncor has identified opportunities to debottleneck Firebag, including the completion of an emulsion handling project, an integrated well pad development and expansion of the company's Solvent SAGD program which could potentially add up to an additional 30 mbbls/d above nameplate capacity by 2024-25.

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, 2019, MacKay River included seven well pads with 114 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 2019, MacKay River production averaged 29 mbbls/d (2018 – 36 mbbls/d) with a SOR of 2.95 (2018 – 2.90). Production in 2019 was impacted by mandatory production curtailment. Following an outage in late 2019, MacKay River is expected to return to normal operations early in the second quarter of 2020. This follows completion of planned maintenance which has been accelerated to the first quarter of 2020 to coincide with the outage in an effort to minimize the impacts to annual production.

Other In Situ Leases

Suncor owns and operates several other oil sands leases which may support future in situ production, including Lewis, Meadow Creek, OSLO, Chard and Kirby. Suncor holds a 100% working interest in Lewis, a 75% working interest in Meadow Creek, a 77.78% working interest in OSLO, interests varying from 25% to 50% in Chard, and a non-operated interest in Kirby (10%). In 2018, Suncor acquired a 100% working interest in leases within the Gregoire area adjacent to its Meadow Creek lands. Meadow Creek is a SAGD project that is part of Suncor's planned in situ replication strategy. Suncor holds a 75% interest and is operator of the project, located approximately 40 km south of Fort McMurray. Meadow Creek consists of two independent In Situ projects: Meadow Creek East and Meadow Creek West.

In early 2017, Suncor received AER approval for the Meadow Creek East project. The project is expected to be developed in two stages with anticipated gross production of 40 mbbls/d 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. Timing of project sanction for Meadow Creek East and West will depend on future market conditions.

In February 2018, Suncor submitted an application for the Lewis project to the AER. Lewis is a SAGD project and is also part of Suncor's planned in situ replication strategy. Suncor holds a 100% interest in the project, located approximately 25 km northeast of Fort McMurray. The project is expected to be developed in stages, with anticipated peak production of 160 mbbls/d. Timing of 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 assets; however, Fort Hills uses a PFT 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 PFT 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 2019, Suncor's share of Fort Hills production averaged 85.3 mbbls/d (2018 – 67.4 mbbls/d) from approximately 51.3 million tonnes of bitumen ore mined (2018 – 38.9 million tonnes). Production in 2019 was impacted by mandatory production curtailment.

Due to a decline in forecasted heavy crude oil prices the company recorded an after-tax impairment charge of $2.803 billion on its share of Fort Hills in the fourth quarter of 2019.

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 operated by Syncrude Canada Ltd. (SCL). In 2006, SCL entered into a Management Services Agreement (MSA) with Imperial Oil Resources Limited (Imperial Oil) to provide business services. Imperial Oil provided notice of termination of the MSA in 2019 and the parties to the joint operation are working on a transition plan to cover the business services as provided by Imperial Oil under the MSA. The project is located near Fort McMurray and includes mining operations at Mildred Lake and Aurora North. In 2012, the Syncrude joint operating partners announced a plan to develop two mining areas adjacent to the current mine, Mildred Lake West Extension (MLX-W) and Mildred Lake East Extension (MLX-E), which, subject to approvals, would consequently extend the life of Mildred Lake

12 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

by a minimum of 10 years. In 2015, a decision was made by the joint operating partners 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 remaining approvals are expected in 2020.

Suncor has been collaborating with Syncrude for several years to achieve sustained reliability improvements and reduce costs. In January 2019, Suncor and SCL entered into a master business services agreement designed to enable Suncor to provide certain business services to SCL. The proximity of Syncrude to Oil Sands Base affords an opportunity for cost management and collaboration between the company and Syncrude in order to provide opportunities to optimize assets, including during periods of planned maintenance or interruption.

In 2018, Suncor reached a formal agreement with its Syncrude joint operation partners to build bi-directional interconnecting pipelines, which will connect Syncrude's Mildred Lake site and Suncor's Oil Sands Base operations. The pipelines are expected to provide increased operational flexibility through the ability to transfer bitumen and gas oils between the two plants, enabling higher reliability and utilization. The pipelines are expected to be in-service by the second half of 2020.

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 which provide heat and power.

Syncrude produces a single sweet SCO product. Marketing of this product is the responsibility of the individual joint venture partners.

Land reclamation activities are similar to those at Oil Sands Base; however, certain aspects of the tailings management processes 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 2019, Suncor's share of Syncrude production was limited by mandatory production curtailment, and averaged 172.3 mbbls/d (2018 – 144.2 mbbls/d). Since returning to normal operating rates in the third quarter of 2018 following a site-wide power outage in the second quarter of 2018, Syncrude has achieved reliable operations without any significant unplanned incidents. On October 29, 2019, Syncrude achieved a historic milestone, producing the three billionth (gross) barrel of crude oil at the Mildred Lake upgrading complex. Asset sustainment and maintenance capital expenditures in 2020 for Syncrude are expected to focus on a planned turnaround and reliability improvements.

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 Aurora South, through the company's 58.74% working interest in the Syncrude joint operation. During 2018, the company disposed of its previous 36.75% working interest in the Joslyn mining project.

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 which 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 AHS at its operated mine sites. Full implementation was completed at the North Steepbank mine in 2018, with full implementation at Fort Hills and Millennium is expected to be completed in 2020 and 2023, respectively. 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 2019, the company moved a total of 48.5 million gross tonnes of ore and overburden (2018 – 39.5 million tonnes) with AHS.

In 2018, Suncor completed the implementation of PASS technology as part of the company's accelerated dewatering project. PASS enables the dewatering of fine tailings from existing tailings ponds and the eventual reclamation and closure of tailings ponds. PASS technology consists of a proprietary mixture of coagulants and flocculants that enable water release and sequestering of fine tailings. Drainage of the first pond, Pond 8B, using the PASS technology commenced in 2018. PASS is expected to treat Suncor's legacy and new fluid tailings inventory over the life

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 13

of mine operations. During 2019, PASS increased the company's tailings treatment capacity to 230% of total annual fluid tailings produced (2018 – 165%).

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:

•
  Solvent+ – This is a suite of in situ solvent technologies that include various combinations of solvents and heating methods. Solvent+ is intended to provide an alternative to steam-based in situ recovery with the goal of reducing energy, GHG emissions and water usage footprints.
•
  In Situ Demonstration Facility (ISDF) – The ISDF is intended to enable Suncor to accelerate the commercial scale testing of in situ technologies. The goal of ISDF is to improve in situ extraction methods while materially improving environmental and economic performance. The ISDF will be located at MacKay River and received AER approval in late 2018.
•
  Zero-Impact Seismic – Zero-Impact Seismic is a seismic technology that has the potential to significantly reduce the surface disturbance of SAGD through the elimination of cutlines. This has the potential to reduce impacts to wildlife habitats and reduce stress on caribou populations. Suncor has completed 2D and 3D tests and will continue to advance the technology through field piloting in 2020.
•
  Non-Aqueous Extraction (NAE) – NAE is a potential new extraction process for oil sands mining operations that utilizes solvents as opposed to water as the primary extraction means. This has the potential to reduce water usage and tailings, and simplify mining processes, while reducing costs and GHG emissions. The company is planning a demonstration scale pilot for the 2021 to 2022 time frame.
•
  Partial Upgrading – Partial upgrading technology is intended to develop a low-temperature thermal cracking process to examine the potential for bitumen to be partially upgraded to a transportable and marketable product. This would increase value by decreasing the amount of diluent required, lower GHG intensity and avoid the need for a complex upgrader.

Sales of Principal Products

Primary markets for SCO and bitumen production from Suncor's Oil Sands segment, including PFT 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 Suncor'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 2019 increased to 116 mbbls/d or 54% (2018 – 106 mbbls/d or 44%) of total In Situ bitumen production as a result of mandatory production curtailment.

|  | 2019 |  | 2018
Sales Volumes and Operating Revenues – Principal Products |  | mbbls/d |  | % operating revenues |  | mbbls/d |  | % operating revenues |
SCO and diesel (including Syncrude) |  | 483.6 |  | 77 |  | 431.7 |  | 83 |
Bitumen |  | 187.5 |  | 22 |  | 191.3 |  | 15 |
Byproducts and other operating revenues(1) |  | n/a |  | 1 |  | n/a |  | 2 |
|  | 671.1 |  |  |  | 623.0 |  |  |

(1)
  Operating revenues include revenues associated with excess power from cogeneration units.

In the normal course of business, Suncor processes its proprietary sour SCO at the company's refineries or enters into long-term sales agreements for its proprietary sour SCO, 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. (Enbridge), 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 this facility. Product moves from the Athabasca Terminal in the following ways:

•
  To Edmonton via the Oil Sands pipeline, which is owned and operated by Suncor. At Edmonton, the product is processed in Suncor's Edmonton refinery, sold to other local refiners, or transferred onto the Enbridge Mainline or the TransMountain Pipeline system.

14 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

•
  To Cheecham, Alberta on the Enbridge Athabasca Pipeline or the Enbridge Wood Buffalo Pipeline and from Cheecham on the Enbridge Athabasca Pipeline or the Enbridge Wood Buffalo Pipeline Extension to Hardisty, Alberta.
•
  To Edmonton via the Enbridge Waupisoo Pipeline, originating at Cheecham.

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:

•
  To Suncor's Commerce City refinery via the Express and Platte pipelines. Suncor owns and operates a pipeline that is connected to the Commerce City refinery, which originates from the Guernsey, Wyoming station.
•
  To Suncor's Sarnia refinery on the Enbridge Mainline and to Suncor's Montreal refinery from Sarnia on Enbridge's Line 9.
•
  To most major refining hubs via the Enbridge Mainline, Express/Platte and Keystone pipeline systems.
•
  To U.S. Puget Sound refineries and to global markets via the TransMountain Pipeline, as well as by rail.

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

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 2019, Suncor incurred royalties at an average rate of 2% of gross revenue for Oil Sands Base (2018 – 1%) and at an average rate of 12% of gross revenue for Syncrude operations (2018 – 3%). Syncrude experienced a higher royalty rate in 2019 compared to the prior year due to a shift from GRR to NRR as a result of higher WCS prices. Oil Sands Base and the Syncrude project are both in the post-payout phase.

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 2019, Fort Hills incurred royalties at an average rate of 2% of gross revenue (2018 – 2%).

In 2019, Suncor incurred royalties for MacKay River, which is in the post-payout phase, at an average rate of 9% of gross revenue at the NRR (2018 – 14%), and royalties at an average rate of 3% of gross revenue for Firebag (2018 – 5%), which continues in the pre-payout phase.

Exploration and Production

E&P Canada – Assets and Operations

East Coast Canada

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 km 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 (68 mbbls/d, net to Suncor) and oil storage capacity of 960 mbbls. Terra Nova was the first harsh environment development in North America to use a FPSO vessel. 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. 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. Drilling activities took place at Terra Nova throughout 2018 and 2019. As at December 31, 2019, there were 29 wells: 18 oil production wells, nine water injection wells and two gas injection wells. The Terra Nova ALE project is expected to commence in the second quarter of 2020 with the FPSO returning to service in the fourth quarter of 2020. Production at Terra Nova is planned to resume once the project is completed. The project is expected to extend the life of Terra Nova by approximately a decade.

In 2019, Suncor's share of Terra Nova production averaged 11.6 mbbls/d (2018 – 11.7 mbbls/d). Annual turnaround maintenance was completed at the Terra Nova facility in May 2019, which lasted approximately 10 days.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 15

Hibernia and the Hibernia Southern Extension Unit (HSEU)

The Hibernia oilfield, encompassing the Hibernia and Ben Nevis Avalon reservoirs, is approximately 315 km 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/day (46 mbbls/d, net to Suncor) and 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, 2019, there were 72 wells: 40 oil production wells, 26 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 HSEU. At the end of 2019, 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 2019, Suncor's share of Hibernia production averaged 20.1 mbbls/d (2018 – 22.1 mbbls/d). Production in 2019 was impacted by an unplanned outage in the third quarter of 2019.

White Rose and the White Rose Extensions

White Rose is approximately 350 km southeast of St. John's. Operated by Husky Oil Operations Limited (Husky), White Rose uses a FPSO vessel and has gross production capacity of 140 mbbls/d (39 mbbls/d, net to Suncor) 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, 2019, there were 45 wells: 24 oil production wells, 16 water injection wells, three gas storage wells, and two 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 include the North Amethyst, South White Rose Extension, and West White Rose satellite fields. First oil was achieved at North Amethyst in May 2010. Development of the South White Rose Extension began in 2013, with first oil being 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 (WWRP), was sanctioned during the second quarter of 2017, with first oil targeted for the end of 2022. The project is 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. Major development activity began in 2018 and will continue in 2020. Due to increased capital cost estimates for the WWRP the company recorded an after-tax impairment charge of $393 million on its share of White Rose in the fourth quarter of 2019.

In 2019, Suncor's share of White Rose production averaged 4.7 mbbls/d (2018 – 6.6 mbbls/d). Turnaround maintenance was completed at White Rose in June 2019, which lasted approximately three weeks. Production at the White Rose field was shut in from mid-November 2018 to late January 2019 due to operational complications. White Rose began a staged return to normal operations, which was completed by the third quarter of 2019.

Hebron

The Hebron oilfield is located 340 km southeast of St. John's and is operated by ExxonMobil Canada Properties (ExxonMobil Canada). 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, net to Suncor, ramping up over the next 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 2019, drilling activities continued at Hebron and will continue throughout 2020. In 2019, Suncor's share of production averaged 23.5 mbbls/d (2018 – 13.0 mbbls/d). As at December 31, 2019, there were 15 wells: 10 oil production wells, three water injection wells, one gas injection well, and one cuttings reinjection well. Annual turnaround maintenance was completed at the Hebron facility in September 2019, which lasted approximately 10 days.

Other Assets

Suncor continues to pursue opportunities offshore Newfoundland and Labrador. During 2018, Suncor was the successful bidder on two exploration licences, including operatorship of one of the two licences, west of the Terra Nova field. In addition, Suncor became an interest holder, with Equinor Canada Ltd., in a licence east of the White Rose field. These licences carry work commitments from 2019 to 2024. The company also holds interests in 48 significant discovery licences and five exploration licences offshore in this area.

16 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

E&P International – Assets and Operations

Offshore U.K. & Norway

Buzzard

The Buzzard oilfield is located in the Outer Moray Firth, 95 km northeast of Aberdeen, Scotland. Operated by CNOOC Petroleum Europe Limited (CNOOC Europe), 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 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. Drilling activities took place at Buzzard during 2019 with two active rigs. Four new infill wells were drilled in 2019 and Buzzard Phase 2 drilling activities took place concurrently. As at December 31, 2019, there were 48 wells: 34 oil and gas production wells and 14 water injection wells. In 2019, Suncor's share of Buzzard production averaged 31.9 mboe/d (2018 – 34.2 mboe/d). Buzzard Phase 2 was sanctioned in 2018 with production anticipated in 2021. Project execution has progressed throughout 2019 and will be tied back to the existing Buzzard complex.

Golden Eagle Area Development (GEAD)

GEAD, which is operated by CNOOC Europe, is approximately 20 km north of the Buzzard oilfield and consists of the unitization of the Peregrine, Hobby, Golden Eagle and Solitaire discoveries. The development incorporates a production, utilities and accommodation platform, linked to a separate wellhead platform, with first oil achieved in October 2014. The facilities have gross production capacity of approximately 76 mboe/d (20 mboe/d, net to Suncor). As at December 31, 2019, there were 20 wells: 15 oil and gas production wells and five water injection wells. In 2019, Suncor's share of GEAD production averaged 9 mboe/d (2018 – 12.4 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 (Equinor). It is located approximately 130 km northwest of the Shetland Islands, in the U.K. North Sea, in water depths of approximately 1,100 metres. The project is currently in the pre-sanction phase with a sanction decision planned for late 2022.

Oda

The Oda field (PL405 licence) was discovered in 2011 and is located 13 km 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, with peak production expected to reach 35 mbbls/d (11 mbbls/d, net to Suncor). Drilling activities were completed in 2018, and first oil was achieved in March 2019. As at December 31, 2019, there were three wells: two production wells and one water injection well.

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 km 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 Ministry of Petroleum and Energy in the first half of 2018. The field will be developed with two subsea templates with six wells tied back to the Equinor-operated Njord platform. First oil is planned for 2021, with peak production expected to reach 34 mbbls/d (6 mbbls/d, net to Suncor) between 2021 and 2022.

Other Assets

Suncor continues to pursue other opportunities offshore of the U.K. and Norway. The company holds interests in 18 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.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 17

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. Suncor had production and liftings from some of its oilfields in 2019, but others remain shut in due to political unrest. The timing of a return to normal operations in Libya remains uncertain.

The estimated cost of Suncor's remaining exploration work program commitment at December 31, 2019, is US$359 million. Suncor declared force majeure for all exploration commitments in Libya effective December 14, 2014, and this declaration remains in effect. During 2019, the company received $264 million after-tax in risk mitigation proceeds for its Libyan assets. The proceeds may be subject to a provisional repayment which is dependent on the future performance and cash flows from Suncor's Libyan assets.

Suncor's share of production in Libya on an economic basis averaged 2.3 mbbls/d in 2019 (2018 – 2.9 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. & 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.

Exploration and Production Sales Summary:

|  | 2019 |  | 2018 |
Sales Volumes |  | mboe/d |  | % operating revenues |  | mboe/d |  | % operating revenues |
E&P Canada |  |  |  |  |  |  |  |  |
| Crude oil and NGLs |  | 60.8 |  | 57 |  | 52.8 |  | 52 |
| Natural gas |  | — |  | — |  | 0.5 |  | — |
E&P International |  |  |  |  |  |  |  |  |
| Crude oil and NGLs(1) |  | 44.3 |  | 42 |  | 48.7 |  | 47 |
| Natural gas |  | 0.8 |  | 1 |  | 0.8 |  | 1 |
Total Exploration and Production |  |  |  |  |  |  |  |  |
| Crude oil and NGLs |  | 105.1 |  | 99 |  | 101.5 |  | 99 |
| Natural gas |  | 0.8 |  | 1 |  | 1.3 |  | 1 |

(1)
  E&P International Crude oil and NGLs includes production volumes for Libya on an economic basis.

Distribution of Products

•
  East Coast Canada – field production is transported by shuttle tanker from offshore installations and either delivered directly to customers (if tanker schedules permit) or to the Newfoundland transshipment terminal in Placentia Bay, where it is subsequently loaded onto tankers for transport to markets in Eastern Canada, the U.S., Europe, Latin America and Asia. Suncor has a 14% ownership interest in the transshipment facility and is part of a group of companies that share the operation of marine transportation assets for East Coast Canada.
•
  Buzzard – crude oil is transported via the third-party operated Forties Pipeline System to the Hound Point terminal in Scotland and sold as part of the Forties Blend crude stream. Natural gas is transported via the third-party operated Frigg Pipeline System to the St. Fergus Gas Terminal in Scotland.
•
  Golden Eagle – crude oil is transported to the third-party operated Flotta Terminal in the Orkney Islands in Scotland, where it is shipped to market as part of the Flotta Gold blend. Natural gas is transported via the third-party operated SAGE Pipeline System to the St. Fergus Gas Terminal in Scotland.

18 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

•
  Oda – crude oil and natural gas is transported via the third-party operated Norpipe to the Teesside terminal in the United Kingdom, where it is shipped to market as part of the Ekofisk Blend crude stream. Natural gas from Oda is injected into the Ula reservoir to improve oil recovery from the Ula field.

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 Royalty Regime (GORR) 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 has reached the net royalty stage, consisting of a two tier profit-sensitive royalty. Tier one is the greater of 10% of gross revenue or 30% of net revenue. Tier two is an additional 12.5% of net revenue. During 2019, Terra Nova royalties averaged 17% of gross revenue (2018 – 20%).

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 (NPI) 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 will coincide with the triggering of the tier one royalty which occurred in 2019.

Hibernia royalties (including the HSEU) and NPI combined to average 32% of gross revenue for 2019 (2018 – 23%).

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 2019, total White Rose royalties averaged 4% of gross revenue (2018 – 7%).

The Hebron royalty consists of an initial sliding-scale basic royalty, followed by a three-tiered royalty which will become payable upon the achievement of specified levels of profitability. The basic royalty will start at 1% and increase 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 2019, Hebron royalties averaged 1% of gross revenue (2018 – 1%).

E&P International

There are no royalties on oil and gas production from Offshore U.K. & Norway; however, oil and gas profits offshore U.K. are subject to a 40% income tax rate. In addition, oil and gas profits offshore Norway are subject to a 78% income tax rate. 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, as well as 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. The Montreal refinery received inland-sourced crude volumes averaging 123.8 mbbls/d in 2019 (2018 – 124.1 mbbls/d).

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

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 19

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. (ParaChem), 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 355,000 metric tonnes in 2019 (2018 – 372,000 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 2019, the plant produced 400 million litres of ethanol (2018 – 402 million litres).

Western North America

Edmonton Refinery

The Edmonton refinery has a crude oil capacity of 142 mbbls/d and 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 partners' share of production) and other producers from the Wood Buffalo and Cold Lake regions of Alberta. The refinery can process approximately 41 mbbls/d of blended heavy feedstock (comprised of 29 mbbls/d of bitumen and 12 mbbls/d of diluent) and process approximately 44 mbbls/d of sour SCO. The refinery can also process approximately 57 mbbls/d of sweet SCO through its synthetic crude train.

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 TransMountain 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. 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.

20 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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, 2019 and 2018.

Average Daily Crude Throughput |  | Montreal |  | Sarnia |  | Edmonton |  | Commerce City |
(mbbls/d, except as noted) |  | 2019 |  | 2018 |  | 2019 |  | 2018 |  | 2019 |  | 2018 |  | 2019 |  | 2018 |
Sweet synthetic |  | 7.9 |  | 8.9 |  | 24.8 |  | 29.7 |  | 54.9 |  | 50.1 |  | — |  | — |
Sour synthetic |  | — |  | — |  | 31.8 |  | 25.7 |  | 45.3 |  | 32.8 |  | 9.4 |  | 9.2 |
Diluted bitumen |  | 20.6 |  | 22.1 |  | — |  | — |  | 43.0 |  | 35.6 |  | 9.9 |  | 11.2 |
Sweet conventional |  | 89.0 |  | 90.0 |  | 0.3 |  | 3.1 |  | — |  | — |  | 63.9 |  | 65.7 |
Sour conventional |  | 8.0 |  | 9.2 |  | 21.0 |  | 19.4 |  | — |  | 4.7 |  | 9.4 |  | 13.4 |
Total |  | 125.5 |  | 130.2 |  | 77.9 |  | 77.9 |  | 143.2 |  | 123.2 |  | 92.6 |  | 99.5 |
Utilization (%) |  | 92 |  | 95 |  | 92 |  | 92 |  | 101 |  | 87 |  | 94 |  | 102 |
Equity Crude Processed(1) |  | 7.7 |  | 7.0 |  | 51.6 |  | 45.0 |  | 121.3 |  | 99.3 |  | 9.4 |  | 9.2 |

(1)
  Includes Suncor's upstream operations, including its working interest in Syncrude.

Refined Petroleum Production Yield Mix |  | Montreal |  | Sarnia |  | Edmonton |  | Commerce City |
(%) |  | 2019 |  | 2018 |  | 2019 |  | 2018 |  | 2019 |  | 2018 |  | 2019 |  | 2018 |
Gasoline |  | 38 |  | 41 |  | 47 |  | 51 |  | 43 |  | 44 |  | 49 |  | 48 |
Distillates |  | 38 |  | 37 |  | 39 |  | 37 |  | 52 |  | 50 |  | 34 |  | 35 |
Other |  | 24 |  | 22 |  | 14 |  | 12 |  | 5 |  | 6 |  | 17 |  | 17 |

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, 2019, Suncor's ownership interests in certain pipelines were as follows:

Pipeline | Ownership |  | Type |  | Origin |  | Destinations |
Portland-Montreal Pipeline | 23.80% |  | Crude oil |  | Portland, Maine |  | Montreal, Quebec |
Trans-Northern Pipeline | 33.30% |  | Refined product |  | Montreal, Quebec |  | Ontario – Ottawa, Toronto & Oakville |
Sun-Canadian Pipeline | 55.00% |  | Refined product |  | Sarnia, Ontario |  | Ontario – Toronto, London & Hamilton |
Alberta Products Pipeline | 35.00% |  | Refined product |  | Edmonton, Alberta |  | Calgary, Alberta |
Rocky Mountain Crude Pipeline | 100.00% |  | Crude oil |  | Guernsey, Wyoming |  | Denver, Colorado |
Centennial Pipeline | 100.00% |  | Crude oil |  | Guernsey, Wyoming |  | Cheyenne, Wyoming |
Oil Sands Pipeline | 100.00% |  | Crude oil |  | Fort McMurray, Alberta |  | Edmonton, Alberta |

Marketing – Assets and Operations

Suncor's retail service station network operates nationally in Canada primarily under the Petro-Canada™ brand. As at December 31, 2019, this network consisted of 1,547 outlets across Canada, of which 796 locations are company-owned locations and 751 are branded-dealers. Selected locations along the Trans-Canada highway comprise the coast-to-coast Electric Highway™ network of fast charging EV 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 4.9 million litres per site in 2019 (2018 – 4.8 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 142 Shell™-branded sites in both Colorado and Wyoming, and with 53 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.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 21

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.

Retail and Wholesale Summary

|  | As at December 31
Locations |  | 2019 |  | 2018 |
Retail Service Stations – Canada |  |  |  |  |
| Petro-Canada™ -branded |  | 1 546 |  | 1 527 |
| Sunoco™ -branded |  | 1 |  | 1 |
|  | 1 547 |  | 1 528 |
Retail Service Stations(1) – U.S. |  |  |  |  |
| Shell™ -branded retail service stations – Colorado/Wyoming |  | 177 |  | 180 |
| Exxon™ -branded retail service stations – Colorado |  | 42 |  | 40 |
| Mobil™ -branded retail service stations – Colorado |  | 20 |  | 18 |
|  | 239 |  | 238 |
Wholesale Cardlock Sites – Canada |  |  |  |  |
| Petro-Canada™-branded cardlock sites (PETRO-PASS™) |  | 310 |  | 307 |

(1)
  Shell™ is a registered U.S. trademark of SHELL TRADEMARK MANAGEMENT B.V., and Exxon™ and Mobil™ are registered U.S. trademarks of Exxon Mobil Corporation.

Refined Products Sales Volumes

|  | 2019 |  | 2018
Sales Volumes |  | mbbls/d |  | % operating revenues |  | mbbls/d |  | % operating revenues |
Gasoline (includes motor and aviation gasoline) |  |  |  |  |  |  |  |  |
| Eastern North America |  | 119.8 |  |  |  | 117.8 |  |  |
| Western North America |  | 126.8 |  |  |  | 127.8 |  |  |
|  | 246.6 |  | 46 |  | 245.6 |  | 47 |
Distillates (includes diesel and heating oils, and aviation jet fuels) |  |  |  |  |  |  |  |  |
| Eastern North America |  | 102.9 |  |  |  | 95.8 |  |  |
| Western North America |  | 115.2 |  |  |  | 107.6 |  |  |
|  | 218.1 |  | 40 |  | 203.4 |  | 39 |
Other (includes heavy fuel oil, asphalts, petrochemicals, other) |  |  |  |  |  |  |  |  |
| Eastern North America |  | 48.8 |  |  |  | 52.7 |  |  |
| Western North America |  | 25.9 |  |  |  | 25.6 |  |  |
|  | 74.7 |  | 14 |  | 78.3 |  | 15 |
|  | 539.4 |  |  |  | 527.3 |  |  |

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.

22 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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. Beginning in the first quarter of 2019, results from the company's Energy Trading business have been included within each of the respective reporting business segments to which the respective trading activity relates. The Energy Trading business was previously reported within the Corporate, Energy Trading and Eliminations segment.

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.

The Energy Trading business supports the company's Refining and Marketing business by optimizing the supply of crude and NGLs 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. Suncor sanctioned the Forty Mile Wind Power Project in late 2019; this 200 MW renewable power project has an estimated total capital spend of $300 million with completion expected in late 2021.

Suncor's wind power projects as at December 31, 2019:

Wind Power Projects |  |  |  | Ownership Interest (%) |  | Gross (MW) |  | Turbines |  | Completed |
Operated by Suncor |  |  |  |  |  |  |  |  |  |  |
| Adelaide |  | Strathroy, Ontario |  | 75.0 |  | 40 |  | 18 |  | 2014 |
Non-operated |  |  |  |  |  |  |  |  |  |  |
| Chin Chute |  | Taber, Alberta |  | 33.3 |  | 30 |  | 20 |  | 2006 |
| Magrath |  | Magrath, Alberta |  | 33.3 |  | 30 |  | 20 |  | 2004 |
| SunBridge |  | Gull Lake, Saskatchewan |  | 50.0 |  | 11 |  | 17 |  | 2002 |

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 23

SUNCOR EMPLOYEES

The following table shows the distribution of employees among Suncor's business units and corporate office.

As at December 31 |  | 2019 |  | 2018 |
Oil Sands(1)(2) |  | 6 400 |  | 6 297 |
Exploration and Production(2) |  | 351 |  | 340 |
Refining and Marketing(2) |  | 2 824 |  | 2 939 |
Corporate and Eliminations(2)(3) |  | 3 314 |  | 2 904 |
Total |  | 12 889 |  | 12 480 |

(1)
  Includes employees related to the Fort Hills operations.
(2)
  Prior period information has been re-classed 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 31% or 4,322 of the company's employees were covered by collective agreements at the end of 2019. The company completed negotiations in 2019 and collective agreements are now in place with United Steelworkers at the Commerce City refinery and with Unifor at Oil Sands Base and Firebag, as well as the Edmonton refinery, the Montreal refinery and the Burrard, Edmonton, London, Montreal and Oakville terminals. Negotiations are in progress for the Terra Nova and Ottawa Terminal collective agreements, representing approximately 71 employees.

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, harassment, 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 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

24 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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, which 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 effective, long-term and mutually beneficial relationships. The policy makes it clear that responsible development takes into account Indigenous interests regarding the opportunities and impacts of energy development on communities and on their traditional and current uses of lands and resources.

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 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. In addition, the EHS&SD Committee has oversight over Suncor's performance with respect to the company's social goal regarding 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 President's Operational Excellence Awards support and highlight the goals of the EH&S policy by honouring employees and contractors who demonstrate an exceptional commitment to EH&S performance. The awards program highlights progress on safety and environmental initiatives and provides educational opportunities for all employees.

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.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 25

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 26, 2020, with an effective date of December 31, 2019. Reserves evaluations have not been updated since the effective date and, thus, do not reflect changes in the company's reserves since that date. The preparation date of the information is January 27, 2020.

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 for Suncor's Mining and In Situ operations is based upon evaluations conducted by GLJ Petroleum Consultants Ltd. (GLJ), contained in their reports dated February 21, 2020 (the GLJ Reports). The reserves data set forth below for all other reserves, which includes Suncor's interests in its conventional assets offshore Newfoundland and Labrador (collectively, E&P Canada), and conventional assets offshore of the U.K. and Norway (collectively, Offshore U.K. & Norway), is based upon evaluations conducted by Sproule Associates Limited or Sproule International Limited (collectively, Sproule), contained in their reports dated February 21, 2020 (the Sproule Reports). Each of GLJ and Sproule (collectively, the Evaluators) are independent qualified reserves evaluators 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 historical 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.

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 variable 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.

26 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

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 reserves and estimated cash flow to be derived from the reserves contained in the reserves evaluations 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:

•
  Volatility of Commodity Prices

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

•
  Carbon Risk

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.

•
  Political Unrest

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, 2019. 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.

•
  Abandonment and Reclamation costs

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

•
  Government Action

Government intervention, including 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 and Policy Effectiveness section of this AIF.

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

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 27

Oil and Gas Reserves Tables and Notes

Summary of Oil and Gas Reserves(1)
as at December 31, 2019
(forecast prices and costs)(2)

|  | SCO(3) |  | Bitumen |  | Light Crude & Medium Crude Oil(4) |  | Conventional Natural Gas(6) |  | Total
|  | (mmbbls) |  | (mmbbls) |  | (mmbbls) |  | (bcfe) |  | (mmboe)
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |
Proved Developed Producing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 1 966 |  | 1 800 |  | 896 |  | 833 |  | — |  | — |  | — |  | — |  | 2 862 |  | 2 632 |
| In Situ |  | 231 |  | 201 |  | 99 |  | 85 |  | — |  | — |  | — |  | — |  | 330 |  | 286 |
| E&P Canada |  | — |  | — |  | — |  | — |  | 72 |  | 63 |  | — |  | — |  | 72 |  | 63 |
Total Canada |  | 2 197 |  | 2 001 |  | 996 |  | 917 |  | 72 |  | 63 |  | — |  | — |  | 3 265 |  | 2 981 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | 47 |  | 47 |  | 2 |  | 2 |  | 48 |  | 48 |
Total Proved Developed Producing |  | 2 197 |  | 2 001 |  | 996 |  | 917 |  | 120 |  | 110 |  | 2 |  | 2 |  | 3 313 |  | 3 029 |
Proved Developed Non-Producing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| E&P Canada |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Total Canada |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Total Proved Developed Non-Producing |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Proved Undeveloped |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | 627 |  | 520 |  | 679 |  | 558 |  | — |  | — |  | — |  | — |  | 1 306 |  | 1 079 |
| E&P Canada |  | — |  | — |  | — |  | — |  | 44 |  | 41 |  | — |  | — |  | 44 |  | 41 |
Total Canada |  | 627 |  | 520 |  | 679 |  | 558 |  | 44 |  | 41 |  | — |  | — |  | 1 350 |  | 1 120 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | 8 |  | 8 |  | 13 |  | 13 |  | 10 |  | 10 |
Total Proved Undeveloped |  | 627 |  | 520 |  | 679 |  | 558 |  | 51 |  | 49 |  | 13 |  | 13 |  | 1 359 |  | 1 130 |
Proved |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 1 966 |  | 1 800 |  | 896 |  | 833 |  | — |  | — |  | — |  | — |  | 2 862 |  | 2 632 |
| In Situ |  | 858 |  | 721 |  | 779 |  | 643 |  | — |  | — |  | — |  | — |  | 1 636 |  | 1 365 |
| E&P Canada |  | — |  | — |  | — |  | — |  | 116 |  | 104 |  | — |  | — |  | 116 |  | 104 |
Total Canada |  | 2 824 |  | 2 521 |  | 1 675 |  | 1 476 |  | 116 |  | 104 |  | — |  | — |  | 4 615 |  | 4 101 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | 56 |  | 56 |  | 15 |  | 15 |  | 58 |  | 58 |
Total Proved |  | 2 824 |  | 2 521 |  | 1 675 |  | 1 476 |  | 172 |  | 160 |  | 15 |  | 15 |  | 4 673 |  | 4 159 |
Probable |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 601 |  | 547 |  | 469 |  | 402 |  | — |  | — |  | — |  | — |  | 1 070 |  | 950 |
| In Situ |  | 1 143 |  | 902 |  | 325 |  | 242 |  | — |  | — |  | — |  | — |  | 1 468 |  | 1 144 |
| E&P Canada |  | — |  | — |  | — |  | — |  | 162 |  | 131 |  | — |  | — |  | 162 |  | 131 |
Total Canada |  | 1 744 |  | 1 450 |  | 794 |  | 644 |  | 162 |  | 131 |  | — |  | — |  | 2 700 |  | 2 224 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | 32 |  | 32 |  | 16 |  | 16 |  | 35 |  | 35 |
Total Probable |  | 1 744 |  | 1 450 |  | 794 |  | 644 |  | 194 |  | 163 |  | 16 |  | 16 |  | 2 735 |  | 2 259 |
Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 2 567 |  | 2 347 |  | 1 365 |  | 1 235 |  | — |  | — |  | — |  | — |  | 3 932 |  | 3 582 |
| In Situ |  | 2 001 |  | 1 624 |  | 1 103 |  | 885 |  | — |  | — |  | — |  | — |  | 3 104 |  | 2 509 |
| E&P Canada |  | — |  | — |  | — |  | — |  | 278 |  | 235 |  | — |  | — |  | 278 |  | 235 |
Total Canada |  | 4 568 |  | 3 971 |  | 2 469 |  | 2 120 |  | 278 |  | 235 |  | — |  | — |  | 7 314 |  | 6 325 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | 88 |  | 88 |  | 31 |  | 31 |  | 93 |  | 93 |
Total Proved Plus Probable |  | 4 568 |  | 3 971 |  | 2 469 |  | 2 120 |  | 366 |  | 323 |  | 31 |  | 31 |  | 7 407 |  | 6 419 |

Please see Notes (1) through (4) and (6) at the end of the reserves data section for important information about volumes in this table.

28 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Reconciliation of Gross Reserves(1)
as at December 31, 2019
(forecast prices and costs)(2)

|  | SCO(3) |  | Bitumen |  | Light Crude & Medium Crude Oil(4)(5) |  | Conventional Natural Gas(6) |  | Total |  |
|  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  |
|  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | bcfe |  | bcfe |  | bcfe |  | mmboe |  | mmboe |  | mmboe |  |
Mining |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | 2 069 |  | 621 |  | 2 690 |  | 942 |  | 496 |  | 1 438 |  | — |  | — |  | — |  | — |  | — |  | — |  | 3 011 |  | 1 117 |  | 4 128 |  |
| Extensions & Improved Recovery(7) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Technical Revisions(8) |  | 41 |  | (20 | ) | 21 |  | (15 | ) | (27 | ) | (42 | ) | — |  | — |  | — |  | — |  | — |  | — |  | 26 |  | (47 | ) | (21 | ) |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | (144 | ) | — |  | (144 | ) | (31 | ) | — |  | (31 | ) | — |  | — |  | — |  | — |  | — |  | — |  | (174 | ) | — |  | (174 | ) |
December 31, 2019 |  | 1 966 |  | 601 |  | 2 567 |  | 896 |  | 469 |  | 1 365 |  | — |  | — |  | — |  | — |  | — |  | — |  | 2 862 |  | 1 070 |  | 3 932 |  |
In Situ |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | 729 |  | 1 175 |  | 1 904 |  | 770 |  | 387 |  | 1 157 |  | — |  | — |  | — |  | — |  | — |  | — |  | 1 499 |  | 1 562 |  | 3 061 |  |
| Extensions & Improved Recovery(7) |  | 122 |  | (36 | ) | 86 |  | 71 |  | (42 | ) | 29 |  | — |  | — |  | — |  | — |  | — |  | — |  | 193 |  | (78 | ) | 115 |  |
| Technical Revisions(8) |  | 37 |  | 4 |  | 41 |  | (22 | ) | (20 | ) | (41 | ) | — |  | — |  | — |  | — |  | — |  | — |  | 15 |  | (16 | ) | — |  |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | (30 | ) | — |  | (30 | ) | (41 | ) | — |  | (41 | ) | — |  | — |  | — |  | — |  | — |  | — |  | (71 | ) | — |  | (71 | ) |
December 31, 2019 |  | 858 |  | 1 143 |  | 2 001 |  | 779 |  | 325 |  | 1 103 |  | — |  | — |  | — |  | — |  | — |  | — |  | 1 636 |  | 1 468 |  | 3 104 |  |
E&P Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | — |  | — |  | — |  | — |  | — |  | — |  | 123 |  | 174 |  | 297 |  | — |  | — |  | — |  | 123 |  | 174 |  | 297 |  |
| Extensions & Improved Recovery(7) |  | — |  | — |  | — |  | — |  | — |  | — |  | 4 |  | 7 |  | 11 |  | — |  | — |  | — |  | 4 |  | 7 |  | 11 |  |
| Technical Revisions(8) |  | — |  | — |  | — |  | — |  | — |  | — |  | 12 |  | (19 | ) | (8 | ) | — |  | — |  | — |  | 12 |  | (19 | ) | (8 | ) |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | — |  | — |  | — |  | — |  | — |  | — |  | (22 | ) | — |  | (22 | ) | — |  | — |  | — |  | (22 | ) | — |  | (22 | ) |
December 31, 2019 |  | — |  | — |  | — |  | — |  | — |  | — |  | 116 |  | 162 |  | 278 |  | — |  | — |  | — |  | 116 |  | 162 |  | 278 |  |
Total Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | 2 798 |  | 1 796 |  | 4 593 |  | 1 712 |  | 883 |  | 2 595 |  | 123 |  | 174 |  | 297 |  | — |  | — |  | — |  | 4 632 |  | 2 853 |  | 7 485 |  |
| Extensions & Improved Recovery(7) |  | 122 |  | (36 | ) | 86 |  | 71 |  | (42 | ) | 29 |  | 4 |  | 7 |  | 11 |  | — |  | — |  | — |  | 196 |  | (71 | ) | 125 |  |
| Technical Revisions(8) |  | 78 |  | (16 | ) | 62 |  | (36 | ) | (47 | ) | (83 | ) | 12 |  | (19 | ) | (8 | ) | — |  | — |  | — |  | 53 |  | (82 | ) | (28 | ) |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | (173 | ) | — |  | (173 | ) | (72 | ) | — |  | (72 | ) | (22 | ) | — |  | (22 | ) | — |  | — |  | — |  | (268 | ) | — |  | (268 | ) |
December 31, 2019 |  | 2 824 |  | 1 744 |  | 4 568 |  | 1 675 |  | 794 |  | 2 469 |  | 116 |  | 162 |  | 278 |  | — |  | — |  | — |  | 4 615 |  | 2 700 |  | 7 314 |  |

Please see Notes (1) through (13) at the end of the reserves data section for important information about volumes in this table.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 29

Reconciliation of Gross Reserves(1) (continued)
as at December 31, 2019
(forecast prices and costs)(2)

|  | SCO(3) |  | Bitumen |  | Light Crude & Medium Crude Oil(4)(5) |  | Conventional Natural Gas(6) |  | Total |  |
|  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  | Proved |  | Probable |  | Proved Plus Probable |  |
|  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | mmbbls |  | bcfe |  | bcfe |  | bcfe |  | mmboe |  | mmboe |  | mmboe |  |
Offshore U.K. & Norway |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | — |  | — |  | — |  | — |  | — |  | — |  | 52 |  | 37 |  | 88 |  | 14 |  | 17 |  | 32 |  | 54 |  | 40 |  | 94 |  |
| Extensions & Improved Recovery(7) |  | — |  | — |  | — |  | — |  | — |  | — |  | 1 |  | 1 |  | 2 |  | — |  | — |  | 1 |  | 1 |  | 1 |  | 3 |  |
| Technical Revisions(8) |  | — |  | — |  | — |  | — |  | — |  | — |  | 19 |  | (6 | ) | 13 |  | 2 |  | (2 | ) | 1 |  | 19 |  | (6 | ) | 13 |  |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | — |  | — |  | — |  | — |  | — |  | — |  | (16 | ) | — |  | (16 | ) | (2 | ) | — |  | (2 | ) | (16 | ) | — |  | (16 | ) |
| December 31, 2019 |  | — |  | — |  | — |  | — |  | — |  | — |  | 56 |  | 32 |  | 88 |  | 15 |  | 16 |  | 31 |  | 58 |  | 35 |  | 93 |  |
Other International (14) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Extensions & Improved Recovery(7) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Technical Revisions(8) |  | — |  | — |  | — |  | — |  | — |  | — |  | 6 |  | — |  | 6 |  | — |  | — |  | — |  | 6 |  | — |  | 6 |  |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13)(14) |  | — |  | — |  | — |  | — |  | — |  | — |  | (6 | ) | — |  | (6 | ) | — |  | — |  | — |  | (6 | ) | — |  | (6 | ) |
December 31, 2019 |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
Total |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
December 31, 2018 |  | 2 798 |  | 1 796 |  | 4 593 |  | 1 712 |  | 883 |  | 2 595 |  | 174 |  | 211 |  | 385 |  | 14 |  | 17 |  | 32 |  | 4 686 |  | 2 892 |  | 7 579 |  |
| Extensions & Improved Recovery(7) |  | 122 |  | (36 | ) | 86 |  | 71 |  | (42 | ) | 29 |  | 5 |  | 8 |  | 13 |  | — |  | — |  | 1 |  | 198 |  | (70 | ) | 128 |  |
| Technical Revisions(8) |  | 78 |  | (16 | ) | 62 |  | (36 | ) | (47 | ) | (83 | ) | 36 |  | (25 | ) | 11 |  | 2 |  | (2 | ) | 1 |  | 78 |  | (88 | ) | (10 | ) |
| Discoveries(9) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Acquisitions(10) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Dispositions(11) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Economic Factors(12) |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  |
| Production(13) |  | (173 | ) | — |  | (173 | ) | (72 | ) | — |  | (72 | ) | (44 | ) | — |  | (44 | ) | (2 | ) | — |  | (2 | ) | (289 | ) | — |  | (289 | ) |
December 31, 2019 |  | 2 824 |  | 1 744 |  | 4 568 |  | 1 675 |  | 794 |  | 2 469 |  | 172 |  | 194 |  | 366 |  | 15 |  | 16 |  | 31 |  | 4 673 |  | 2 735 |  | 7 407 |  |

Please see Notes (1) through (14) at the end of the reserves data section for important information about volumes in this table.

30 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Notes to Reserves Data Tables
as at December 31, 2019

(1)
  Reserves data tables may not add due to rounding.
(2)
  See the Notes to Future Net Revenues Tables for information on forecast prices and costs.
(3)
  SCO reserves figures include the company's diesel sales volumes.
(4)
  Gross volumes of Light Crude & Medium Crude Oil for E&P Canada include immaterial quantities of Heavy Crude Oil as follows: Proved Developed Producing of 26 mmbbls, Proved Undeveloped of 28 mmbbls, Proved of 54 mmbbls, Probable of 37 mmbbls and Proved Plus Probable of 91 mmbbls. Net volumes of Light Crude & Medium Crude Oil for E&P Canada include immaterial quantities of Heavy Crude Oil as follows: Proved Developed Producing of 25 mmbbls, Proved Undeveloped of 27 mmbbls, Proved of 52 mmbbls, Probable of 30 mmbbls and Proved Plus Probable of 82 mmbbls.
(5)
  Light Crude & Medium Crude Oil Technical Revisions for E&P Canada include quantities of Heavy Crude Oil as follows: Proved of 1.5 mmbbls, Probable of (2.5) mmbbls and Proved Plus Probable of (0.9) mmbbls.
(6)
  Conventional Natural Gas includes immaterial amounts of NGLs (0.6 mmbbls of Proved and 1.3 mmbbls of Proved Plus Probable NGLs).
(7)
  Extensions & Improved Recovery are additions to the reserves resulting from step-out drilling, infill drilling and implementation of improved recovery schemes. Negative volumes, if any, for Probable reserves result from the transfer of Probable reserves to Proved reserves. Changes in 2019 are primarily a result of drilling extensions at Firebag.
(8)
  Technical Revisions include changes in previous estimates resulting from new technical data or revised interpretations. Changes in 2019 are primarily due to new information obtained during the year, including drilling results and ongoing field performance. For Other International, a technical revision has been made to offset production (refer to Note 14 below).
(9)
  Discoveries are additions to reserves in reservoirs where no reserves were previously booked and are as a result of the confirmation of the existence of an accumulation of a significant quantity of potentially recoverable petroleum. There were no discoveries in 2019.
(10)
  Acquisitions are additions to reserves estimates as a result of purchasing interests in oil and gas properties.
(11)
  Dispositions are reductions in reserves estimates as a result of selling all or a portion of an interest in oil and gas properties.
(12)
  Economic Factors are changes due primarily to price forecasts, inflation rates or regulatory changes.
(13)
  Production quantities may include estimated production for periods near the end of the year when actual sales quantities were not available at the time the reserves evaluations were conducted.
(14)
  Other International includes production for Libya based on the company's 50% working interest. Production for Libya is offset by Technical Revisions of an equal amount, since Suncor's Libya assets are classified as contingent resources due to political unrest.

Definitions for Reserves Data Tables

In the tables set forth above and elsewhere in this AIF, the following definitions and other notes are applicable:

Gross means:

(a)
  in relation to Suncor's interest in production or reserves, Suncor's working-interest share before deduction of royalties and without including any royalty interests of Suncor;
(b)
  in relation to Suncor's interest in wells, the total number of wells in which Suncor has an interest; and
(c)
  in relation to Suncor's interest in properties, the total area of properties in which Suncor has an interest.

Net means:

(a)
  in relation to Suncor's interest in production or reserves, Suncor's working-interest share after deduction of royalty obligations, plus the company's royalty interests in production or reserves;
(b)
  in relation to Suncor's interest in wells, the number of wells obtained by aggregating Suncor's working interest in each of the company's gross wells; and
(c)
  in relation to Suncor's interest in a property, the total area in which Suncor has an interest multiplied by the working interest owned by Suncor.

Reserves Categories

The reserves estimates presented are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation (COGE) Handbook. A summary of those definitions is set forth below.

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, as of a given date, based on analyses of drilling, geological, geophysical and engineering data, the use of established technology, and specified economic conditions, which are generally accepted as being reasonable.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 31

Reserves are classified according to the degree of certainty associated with the estimates:

Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated Proved reserves. Proved reserves estimates should target at least a 90% probability that the quantities actually recovered will equal or exceed the estimate.

Probable reserves are those additional reserves that are less certain to be recovered than Proved reserves. It is equally likely that the actual remaining quantities recovered will be greater or less than the sum of the estimated Proved Plus Probable reserves. That is, Proved Plus Probable reserves estimates should target at least a 50% probability that the quantities actually recovered will equal or exceed the estimate.

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Proved and Probable reserves categories may be divided into Developed and Undeveloped categories:

Developed reserves are those reserves that are expected to be recovered (i) from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (for example, when compared to the cost of drilling a well) to put the reserves on production, or (ii) for mining assets, through installed extraction equipment and infrastructure that is operational at the time of the reserves estimate. The Developed category may be subdivided into Producing and Non-Producing.

(a)
  Developed Producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate. These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.
(b)
  Developed Non-Producing reserves are those reserves that either have not been on production, or have previously been on production but are shut in, and the date of resumption of production is unknown.

Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves category (Proved or Probable) to which they are assigned.

For any given pool, it may be appropriate to allocate total pool reserves between the Developed and Undeveloped categories or to subdivide the Developed reserves for the pool between Developed Producing and Developed Non-Producing. This allocation should be based on the estimator's assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

32 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Future Net Revenues Tables and Notes

Net Present Values of Future Net Revenues Before Income Taxes(1)
as at December 31, 2019
(forecast prices and costs)

|  | (in $ millions, discounted at % per year) |  | Unit Value(2) |
|  | 0% |  | 5% |  | 10% |  | 15% |  | 20% |  | ($/boe) |
Proved Developed Producing |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 37 000 |  | 28 445 |  | 19 865 |  | 14 479 |  | 11 104 |  | 7.55 |
| In Situ |  | 8 986 |  | 7 891 |  | 6 997 |  | 6 275 |  | 5 691 |  | 24.49 |
| E&P Canada |  | 1 833 |  | 2 047 |  | 2 066 |  | 2 006 |  | 1 919 |  | 32.88 |
Total Canada |  | 47 820 |  | 38 383 |  | 28 927 |  | 22 760 |  | 18 714 |  | 9.70 |
Offshore U.K. & Norway |  | 2 142 |  | 2 103 |  | 2 022 |  | 1 927 |  | 1 834 |  | 42.31 |
Total Proved Developed Producing |  | 49 961 |  | 40 486 |  | 30 949 |  | 24 688 |  | 20 547 |  | 10.22 |
Proved Developed Non-Producing |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | — |  | — |  | — |  | — |  | — |
| E&P Canada |  | — |  | — |  | — |  | — |  | — |  | — |
Total Canada |  | — |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway |  | 38 |  | 35 |  | 34 |  | 32 |  | 31 |  | 74.23 |
Total Proved Developed Non-Producing |  | 38 |  | 35 |  | 34 |  | 32 |  | 31 |  | 74.23 |
Proved Undeveloped |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | 36 739 |  | 19 520 |  | 11 333 |  | 7 085 |  | 4 696 |  | 10.50 |
| E&P Canada |  | 1 972 |  | 1 723 |  | 1 484 |  | 1 283 |  | 1 121 |  | 35.97 |
Total Canada |  | 38 711 |  | 21 243 |  | 12 817 |  | 8 368 |  | 5 817 |  | 11.44 |
Offshore U.K. & Norway |  | 437 |  | 359 |  | 294 |  | 240 |  | 196 |  | 29.93 |
Total Proved Undeveloped |  | 39 147 |  | 21 601 |  | 13 111 |  | 8 609 |  | 6 013 |  | 11.60 |
Proved |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 37 000 |  | 28 445 |  | 19 865 |  | 14 479 |  | 11 104 |  | 7.55 |
| In Situ |  | 45 725 |  | 27 411 |  | 18 329 |  | 13 360 |  | 10 387 |  | 13.43 |
| E&P Canada |  | 3 805 |  | 3 770 |  | 3 550 |  | 3 290 |  | 3 039 |  | 34.11 |
Total Canada |  | 86 530 |  | 59 626 |  | 41 744 |  | 31 129 |  | 24 530 |  | 10.18 |
Offshore U.K. & Norway |  | 2 616 |  | 2 497 |  | 2 349 |  | 2 200 |  | 2 061 |  | 40.46 |
Total Proved |  | 89 146 |  | 62 123 |  | 44 093 |  | 33 329 |  | 26 591 |  | 10.60 |
Probable |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 27 472 |  | 11 922 |  | 6 432 |  | 4 010 |  | 2 758 |  | 6.77 |
| In Situ |  | 71 102 |  | 19 872 |  | 7 521 |  | 3 792 |  | 2 378 |  | 6.57 |
| E&P Canada |  | 7 163 |  | 5 076 |  | 3 584 |  | 2 589 |  | 1 915 |  | 27.40 |
Total Canada |  | 105 737 |  | 36 869 |  | 17 536 |  | 10 391 |  | 7 052 |  | 7.88 |
Offshore U.K. & Norway |  | 2 079 |  | 1 690 |  | 1 366 |  | 1 117 |  | 929 |  | 38.99 |
Total Probable |  | 107 816 |  | 38 559 |  | 18 903 |  | 11 508 |  | 7 980 |  | 8.37 |
Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 64 472 |  | 40 367 |  | 26 297 |  | 18 489 |  | 13 862 |  | 7.34 |
| In Situ |  | 116 827 |  | 47 283 |  | 25 850 |  | 17 152 |  | 12 765 |  | 10.30 |
| E&P Canada |  | 10 968 |  | 8 846 |  | 7 134 |  | 5 879 |  | 4 955 |  | 30.37 |
Total Canada |  | 192 267 |  | 96 495 |  | 59 281 |  | 41 520 |  | 31 582 |  | 9.37 |
Offshore U.K. & Norway |  | 4 696 |  | 4 187 |  | 3 715 |  | 3 317 |  | 2 989 |  | 39.91 |
Total Proved Plus Probable |  | 196 963 |  | 100 682 |  | 62 996 |  | 44 837 |  | 34 571 |  | 9.81 |

Please see the Notes at the end of the Future Net Revenues Tables.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 33

Net Present Values of Future Net Revenues After Income Taxes(1)
as at December 31, 2019
(forecast prices and costs)

|  | (in $ millions, discounted at % per year) |
|  | 0% |  | 5% |  | 10% |  | 15% |  | 20% |
Proved Developed Producing |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 28 142 |  | 23 022 |  | 16 293 |  | 11 982 |  | 9 272 |
| In Situ |  | 7 042 |  | 6 204 |  | 5 505 |  | 4 937 |  | 4 475 |
| E&P Canada |  | 1 473 |  | 1 715 |  | 1 758 |  | 1 718 |  | 1 647 |
Total Canada |  | 36 657 |  | 30 941 |  | 23 555 |  | 18 637 |  | 15 394 |
Offshore U.K. & Norway |  | 1 246 |  | 1 228 |  | 1 186 |  | 1 137 |  | 1 088 |
Total Proved Developed Producing |  | 37 902 |  | 32 169 |  | 24 741 |  | 19 774 |  | 16 482 |
Proved Developed Non-Producing |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | — |  | — |  | — |  | — |
| E&P Canada |  | — |  | — |  | — |  | — |  | — |
Total Canada |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway |  | 23 |  | 22 |  | 21 |  | 20 |  | 19 |
Total Proved Developed Non-Producing |  | 23 |  | 22 |  | 21 |  | 20 |  | 19 |
Proved Undeveloped |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | 28 032 |  | 14 747 |  | 8 466 |  | 5 228 |  | 3 418 |
| E&P Canada |  | 1 459 |  | 1 281 |  | 1 097 |  | 941 |  | 814 |
Total Canada |  | 29 490 |  | 16 027 |  | 9 563 |  | 6 169 |  | 4 232 |
Offshore U.K. & Norway |  | 395 |  | 325 |  | 266 |  | 219 |  | 179 |
Total Proved Undeveloped |  | 29 885 |  | 16 352 |  | 9 829 |  | 6 387 |  | 4 411 |
Proved |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 28 142 |  | 23 022 |  | 16 293 |  | 11 982 |  | 9 272 |
| In Situ |  | 35 074 |  | 20 950 |  | 13 971 |  | 10 165 |  | 7 893 |
| E&P Canada |  | 2 932 |  | 2 996 |  | 2 855 |  | 2 659 |  | 2 461 |
Total Canada |  | 66 147 |  | 46 968 |  | 33 118 |  | 24 806 |  | 19 626 |
Offshore U.K. & Norway |  | 1 663 |  | 1 574 |  | 1 473 |  | 1 376 |  | 1 286 |
Total Proved |  | 67 810 |  | 48 542 |  | 34 591 |  | 26 181 |  | 20 912 |
Probable |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 21 595 |  | 9 138 |  | 4 813 |  | 2 937 |  | 1 981 |
| In Situ |  | 54 598 |  | 15 186 |  | 5 756 |  | 2 919 |  | 1 841 |
| E&P Canada |  | 5 283 |  | 3 739 |  | 2 593 |  | 1 828 |  | 1 315 |
Total Canada |  | 81 476 |  | 28 063 |  | 13 162 |  | 7 685 |  | 5 137 |
Offshore U.K. & Norway |  | 1 051 |  | 892 |  | 746 |  | 628 |  | 535 |
Total Probable |  | 82 527 |  | 28 954 |  | 13 907 |  | 8 312 |  | 5 672 |
Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 49 737 |  | 32 159 |  | 21 106 |  | 14 920 |  | 11 253 |
| In Situ |  | 89 672 |  | 36 136 |  | 19 727 |  | 13 084 |  | 9 734 |
| E&P Canada |  | 8 214 |  | 6 735 |  | 5 448 |  | 4 487 |  | 3 776 |
Total Canada |  | 147 623 |  | 75 030 |  | 46 280 |  | 32 490 |  | 24 763 |
Offshore U.K. & Norway |  | 2 714 |  | 2 466 |  | 2 219 |  | 2 003 |  | 1 821 |
Total Proved Plus Probable |  | 150 337 |  | 77 496 |  | 48 499 |  | 34 494 |  | 26 584 |

Please see the Notes at the end of the Future Net Revenues Tables.

34 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Total Future Net Revenues(1)
as at December 31, 2019
(forecast prices and costs)

(in $ millions, undiscounted) |  | Revenue |  | Royalties |  | Operating Costs |  | Development Costs |  | Abandonment and Reclamation Costs |  | Future Net Revenues Before Deducting Future Income Tax Expenses |  | Future Income Tax Expenses |  | Future Net Revenues After Deducting Future Income Tax Expenses |
Proved Developed Producing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 245 328 |  | 20 587 |  | 139 235 |  | 30 021 |  | 18 485 |  | 37 000 |  | 8 859 |  | 28 142 |
| In Situ |  | 24 586 |  | 3 111 |  | 9 653 |  | 2 277 |  | 559 |  | 8 986 |  | 1 944 |  | 7 042 |
| E&P Canada |  | 6 475 |  | 826 |  | 1 890 |  | 372 |  | 1 554 |  | 1 833 |  | 360 |  | 1 473 |
Total Canada |  | 276 390 |  | 24 524 |  | 150 779 |  | 32 670 |  | 20 597 |  | 47 820 |  | 11 163 |  | 36 657 |
Offshore U.K. & Norway |  | 4 282 |  | — |  | 1 383 |  | 91 |  | 665 |  | 2 142 |  | 896 |  | 1 246 |
Total Proved Developed Producing |  | 280 671 |  | 24 524 |  | 152 162 |  | 32 762 |  | 21 262 |  | 49 961 |  | 12 059 |  | 37 902 |
Proved Developed Non-Producing |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| E&P Canada |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Total Canada |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway |  | 38 |  | — |  | 1 |  | — |  | — |  | 38 |  | 15 |  | 23 |
Total Proved Developed Non-Producing |  | 38 |  | — |  | 1 |  | — |  | — |  | 38 |  | 15 |  | 23 |
Proved Undeveloped |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | 107 454 |  | 18 257 |  | 33 569 |  | 17 687 |  | 1 202 |  | 36 739 |  | 8 707 |  | 28 032 |
| E&P Canada |  | 4 090 |  | 227 |  | 1 058 |  | 503 |  | 331 |  | 1 972 |  | 513 |  | 1 459 |
Total Canada |  | 111 544 |  | 18 484 |  | 34 626 |  | 18 190 |  | 1 533 |  | 38 711 |  | 9 220 |  | 29 490 |
Offshore U.K. & Norway |  | 835 |  | — |  | 98 |  | 234 |  | 66 |  | 437 |  | 42 |  | 395 |
Total Proved Undeveloped |  | 112 379 |  | 18 484 |  | 34 724 |  | 18 424 |  | 1 599 |  | 39 147 |  | 9 262 |  | 29 885 |
Proved |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 245 328 |  | 20 587 |  | 139 235 |  | 30 021 |  | 18 485 |  | 37 000 |  | 8 859 |  | 28 142 |
| In Situ |  | 132 040 |  | 21 368 |  | 43 222 |  | 19 964 |  | 1 761 |  | 45 725 |  | 10 652 |  | 35 074 |
| E&P Canada |  | 10 565 |  | 1 053 |  | 2 948 |  | 875 |  | 1 884 |  | 3 805 |  | 873 |  | 2 932 |
Total Canada |  | 387 934 |  | 43 008 |  | 185 405 |  | 50 860 |  | 22 131 |  | 86 530 |  | 20 383 |  | 66 147 |
Offshore U.K. & Norway |  | 5 155 |  | — |  | 1 482 |  | 326 |  | 731 |  | 2 616 |  | 953 |  | 1 663 |
Total Proved |  | 393 089 |  | 43 008 |  | 186 887 |  | 51 186 |  | 22 862 |  | 89 146 |  | 21 336 |  | 67 810 |
Probable |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 111 437 |  | 12 889 |  | 59 234 |  | 9 849 |  | 1 993 |  | 27 472 |  | 5 877 |  | 21 595 |
| In Situ |  | 188 644 |  | 38 759 |  | 52 355 |  | 25 077 |  | 1 352 |  | 71 102 |  | 16 503 |  | 54 598 |
| E&P Canada |  | 16 622 |  | 3 106 |  | 3 743 |  | 1 981 |  | 629 |  | 7 163 |  | 1 881 |  | 5 283 |
Total Canada |  | 316 703 |  | 54 754 |  | 115 332 |  | 36 907 |  | 3 974 |  | 105 737 |  | 24 261 |  | 81 476 |
Offshore U.K. & Norway |  | 3 366 |  | — |  | 1 034 |  | 144 |  | 108 |  | 2 079 |  | 1 029 |  | 1 051 |
Total Probable |  | 320 069 |  | 54 754 |  | 116 366 |  | 37 051 |  | 4 082 |  | 107 816 |  | 25 289 |  | 82 527 |
Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 356 766 |  | 33 476 |  | 198 470 |  | 39 870 |  | 20 478 |  | 64 472 |  | 14 735 |  | 49 737 |
| In Situ |  | 320 685 |  | 60 127 |  | 95 577 |  | 45 041 |  | 3 113 |  | 116 827 |  | 27 155 |  | 89 672 |
| E&P Canada |  | 27 187 |  | 4 159 |  | 6 691 |  | 2 856 |  | 2 513 |  | 10 968 |  | 2 754 |  | 8 214 |
Total Canada |  | 704 637 |  | 97 762 |  | 300 737 |  | 87 767 |  | 26 104 |  | 192 267 |  | 44 644 |  | 147 623 |
Offshore U.K. & Norway |  | 8 521 |  | — |  | 2 516 |  | 470 |  | 839 |  | 4 696 |  | 1 981 |  | 2 714 |
Total Proved Plus Probable |  | 713 158 |  | 97 762 |  | 303 253 |  | 88 237 |  | 26 944 |  | 196 963 |  | 46 625 |  | 150 337 |

Please see the Notes at the end of the Future Net Revenues Tables.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 35

Future Net Revenues by Product Type(1)
as at December 31, 2019
(forecast prices and costs)

(before income taxes, discounted at 10% per year) |  | $ millions |  | Unit Value $/boe(2) |
Proved Developed Producing |  |  |  |  |
| SCO |  | 21 529 |  | 10.76 |
| Bitumen |  | 5 333 |  | 5.81 |
| Light Crude & Medium Crude Oil |  | 2 594 |  | 30.52 |
| Heavy Crude Oil |  | 1 483 |  | 58.65 |
| Conventional Natural Gas(3) |  | 10 |  | 31.12 |
Total Proved Developed Producing |  | 30 949 |  | 10.22 |
Proved |  |  |  |  |
| SCO |  | 28 129 |  | 11.16 |
| Bitumen |  | 10 065 |  | 6.82 |
| Light Crude & Medium Crude Oil |  | 3 331 |  | 31.01 |
| Heavy Crude Oil |  | 2 521 |  | 48.21 |
| Conventional Natural Gas(3) |  | 47 |  | 19.50 |
Total Proved |  | 44 093 |  | 10.60 |
Proved Plus Probable |  |  |  |  |
| SCO |  | 40 642 |  | 10.23 |
| Bitumen |  | 11 506 |  | 5.43 |
| Light Crude & Medium Crude Oil |  | 7 296 |  | 30.28 |
| Heavy Crude Oil |  | 3 465 |  | 42.29 |
| Conventional Natural Gas(3) |  | 89 |  | 17.40 |
Total Proved Plus Probable |  | 62 997 |  | 9.81 |

(1)
  Figures may not add due to rounding.
(2)
  Unit values are net present values of future net revenues before deducting estimated cash income taxes payable, discounted at 10%, divided by net reserves.
(3)
  Conventional natural gas includes associated NGLs.

36 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Notes to Future Net Revenues Tables

In Situ Future Net Revenues

Future net revenues for In Situ properties reflect the flexibility of Suncor's operations, which allows production from these properties to be either upgraded to SCO or sold as non-upgraded bitumen. The proportion of upgraded production is based on estimated available upgrading capacity and can vary depending on pricing of the respective products, maintenance, fluctuations in production from mining and extraction operations, or changes in the company's overall Oil Sands development strategy.

In Situ future net revenues disclosed above include estimates of production volumes upgraded to SCO and the associated estimated future sales prices and upgrader operating and sustaining capital costs, based on estimates of upgrader capacity available for processing In Situ volumes. For total Proved Plus Probable reserves, approximately 49% to 57% of Firebag bitumen production is estimated to be upgraded to SCO from 2020 to 2035 and 100% thereafter. These assumptions have resulted in a $3.4 billion increase in the net present value of future net revenues (total Proved Plus Probable reserves, before tax, discounted at 10%) attributable to In Situ production relative to the scenario where none of the bitumen is upgraded.

Revenues and the natural gas fuel expense associated with excess power generated from cogeneration facilities at Firebag are included in future net revenues.

Forecast Prices and Costs

The forecast price and cost assumptions include changes in wellhead selling prices, take into account escalation with respect to future operating and capital costs, and assume the continuance of current laws and regulations. Crude oil, natural gas and other important benchmark reference pricing, as well as inflation and exchange rates utilized in the GLJ Reports and the Sproule Reports, were derived using averages of forecasts developed by GLJ, Sproule and McDaniel & Associates Consultants Ltd., all of whom are independent qualified reserves evaluators, dated January 1, 2020. Resultant forecasts are set out below. To the extent there are fixed or presently determinable future prices to which Suncor is legally bound by contractual or other obligations to supply a physical product, including those for an extension period of a contract that is likely to be extended, those prices have been incorporated into the forecast prices as applied to the pertinent properties. Benchmark forecast prices have been adjusted for quality differentials and transportation costs applicable to the specific evaluation areas and products. The inflation rates utilized in cost forecasts were nil in 2020, 1.7% in 2021, and 2.0% thereafter.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 37

Prices Impacting Reserves Tables

Forecast |  | Brent North Sea(1) |  | WTI Cushing Oklahoma(2) |  | WCS Hardisty Alberta(3) |  | Light Sweet Edmonton Alberta(4) |  | Pentanes Plus Edmonton Alberta(5) |  | AECO Gas(6) |  | National Balancing Point North Sea(7) |
Year |  | US$/bbl |  | US$/bbl |  | Cdn$/bbl |  | Cdn$/bbl |  | Cdn$/bbl |  | Cdn$/mmbtu |  | Cdn$/mmbtu |
2019(8) |  | 64.18 |  | 57.03 |  | 58.75 |  | 69.21 |  | 70.14 |  | 1.75 |  | 3.98 |
2020 |  | 66.33 |  | 61.00 |  | 57.57 |  | 72.64 |  | 76.83 |  | 2.04 |  | 7.48 |
2021 |  | 67.94 |  | 63.75 |  | 62.35 |  | 76.06 |  | 79.82 |  | 2.32 |  | 7.90 |
2022 |  | 70.06 |  | 66.18 |  | 64.33 |  | 78.35 |  | 82.30 |  | 2.62 |  | 8.23 |
2023 |  | 71.66 |  | 67.91 |  | 66.23 |  | 80.71 |  | 84.72 |  | 2.71 |  | 8.70 |
2024 |  | 73.27 |  | 69.48 |  | 67.96 |  | 82.64 |  | 86.71 |  | 2.81 |  | 8.97 |
2025 |  | 74.57 |  | 71.07 |  | 69.72 |  | 84.60 |  | 88.73 |  | 2.89 |  | 9.24 |
2026 |  | 76.22 |  | 72.68 |  | 71.49 |  | 86.57 |  | 90.77 |  | 2.96 |  | 9.47 |
2027 |  | 77.83 |  | 74.24 |  | 73.19 |  | 88.49 |  | 92.76 |  | 3.03 |  | 9.61 |
2028 |  | 79.36 |  | 75.73 |  | 74.80 |  | 90.31 |  | 94.65 |  | 3.10 |  | 9.76 |
2029 |  | 80.92 |  | 77.24 |  | 76.43 |  | 92.17 |  | 96.57 |  | 3.17 |  | 9.90 |
2030 |  | 82.54 |  | 78.79 |  | 77.96 |  | 94.01 |  | 98.53 |  | 3.24 |  | 10.10 |
2031 |  | 84.19 |  | 80.36 |  | 79.52 |  | 95.89 |  | 100.50 |  | 3.30 |  | 10.30 |
2032 |  | 85.87 |  | 81.97 |  | 81.11 |  | 97.81 |  | 102.51 |  | 3.37 |  | 10.51 |
2033 |  | 87.59 |  | 83.61 |  | 82.73 |  | 99.76 |  | 104.56 |  | 3.43 |  | 10.72 |
2034 |  | 89.35 |  | 85.28 |  | 84.39 |  | 101.76 |  | 106.65 |  | 3.50 |  | 10.93 |
2035+ |  | +2.0%/yr |  | +2.0%/yr |  | +2.0%/yr |  | +2.0%/yr |  | +2.0%/yr |  | +2.0%/yr |  | +2.0%/yr |

(1)
  Price used when determining offshore light crude oil and medium crude oil and heavy crude oil reserves for E&P Canada and Offshore U.K. & Norway reserves.
(2)
  Price used when determining portions of bitumen reserves presented as In Situ and Mining reserves that are sold at the U.S. Gulf Coast, as well as for determining portions of bitumen pricing for royalty calculation purposes.
(3)
  Price used when determining portions of bitumen reserves presented as In Situ and Mining reserves that are sold in Canada, as well as for determining bitumen pricing for royalty calculation purposes.
(4)
  Price used when determining SCO reserves presented as In Situ and Mining reserves.
(5)
  Price used when determining the cost of diluent associated with bitumen reserves presented as In Situ and Mining reserves, as well as when accounting for diluent in determining bitumen pricing for royalty calculation purposes. A bitumen/diluent ratio of approximately two barrels of bitumen for one barrel of diluent was used for In Situ reserves and a ratio of approximately three barrels of bitumen for one barrel of diluent was used for Mining reserves. Price also used when determining NGLs reserves.
(6)
  Price used when determining natural gas input costs for the production of SCO and bitumen reserves.
(7)
  Price used when determining conventional natural gas reserves presented as Offshore U.K. & Norway reserves.
(8)
  Prices for 2019 reflect the company's historical weighted average prices.

Forecast Foreign Exchange Rates Impacting Forecast Prices

Forecast |  | US$/Cdn$ Exchange Rate |  | Cdn$/€ Exchange Rate |  | Cdn$/£ Exchange Rate |
Year |  |  |  |  |  |  |
2020 |  | 0.760 |  | 1.474 |  | 1.678 |
2021 |  | 0.770 |  | 1.474 |  | 1.656 |
2022 |  | 0.785 |  | 1.465 |  | 1.624 |
2023 |  | 0.785 |  | 1.465 |  | 1.624 |
2024 |  | 0.785 |  | 1.465 |  | 1.624 |
2025+ |  | 0.785 |  | 1.465 |  | 1.624 |

Disclosure of Net Present Values of Future Net Revenues After Income Taxes

Values presented in the table for Net Present Values of Future Net Revenues After Income Taxes reflect income tax burdens of assets at a business area or legal entity level based on tax pools associated with that business area or legal entity. Suncor's actual corporate legal entity structure for income taxes and income tax planning has not been considered, and, therefore, the total value for income taxes presented in the total future net revenues table may not provide an estimate of the value at the corporate entity level, which may be significantly different. The 2019 audited Consolidated Financial Statements and the MD&A should be consulted for information on income taxes at the corporate entity level.

38 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Additional Information Relating to Reserves Data

Future Development Costs(1)
as at December 31, 2019
(forecast prices and costs)

($ millions) |  | 2020 |  | 2021 |  | 2022 |  | 2023 |  | 2024 |  | Remainder |  | Total |  | Discounted At 10% |
Proved |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 1 553 |  | 2 279 |  | 2 559 |  | 2 602 |  | 2 028 |  | 19 000 |  | 30 021 |  | 15 909 |
| In Situ |  | 821 |  | 1 021 |  | 796 |  | 425 |  | 547 |  | 16 353 |  | 19 964 |  | 7 700 |
| E&P Canada |  | 286 |  | 149 |  | 119 |  | 41 |  | 57 |  | 222 |  | 875 |  | 727 |
Total Canada |  | 2 660 |  | 3 449 |  | 3 475 |  | 3 068 |  | 2 633 |  | 35 576 |  | 50 860 |  | 24 336 |
Offshore U.K. & Norway |  | 241 |  | 22 |  | 6 |  | 11 |  | 7 |  | 38 |  | 326 |  | 301 |
Total Proved |  | 2 901 |  | 3 471 |  | 3 481 |  | 3 079 |  | 2 640 |  | 35 613 |  | 51 186 |  | 24 637 |
Proved Plus Probable |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 1 768 |  | 2 622 |  | 3 003 |  | 3 184 |  | 2 562 |  | 26 731 |  | 39 870 |  | 19 182 |
| In Situ |  | 807 |  | 860 |  | 779 |  | 502 |  | 430 |  | 41 664 |  | 45 041 |  | 8 563 |
| E&P Canada |  | 730 |  | 408 |  | 414 |  | 278 |  | 197 |  | 828 |  | 2 856 |  | 2 263 |
Total Canada |  | 3 305 |  | 3 890 |  | 4 196 |  | 3 964 |  | 3 189 |  | 69 224 |  | 87 767 |  | 30 008 |
Offshore U.K. & Norway |  | 339 |  | 22 |  | 6 |  | 11 |  | 7 |  | 84 |  | 470 |  | 413 |
Total Proved Plus Probable |  | 3 644 |  | 3 912 |  | 4 202 |  | 3 975 |  | 3 196 |  | 69 307 |  | 88 237 |  | 30 421 |

(1)
  Figures may not add due to rounding.

Development costs include costs associated with both Developed and Undeveloped reserves. Significant development activities and costs for 2020 are expected to include:

•
  Mining development activities include capital investments expected to maintain the production capacity of existing facilities, including, but not limited to, tailings infrastructure, major maintenance, truck and shovel replacement, the replenishment of catalysts in hydrotreating units at the upgraders and improvements to utilities, roads and other facilities, and the implementation of technologies expected to reduce costs, including AHS.
•
  For both Firebag and MacKay River operations within In Situ, the drilling of new well pairs, as well as the design and construction of new well pads that are expected to maintain existing production levels in future years.
•
  For E&P Canada, development of the WWRP, the Terra Nova ALE project, development drilling at Hibernia and Hebron.
•
  For E&P International, development of the Norwegian Fenja project, as well as development drilling at Buzzard.

Future development costs disclosed above are associated with reserves as evaluated by GLJ and Sproule and are subject to change based on many factors, including economic conditions. Management currently believes that internally generated cash flows, existing and future credit facilities, issuing commercial paper and accessing capital markets will be sufficient to fund future development costs. There can be no guarantee that funds will be available or that Suncor will allocate funding to develop all of the reserves attributed in the GLJ Reports and the Sproule Reports. Failure to develop those reserves would have a negative impact on future cash flow provided by operating activities.

Interest expense or other costs of external funding are not included in the reserves and future net revenues estimates and could reduce future net revenues to some degree depending upon the funding sources utilized. Suncor does not anticipate that interest expense or other funding costs on their own would make development of any property uneconomic.

Abandonment and Reclamation Costs

The company completes an annual review of its consolidated abandonment and reclamation cost estimates. The estimates are based on the anticipated method and extent of restoration, consistent with legal requirements, technological advances and the possible future use of the site.

As at December 31, 2019, Suncor estimated its undiscounted, uninflated abandonment and reclamation costs for its upstream assets to be approximately $12.7 billion (discounted at 10%, approximately $2.7 billion) excluding Refining and Marketing liabilities ($0.2 billion, undiscounted

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 39

and uninflated). Abandonment and reclamation costs are limited to current disturbances at December 31, 2019 for Suncor's assets, except for Syncrude, which is estimated on a life of mine basis, where it is assumed that material from future disturbances will be required to settle the existing obligation at December 31, 2019. Suncor estimates that it will incur $1.0 billion of its identified abandonment and reclamation costs during the next three years (undiscounted: 2020 – $0.5 billion, 2021 – $0.2 billion, 2022 – $0.2 billion), more than 82% of which is associated with Oil Sands mining operations.

The abandonment and reclamation cost estimates included in the net present values of the company's Proved and Probable reserves include costs related to the reclamation of disturbed land from oil sands mining activities, future mining disturbances, the treatment of legacy oil sands tailings, the decommissioning of oil sands and natural gas processing facilities and well pads, existing and future reserve wells and associated service wells, disturbed lease sites, and future lease site disturbances. Approximately $26.9 billion (inflated and undiscounted) has been deducted as abandonment and reclamation costs in estimating the future net revenues from Proved Plus Probable reserves, including $23.6 billion related to the company's oil sands upgraders, extraction facilities, tailings ponds, subsurface wells and central processing facilities, which includes amounts related to current disturbances.

Gross Proved and Probable Undeveloped Reserves

The tables below outline the gross Proved and Probable Undeveloped reserves and represent Undeveloped reserves additions resulting from acquisitions, discoveries, infill drilling, improved recovery and/or extensions in the year when the events first occurred.

40 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Gross Proved Undeveloped Reserves(1)
(forecast prices and costs)

|  | 2017 |  | 2018 |  | 2019
|  | First Attributed |  | Total as at December 31, 2017 |  | First Attributed |  | Total as at December 31, 2018 |  | First Attributed |  | Total as at December 31, 2019 |
SCO (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | — |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | 575 |  | — |  | 548 |  | 53 |  | 627 |
Total SCO |  | — |  | 575 |  | — |  | 548 |  | 53 |  | 627 |
Bitumen (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 40 |  | 929 |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | 675 |  | — |  | 653 |  | 52 |  | 679 |
Total Bitumen |  | 40 |  | 1 603 |  | — |  | 653 |  | 52 |  | 679 |
Light Crude & Medium Crude Oil (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | 1 |  | 13 |  | 1 |  | 15 |  | 2 |  | 16 |
Offshore U.K. & Norway |  | — |  | — |  | 8 |  | 8 |  | 1 |  | 8 |
Total Light Crude & Medium Crude Oil |  | 1 |  | 13 |  | 9 |  | 23 |  | 3 |  | 24 |
Heavy Crude Oil (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | — |  | 34 |  | — |  | 46 |  | — |  | 28 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | — |  | — |
Total Heavy Crude Oil |  | — |  | 34 |  | — |  | 46 |  | — |  | 28 |
Conventional Natural Gas (bcfe) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | — |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway(2) |  | — |  | — |  | 13 |  | 13 |  | — |  | 13 |
Total Conventional Natural Gas |  | — |  | — |  | 13 |  | 13 |  | — |  | 13 |
Total (mmboe) |  | 41 |  | 2 226 |  | 11 |  | 1 273 |  | 108 |  | 1 359 |

(1)
  Figures may not add due to rounding.
(2)
  Includes immaterial amounts of NGLs (less than 0.6 mmbbls).

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 41

Gross Probable Undeveloped Reserves(1)
(forecast prices and costs)

|  | 2017 |  | 2018 |  | 2019
|  | First Attributed |  | Total as at December 31, 2017 |  | First Attributed |  | Total as at December 31, 2018 |  | First Attributed |  | Total as at December 31, 2019 |
SCO (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | — |  | 282 |  | 26 |  | 308 |  | — |  | 321 |
| In Situ |  | — |  | 1 167 |  | — |  | 1 114 |  | — |  | 1 070 |
Total SCO |  | — |  | 1 449 |  | 26 |  | 1 423 |  | — |  | 1 391 |
Bitumen (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
| Mining |  | 25 |  | 581 |  | — |  | — |  | — |  | — |
| In Situ |  | — |  | 275 |  | — |  | 330 |  | — |  | 267 |
Total Bitumen |  | 25 |  | 856 |  | — |  | 330 |  | — |  | 267 |
Light Crude & Medium Crude Oil (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | 33 |  | 104 |  | 1 |  | 95 |  | 6 |  | 96 |
Offshore U.K. & Norway |  | 2 |  | 12 |  | 8 |  | 9 |  | 1 |  | 8 |
Total Light Crude & Medium Crude Oil |  | 34 |  | 116 |  | 9 |  | 104 |  | 7 |  | 104 |
Heavy Crude Oil (mmbbls) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | — |  | 73 |  | — |  | 28 |  | — |  | 15 |
Offshore U.K. & Norway |  | — |  | — |  | — |  | — |  | — |  | — |
Total Heavy Crude Oil |  | — |  | 73 |  | — |  | 28 |  | — |  | 15 |
Conventional Natural Gas (bcfe) |  |  |  |  |  |  |  |  |  |  |  |  |
E&P Canada |  | — |  | — |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway(2) |  | — |  | 3 |  | 15 |  | 15 |  | — |  | 15 |
Total Conventional Natural Gas |  | — |  | 3 |  | 15 |  | 15 |  | — |  | 15 |
Total (mmboe) |  | 59 |  | 2 494 |  | 37 |  | 1 886 |  | 7 |  | 1 780 |

(1)
  Figures may not add due to rounding.
(2)
  Includes immaterial amounts of NGLs (less than 0.7 mmbbls).

42 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Generally, Proved Undeveloped and Proved Plus Probable Undeveloped reserves are attributed based on the associated confidence levels required for Proved and Proved Plus Probable reserves, respectively, arising from the consideration of factors such as regulatory approvals, availability of markets and infrastructure, development timing, and technical aspects, and have been assigned in accordance with COGE Handbook guidelines. Probable reserves are calculated as the difference between Proved and Proved Plus Probable reserves.

In Situ

Undeveloped In Situ reserves, which constitute approximately 96% of Suncor's gross Proved Undeveloped reserves and 75% of Suncor's gross Probable Undeveloped reserves have been assigned to reserves areas which are not classified as Developed and are related only to those sustaining pads and well pairs required for current producing or sanctioned projects. Suncor has delineated In Situ reserves to a high degree of certainty through seismic data and core hole drilling, consistent with COGE Handbook guidelines. In most cases, reserves have been drilled to a density of 16 delineation wells per section (i.e., 40-acre spacing), which is in excess of the eight delineation wells per section (80-acre spacing) required for regulatory approval. Further delineation is pursued through annual core hole drilling programs to refine development plans. Proved Undeveloped reserves have been assigned to areas delineated with vertical wells on 80-acre well spacing with 3D seismic control or 40-acre spacing without 3D seismic control. Probable Undeveloped areas are limited to areas delineated with vertical wells on 320-acre spacing with seismic control or 160-acre spacing without seismic control. Development of undeveloped In Situ reserves is an ongoing process and is a function of processing capacity and the forecasts of the declining production from existing In Situ wells. When production is forecast to decline, Suncor makes application for and, upon approval, commences development of the reserves and wells surrounding the declining areas. This entails drilling replacement well pairs and constructing sustaining pads and may take several years. Management uses integrated plans to forecast future Proved Undeveloped and Probable Undeveloped reserves development activity. These detailed plans align current production, processing and pipeline constraints (which, in the case of processing constraints, do not permit Suncor to develop all of its undeveloped In Situ reserves within two years), capital spending commitments and future development for the next 10 years, and are updated and approved annually for internal and external factors affecting planned activity. The economic viability of developing sustaining pads and associated well pairs is tested to ensure that ongoing development is economic as required for reserves assessment.

Mining

Undeveloped Mining reserves constitute approximately 18% of Suncor's gross Probable Undeveloped reserves, and relate to the Syncrude MLX-W mining area, which is well-delineated by core hole drilling. The Syncrude MLX-W mining area received AER approval in 2019 and remaining approvals are expected in 2020.

E&P

Undeveloped conventional reserves (light crude oil and medium crude oil, heavy crude oil and natural gas) constitute approximately 4% of Suncor's gross Proved Undeveloped reserves and approximately 7% of Suncor's gross Probable Undeveloped reserves and relate to the company's offshore assets at E&P Canada, mainly associated with future drilling at Hebron, and under-drilled or undrilled fault blocks related to areas in Hibernia, White Rose and Terra Nova, infill drilling in Buzzard and at the Fenja development project offshore Norway. Attribution of Proved Undeveloped and Probable Undeveloped reserves reflect, where applicable, the respective degrees of certainty with respect to various reservoir parameters, primarily drainage areas and recovery factors. In developing undeveloped conventional reserves, Suncor considers existing facility capacity, capital allocation plans, and remaining reserves availability. Suncor plans to proceed with development of essentially all Proved Undeveloped reserves within the next three years and with the development of all Probable Undeveloped reserves within the next five years.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 43

Properties with no Attributed Reserves

The following table is a summary of properties to which no reserves are attributed as at December 31, 2019. For lands in which Suncor holds interests in different formations under the same surface area pursuant to separate leases, the area has been counted for each lease.

Country |  | Gross Hectares |  | Net Hectares |
Canada |  | 4 679 968 |  | 3 380 340 |
Libya |  | 3 117 800 |  | 1 422 900 |
Syria |  | 345 194 |  | 345 194 |
Norway |  | 264 981 |  | 96 642 |
U.K. |  | 54 589 |  | 20 034 |
Total |  | 8 462 532 |  | 5 265 110 |

Suncor's unproved properties include exploration properties in a preliminary phase of evaluation, to discovery areas where tenure to the property is held indefinitely on the basis of hydrocarbon test results, but where economic development is not currently possible or has not yet been sanctioned. Certain properties may be in a relatively mature phase of evaluation, where a significant amount of appraisal or even development has occurred; however, reserves cannot be attributed due to one or more contingencies, such as project sanction, or, in the case of Libya and Syria, political unrest. In many cases where reserves are not attributed to lands containing one or more discovery wells, the key limiting factor is the lack of available production infrastructure. Each year, as part of the company's process to review the economic viability of its properties, some properties are selected for further development activities, while others are temporarily deferred, sold, swapped or relinquished back to the mineral rights owner. Refer to the Risk Factors section of this AIF for additional information on risks and uncertainties.

In 2020, Suncor's rights to 61,261 net hectares in Canada, nil net hectares in Norway and 8,732 net hectares in the U.K. are scheduled to expire. The expiries include approximately 27,775 net hectares in In Situ and nil net hectares in Mining. Substantial portions of expiring lands may have their tenure continued beyond 2020 through the conduct of work programs and/or the payment of prescribed fees to the mineral rights owner.

44 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Oil and Gas Properties and Wells

For descriptions of Suncor's important properties, plants, facilities and installations, refer to the Narrative Description of Suncor's Businesses section within this AIF.

The following table is a summary of the company's oil and gas wells as at December 31, 2019.

|  | Oil Wells(1) |  | Natural Gas Wells(1)
|  | Producing |  | Non-Producing(2)(3) |  | Producing |  | Non-Producing(2)(3) |
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |
Alberta – In Situ(4) |  | 408.0 |  | 408.0 |  | 34.0 |  | 34.0 |  | — |  | — |  | — |  | — |
Newfoundland and Labrador |  | 86.0 |  | 21.5 |  | 6.0 |  | 1.7 |  | — |  | — |  | — |  | — |
Offshore U.K. & Norway |  | 50.0 |  | 14.5 |  | 1.0 |  | 0.3 |  | — |  | — |  | — |  | — |
Other International(5) |  | — |  | — |  | 419.0 |  | 211.1 |  | — |  | — |  | 6.0 |  | 6.0 |
Total |  | 544.0 |  | 444.0 |  | 460.0 |  | 247.1 |  | — |  | — |  | 6.0 |  | 6.0 |

(1)
  Alberta oil wells and Other International oil and gas wells are onshore whereas Newfoundland and Labrador and Offshore U.K. & Norway wells are offshore.
(2)
  Non-producing wells include, but are not limited to, wells where there is no near-term plan for abandonment, wells where drilling has finished but the well has not been completed, wells requiring maintenance or workover where the resumption of production is not known, and wells that have been shut in and the date of resumption of production is not known with reasonable certainty.
(3)
  Non-producing wells do not necessarily lead to classification of Non-Producing reserves.
(4)
  SAGD well pairs and multi-lateral wells are each counted as one well.
(5)
  Other International includes wells associated with the company's operations in Syria and Libya. There are no reserves associated with wells in Syria or Libya.

There are no producing wells associated with Mining properties. Suncor has no Proved Developed Non-Producing reserves or Probable Developed Non-Producing reserves in its Mining reserves.

For In Situ properties, Proved Non-Producing reserves and Probable Non-Producing reserves, if any, are associated with SAGD well pairs that have typically been drilled within the last three years, yet require further capital for completion and tie in to facilities to bring the wells on-stream. Because this capital is small relative to the cost to drill, complete and tie in a well pair, the associated reserves are considered Developed.

Costs Incurred

The table below summarizes the company's costs incurred related to its oil and gas activities for the year ended December 31, 2019.

($ millions) |  | Exploration Costs |  | Proved Property Acquisition Costs |  | Unproved Property Acquisition Costs |  | Development Costs |  | Total |
Canada – Mining and In Situ |  | 204 |  | — |  | — |  | 3 580 |  | 3 784 |
Canada – E&P Canada |  | 105 |  | — |  | — |  | 673 |  | 778 |
Total Canada |  | 309 |  | — |  | — |  | 4 253 |  | 4 562 |
Offshore U.K. & Norway |  | 135 |  | — |  | — |  | 319 |  | 454 |
Other International |  | 8 |  | — |  | — |  | — |  | 8 |
Total |  | 452 |  | — |  | — |  | 4 572 |  | 5 024 |

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 45

Exploration and Development Activities

The table below outlines the gross and net exploratory and development wells the company completed during the year ended December 31, 2019.

|  | Exploratory Wells(1) |  | Development Wells
Total number of wells completed |  | Gross |  | Net |  | Gross |  | Net |
Canada – Oil Sands |  |  |  |  |  |  |  |  |
| Oil |  | — |  | — |  | 9.0 |  | 9.0 |
| Service(2) |  | 38.0 |  | 38.0 |  | 14.0 |  | 14.0 |
| Stratigraphic Test(3) |  | 223.0 |  | 223.0 |  | 783.0 |  | 539.7 |
| Total |  | 261.0 |  | 261.0 |  | 806.0 |  | 562.7 |
Canada – E&P Canada |  |  |  |  |  |  |  |  |
| Oil |  | 1.0 |  | 0.2 |  | 11.0 |  | 2.6 |
| Dry Hole |  | 1.0 |  | 0.3 |  | — |  | — |
| Natural Gas |  | — |  | — |  | — |  | — |
| Service(2) |  | — |  | — |  | 3.0 |  | 0.6 |
| Stratigraphic Test |  | — |  | — |  | — |  | — |
| Total |  | 2.0 |  | 0.5 |  | 14.0 |  | 3.2 |
Total Canada |  |  |  |  |  |  |  |  |
| Oil |  | 1.0 |  | 0.2 |  | 20.0 |  | 11.6 |
| Dry Hole |  | 1.0 |  | 0.3 |  | — |  | — |
| Natural Gas |  | — |  | — |  | — |  | — |
| Service(2) |  | 38.0 |  | 38.0 |  | 17.0 |  | 14.6 |
| Stratigraphic Test |  | 223.0 |  | 223.0 |  | 783.0 |  | 539.7 |
| Total |  | 263.0 |  | 261.5 |  | 820.0 |  | 565.9 |
Offshore U.K. & Norway |  |  |  |  |  |  |  |  |
| Oil |  | 2.0 |  | 0.5 |  | 4.0 |  | 1.2 |
| Dry Hole |  | 1.0 |  | 0.4 |  | — |  | — |
| Service(2) |  | — |  | — |  | — |  | — |
| Stratigraphic Test |  | — |  | — |  | — |  | — |
| Total |  | 3.0 |  | 0.9 |  | 4.0 |  | 1.2 |

(1)
  Exploratory wells for Oil Sands include activity related to technology pilot projects.
(2)
  Service wells for Oil Sands include the injection well in a SAGD well pair, in addition to observation and disposal wells. Service wells for E&P Canada include water and gas injection wells, disposal wells, and cuttings reinjection wells.
(3)
  Stratigraphic test wells for Oil Sands include core hole drilling wells.

46 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Significant exploration and development activities in 2019 included:

•
  For Mining, at Oil Sands Base development activities included turnaround and major maintenance at Upgrader 1, construction of fluid management facilities and utilities sustainment. At Fort Hills, development activities focused on completion of the remaining construction activities in secondary extraction. Other development activities for Fort Hills included advancing tailings infrastructure and procuring mobile equipment. At Syncrude, development activities included turnaround and reliability projects.
•
  For In Situ, the drilling of new well pairs and infill wells at Firebag and MacKay River that are expected to assist in maintaining production levels in future years as well as provide future growth. Also included are stratigraphic test well drilling programs.
•
  For E&P Canada, drilling activities at Hebron, White Rose, Hibernia and Terra Nova, as well as development work on the WWRP. The drilling of one exploration well was also completed.
•
  For E&P International, development work on Buzzard and the Norwegian Oda and Fenja projects. The drilling of two exploration wells was also completed.

For significant exploration and development activities expected to occur in 2020 and beyond, refer to the Narrative Description of Suncor's Businesses and Additional Information Relating to Reserves Data – Future Development Costs sections in this AIF.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 47

Production History(1)

2019 |  | Q1 |  | Q2 |  | Q3 |  | Q4 |  | Year Ended |  |
Canada – Oil Sands |  |  |  |  |  |  |  |  |  |  |  |
| Total production (mbbls/d) |  | 657.2 |  | 692.2 |  | 670.0 |  | 662.3 |  | 670.4 |  |
| Oil Sands operations Bitumen (mbbls/d) |  | 55.4 |  | 118.7 |  | 105.2 |  | 118.1 |  | 99.5 |  |
| ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 41.59 |  | 48.26 |  | 42.21 |  | 36.73 |  | 42.08 |  |
| Royalties |  | (1.37 | ) | (2.96 | ) | (1.98 | ) | (1.23 | ) | (1.94 | ) |
| Production costs |  | (8.56 | ) | (8.86 | ) | (8.07 | ) | (9.10 | ) | (8.68 | ) |
| Netback(4) |  | 31.66 |  | 36.44 |  | 32.16 |  | 26.40 |  | 31.46 |  |
| Oil Sands operations SCO and diesel (mbbls/d) |  | 341.2 |  | 295.5 |  | 317.0 |  | 300.0 |  | 313.3 |  |
| ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 64.90 |  | 74.97 |  | 68.11 |  | 70.93 |  | 69.65 |  |
| Royalties |  | (1.38 | ) | (2.98 | ) | (2.17 | ) | (2.02 | ) | (2.13 | ) |
| Production costs |  | (28.98 | ) | (33.33 | ) | (27.74 | ) | (31.54 | ) | (30.31 | ) |
| Netback(4) |  | 34.54 |  | 38.66 |  | 38.20 |  | 37.37 |  | 37.21 |  |
| Fort Hills Bitumen (mbbls/d) |  | 78.4 |  | 89.3 |  | 85.5 |  | 87.9 |  | 85.3 |  |
| ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 49.95 |  | 57.10 |  | 48.50 |  | 41.41 |  | 48.96 |  |
| Royalties |  | (1.43 | ) | (1.27 | ) | (1.70 | ) | (1.10 | ) | (1.37 | ) |
| Production costs |  | (25.17 | ) | (24.43 | ) | (22.75 | ) | (25.19 | ) | (24.35 | ) |
| Netback(4) |  | 23.35 |  | 31.40 |  | 24.05 |  | 15.12 |  | 23.24 |  |
| Syncrude SCO (mbbls/d) |  | 182.2 |  | 188.7 |  | 162.3 |  | 156.3 |  | 172.3 |  |
| ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 67.90 |  | 79.32 |  | 74.07 |  | 72.14 |  | 73.45 |  |
| Royalties |  | (8.09 | ) | (12.59 | ) | (9.17 | ) | (4.49 | ) | (8.75 | ) |
| Production costs |  | (31.53 | ) | (28.73 | ) | (33.80 | ) | (32.65 | ) | (31.56 | ) |
| Netback(4) |  | 28.28 |  | 38.00 |  | 31.10 |  | 35.00 |  | 33.14 |  |
Canada – Light Crude & Medium Crude Oil |  |  |  |  |  |  |  |  |  |  |  |
| Total production (mbbls/d) |  | 58.3 |  | 61.9 |  | 49.6 |  | 69.6 |  | 59.9 |  |
| ($/bbl) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 84.60 |  | 90.48 |  | 79.39 |  | 84.36 |  | 84.86 |  |
| Royalties |  | (19.75 | ) | (13.65 | ) | (6.54 | ) | (13.46 | ) | (13.62 | ) |
| Production costs |  | (15.63 | ) | (10.96 | ) | (16.49 | ) | (11.28 | ) | (13.45 | ) |
| Netback(4) |  | 49.22 |  | 65.87 |  | 56.36 |  | 59.62 |  | 57.79 |  |
Offshore U.K. & Norway – Light Crude & Medium Crude Oil(3) |  |  |  |  |  |  |  |  |  |  |  |
| Total production (mboe/d) |  | 47.1 |  | 47.2 |  | 40.6 |  | 43.6 |  | 44.6 |  |
| ($/boe) |  |  |  |  |  |  |  |  |  |  |  |
| Average price realized(2) |  | 83.18 |  | 87.89 |  | 75.18 |  | 78.74 |  | 81.22 |  |
| Royalties |  | — |  | — |  | — |  | — |  | — |  |
| Production costs |  | (5.09 | ) | (7.08 | ) | (5.29 | ) | (8.30 | ) | (6.45 | ) |
| Netback(4)(5) |  | 78.09 |  | 80.81 |  | 69.89 |  | 70.42 |  | 74.77 |  |

(1)
  Production and liftings in Libya were intermittent in 2019 and not material to Suncor, and therefore are not included.
(2)
  Average price realized is net of transportation costs, and before royalties.
(3)
  Volumes include field production for immaterial amounts of associated gas and NGLs.
(4)
  Netback is a non-GAAP financial measure. See the Advisory – Forward-Looking Information and Non-GAAP Financial Measures section of this AIF.
(5)
  Netback for Q4 and Year Ended includes sales from Oda, offshore Norway.

48 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

The following table provides the production volumes(1) on a working-interest basis, before royalties for each of Suncor's important fields for the year ended December 31, 2019.

|  | SCO |  | Bitumen |  | Light & Medium Oil |
|  | mbbls/d |  | mbbls/d |  | mboe/d |
Mining – Suncor |  | 222.9 |  | — |  | — |
Mining – Syncrude |  | 172.3 |  | — |  | — |
Mining – Fort Hills |  | — |  | 85.3 |  | — |
Firebag |  | 90.4 |  | 70.3 |  | — |
MacKay River |  | — |  | 29.2 |  | — |
Buzzard |  | — |  | — |  | 31.9 |
GEAD |  | — |  | — |  | 9.0 |
Hibernia |  | — |  | — |  | 20.1 |
White Rose |  | — |  | — |  | 4.7 |
Terra Nova |  | — |  | — |  | 11.6 |
Hebron |  | — |  | — |  | 23.5 |

(1)
  Volumes shown are actual volumes and may differ from the estimated volumes shown in the Reconciliation of Gross Reserves Table.

Production Estimates

The table below outlines the production estimates for 2020 that are included in the estimates of Proved reserves and Probable reserves as at December 31, 2019.

|  | SCO |  | Bitumen |  | Light & Medium Crude Oil |  | Conventional Natural Gas |  | Total |
|  | (mbbls/d)(1) |  | (mbbls/d)(1) |  | (mbbls/d)(1) |  | (mmcfe/d)(1)(2) |  | (mboe/d)(1) |
|  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |  | Gross |  | Net |
Canada |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Proved |  | 452 |  | 433 |  | 207 |  | 195 |  | 59 |  | 50 |  | — |  | — |  | 717 |  | 679 |
| Probable |  | 32 |  | 30 |  | 11 |  | 8 |  | 7 |  | 6 |  | — |  | — |  | 49 |  | 45 |
| Proved Plus Probable |  | 483 |  | 463 |  | 218 |  | 204 |  | 65 |  | 57 |  | — |  | — |  | 766 |  | 724 |
Offshore U.K. & Norway |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Proved |  | — |  | — |  | — |  | — |  | 40 |  | 40 |  | 4 |  | 4 |  | 40 |  | 40 |
| Probable |  | — |  | — |  | — |  | — |  | 5 |  | 5 |  | 2 |  | 2 |  | 5 |  | 5 |
| Proved Plus Probable |  | — |  | — |  | — |  | — |  | 44 |  | 44 |  | 6 |  | 6 |  | 45 |  | 45 |
Total(1)(2) |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |  |
| Proved |  | 452 |  | 433 |  | 207 |  | 195 |  | 98 |  | 90 |  | 4 |  | 4 |  | 757 |  | 719 |
| Probable |  | 32 |  | 30 |  | 11 |  | 8 |  | 11 |  | 11 |  | 2 |  | 2 |  | 54 |  | 50 |
| Proved Plus Probable |  | 483 |  | 463 |  | 218 |  | 204 |  | 110 |  | 101 |  | 6 |  | 6 |  | 811 |  | 769 |

(1)
  Figures may not add due to rounding.
(2)
  Conventional Natural Gas includes immaterial amounts of NGLs.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 49

The following properties each account for approximately 20% or more of total estimated production for 2020.

Proved

•
  From Millennium and North Steepbank: 222 mbbls/d of SCO, which represents approximately 29% of total estimated production for 2020.
•
  From Firebag: 168 mbbls/d of SCO and bitumen (79 mbbls/d and 89 mbbls/d, respectively), which represents approximately 22% of total estimated production for 2020.
•
  From Syncrude: 151 mbbls/d of SCO, which represents approximately 20% of total estimated production for 2020.

Proved Plus Probable

•
  From Millennium and North Steepbank: 235 mbbls/d of SCO, which represents approximately 29% of total estimated production for 2020.
•
  From Firebag: 180 mbbls/d of SCO and bitumen (84 mbbls/d and 96 mbbls/d, respectively), which represents approximately 22% of total estimated production for 2020.
•
  From Syncrude: 165 mbbls/d of SCO from Syncrude, which represents approximately 20% of total estimated production for 2020.

None of the company's Light & Medium Crude Oil production associated with its E&P Canada and Offshore U.K. & Norway assets accounts for 20% or more of the total estimated production for 2020.

Work Commitments

The practice of governments requiring companies to pledge to carry out work commitments in exchange for the right to carry out exploration for and development of hydrocarbons is common, particularly in unexplored or lightly explored regions of the world. The following table shows the estimated values of work commitments Suncor has made in regard to the lands to which it holds rights as at December 31, 2019. These commitments run through 2021 and beyond, and are primarily for conducting seismic programs and drilling exploration wells.

Country/Area ($ millions) |  | 2020 |  | 2021 |  | 2022+ |  | Total |
Canada |  | — |  | — |  | — |  | — |
Other International |  | — |  | — |  | 499 |  | 499 |

Forward Contracts

Suncor may use financial derivatives to manage its exposure to fluctuations in commodity prices. A description of Suncor's use of such instruments is provided in the 2019 audited Consolidated Financial Statements and related MD&A for the year ended December 31, 2019.

Tax Horizon

In 2019, Suncor was subject to cash tax in the majority of the jurisdictions in which it generates earnings, including earnings related to its Canadian, U.S., U.K. and Libyan production. Based on projected future net earnings, Suncor is expected to be cash taxable on the majority of its earnings in 2020.

50 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations. These regulations are imposed by legislation enacted by various levels of government and, with respect to the export and taxation of oil and natural gas, by agreements among the governments of Canada, Ontario, Quebec, Alberta, British Columbia, and Newfoundland and Labrador, as well as the governments of the United States and other foreign jurisdictions in which Suncor operates, all of which should be carefully considered by investors in the oil and gas industry. Current legislation is a matter of public record. All governments have the ability to change legislation, and the company is unable to predict what additional legislation or amendments to legislation may be enacted. Suncor may engage in government consultation regarding proposed legislative changes to ensure Suncor's interests are recognized. The following discussion outlines some of the principal legislation, regulations and agreements that govern Suncor's operations.

Pricing, Marketing and Exporting Crude Oil

The producers of oil are entitled to negotiate sales and purchase agreements directly with oil purchasers. Most agreements are linked to global oil prices. In Canada, oil exporters are also entitled to enter into export contracts. If the term of an export contract exceeds one year for light and medium crude oil or exceeds two years for oil other than heavy crude oil (in either case, to a maximum of 25 years), the exporter is required to obtain an export licence from the Canada Energy Regulator (CER, formerly the National Energy Board). If the term of an export contract does not exceed one year for oil other than heavy crude oil or does not exceed two years for heavy crude oil, the exporter is required to obtain an order from the CER approving such export.

In June 2019, Parliament adopted Bill C-69, an Act to enact the Impact Assessment Act and the Canadian Energy Regulator Act, to amend the Navigation Protection Act and to make consequential amendments to other Acts (Bill C-69), which, among other things, established the CER and changed the energy regulatory regime. The changes resulting from Bill C-69 have not materially altered the previous requirements concerning oil exports. However, at this stage, it is not certain whether or when the federal government might issue new or revised regulations that might impact the oil export regime.

Under the North American Free Trade Agreement (NAFTA), Canada is free to determine whether exports of energy resources to the United States or Mexico will be allowed, subject to certain conditions, and provided that any export restrictions do not (i) reduce the proportion of energy resources exported by Canada relative to the total supply of goods exported by Canada as compared to the proportion prevailing in the most recent 36-month period; (ii) impose an export price higher than the domestic price (subject to an exception with respect to certain measures which only restrict the volume of exports); or (iii) disrupt normal channels of supply. All three countries are prohibited from imposing minimum or maximum export or import price requirements.

NAFTA requires energy regulators to ensure the orderly and equitable implementation of any regulatory changes and to ensure that the application of those changes will cause minimal disruption to contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, all of which are important for Canadian oil and natural gas exports.

In November 2018, Canada, the U.S. and Mexico signed the Canada-United States-Mexico Agreement (CUSMA) with a view to replacing NAFTA. Under CUSMA, Canada will no longer be subject to the proportionality provisions in NAFTA's energy chapter, which should permit the expansion of oil and gas exports beyond the U.S. In addition, CUSMA includes a change to the oil and gas rules of origin that will allow Canadian exporters to more easily qualify for duty-free treatment for shipments to the U.S. Canada must, however, notify the U.S. of its intention to enter free trade talks with any "non-market economies" under CUSMA, which may include China or other potential importers of Canadian oil and gas exports. Legislatures from each of the three countries must ratify CUSMA according to their own legislative processes before it goes into effect and replaces NAFTA. Legislation implementing the CUSMA was passed by the U.S. House of Representatives and the U.S. Senate on December 19, 2019 and January 16, 2020, respectively, and was signed into law by President Trump on January 29, 2020. In addition, CUSMA was ratified by the Senate of Mexico in June 2019, and will be formally ratified in that country when the President of Mexico announces ratification in the Federal Register of Mexico. Canada's implementation bill was introduced in May 2019 but will need to be re-introduced to Parliament. The timeline for ratification of CUSMA is currently uncertain in Canada.

Internationally, prices for crude oil and natural gas fluctuate in response to changes in the supply of and demand for crude oil and natural gas, market uncertainty and a variety of other factors beyond Suncor's control. These factors include, but are not limited to, the actions of OPEC and other large oil and natural gas producing countries, world economic conditions, government regulation, political developments, the foreign supply of oil, the price of foreign imports, the availability of alternate fuel sources and weather conditions.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 51

Royalties and Income Taxes

Canada

The royalty regime is a significant factor in the profitability of SCO, bitumen, crude oil, NGLs and natural gas production. Royalties on production from lands other than Crown lands are determined by negotiations between the mineral freehold owner and the lessee. Crown royalties are determined by governmental regulation or by agreement with governments in certain circumstances, which are subject to change as a result of numerous factors, including political considerations.

For a discussion of the royalties in Alberta and Newfoundland and Labrador, refer to the Narrative Description of Suncor's Businesses section of this AIF.

The Canadian federal corporate income tax rate levied on taxable income for 2019 was 15% for active business income, including resource income. The average provincial income tax rate for Suncor in 2019 was approximately 11.74%.

On May 28, 2019, the Alberta government substantively enacted legislation to effect a staged reduction to the corporate income tax rate. The legislation decreases the corporate income tax rate from 12% to 8% as follows: 11% effective July 1, 2019, 10% effective January 1, 2020, 9% effective January 1, 2021 and 8% effective January 1, 2022. The reduction in the Alberta corporate income tax rate resulted in a reduction to Suncor's blended provincial income tax rate in 2019 as well as a $1.1 billion reduction to Suncor's consolidated deferred income tax liability.

Other Jurisdictions

Operations in the U.S. are subject to the U.S. federal tax rate of 21% and the effective rate for state taxes is approximately 1.6%, resulting in a total U.S. income tax rate of approximately 22.6%.

Operations in the U.K. are subject to a tax rate of 40%, made up of the corporate income tax rate and the supplemental charge. In Norway, operations are subject to a tax rate of 78%.

Amounts presented in Suncor's 2019 audited Consolidated Financial Statements as royalties for production from the company's Libya operations are determined pursuant to EPSAs. The amounts calculated reflect the difference between Suncor's working interest in the particular project and the net revenue attributable to Suncor under the terms of the respective EPSAs. All government interests in these operations, except for income taxes, are presented as royalties.

Land Tenure

In Canada, crude oil and natural gas located in the western provinces are predominantly owned by the respective provincial governments. Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences and permits for varying terms, and on conditions set forth in provincial legislation, including requirements to perform specific work or make payments. Oil and natural gas located in the western provinces may also be privately owned, and rights to explore for and produce such oil and natural gas resources are granted pursuant to a private lease on the terms and conditions negotiated with the mineral rights holder. In central and eastern provinces and offshore areas of Canada, the mineral rights are primarily owned by the Canadian federal government, which, either directly or through shared jurisdiction agreements with the relevant provincial or territorial authorities, grants tenure in the form of exploration, significant discovery, and production licences.

In many other international jurisdictions, including the ones in which Suncor has operations, crude oil and natural gas are most commonly owned by national governments that grant rights in the form of exploration licences and permits, production licences, PSCs and other similar forms of tenure. In all cases, Suncor's right to explore, develop and produce crude oil and natural gas is subject to ongoing compliance with the regulatory requirements established by the relevant country.

Environmental Regulation

The company is subject to environmental regulation under a variety of Canadian, U.S., U.K. and other foreign, federal, provincial, territorial, state and municipal laws and regulations. Among other things, these environmental regulatory regimes impose restrictions and prohibitions on the spill, release or emission of various substances including oil and gas and the byproducts associated with the production thereof, which apply to Suncor and all other companies in the energy industry. Applicable regulatory regimes require Suncor to obtain operating licences and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, as well as the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are generally required before most new major projects or significant changes to existing operations can be initiated. In addition, these environmental regulatory regimes require the company to abandon and reclaim mine, well and facility sites to the satisfaction of regulatory authorities. In some cases, abandonment and reclamation obligations may remain with the company even after disposition of an asset to a third party. Compliance with such legislation can require significant expenditures, and a breach of these requirements may result in suspension or revocation of necessary licences and authorizations, civil liability for pollution damage, and/or the imposition of material fines and penalties.

52 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

In addition to the specific requirements outlined above, Suncor anticipates that future amendments to environmental laws will result in the imposition of additional requirements on companies operating in the energy industry.

A number of statutes, regulations and governance frameworks pertaining to environmental regulation are currently under development and, in some cases, proposed amendments have been issued by the provincial regulators that oversee oil sands development for comment by industry. These statutes, regulations and frameworks relate to issues such as tailings management, water use, biodiversity, air emissions including methane emissions reduction, and land use. The company is committed to working with the appropriate regulatory bodies as they develop new policies, and to fully complying with all existing and new statutes, regulations and frameworks as they apply to the company's operations.

In general, the impact of current and future environmental laws and regulations on the company's business and operations, including laws and regulations relating to climate change, remains uncertain. It is not possible to predict the nature of any future legislative requirements, including those currently set out in the Impact Assessment Act and the Canadian Energy Regulator Act, or the impact the future requirements will have on the company and its business, financial condition and results of operations. Suncor continues to actively work to mitigate the company's environmental impact, including taking action to reduce GHG emissions intensity, installing new emissions abatement equipment, investing in renewable forms of energy, such as wind power and biofuels, undertaking land reclamation activities, investing in environmentally focused research and development, and working to advance other environmental technologies. Refer to the Narrative Description of Suncor's Businesses – Oil Sands – New Technology section of this AIF.

Recent developments in environmental regulation and related government initiatives have had an impact on many areas important to Suncor's operations, some of which are summarized in the following subsections.

Climate Change

Suncor operates in many jurisdictions that regulate, or have proposed to regulate, industrial GHG emissions. Suncor is committed to fully complying with existing regulations and will continue to constructively engage the appropriate governmental bodies in meaningful dialogue to harmonize regulations focused on achieving actual reduction goals and sustainable resource development across jurisdictions where Suncor owns and operates assets.

As part of its ongoing business planning, Suncor estimates future costs associated with CO2 emissions in its operations and in the evaluation of future projects. These estimates use the company's outlook for the carbon price under current and pending GHG regulations which are used in conjunction with other tools to test the company's business strategy against a range of policy designs. Currently, Suncor applies Provincial and Federal carbon regimes and a price of $30 per tonne of CO2e which steadily increases to approximately $100 per tonne of CO2e in 2040 as part of its base case evaluations. The company expects that GHG emissions regulation will continue to evolve with a carbon price that weighs economic, environmental and energy security objectives. Suncor will continue to review the impact of future carbon-constrained scenarios (and changing carbon pricing) on its business strategy.

Environmental regulations and initiatives related to climate change and GHG emissions are described below.

International Climate Change Agreements

The goals of the Paris Agreement on climate change, an agreement within the United Nations Framework Convention on Climate Change that came into force on November 4, 2016, are to prevent the global temperature rise from exceeding 2 degrees Celsius above pre-industrial levels and to pursue efforts to limit the temperature increase to 1.5 degrees Celsius above pre-industrial levels. Pursuant to the Paris Agreement, the Government of Canada set a goal to reduce GHG emissions economy-wide by 30% below 2005 levels by 2030. The federal government has also signalled its intentions to introduce legislation that will commit Canada to a net-zero emissions goal by 2050.

Canadian Federal GHG Regulations

Enacted and Effective

In furtherance of its commitments under the Paris Agreement, the federal government developed the Pan-Canadian Framework on Clean Growth and Climate Change (PCF) in 2016 to meet Canada's emissions target while enabling economic growth.

Under the PCF, the federal government requires all provinces and territories to have a carbon price, starting at $20 per tonne of CO2e in 2019 and rising by $10 per year to $50 per tonne of CO2e in 2022. Jurisdictions can implement: (i) an explicit price-based system (such as the carbon tax adopted by British Columbia), (ii) the carbon levy and performance-based emissions system (adopted in Alberta), or (iii) cap-and-trade system (which has been adopted in Quebec). Within these programs, provinces have discretion to manage competitiveness of their energy intensive trade-exposed industries. The provincial carbon pricing initiatives applied in Alberta, British Columbia, Quebec, Ontario, and Newfoundland and Labrador and their impact on Suncor are described in the Canadian Provincial GHG Regulations section below.

The 2018 federal Greenhouse Gas Pollution Pricing Act (GGPPA) establishes the federal carbon price on GHG emissions applicable as of January 2019. The GGPPA reinforces the approach taken in the PCF and is only

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 53

intended to serve as a regulatory carbon pricing "backstop" to any province or territory that requests it, or to those jurisdictions that have not otherwise implemented a compliant provincial or territorial carbon pricing regime. The GGPPA consists of two parts: (1) an economy-wide consumer carbon levy on the use and combustion of fossil fuels; and (2) an Output Based Pricing System (OBPS) applied to heavy industrial sectors that face international competition.

Under Development

In addition to GGPPA's carbon pricing "backstop", a Clean Fuel Standard (CFS) is being developed by the federal government with the objective of achieving annual reductions of 30 Mt of CO2e emissions by 2030. The CFS will be implemented under the Canadian Environmental Protection Act (CEPA). When implemented, it is expected that the CFS will require reductions in the carbon intensity of the fuels supplied into Canada, based on a new life cycle analysis model under development by the federal government. The approach is not expected to differentiate between crude oil produced in or imported into Canada. CFS is expected to apply to a broad suite of fuels used in transportation, industry, homes and buildings. The CFS regulations are being developed in stages, based on the class of fuel, and are expected to be finalized and enacted between 2022-23. Until such regulations are published, the company is unable to predict the impact, if any, that CFS will have on its business.

Canadian Provincial GHG Regulations

Alberta

Carbon Competitiveness Incentive Regulation (CCIR)

From January 1, 2018 until December 31, 2019, the applicable Alberta legislation was the CCIR. Under the CCIR, regulated facilities (which included Suncor's Oil Sands Base operations, Firebag, MacKay River, Fort Hills and the Edmonton refinery) were incented to reduce GHG emissions through improving performance by establishing product-based performance standards (also called output-based allocations) across all industries.

Suncor's compliance cost under the CCIR for the 2018 compliance year was $47 million in respect of its owned and operated properties. The 2018 compliance cost for Syncrude was $26 million, net to Suncor.

The 2019 compliance cost for all Suncor's owned and operated Alberta assets was $87 million and $21 million, net to Suncor, for Syncrude, respectively. Fort Hills remained exempt from compliance costs as a "new facility" under the CCIR until the end of 2019.

In addition to the regulations under the CCIR, the Alberta Oil Sands Emissions Limit Act (the OSELA) sets a limit of 100 Mt of CO2e per year in the oil sands sector, excluding emissions from cogeneration and new upgrading capacity, allowing for continued growth and development while the sector works to accelerate emissions reduction technologies and operational optimization. Current oil sands emissions in Alberta are estimated to be 71 Mt per year, including existing upgrading capacity, but excluding cogenerated electricity sold to the Alberta power grid. The mechanics of implementation and enforcement of the OSELA remain under review by the Government of Alberta and, therefore, it is not yet possible to predict the long-term impact on Suncor.

Technology Innovation and Emissions Reduction Implementation Act (TIER)

On October 29, 2019, the Government of Alberta introduced TIER, which includes new carbon pricing legislation for large industrial emitters. TIER came into force on January 1, 2020, replacing CCIR. TIER meets the federal government's stringency benchmark criteria for large industrial emitters for 2020. As a result, the federal output-based carbon pricing system applicable to large industrial emitters, described under GGPPA, will not apply to Alberta. TIER applies to large industrial facilities in Alberta with CO2e emissions in excess of 100,000 tonnes per year which, for Suncor, includes Oil Sands Base, Firebag, MacKay River, Fort Hills and the Edmonton refinery. Such facilities will be required to reduce emissions by 10% starting in 2020 with a further 1% per year reduction thereafter. Failure to meet emissions reduction targets results in being assessed at the prevailing carbon price. The carbon price under TIER will remain unchanged from the CCIR price of $30 per tonne of CO2e.

Electricity generators will continue to be subject to the existing "good-as-best-gas" standard of 370 tonnes of CO2e per GWh. Currently, Suncor's facilities are more efficient than the electricity standard and therefore earn credits.

Under TIER, each of Suncor's facilities is required to comply with the least stringent of either: (1) a facility-specific benchmark based on the average historical performance of that facility between 2013-15; or (2) a high-performance benchmark. All of Suncor's operations fall under the facility-specific benchmark. The high-performance benchmark is a product-specific, high-performance benchmark reflecting emissions intensity of high performance in a sector (calculated as average emissions intensity of the top 10% of facilities). Under TIER, facilities emitting over their prescribed benchmarks will be subject to a compliance obligation, while facilities emitting under their respective benchmarks will be able to generate Emissions Performance Credits (EPCs) and offset credits. Suncor will continue to generate such credits from its cogeneration and renewable energy assets.

Compared to CCIR, TIER is expected to result in lower compliance costs to Suncor. The 2020 estimated compliance cost for all of Suncor's owned and operated Alberta assets is $30 million, and $26 million, net to Suncor, for Syncrude.

54 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Effective as of January 1, 2020, the federal fuel charge under GGPPA will apply to Alberta consumers as a $20 per tonne of CO2e carbon levy on GHG emissions resulting from the combustion of fossil fuels for heating and transportation.

British Columbia

The Province of British Columbia enacted a consumption-based carbon tax in 2008. The purchasers or users of fuels pay the carbon tax, which is collected by Suncor and forwarded onto the government. The tax was $40 per tonne of CO2e in 2019 and will rise to $45 per tonne of CO2e in 2020 and $50 per tonne of CO2e in 2021.

Quebec

Implemented in 2013, Quebec's cap and trade system for greenhouse gas emissions allowances applies to companies in the industrial and electricity sectors that emit 25,000 Mt or greater of CO2e per year. Quebec's cap-and-trade system is linked to the Western Climate Initiative (WCI), an organization set up to help member states in the U.S. and Canadian provinces execute their cap-and-trade systems. Allowances and offsets are fungible across the WCI. In Quebec, emitters are required to either reduce their emissions or purchase eligible compliance mechanisms to cover their emissions above a specified cap. The cap and the allocation of free allowances are established by the Province. Suncor's Montreal refinery is subject to stationary emissions, and associated transportation end-users are subject to Quebec's cap-and-trade system.

For the 2018 and 2019 compliance years, the cost of compliance for the Montreal refinery was $1.2 million and $2 million, respectively. The 2020 estimated compliance cost attributed to the Montreal refinery's stationary emissions is $1.7 million. Compliance costs associated with end-user emissions arising from transportation fuels consumption are passed through to the customer at the time of purchase.

Ontario

Enacted and Effective

Effective January 1, 2018, Ontario formally launched its cap-and-trade system under WCI. Due to a change in government, the program was effectively cancelled July 3, 2018. This was finalized by the passage of Bill 4, Cap and Trade Cancellation Act effective October 31, 2018. As a result, Ontario became subject to the two-part federal government GGPPA program in 2019. Pursuant to the program, facilities that generate more than 25,000 tonnes of GHG emissions per year (including Suncor's Sarnia refinery and St. Clair ethanol plant) are subject to the Output Based Pricing System (OBPS). In addition, the federal carbon levy was applied to the combustion of all fossil fuels by consumers in Ontario. Similar to Quebec, costs attributed to the carbon levy on emissions from transportation fuels are passed through to the customer. Carbon prices pursuant to both aspects of the GGPPA program were $20 per tonne of CO2e in 2019 and $30 per tonne of CO2e in 2020.

For the 2018 and 2019 compliance year, the cost of compliance under the WCI and OBPS for the Sarnia refinery was $3.1 million and a credit of $0.43 million, respectively. For the St. Clair ethanol plant, the cost of compliance under the WCI and OBPS was nil and $0.75 million, respectively. The 2020 estimated compliance costs attributed to the Sarnia refinery and the St. Clair ethanol plant are nil and $1 million, respectively.

Under Development

Since the federal government's GGPPA program has been in place, the Government of Ontario has proposed an Emissions Performance Standards (EPS) that would be a "made in Ontario" carbon pricing system for large emitters. However, the federal government has indicated that Ontario will remain under the GGPPA program until the federal government conducts a countrywide review of provincial and territorial programs in 2022.

Newfoundland and Labrador

Enacted and Effective

Newfoundland and Labrador's carbon pricing program is a hybrid system comprised of performance standards for large industrial facilities, including large-scale electricity generation, plus a consumer carbon tax on transportation, building fuels, and other fuels combusted in the province. Performance standards for large industrial facilities are legislated under the Management of Greenhouse Gas Act (MGGA) and associated regulations, which apply to all facilities that emit 15,000 tonnes of CO2e or more per annum and therefore applies to Terra Nova, Hibernia, White Rose, and Hebron. Consistent with the federal carbon pricing scheme, the Newfoundland and Labrador carbon price started in 2019 at $20 per tonne of CO2e and increased to $30 per tonne of CO2e for 2020.

For 2019, onshore facilities are assigned an annual GHG reduction target equal to 6% below the facility's 2016-17 historical average emissions-to-output ratio. The target increases by 2% per year until the reduction target reaches 12% in 2022. To protect the competitiveness of offshore petroleum facilities, each regulated facility will be assigned the same percentage reductions to its average emissions level, excluding federally regulated emissions for methane from venting and fugitive emissions. Consistent with the government's Advance 2030 initiative to encourage oil and gas development in the province, mobile offshore drilling unit activities related to exploration are exempt from the calculation for the unit's annual GHG reduction target.

The 2019 compliance cost attributed to the company's operated E&P Canada assets (Terra Nova), located offshore Newfoundland and Labrador, was $2.3 million. For 2020, the

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 55

forecast compliance cost is nil due to a planned maintenance turnaround program at Terra Nova.

Under Development

The MGGA also contemplates the establishment of a fund for energy efficient and clean technology through compliance payments made by industrial emitters. This is expected to support technology and innovation as well as provide flexible compliance options and protect the competitiveness of energy-intensive, trade-exposed sectors such as the province's offshore petroleum sector. Large industrial emitters, which include the offshore petroleum sector, account for approximately 43% of the province's current emissions.

U.S. GHG Regulations

Enacted and Effective

The U.S. Environmental Protection Agency (U.S. EPA) has established a rule mandating that all large facilities (defined as facilities emitting greater than 25,000 tonnes of CO2e per year, which includes Suncor's refinery in Commerce City, Colorado) must report their GHG emissions.

In 2019, the State of Colorado passed a suite of energy and climate change related legislation that includes, but is not limited to, setting statewide targets to reduce 2025 GHG emissions by at least 26%; 2030 GHG emissions by 50%; and 2050 GHG emissions by 90%, using a 2005 baseline year. The legislation also includes rules to reduce emissions from the oil and gas sector, including the potential introduction of a low-carbon fuel standard, requirements to monitor, measure, report and forecast stationary emissions from large industrial facilities, and leak detection and repair as well as transitioning Colorado's electricity system to become 80% renewable by 2030 and 100% renewable by 2040. The outcome of these changes in approach to GHG emissions is currently unclear and the impact on Suncor, including its Commerce City, Colorado refinery, is unknown at this time.

Under Development

The mandate of the U.S. EPA is under review by the current administration. In June 2017, the withdrawal of the U.S. from the Paris Agreement was announced, with the current administration commencing formal proceedings to withdraw the U.S. from the Paris Agreement in November 2019. The current administration has also overturned a number of regulations promulgated by previous administrations intended to monitor or restrict climate change.

Notwithstanding the above, the United States Climate Alliance, a network consisting of the governors of 24 states, which include Colorado, remain committed to advancing efforts to address climate change through policies that encourage investment in clean energy, energy efficiency and climate resilience. Suncor continues to monitor these developments and constructively participate where appropriate.

International Regulations

The European Union Emissions Trading Scheme (EU ETS) applies to Suncor's non-operated offshore U.K. and Norway assets. The EU ETS requires that member countries set emissions limits for installations in their country covered by the scheme and assigns such installations an emissions cap. Installations may meet their cap by reducing emissions or by buying allowances from other participants. Phase III of EU ETS includes a transition from free allocation to auctioning allowances.

Land Use

In 2012, the Government of Alberta approved the Lower Athabasca Regional Plan (LARP). The LARP addresses land-use management in the Lower Athabasca region of Alberta, which includes the area of the province in which Suncor's Oil Sands business is located. The LARP, which was developed pursuant to the Alberta Land Stewardship Act, is part of Alberta's approach to managing land and natural resources to achieve long-term economic, environmental and social goals, and identifies new conservation areas as well as management frameworks to ensure the continued regional quality of air, surface water and groundwater. The conservation areas established by LARP do not overlap with any of Suncor's or Syncrude's leases.

The management frameworks established under LARP formalize a number of regulatory tools used by the government to manage environmental aspects of oil sands development, including cumulative environmental effects of management on a regional scale. As a result, LARP may require Suncor and Syncrude to have greater participation in the overall evaluation of environmental issues and emissions in the Lower Athabasca region. The frameworks established under LARP include the following:

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  Air Quality Management Framework (AQMF). The AQMF is designed to maintain flexibility and to manage the cumulative effects of development on air quality within the Lower Athabasca region, setting triggers and limits for nitrogen dioxide (NO2) and sulphur dioxide (SO2). The AQMF includes ambient air quality triggers and limits. Regulatory actions will occur when triggers or limits are reached or exceeded.
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  Surface Water Quality Management Framework (SWMF-Quality). The SWMF-Quality provides a basis with which to monitor and manage long-term, cumulative changes in water quality within the Lower Athabasca River. The SWMF-Quality includes quality limits and triggers for various indicators, based on existing Alberta, Canadian Council of Ministers of the Environment, Health Canada and U.S. EPA guidelines. Regulatory

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actions will occur when triggers or limits are reached or exceeded.

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  Surface Water Quantity Management Framework (SWMF-Quantity). The SWMF-Quantity establishes weekly management triggers and water withdrawal limits that enable proactive management of mineable oil sands water used from the Athabasca River. Weekly water withdrawal limits reflect seasonal variability and may become more restrictive as flows in the river change. Suncor and Syncrude have voluntarily agreed to minimize water withdrawals for pre-existing plant operations to no more than their annual withdrawal licence average of 2 m3/s, during periods of low flow for the Athabasca River. The Fort Hills mining project has on-site water storage to meet the SWMF-Quantity requirements during low flow. To ensure that weekly flow triggers and cumulative water use limits for oil sands mining operators are met, each oil sands mining operator enters into an annual Oil Sands Water Management Sharing Agreement which is submitted to Fisheries and Oceans Canada and Alberta Environment and Parks. The agreement reduces the cumulative amount of water being withdrawn by oil sands mining operations when necessary to ensure that the cumulative water use limits established under SWQMF-Quantity are met.
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  Groundwater Management Framework (GMF). The GMF aims to manage non-saline groundwater resources in a sustainable manner and protect groundwater resources from contamination and over use. It aims to ensure timely detection of key changes to indicators and describes the management response that will be initiated if triggers or limits, including site-specific measures, are reached or exceeded.
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  Tailings Management Framework for Mineable Athabasca Oil Sands (TMF). The TMF provides oil sands mining operations with direction regarding the management of fluid tailings volumes during and after mine operation in order to manage and mitigate liability and environmental risk resulting from the accumulation of fluid tailings on the landscape. It is anticipated that the TMF will result in technological innovations in tailings management and reduce the overall volumes of fluid tailings associated with oil sands mining and extraction. As a part of the implementation of the TMF, the AER finalized the Tailings Directive in October 2017. The Tailings Directive follows TMF guidance by requiring fluid tailings inventory triggers and a limit, as well as management actions such as a compliance levy and financial security through the Mine Financial Security Program (MFSP), to support the overarching objective of minimizing fluid tailings accumulation while balancing environmental, social and economic needs. The amount of any financial management actions, including compliance levies, and financial bonds through the MFSP have yet to be set. As such, it is not possible to predict what impact financial management actions imposed pursuant to the Tailings Directive could have on Suncor at this time.

Suncor is committed to reclaiming and remediating lands affected by its operations. Suncor has improved its tailings management efforts and became the first company to reclaim an oil sands tailings pond, convert a second to a fluid tailings treatment area, and make another pond trafficable with coke capping. Under the TMF, updated tailings management plans have been submitted and approved for Oil Sands Base (2017), Syncrude Aurora North (2018), Syncrude Mildred Lake (2019), and Fort Hills (2019).

Another component identified in the TMF is integrated water management. In order to support successful closure and reclamation, water quantity must be reduced and quality must be managed.

Dam Integrity

The Government of Alberta has a rigorous and stringent regulatory system to manage dams within the province. In December 2018, the Water (Ministerial) Regulation was updated and includes new dam regulatory requirements. The primary purpose of these updates is to address regulatory requirements for in-stream dams (i.e., hydroelectric) requirements. However, these new requirements will also apply to all dams in Alberta, including off-stream dams (i.e., tailings dams).

Throughout 2019, the AER developed regulatory tools to provide guidance for how these new requirements apply to tailings facilities that are regulated by the AER, including oil sands tailings dams. The AER released Manual 019: Decommissioning, Closure, and Abandonment of Dams at Energy Projects (Manual 019) in January 2020, which explains how existing regulatory requirements pertaining to the decommissioning, closure, and abandonment of dams will be assessed and enforced by the AER rather than introducing any new requirements. These regulations are supplemented by Suncor's internal programs which are designed to provide additional oversight in accordance with industry best practices. The provincial dam integrity program may result in additional costs associated with monitoring, planning and measurements in addition to or in advance of current plans. Given the recent release of Manual 019, ongoing uncertainty about how the new regulations will apply to oil sands facilities may result in delay in regulatory approvals for facilities being reviewed under the new requirements.

Reclamation

The Government of Alberta's MFSP accounts for the environmental liability associated with the suspension, abandonment, remediation and surface reclamation of oil

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sands mines and plant sites. The MFSP requires a base amount of security for each project. Suncor has provided this security in the form of letters of credit and is in compliance with the MFSP. Additional security may be required under other conditions, such as failure to meet current reclamation plans, or when the estimated remaining production life of the mine reaches certain levels; however, Suncor has not been required to provide any additional security to date. The MFSP has been designed by the Government of Alberta to include a periodic review of the program to ensure it is functioning properly and provides early warning of any potential risks of a tailings management action specific to the TMF. It is expected that revisions to the MFSP will be completed between 2020 to 2023.

Oil Sands Monitoring

In 2012, Canada and Alberta adopted the Joint Canada-Alberta Implementation Plan for Oil Sands Monitoring (Monitoring Plan). The intent of the Monitoring Plan is to provide scientifically rigorous, comprehensive, integrated and transparent environmental monitoring, including an improved understanding of the cumulative environmental impact of oil sands development. The total cost to the oil sands industry of enhanced monitoring under the Monitoring Plan has been estimated at approximately $50 million per year. The 2019 annual cost to Suncor under the Monitoring Plan is estimated to be approximately $11 million, including Suncor's net share of Syncrude compliance costs.

Industry Collaboration Initiatives

Environmentally focused collaboration between companies and stakeholders is an important focus for the oil sands industry. Suncor is a founding member of Canada's Oil Sands Innovation Alliance (COSIA) and is committed to collaborative action to accelerate improvements in environmental performance, including tailings, water, land, monitoring and GHG emissions. COSIA works with other collaborative networks to share knowledge and expertise about new technologies and innovation related to environmental performance.

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RISK FACTORS

Suncor is committed to a proactive program of enterprise risk management intended to enable decision-making through consistent identification and assessment of risks inherent to its assets, activities and operations. Some of these risks are common to operations in the oil and gas industry as a whole, while some are unique to Suncor. The realization of any of the following risks could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Volatility of Commodity Prices

Suncor's financial performance is closely linked to prices for crude oil in the company's upstream business and prices for refined petroleum products in the company's downstream business and, to a lesser extent, to natural gas and electricity prices in the company's upstream business where natural gas and power are both inputs and outputs of production processes. The prices for all of these commodities can be influenced by global and regional supply and demand factors, which are factors that are beyond the company's control and can result in a high degree of price volatility.

Crude oil prices are also affected by, among other things, global economic health (particularly in emerging markets), market access constraints, regional and international supply and demand imbalances, political developments and government action (including the mandatory production curtailments recently imposed by the Government of Alberta), decisions by OPEC to not impose quotas on its members, compliance or non-compliance with quotas agreed upon by OPEC members and other countries, and weather. These factors impact the various types of crude oil and refined products differently and can impact differentials between light and heavy grades of crude oil (including blended bitumen), and between conventional oil and SCO.

Refined petroleum product prices and refining margins are also affected by, among other things, crude oil prices, the availability of crude oil and other feedstock, levels of refined product inventories, regional refinery availability, market access, marketplace competitiveness, and other local market factors. Natural gas prices in North America are affected by, among other things, supply and demand, and by prices for alternative energy sources. Decreases in product margins or increases in natural gas prices could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

In addition, oil and natural gas producers in North America, and particularly in Canada, may receive discounted prices for their production relative to certain international prices, due in part to constraints on the ability to transport and sell such products to international markets. A failure to resolve such constraints may result in continued discounted or reduced commodity prices realized by oil and natural gas producers such as Suncor. Suncor's production from Oil Sands includes significant quantities of bitumen and SCO that may trade at a discount to light and medium crude oil. Bitumen and SCO are typically more expensive to produce and process. In addition, the market prices for these products may differ from the established market indices for light and medium grades of crude oil. As a result, the price received for bitumen and SCO may differ from the benchmark they are priced against. Future quality differentials are uncertain and unfavourable differentials could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

In the fourth quarter of 2018, there was insufficient market access capacity to remove production from the Western Canada Sedimentary Basin causing the differential between WTI and WCS to widen significantly. The situation triggered a response from the Government of Alberta in the form of a mandatory production curtailment, which commenced in early 2019. Such circumstances may result in worsening and/or prolonged price volatility and/or further negative impacts on market dynamics that cannot currently be fully anticipated. Wide differentials, such as those experienced in the fourth quarter of 2018 or a prolonged period of low and/or volatile commodity prices, particularly for crude oil, could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations, and may also lead to the impairment of assets, or to the cancellation or deferral of Suncor's growth projects.

Market Access

Suncor's production of bitumen is expected to grow. The markets for bitumen blends or heavy crude oil are more limited than those for light crude oil, making them more susceptible to supply and demand changes and imbalances (whether as a result of the availability, proximity, and capacity of pipeline facilities, railcars, or otherwise). Heavy crude oil generally receives lower market prices than light crude, due principally to the lower quality and value of the refined product yield and the higher cost to transport the more viscous product on pipelines, and this price differential can be amplified due to supply and demand imbalances.

Market access for Suncor's oil sands production may be constrained by insufficient pipeline takeaway capacity, including the lack of new pipelines due to an inability to secure required approvals and negative public perception. There is a risk that constrained market access for oil sands production, growing inland production and refinery outages could create widening differentials that could impact the profitability of product sales. Market access for refined products may also be constrained by insufficient takeaway capacity, which could create a supply/demand imbalance. The occurrence of any of the foregoing could have a material adverse effect on the company's business, financial condition, reserves and results of operations.

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Major Operational Incidents (Safety, Environmental and Reliability)

Each of Suncor's primary operating businesses – Oil Sands, E&P, and Refining and Marketing – requires significant levels of investment in the design, operation, and maintenance and decommissioning of facilities, and carries the additional economic risk associated with operating reliably or enduring a protracted operational outage. The breadth and level of integration of Suncor's operations adds complexity.

The company's businesses also carry the risks associated with environmental and safety performance, which is closely scrutinized by governments, the public and the media, and could result in a suspension of or inability to obtain regulatory approvals and permits, or, in the case of a major environmental or safety incident, delays in resuming normal operations, fines, civil suits or criminal charges against the company.

In general, Suncor's operations are subject to operational hazards and risks such as, among others, fires (including forest fires), explosions, blow-outs, power outages, prolonged periods of extreme cold or extreme heat, severe winter climate conditions, flooding, droughts and other extreme weather conditions, railcar incidents or derailments, the migration of harmful substances such as oil spills, gaseous leaks or a release of tailings into water systems, pollution and other environmental risks, and accidents, any of which can interrupt operations or cause personal injury or death, or damage to property, equipment (including information technology and related data and controls systems), and the environment.

The reliable operation of production and processing facilities at planned levels and Suncor's ability to produce higher value products can also be impacted by, among other things, failure to follow the company's policies, standards and operating procedures or operate within established operating parameters, equipment failure through inadequate maintenance, unanticipated erosion or corrosion of facilities, manufacturing and engineering flaws, and labour shortage or interruption. The company is also subject to operational risks such as sabotage, terrorism, trespass, theft and malicious software, network or cyber attacks.

In addition to the foregoing factors that affect Suncor's business generally, each business unit is susceptible to additional risks due to the nature of its business, including, among others, the following:

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  Suncor's Oil Sands business is susceptible to loss of production, slowdowns, shutdowns or restrictions on its ability to produce higher value products, due to the failure of any one or more interdependent component systems, and other risks inherent to oil sands operations;
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  For Suncor's E&P businesses, there are risks and uncertainties associated with drilling for oil and natural gas, the operation and development of such properties and wells (including encountering unexpected formations, pressures, or the presence of hydrogen sulphide), premature declines of reservoirs, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids and other accidents;
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  Suncor's E&P offshore operations occur in areas subject to hurricanes and other extreme weather conditions, such as winter storms, pack ice, icebergs and fog. The occurrence of any of these events could result in production shut-ins, the suspension of drilling operations, damage to or destruction of the equipment involved and injury or death of rig personnel. Harsh weather conditions, particularly in the winter season, may also impact the successful execution of maintenance and startup of operations. Suncor's E&P offshore operations could be indirectly affected by catastrophic events occurring at other third-party offshore operations, which could give rise to liability, damage to the company's equipment, harm to individuals, force a shutdown of facilities or operations, or result in a shortage of appropriate equipment or specialists required to perform planned operations; and
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  Suncor's Refining and Marketing operations are subject to all of the risks normally inherent in the operation of refineries, terminals, pipelines and other distribution facilities and service stations, including, among others, loss of production, slowdowns or shutdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock, or other incidents.

Although the company maintains a risk management program, which includes an insurance component, such insurance may not provide comprehensive coverage in all circumstances, nor are all such risks insurable. The company self-insures some risks, and the company's insurance coverage does not cover all the costs arising out of the allocation of liabilities and risk of loss arising from Suncor operations.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Government/Regulatory and Policy Effectiveness

Suncor's businesses operate under federal, provincial, territorial, state and municipal laws in numerous countries. The company is also subject to regulation and intervention by governments in oil and gas industry matters, such as, among others, land tenure, royalties, taxes (including income taxes), government fees, production rates (including restrictions on production), environmental protection, wildlife, fish, safety performance, the reduction of GHG and other emissions, the export of crude oil, natural gas and other products, interactions with foreign governments, the awarding or acquisition of exploration and production rights, oil sands leases or other interests, the imposition of specific

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drilling obligations, control over the development, reclamation and abandonment of fields and mine sites, mine financial security requirements, approval of logistics infrastructure, and possibly expropriation or cancellation of contract rights. As part of ongoing operations, the company is also required to comply with a large number of EH&S regulations under a variety of Canadian, U.S., U.K., Norwegian and other foreign, federal, provincial, territorial, state and municipal laws and regulations. Failure to comply with applicable laws and regulations may result in, among other things, the imposition of fines and penalties, production constraints, a compulsory shutdown of facilities or suspension of operations, reputational damage, delays, increased costs, denial of operating and growth permit applications, censure, liability for cleanup costs and damages, and the loss of important licences and permits.

Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain various federal, provincial, territorial, state and municipal permits and regulatory approvals, and must also obtain licences to operate certain assets. These processes can involve, among other things, Indigenous and stakeholder consultation, environmental impact assessments and public hearings, government intervention and may be subject to conditions, including security deposit obligations and other commitments. Compliance can also be affected by the loss of skilled staff, inadequate internal processes and compliance auditing.

Failure to obtain, comply with, satisfy the conditions of or maintain regulatory permits, licences and approvals, or failure to obtain them on a timely basis or on satisfactory terms, could result in prosecution, fines, delays, abandonment or restructuring of projects and increased costs, all of which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations. Suncor's businesses can also be indirectly impacted by a third party's inability to obtain regulatory approval for a shared infrastructure project or a third-party infrastructure project on which a portion of Suncor's business depends.

Changes in government policy, regulation or other laws, or the interpretation thereof, or opposition to Suncor's projects or third-party pipeline and infrastructure projects that delays or prevents necessary permits or regulatory approvals, or which makes current operations or growth projects less profitable or uneconomic could materially impact Suncor's operations, existing and planned projects, financial condition, reserves and results of operations. Obtaining necessary approvals or permits has become more difficult due to increased public opposition and Indigenous consultation requirements as well as increased political involvement. The federal government's Impact Assessment Act (formerly Bill C-69) also came into force in August 2019 and will impact the manner in which large energy projects are approved. This development could also lead to significant delays and additional compliance costs, and staffing and resource levels, and also increase exposure to other risks to Suncor's business, including environmental or safety non-compliance, permit approvals, and project development and execution, all of which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations. Refer to the Industry Conditions section of this AIF.

Suncor is subject to the mandatory production curtailments imposed by the Government of Alberta that commenced in early 2019. The duration, extent and consequences of the curtailments to Suncor's business are not fully known; however, prolonged production curtailment or changes to the curtailment levels could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Greenhouse Gas Emissions and Targets

Among other sustainability goals, Suncor has committed to reducing the total GHG emissions intensity of its oil and gas petroleum products by 30% by 2030 (based on a 2014 baseline year). Our ability to lower GHG emissions on both an absolute basis and in respect of our 2030 total emissions reduction target is subject to numerous risks and uncertainties and our actions taken in implementing these objectives may also expose us to certain additional and/or heightened financial and operational risks.

A reduction in GHG emissions relies on, among other things, our ability to implement and improve energy efficiency at all of our facilities, future development and growth opportunities, develop and deploy new technologies, invest in low-carbon power and transition to low-carbon fuels. In the event that we are unable to implement these strategies and technologies as planned without negatively impacting our expected operations or business plans, or in the event that such strategies or technologies do not perform as expected, we may be unable to meet our GHG targets or goals on the current timelines, or at all.

In addition, achieving our GHG emission reductions target and goals could require significant capital expenditures and resources, with the potential that the costs required to achieve our target and goals materially differ from our original estimates and expectations, which differences may be material. In addition, the shift in resources and focus towards emissions reduction could have a negative impact on our operating results. The overall final cost of investing in and implementing an emissions-intensity reduction strategy and technologies in furtherance of such strategy, and the resultant change in the deployment of our resources and focus, could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

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Competition

The global petroleum industry is highly competitive in many aspects, including the exploration for and the development of new sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and marketing of refined petroleum products. Suncor competes in virtually every aspect of its business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. The increasing volatility of the political and social landscape at provincial, federal, territorial, state, municipal and international levels adds complexity.

For Suncor's Oil Sands business, it is difficult to assess the number, level of production and ultimate timing of all potential new projects or when existing production levels may increase. Although current commodity pricing and increased regulatory requirements have slowed certain larger projects in the short term, an increase in the level of activity may have an impact on regional infrastructure, including pipelines, and could place stress on the availability and cost of all resources required to build and run new and existing oil sands operations.

For Suncor's Refining and Marketing business, management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that the company's downstream business unit participates in new product markets, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.

There is a risk that increased competition could cause costs to increase, put further strain on existing infrastructure and cause margins for refined and unrefined products to be volatile, and impact demand for Suncor's products, which could have a material adverse effect on Suncor's business, financial condition and results of operations.

Carbon Risk

Public support for climate change action and receptivity to alternative/renewable energy technologies has grown in recent years. Governments in Canada and around the world have responded to these shifting societal attitudes by adopting ambitious emissions reduction targets and supporting legislation, including measures relating to carbon pricing, clean energy and fuel standards, and alternative energy incentives and mandates. There has also been increased activism and public opposition to fossil fuels, and oil sands in particular. Refer to the Industry Conditions – Environmental Regulation – Climate Change section of this AIF.

Existing and future laws and regulations may impose significant liabilities on a failure to comply with their requirements. Concerns over climate change, fossil fuel extraction, GHG emissions, and water and land-use practices could lead governments to enact additional or more stringent laws and regulations applicable to Suncor and other companies in the energy industry in general, and in the oil sands industry in particular.

Changes to environmental regulations, including regulation relating to climate change, could impact the demand for, formulation or quality of the company's products, or could require increased capital expenditures, operating expenses, abandonment and reclamation obligations and distribution costs, which may not be recoverable in the marketplace and which may result in current operations or growth projects becoming less profitable or uneconomic. In addition, such regulatory changes could necessitate that Suncor develop new technologies. Such technology development could require a significant investment of capital and resources, and any delay in or failure to identify and develop such technologies or obtain regulatory approvals for these technology projects could prevent Suncor from obtaining regulatory approvals for projects or being able to successfully compete with other companies. Increasing environmental regulation in the jurisdictions in which Suncor operates may also make it difficult for Suncor to compete with companies operating in other jurisdictions with fewer or less costly regulations. In addition, legislation or policies that limit the purchase of production from the oil sands may be adopted in domestic and/or foreign jurisdictions, which, in turn, may limit the world market for Suncor's upstream production and reduce the prices the company receives for its products, and could result in delayed development, stranded assets or the company being unable to further develop its resources. The complexity, breadth and velocity of changes in environmental regulation make it extremely difficult to predict the potential impact to Suncor.

Suncor continues to monitor the international and domestic efforts to address climate change. While it currently appears that GHG regulations and targets will continue to become more stringent, and while Suncor continues its efforts to reduce the intensity of its GHG emissions, the absolute GHG emissions of the company may rise as a result of growth. Increases in GHG emissions may impact the profitability of the company's projects, as Suncor will be subject to incremental levies and taxes. There is also a risk that Suncor could face litigation initiated by third parties relating to climate change, including litigation pertaining to GHG emissions, the production, sale, or promotion of fossil fuels and petroleum products, and/or disclosure. For example, the Board of County Commissioners of Boulder County, the Board of County Commissioners of San Miguel County and the City of Boulder, all of Colorado, have brought an action against Suncor and certain of its subsidiaries seeking, among other things, compensation for impacts they allege with respect to climate change. In addition, the mechanics of implementation and enforcement of the OSELA are currently under review and it is not yet possible to predict the impact

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on Suncor. However, such impact could be material. Refer to the Industry Conditions – Environmental Regulation – Climate Change – Canadian Provincial GHG Regulations (Alberta) section of this AIF.

These developments and future developments could adversely impact the demand for Suncor's products, the ability of Suncor to maintain and grow its production and reserves, and Suncor's reputation, and could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Environmental Compliance

Tailings Management and Water Release

Each oil sands mine is required under the Tailings Directive to seek approval for its updated fluid tailings management plans. If a mine fails to meet a condition of its approved plan, the applicable company could be subject to enforcement actions, including being required to curtail production, and financial consequences, including being subject to a compliance levy or being required to post additional security under the MFSP. The full impact of the TMF, the Tailings Directive and updates to the dam regulations including the financial consequences of exceeding compliance levels, is not yet fully known, as certain associated policy updates and regulation updates are still under development. Such updates could also restrict the technologies that the company may employ for tailings management, which could adversely impact the company's business plans. There could also be risks if the company's tailings management operations fail to operate as anticipated. The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations. Refer to the Industry Conditions – Environmental Regulation – Land Use and Dam Integrity section of this AIF.

In addition, an integrated water management approach to support operations and successful reclamation and closure requires the release of treated oil sands mine water to the environment, which is not currently permitted for oil sands mines under existing laws. There is no certainty as to when regulations authorizing such water release would be enacted, the content of any such regulations, and the ability of and timing for the company to obtain the required approvals under such regulations to permit such water release. The absence of effective government regulations in this area could impact the success and timing of closure and reclamation plans, which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Alberta's Land-Use Framework (LARP)

The implementation of, and compliance with, the terms of the LARP may adversely impact Suncor's current properties and projects in northern Alberta due to, among other things, environmental limits and thresholds. The impact of the LARP on Suncor's operations may be outside of the control of the company, as Suncor's operations could be impacted as a result of restrictions imposed due to the cumulative impact of development by the other operators in the area and not solely in relation to Suncor's direct impact. The uncertainty of changes in Suncor's future development and existing operations required as a result of the LARP could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Alberta Environment and Parks (AEP) Water Licences

Suncor currently relies on water obtained under licences from AEP to provide domestic and utility water for the company's Oil Sands business. Water licences, like all regulatory approvals, contain conditions to be met in order to maintain compliance with the licence. There can be no assurance that the licences to withdraw water will not be rescinded or that additional conditions will not be added. It is also possible that regional water management approaches may require water-sharing agreements between stakeholders. In addition, the expansion of the company's projects may rely on securing licences for additional water withdrawal, and there can be no assurance that these licences will be granted in a timely manner or that they will be granted on terms favourable to Suncor. There is also a risk that future laws or changes to existing laws or regulations relating to water access could cause capital expenditures and operating expenses relating to water licence compliance to increase. The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Species at Risk Act

Woodland caribou have been identified as "threatened" under the Species at Risk Act (Canada). In response to the Government of Canada's Recovery Strategy for Woodland Caribou, provincial caribou range plans are being developed. Suncor has existing, planned and potential future projects within caribou ranges in Alberta. The development and implementation of range plans in these areas may have an impact on the pace and amount of development in these areas and could potentially increase costs for restoration or offsetting requirements, which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Air Quality Management

A number of Canadian federal and provincial air quality regulations and frameworks are currently being developed, changed and/or implemented, which could have an impact on the company's existing and planned projects by requiring the company to invest additional capital or incur additional operating and compliance expenses, including, among other things, potentially requiring the company to retrofit

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equipment to meet new requirements and increase monitoring and mitigation plans. The full impact of these regulations and frameworks is not yet known; however, they could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Alberta Wetland Policy

Pursuant to the Alberta Wetland Policy, development in wetland areas may be obligated to avoid wetlands or mitigate the development's effects on wetlands. Although the full impact of the policy on Suncor is not yet fully known, certain Suncor operations and growth projects will be affected by aspects of the policy where avoidance is not possible and wetland reclamation or replacement may be required, which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Information Security

The efficient operation of Suncor's business is dependent on computer hardware, software and networked systems, including the systems of cloud providers and third parties with which Suncor conducts business. Digital transformation continues to increase the number of, and complexity of, such systems. In the ordinary course of Suncor's business, Suncor collects and stores sensitive data, including intellectual property, proprietary business information and personal information of the company's employees and retail customers. Suncor's operations are also dependent upon a large and complex information framework. Suncor relies on industry accepted security measures, controls and technology to protect Suncor's information systems and securely maintain confidential and proprietary information stored on the company's information systems, and has adopted a continuous process to identify, assess and manage threats to the company's information systems. While Suncor has an information and cyber security program in place, the measures, controls and technology on which the company relies may not be adequate due to the increasing volume, sophistication and rapidly evolving nature of cyber threats. Suncor's information technology and infrastructure, including process control systems, may be vulnerable to attacks by malicious persons or entities motivated by, among others, geopolitical, financial or activist reasons, or breached due to employee error, malfeasance or other disruptions, including natural disasters and acts of war. Any such attack or breach could compromise Suncor's networks, and the information Suncor stores could be accessed, publicly disclosed, lost, stolen or compromised. Any such attack, breach, access, disclosure or loss of information could result in legal claims or proceedings, liability under laws that protect the privacy of personal information, regulatory penalties, disruptions to Suncor's operations, decreased performance and production, increased costs, and damage to Suncor's reputation, physical harm to people or the environment or other negative consequences to Suncor or third parties, which could have a material adverse effect on Suncor's business, financial condition and results of operations. Although the company maintains a risk management program, which includes an insurance component that may provide coverage for the operational impacts from an attack to, or breach of, Suncor's information technology and infrastructure, including process control systems, the company does not maintain stand-alone cyber insurance. Furthermore, not all cyber risks are insurable. As a result, Suncor's existing insurance may not provide adequate coverage for losses stemming from a cyber attack to, or breach of, its information technology and infrastructure.

Security and Terrorist Threats

Security threats and terrorist or activist activities may impact Suncor's personnel, which could result in injury, death, extortion, hostage situations and/or kidnapping, including unlawful confinement. A security threat, terrorist attack or activist incident targeted at a facility or office owned or operated by Suncor could result in the interruption or cessation of key elements of Suncor's operations. Outcomes of such incidents could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Project Development and Execution

There are certain risks associated with the development and execution of Suncor's major projects and the commissioning and integration of new facilities within its existing asset base.

Project development and execution risk consists of four related primary risks:

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  Development – a failure to select the right projects and identify effective scope and solution;
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  Engineering – a failure in the specification, design or technology selection;
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  Construction – a failure to build the project in the approved time, in accordance with design, and at the agreed cost; and
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  Commissioning and startup – a failure of the facility to meet agreed performance targets, including operating costs, efficiency, yield and maintenance costs.

Project development and execution can also be impacted by, among other things:

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  The effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment, which could significantly impact the company's ability to obtain the necessary environmental and other regulatory approvals;
•
  The impact of general economic, business and market conditions and the company's ability to finance growth, including major growth projects in progress, if

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commodity prices were to decline and stay at low levels for an extended period;

•
  The complexity and diversity of Suncor's portfolio, including joint venture assets;
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  The accuracy of project cost and schedule estimates, as actual costs and schedules for major projects can vary from estimates, and these differences can be material;
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  The availability and cost of materials, equipment, qualified personnel, and logistics infrastructure, maintaining adequate quality management and risks associated with logistics and offshore fabrication, including the cost of materials, and equipment fabricated offshore may be impacted by tariffs, duties and quotas;
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  The inability or unwillingness of third-party vendors, contractors or service providers to provide materials, equipment, personnel and services of necessary quality in the timelines anticipated and at the agreed upon cost;
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  The complexities and uncertainties associated with identification, development and integration of new technologies into the company's existing and new assets;
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  Complexities and risks associated with constructing projects within operating environments and confined construction areas;
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  The commissioning and integration of new facilities within the company's existing asset base could cause delays in achieving guidance, targets and objectives;
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  Risks relating to restarting projects placed in safe mode, including increased capital costs; and
•
  The impact of weather conditions.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Technology Risk

There are risks associated with sustainability, growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations, including that the results of the application of new technologies may differ from simulated, test or pilot environments, or that third-party intellectual property protections may impede the development and implementation of new technology. The success of projects incorporating new technologies cannot be assured. Advantages accrue to companies that can develop and adopt emerging technologies in advance of competitors. The inability to develop, implement and monitor new technologies may impact the company's ability to develop its new or existing operations in a profitable manner or comply with regulatory requirements, which could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Cumulative Impact and Pace of Change

In order to achieve Suncor's business objectives, the company must operate efficiently, reliably and safely, and, at the same time, deliver growth and sustaining projects safely, on budget and on schedule. The ability to achieve these two sets of objectives is critically important for Suncor to deliver value to shareholders and stakeholders. These ambitious business objectives compete for resources, and may negatively impact the company should there be inadequate consideration of the cumulative impacts of prior and parallel initiatives on people, processes and systems. The establishment of the Transformation Management Office to support Suncor's digital transformation is expected to assist with the transformation, but there is still a risk that these objectives may exceed Suncor's capacity to adopt and implement change. The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Joint Arrangement Risk

Suncor has entered into joint arrangements and other contractual arrangements with third parties, including arrangements where other entities operate assets in which Suncor has ownership or other interests. These joint arrangements include, among others, those with respect to Syncrude, Fort Hills, In Situ assets, and operations in Suncor's E&P Canada and E&P International businesses. The success and timing of activities relating to assets and projects operated by others, or developed jointly with others, depend upon a number of factors that are outside of Suncor's control, including, among others, the timing and amount of capital expenditures, the timing and amount of operational and maintenance expenditures, the operator's expertise, financial resources and risk management practices, the approval of other participants, and the selection of technology.

These co-owners may have objectives and interests that do not coincide with and may conflict with Suncor's interests. Major capital decisions affecting joint arrangements may require agreement among the co-owners, while certain operational decisions may be made solely at the discretion of the operator of the applicable assets. While joint venture counterparties may generally seek consensus with respect to major decisions concerning the direction and operation of the assets and the development of projects, no assurance can be provided that the future demands or expectations of the parties relating to such assets and projects will be met satisfactorily or in a timely manner. Failure to satisfactorily meet demands or expectations by all of the parties may affect the company's participation in the operation of such assets or in the development of such projects, the company's ability to obtain or maintain necessary licences or approvals, or the timing for undertaking various activities. In addition, disputes may arise pertaining to the timing, scope, funding

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and/or capital commitments with respect to projects that are being jointly developed.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Financial Risks

Energy Trading and Risk Management Activities and the Exposure to Counterparties

The nature of Suncor's energy trading and risk management activities, which may make use of derivative financial instruments to manage its exposure to commodity price and other market risks, creates exposure to financial risks, which include, but are not limited to, the following:

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  Unfavourable movements in commodity prices, interest rates or foreign exchange could result in a financial or opportunity loss to the company;
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  A lack of counterparties, due to market conditions or other circumstances, could leave the company unable to liquidate or offset a position, or unable to do so at or near the previous market price;
•
  The company may not receive funds or instruments from counterparties at the expected time or at all;
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  The counterparty could fail to perform an obligation owed to Suncor;
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  Loss as a result of human error or deficiency in the company's systems or controls; and
•
  Loss as a result of contracts being unenforceable or transactions being inadequately documented.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition and results of operations.

Exchange Rate Fluctuations

The company's 2019 audited Consolidated Financial Statements are presented in Canadian dollars. The majority of Suncor's revenues from the sale of oil, natural gas and petroleum products are based on prices that are determined by, or referenced to, U.S. dollar benchmark prices, while the majority of Suncor's expenditures are realized in Canadian dollars. The company also owes a portion of its debt in U.S. dollars. Suncor's financial results, therefore, can be affected significantly by the exchange rates between the Canadian dollar and the U.S. dollar. The company also undertakes operations administered through international subsidiaries, and, therefore, to a lesser extent, Suncor's results can be affected by the exchange rates between the Canadian dollar and the euro, the British pound and the Norwegian krone. These exchange rates may vary substantially and may give rise to favourable or unfavourable foreign currency exposure. A decrease in the value of the Canadian dollar relative to the U.S. dollar will increase the revenues received from the sale of commodities. An increase in the value of the Canadian dollar relative to the U.S. dollar will decrease revenue received from the sale of commodities. A decrease in the value of the Canadian dollar relative to the U.S. dollar from the previous balance sheet date increases the amount of Canadian dollars required to settle U.S. dollar denominated obligations. As at December 31, 2019, the Canadian dollar strengthened in relation to the U.S. dollar to $0.77 from $0.73 at the start of 2019. Exchange rate fluctuations could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Interest Rate Risk

The company is exposed to fluctuations in short-term Canadian and U.S. interest rates as Suncor maintains a portion of its debt capacity in revolving and floating rate credit facilities and commercial paper, and invests surplus cash in short-term debt instruments and money market instruments. Suncor is also exposed to interest rate risk when debt instruments are maturing and require refinancing, or when new debt capital needs to be raised. The company is also exposed to changes in interest rates when derivative instruments are used to manage the debt portfolio, including hedges of prospective new debt issuances. Unfavourable changes in interest rates could have a material adverse effect on Suncor's business, financial condition and results of operations.

Issuance of Debt and Debt Covenants

Suncor expects that future capital expenditures will be financed out of cash and cash equivalents balances, cash flow provided by operating activities, available committed credit facilities, issuing commercial paper and accessing capital markets. This ability is dependent on, among other factors, commodity prices, the overall state of the capital markets, and financial institutions and investor appetite for investments in the energy industry generally, and the company's securities in particular. To the extent that external sources of capital become limited or unavailable or available on unfavourable terms, the ability to make capital investments and maintain existing properties may be constrained.

If the company finances capital expenditures in whole or in part with debt, that may increase its debt levels above industry standards for oil and gas companies of similar size. Depending on future development and growth plans, additional debt financing may be required that may not be available or, if available, may not be available on favourable terms, including higher interest rates and fees. Neither the articles of Suncor (the Articles) nor its by-laws limit the amount of indebtedness that may be incurred; however, Suncor is subject to covenants in its existing credit facilities and seeks to avoid an unfavourable cost of debt. The level of the company's indebtedness, from time to time, could impair

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its ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively affect its credit ratings.

Suncor is required to comply with financial and operating covenants under existing credit facilities and debt securities. Covenants are reviewed based on actual and forecast results and the company has the ability to make changes to its development plans, capital structure and/or dividend policy to comply with covenants under the credit facilities. If Suncor does not comply with the covenants under its credit facilities and debt securities, there is a risk that repayment could be accelerated and/or the company's access to capital could be restricted or only be available on unfavourable terms.

Rating agencies regularly evaluate the company, including its subsidiaries. Their ratings of Suncor's long-term and short-term debt are based on a number of factors, including the company's financial strength, as well as factors not entirely within its control, including conditions affecting the oil and gas industry generally, and the wider state of the economy. Credit ratings may be important to customers or counterparties when Suncor competes in certain markets and when it seeks to engage in certain transactions, including transactions involving over-the-counter derivatives. There is a risk that one or more of Suncor's credit ratings could be downgraded, which could potentially limit its access to private and public credit markets and increase the company's cost of borrowing.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Royalties and Taxes

Suncor is subject to royalties and taxes imposed by governments in numerous jurisdictions.

Royalties can be impacted by changes in crude oil and natural gas pricing, production volumes, and capital and operating costs, by changes to existing legislation or PSCs, and by results of regulatory audits of prior year filings and other such events. The final determination of these events may have a material impact on the company's royalties expense.

An increase in Suncor's royalties expense, income taxes, property taxes, carbon taxes, levies, tariffs, duties, quotas, border taxes, and other taxes and government-imposed compliance costs could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Dividends and Share Repurchases

Suncor's payment of future dividends on its common shares and future share repurchases by Suncor of its common shares will be dependent on, among other things, legislative and stock exchange requirements, the company's financial condition, results of operations, cash flow, the need for funds to finance ongoing operations and growth projects, debt covenants and other business considerations as the company's Board considers relevant. There can be no assurance that Suncor will continue to pay dividends or repurchase shares in the future.

E&P Reserves Replacement

Suncor's future offshore production, and therefore its cash flows and results of operations from E&P, are highly dependent upon success in exploiting its current reserves base and acquiring or discovering additional reserves. Without additions to its E&P reserves through exploration, acquisition or development activities, Suncor's production from its offshore assets will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent Suncor's cash flow is insufficient to fund capital expenditures and external sources of capital become limited or unavailable, Suncor's ability to make the necessary capital investments to maintain and expand its reserves will be impaired. In addition, Suncor may be unable to develop or acquire additional reserves to replace its crude oil and natural gas production at acceptable costs.

Uncertainties Affecting Reserves Estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the company's control. Suncor's actual production, revenues, royalties, taxes, and development and operating expenditures with respect to the company's reserves will vary from its estimates, and such variances could be material. Refer to the Statement of Reserves Data and Other Oil and Gas Information – Significant Risk Factors and Uncertainties Affecting Reserves section of this AIF.

Third-Party Service Providers

Suncor's businesses are reliant on the operational integrity of a large number of third-party service providers, including input and output commodity transport (pipelines, rail, trucking, marine) and utilities associated with various Suncor and jointly owned facilities, including electricity. A disruption in service or limited availability by one of these third parties can also have a dramatic impact on Suncor's operations and growth plans. Pipeline constraints that affect takeaway capacity or supply of inputs, such as hydrogen and power for example, could impact the company's ability to produce at capacity levels. Disruptions in pipeline service could adversely affect commodity prices, Suncor's price realizations, refining operations and sales volumes, or limit the company's ability to produce and deliver production. These interruptions may be caused by the inability of the pipeline to operate or by the oversupply of feedstock into the system that exceeds pipeline capacity. Short-term operational constraints on pipeline systems arising from pipeline interruption and/or increased supply of crude oil have occurred in the past and could occur in the future. There is a risk that third-party

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outages could impact Suncor's production or price realizations, which could have a material adverse effect on Suncor's business, financial condition and results of operations.

Foreign Operations

The company has operations in a number of countries with different political, economic and social systems. As a result, the company's operations and related assets are subject to a number of risks and other uncertainties arising from foreign government sovereignty over the company's international operations, which may include, among other things:

•
  Currency restrictions and restrictions on repatriation of funds;
•
  Loss of revenue, property and equipment as a result of expropriation, nationalization, war, insurrection, and geopolitical and other political risks;
•
  Increases in taxes and government royalties;
•
  Compliance with existing and emerging anti-corruption laws, including the Foreign Corrupt Practices Act (United States), the Corruption of Foreign Public Officials Act (Canada) and the United Kingdom Bribery Act;
•
  Renegotiation of contracts with government entities and quasi-government agencies;
•
  Changes in laws and policies governing operations of foreign-based companies; and
•
  Economic and legal sanctions (such as restrictions against countries experiencing political violence, or countries that other governments may deem to sponsor terrorism).

If a dispute arises in the company's foreign operations, the company may be subject to the exclusive jurisdiction of foreign courts or may not be able to subject foreign persons to the jurisdiction of a court in Canada or the U.S. In addition, as a result of activities in these areas and a continuing evolution of an international framework for corporate responsibility and accountability for international crimes, there is a risk the company could also be exposed to potential claims for alleged breaches of international or local law.

The impact that future potential terrorist attacks, regional hostilities or political violence, such as that experienced in Libya and Syria, may have on the oil and gas industry, and on our operations in particular, is not known at this time. This uncertainty may affect operations in unpredictable ways, including disruptions of fuel supplies and markets, particularly crude oil, and the possibility that infrastructure facilities, including pipelines, production facilities, processing plants and refineries, could be direct targets of, or collateral damage of, an act of terror, political violence or war. Suncor may be required to incur significant costs in the future to safeguard its assets against terrorist activities or to remediate potential damage to its facilities. There can be no assurance that Suncor will be successful in protecting itself against these risks and the related safety and financial consequences.

Despite Suncor's training and policies around bribery and other forms of corruption, there is a risk that Suncor, or some of its employees or contractors, could be charged with bribery or corruption. Any of these violations could result in onerous penalties. Even allegations of such behaviour could impair Suncor's ability to work with governments or non-government organizations and could result in the formal exclusion of Suncor from a country or area, sanctions, fines, project cancellations or delays, the inability to raise or borrow capital, reputational impacts and increased investor concern.

The occurrence of any of the foregoing could have a material adverse effect on Suncor's business, financial condition, reserves and results of operations.

Skills, Resource Shortage and Reliance on Key Personnel

The successful operation of Suncor's businesses and the company's ability to expand operations will depend upon the availability of, and competition for, skilled labour and materials supply. There is a risk that the company may have difficulty sourcing the required labour for current and future operations. The risk could manifest itself primarily through an inability to recruit new staff without a dilution of talent, to train, develop and retain high-quality and experienced staff without unacceptably high attrition, and to satisfy an employee's work/life balance and desire for competitive compensation. The labour market in Alberta has been historically tight, and, while the current economic situation has partially moderated this effect, it remains a risk to be managed. The increasing age of the company's existing workforce and changing skillsets as technology continues to evolve adds further pressure. The availability of competent and skilled contractors for current and future operations is also a risk depending on market conditions. Materials may also be in short supply due to smaller labour forces in many manufacturing operations. Suncor's ability to operate safely and effectively and complete all projects on time and on budget has the potential to be significantly impacted by these risks and this impact could be material.

The company's success also depends in large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the company. The contributions of the existing management team to the immediate and near-term operations of the company are likely to continue to be of central importance for the foreseeable future.

Labour Relations

Hourly employees at Suncor's oil sands facilities (excluding MacKay River), all of the company's refineries, and the majority of the company's terminal and distribution operations are represented by labour unions or employee

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associations. Approximately 31% of the company's employees were covered by collective agreements at the end of 2019. Negotiations for new collective agreements are in progress for two facilities across the company. Any work interruptions involving the company's employees (including as a result of a strike or lockout), contract trades utilized in the company's projects or operations, or any jointly owned facilities operated by another entity present a significant risk to the company and could have a material adverse effect on Suncor's business, financial condition and results of operations.

Land Claims and Indigenous Consultation

Indigenous Peoples have claimed Indigenous title and rights to portions of Western Canada. In addition, Indigenous Peoples have filed claims against industry participants relating in part to land claims, which may affect the company's business.

The requirement to consult with Indigenous Peoples in respect of oil and gas projects and related infrastructure has also increased in recent years. In addition, in recent years, the Canadian federal government and the provincial government in Alberta have made a commitment to renew their relationships with the Indigenous Peoples of Canada. The federal government has stated it now fully supports the United Nations Declaration on the Rights of Indigenous Peoples (the Declaration) without qualification and that Canada intends "nothing less than to adopt and implement the Declaration in accordance with the Canadian Constitution". At this time, it is unclear how the Declaration will be adopted into Canadian law and the impact of the Declaration on the Crown's duty to consult with Indigenous Peoples.

Suncor is unable to assess the effect, if any, that any such land claims, consultation requirements with Indigenous Peoples or adoption of the Declaration into Canadian law may have on Suncor's business; however, the impact may be material.

Litigation Risk

There is a risk that Suncor or entities in which it has an interest may be subject to litigation, and claims under such litigation may be material. Various types of claims may be raised in these proceedings, including, but not limited to, environmental damage, climate change and the impacts thereof, breach of contract, product liability, antitrust, bribery and other forms of corruption, tax, patent infringement, disclosure, employment matters and in relation to an attack, breach or unauthorized access to Suncor's information technology and infrastructure. Litigation is subject to uncertainty and it is possible that there could be material adverse developments in pending or future cases. Unfavourable outcomes or settlements of litigation could encourage the commencement of additional litigation. Suncor may also be subject to adverse publicity and reputational impacts associated with such matters, regardless of whether Suncor is ultimately found liable. There is a risk that the outcome of such litigation may be materially adverse to the company and/or the company may be required to incur significant expenses or devote significant resources in defence against such litigation, the success of which cannot be guaranteed.

Trade Risk Relating to CUSMA

If CUSMA is ratified, Canada will no longer be subject to the proportionality provisions in NAFTA's energy chapter, enabling Canada to expand oil and gas exports beyond the U.S. Further, a change to the oil and gas rules of origin under CUSMA will allow Canadian exporters to more easily qualify for duty-free treatment for shipments to the U.S. Canada must, however, notify the U.S. of its intention to enter into free trade talks with any "non-market economies" under CUSMA, which may include China or any other importers of Canadian oil and gas exports. Although CUSMA has been signed, Canada has yet to ratify CUSMA according to its legislative processes before it goes into effect and replaces NAFTA. The outcome of the ratification process in Canada is not complete and is therefore uncertain. If CUSMA is not ratified and adopted by all three countries, the sale and transportation of Suncor's products within North America could be affected in a manner which could negatively impact Suncor's business, financial condition and results from operations.

Control Environment

Based on their inherent limitations, disclosure controls and procedures and internal controls over financial reporting may not prevent or detect misstatements, and even those controls determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Failure to adequately prevent, detect and correct misstatements could have a material adverse effect on how Suncor's business, financial condition and results of operations are reported.

Insurance Coverage

Suncor maintains insurance coverage as part of its risk management program. However, such insurance may not provide comprehensive coverage in all circumstances, nor are all such risks insurable. The company self-insures some risks, and the company's insurance coverage does not cover all the costs arising out of the allocation of liabilities and risk of loss arising from Suncor operations.

Suncor's insurance policies are generally renewed on an annual basis and, depending on factors such as market conditions, the premiums, policy limits and/or deductibles for certain insurance policies can vary substantially. In some instances, certain insurance may become unavailable or available only for reduced amounts of coverage. Significantly increased costs could lead the company to decide to reduce,

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 69

or possibly eliminate, coverage. In addition, insurance is purchased from a number of third-party insurers, often in layered insurance arrangements, some of whom may discontinue providing insurance coverage for their own policy or strategic reasons. Should any of these insurers refuse to continue to provide insurance coverage, the company's overall risk exposure could be increased.

DIVIDENDS

The Board of Directors has established a practice of paying dividends on Suncor's common shares on a quarterly basis. Suncor reviews its ability to pay dividends from time to time with regard to legislative requirements, the company's financial position, financing requirements for growth, cash flow and other factors. The Board approved a quarterly dividend of $0.32 per common share in each quarter of 2017, a quarterly dividend of $0.36 per common share in each quarter of 2018 and a quarterly dividend of $0.42 per common share in each quarter of 2019. Dividends are paid subject to applicable law, if, as and when declared by the Board.

Year ended December 31 |  | 2019 |  | 2018 |  | 2017 |
Cash dividends per common share ($) |  | 1.68 |  | 1.44 |  | 1.28 |

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DESCRIPTION OF CAPITAL STRUCTURE

The company's authorized share capital is comprised of an unlimited number of common shares, an unlimited number of preferred shares issuable in series designated as senior preferred shares, and an unlimited number of preferred shares issuable in series designated as junior preferred shares.

As at December 31, 2019, there were 1,531,873,743 common shares issued and outstanding. To the knowledge of the Board of Directors and executive officers of Suncor, no person beneficially owns, or exercises control or direction over, securities carrying 10% or more of the voting rights attached to any class of voting securities of the company. The holders of common shares are entitled to attend all meetings of shareholders and vote at any such meeting on the basis of one vote for each common share held. Common shareholders are entitled to receive any dividend declared by the Board on the common shares and to participate in a distribution of the company's assets among its shareholders for the purpose of winding up its affairs. The holders of the common shares shall be entitled to share, on a pro rata basis, in all distributions of such assets.

Petro-Canada Public Participation Act

The Petro-Canada Public Participation Act requires that the Articles of Suncor include certain restrictions on the ownership and voting of voting shares of the company. The common shares of Suncor are voting shares. No person, together with associates of that person, may subscribe for, have transferred to that person, hold, beneficially own or control otherwise than by way of security only, or vote in the aggregate, voting shares of Suncor to which are attached more than 20% of the votes attached to all outstanding voting shares of Suncor. Additional restrictions include provisions for suspension of voting rights, forfeiture of dividends, prohibitions against share transfer, compulsory sale of shares, and redemption and suspension of other shareholder rights. The Board may at any time require holders of, or subscribers for, voting shares, and certain other persons, to furnish statutory declarations as to ownership of voting shares and certain other matters relevant to the enforcement of the restrictions. Suncor is prohibited from accepting any subscription for, and issuing or registering a transfer of, any voting shares if a contravention of the individual ownership restrictions results.

Suncor's Articles, as required by the Petro-Canada Public Participation Act, also include provisions requiring Suncor to maintain its head office in Calgary, Alberta; prohibiting Suncor from selling, transferring or otherwise disposing of all or substantially all of its assets in one transaction, or several related transactions, to any one person or group of associated persons, or to non-residents, other than by way of security only in connection with the financing of Suncor; and requiring Suncor to ensure (and to adopt, from time to time, policies describing the manner in which Suncor will fulfil the requirement to ensure) that any member of the public can, in either official language of Canada (English or French), communicate with and obtain available services from Suncor's head office and any other facilities where Suncor determines there is significant demand for communication with, and services from, that facility in that language.

Credit Ratings

The following information regarding the company's credit ratings is provided as it relates to the company's cost of funds and liquidity. In particular, the company's ability to access unsecured funding markets and to engage in certain collateralized business activities on a cost-effective basis is primarily dependent upon maintaining competitive credit ratings. A lowering of the company's credit rating may also have potentially adverse consequences for the company's funding capacity for growth projects or access to the capital markets, may affect the company's ability, and the cost, to enter into normal course derivative or hedging transactions and may require the company to post additional collateral under certain contracts.

The following table shows the ratings issued for Suncor Energy Inc. by the rating agencies noted herein as of February 26, 2020. The credit ratings are not recommendations to purchase, hold or sell the debt securities in as much as such ratings do not comment as to the market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely at any time by a rating agency in the future if, in its judgment, circumstances so warrant.

|  | Senior Unsecured(1) |  | Outlook |  | Canadian Commercial Paper Program |  | U.S. Commercial Paper Program |
Standard & Poor's (S&P) |  | A- |  | Stable |  | A-1 (low) |  | A-2 |
Dominion Bond Rating Service (DBRS) |  | A (low) |  | Stable |  | R-1 (low) |  | Not rated |
Moody's Investors Service (Moody's) |  | Baa1 |  | Stable |  | Not rated |  | P-2 |

(1)
  The Senior Unsecured debt of Suncor Energy Ventures Corporation, a wholly owned subsidiary of Suncor, which indirectly owns a 36.74% ownership in the Syncrude joint operation previously owned by COS (refer to Intercorporate Relationships), is rated A- (Stable) by S&P and Bal (Stable) by Moody's. DBRS does not issue a separate credit rating for Suncor Energy Ventures Corporation.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 71

S&P credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest quality. A rating of A by S&P is the third highest of 10 categories. An obligation rated A is somewhat more susceptible to the adverse effects of changes in circumstances and economic conditions than obligations in higher rated categories (AA or AAA); however, the obligor's capacity to meet its financial commitment on the obligation is still strong. The addition of a plus (+) or minus (-) designation after the rating indicates the relative standing within a particular rating category. S&P credit ratings on commercial paper are on a short-term debt rating scale that ranges from A-1 to D, representing the range of such securities rated from highest to lowest quality. A Canadian rating by S&P of A-1 (low) is the third highest of eight categories and a U.S. rating of A-2 is the second highest of six categories, indicating a slightly higher susceptibility to the adverse effects of changes in circumstances and economic conditions than obligations in higher categories; the obligor's capacity to meet its financial commitment on the obligation is satisfactory.

DBRS credit ratings on long-term debt are on a rating scale that ranges from AAA to D, representing the range of such securities rated from highest to lowest. A rating of A by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality, with the capacity for the payment of financial obligations being substantial, but of a lesser credit quality than an AA rating. Entities in the A category may be vulnerable to future events, but qualifying negative factors are considered manageable. All rating categories other than AAA and D also contain designations for (high) and (low). The assignment of a (high) or (low) designation within a rating category indicates relative standing within that category. The absence of either a (high) or (low) designation indicates the rating is in the middle of the category. DBRS's credit ratings on commercial paper are on a short-term debt rating scale that ranges from R-1 (high) to D, representing the range of such securities rated from highest to lowest quality. A rating of R-1 (low) by DBRS is the third highest of 10 categories and is assigned to debt securities considered to be of good credit quality. The capacity for the payment of short-term financial obligations as they fall due is substantial, with overall strength not as favourable as higher rating categories. Entities in this category may be vulnerable to future events, but qualifying negative factors are considered manageable. The R-1 and R-2 commercial paper categories are denoted by (high), (middle) and (low) designations.

Moody's credit ratings on long-term debt are on a rating scale that ranges from Aaa to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa by Moody's is the fourth highest of nine categories. Obligations rated Baa are judged to be medium grade and subject to moderate credit risk and, as such, may possess certain speculative characteristics. A rating of Ba by Moody's is the fifth highest of nine categories. Obligations rated Ba are judged to be speculative and are subject to substantial credit risk. For rating categories Aa through Caa, Moody's appends numerical modifiers 1, 2 or 3 to each generic rating classification. The modifier 1 indicates that the obligation ranks in the higher end of its generic rating category; the modifier 2 indicates a mid-range ranking; and the modifier 3 indicates a ranking in the lower end of that generic rating category. A rating of P-2 by Moody's for commercial paper is the second highest of four rating categories and indicates a strong ability to repay short-term debt obligations.

Suncor has paid each of S&P, DBRS and Moody's their customary fees in connection with the provision of the above ratings. Suncor has not made any payments to S&P, DBRS or Moody's in the past two years for services unrelated to the provision of such ratings.

72 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

MARKET FOR SECURITIES

Suncor's common shares are listed on the TSX in Canada and on the NYSE in the U.S. The price ranges and the volumes traded on the TSX for the year ended December 31, 2019 are as follows:

TSX

|  | Price Range (Cdn$) |  | Trading Volume |
|  | High |  | Low |  | (000s) |
2019 |  |  |  |  |  |  |
January |  | 43.28 |  | 37.28 |  | 81 482 |
February |  | 45.67 |  | 42.04 |  | 74 784 |
March |  | 46.50 |  | 43.18 |  | 102 392 |
April |  | 46.00 |  | 43.11 |  | 64 879 |
May |  | 44.38 |  | 40.78 |  | 78 464 |
June |  | 42.27 |  | 40.03 |  | 72 834 |
July |  | 42.77 |  | 37.54 |  | 56 307 |
August |  | 39.14 |  | 36.32 |  | 75 624 |
September |  | 43.34 |  | 37.56 |  | 95 063 |
October |  | 42.11 |  | 38.05 |  | 54 710 |
November |  | 42.99 |  | 39.16 |  | 78 455 |
December |  | 43.16 |  | 40.71 |  | 78 648 |

For information in respect of options to purchase common shares of Suncor and common shares issued upon the exercise of options, see the Share-Based Compensation note to the 2019 audited Consolidated Financial Statements, which is incorporated by reference into this AIF and available on SEDAR at www.sedar.com.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 73

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are directors of Suncor on the date hereof. The term of each director is from the date of the meeting at which he or she is elected or appointed until the next annual meeting of shareholders or until a successor is elected or appointed.

Name and Jurisdiction of Residence |  | Period Served and Independence |  | Biography |
Patricia M. Bedient(3)(4) Washington, U.S. |  | Director since 2016 Independent |  | Patricia Bedient retired as executive vice president of Weyerhaeuser Company (Weyerhaeuser), one of the world's largest integrated forest products companies, effective July 1, 2016. From 2007 until February 2016, she also served as chief financial officer. Prior to this, she held a variety of leadership roles in finance and strategic planning at Weyerhaeuser after joining the company in 2003. Before joining Weyerhaeuser, she spent 27 years with Arthur Andersen LLP and ultimately served as the managing partner for its Seattle office and partner in charge of the firm's forest products practice. Ms. Bedient serves on the board of directors of Alaska Air Group, Inc. and Park Hotels & Resorts Inc. and also serves on the Overlake Hospital Medical Center board of trustees, the Oregon State University board of trustees, and the University of Washington Foster School of Business advisory board. She achieved national recognition in 2012 when The Wall Street Journal named her one of the Top 25 CFOs in the United States. She is a member of the American Institute of CPAs and the Washington Society of CPAs. Ms. Bedient received her bachelor's degree in business administration, with concentrations in finance and accounting, from Oregon State University in 1975. |
Mel E. Benson(1)(2) Alberta, Canada |  | Director since 2000 Independent |  | Mel Benson is president of Mel E. Benson Management Services Inc., an international consulting firm working in various countries with a focus on First Nations and corporate negotiations and is currently a director at Tectonic Metals Inc., a mineral exploration company. Mr. Benson retired from Exxon International and Imperial Oil Canada in 2000 after a long career as an operations manager and senior member of project management. While based in Houston, Texas, Mr. Benson worked on international projects based in Africa and the former Soviet Union. Mr. Benson is a member of Beaver Lake Cree Nation, located in northeast Alberta. In 2015, Mr. Benson was inducted into the Aboriginal Business Hall of Fame and received the lifetime achievement award, and he has previously received the Indspire Award for Business. |

74 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

John D. Gass(1)(4) Florida, U.S. |  | Director since 2014 Independent |  | John Gass is former vice president, Chevron Corporation, a major integrated oil and gas company, and former president, Chevron Gas and Midstream, positions he held from 2003 until his retirement in 2012. He has extensive international experience, having served in a diverse series of operational positions in the oil and gas industry with increasing responsibility throughout his career. Mr. Gass serves as a director of Southwestern Energy Company. He is also a member of the advisory board for the Vanderbilt Eye Institute. Mr. Gass graduated from Vanderbilt University in Nashville, Tennessee, with a bachelor's degree in civil engineering. He also holds a master's degree in civil engineering from Tulane University in New Orleans, Louisiana. A resident of Florida, he is a member of the American Society of Civil Engineers and the Society of Petroleum Engineers. |
Dennis Houston(1)(2) Texas, U.S. |  | Director since 2018 Independent |  | Dennis Houston served as executive vice president of ExxonMobil Refining & Supply Company, chairman and president of ExxonMobil Sales & Supply LLC and chairman of Standard Tankers Bahamas Limited until his retirement in 2010. Prior to that, Mr. Houston held a variety of leadership and engineering roles in the midstream and downstream businesses in the ExxonMobil organization. Mr. Houston has approximately 40 years' experience in the oil and gas industry, including over 35 years with ExxonMobil and its related companies. Mr. Houston serves on the board of directors of Argus Media Limited and GasLog Ltd. Mr. Houston holds a bachelor's degree in chemical engineering from the University of Illinois and an honorary doctorate of public administration degree from Massachusetts Maritime Academy. Mr. Houston has served on a variety of advisory councils, including an appointment by President George H.W. Bush to the National Infrastructure Advisory Council, the Chemical Sciences Leadership Council at the University of Illinois and the Advisory Council – Center for Energy, Marine Transportation & Public Policy at Columbia University. Mr. Houston also serves on the Alexander S. Onassis Public Benefit Foundation board, is honorary consul to the Texas Region for the Principality of Liechtenstein and a board member for the American Bureau of Shipping Group of Companies. |

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 75

Mark Little Alberta, Canada |  | Director since 2019 Non-independent, management |  | Mark Little is president and chief executive officer of Suncor. He previously served as the company's president and chief operating officer before being appointed to his current position in May 2019. His past roles include serving as president of Suncor's upstream organization with responsibility for all of Suncor's operated and non-operated oil sands, in situ, conventional exploration and production assets worldwide, as well as executive vice president, Oil Sands and senior vice president, International and Offshore. Mr. Little was also senior vice president, Integration, following Suncor's merger with Petro-Canada and senior vice president, Strategic Growth and Energy Trading. In these roles, Mr. Little's accountabilities have spanned from operations in the Wood Buffalo region to operations in offshore East Coast Canada, the North Sea, and international onshore operations in Latin America, North Africa and the Near East, where he oversaw significant improvements in efficiency and performance, as well as portfolio growth. Before joining Suncor, Mr. Little led the development of oil sands projects for a major international energy company. His past experience also includes leadership roles in oil sands production and refining operations, strategic planning, environment, health and safety, and energy trading. Mr. Little has been active in industry and the community, serving as chair of the board of directors of Syncrude Canada and as a member of Energy Safety Canada until 2018. Mr. Little also was chair of the Oil Sands Safety Association prior to its merger into Energy Safety Canada. Having played an integral role in the signing of agreements with the Fort McKay and Mikisew Cree First Nations relating to Suncor's East Tank Farm, he has actively promoted the partnership as a model for future energy development with Indigenous communities. He is a current member of the Canadian Association of Petroleum Producers, where he also serves as a member of the Executive Committee and Oil Sands CEO Council. He has co-chaired the Canadian Council of Aboriginal Business' procurement initiative and is a past board member of Accenture Global Energy. Mr. Little holds degrees in both computer science from the University of Calgary and applied petroleum engineering technology from SAIT, and is a graduate of the advanced management program at Harvard Business School. |

76 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Brian MacDonald(3)(4) Florida, U.S. |  | Director since 2018 Independent |  | Brian MacDonald was the president and chief executive officer of CDK Global, Inc., a leading global provider of integrated information technology and digital marketing solutions to the automotive retail and adjacent industries from 2016 to November 2018. Prior to joining CDK Global, Inc., Mr. MacDonald served as chief executive officer and president of Hertz Equipment Rental Corporation, and served as interim chief executive officer of Hertz Corporation. Mr. MacDonald previously served as president and chief executive officer of ETP Holdco Corporation, an entity formed following Energy Transfer Partners' $5.3 billion acquisition of Sunoco Inc., where Mr. MacDonald had served as chairman, president and chief executive officer. He was the chief financial officer at Sunoco Inc. and held senior financial roles at Dell Inc. Prior to Dell Inc., Mr. MacDonald spent more than 13 years in several financial management roles at General Motors Corporation in North America, Asia and Europe. He previously served on the board of directors for ComputerSciences Corporation (now DXC Technology Company), Ally Financial Inc., Sunoco Inc., Sunoco Logistics L.P. and CDK LGlobal, Inc. Mr. MacDonald earned a MBA from McGill University and a bachelor's of science, with a concentration in chemistry, from Mount Allison University. |
Maureen McCaw(2)(3) Alberta, Canada |  | Director since 2004 (Petro-Canada 2004 to July 31, 2009) Independent |  | Maureen McCaw was most recently executive vice-president of Leger Marketing, Canada's largest privately held market research firm and formerly president of Criterion Research, a company she founded. Ms. McCaw currently serves as a director of the Francis Winspear Centre for Music and the Edmonton Symphony Orchestra and the Nature Conservancy of Canada. Ms. McCaw has previously served on a number of boards of directors including as chair of the CBC Pension Plan board of trustees, the Edmonton International Airport and the Edmonton Chamber of Commerce. Ms. Caw has also served on the board of directors of the Canadian Broadcasting Corporation. Ms. Caw holds a bachelor of arts degree in economics from the University of Alberta, completed Columbia Business School's executive program in financial accounting and earned an ICD.D certification from the Institute of Corporate Directors. |

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Lorraine Mitchelmore(2)(3) Alberta, Canada |  | Director since 2019 Independent |  | Lorraine Mitchelmore has over 30 years' international oil and gas industry experience. She most recently served as President and CEO for Field Upgrading, a private equity backed fuel upgrading technology company. Prior to Field Upgrading, she held progressively senior roles at Royal Dutch Shell. Ms. Mitchelmore joined Shell in 2002, becoming President and Country Chair of Shell Canada Limited in 2009. Prior to joining Shell, she worked with Petro-Canada, Chevron and BHP Petroleum in the upstream business units in a combination of technical, exploration & development, and commercial roles. Ms. Mitchelmore has been a director of the Bank of Montreal since 2015 and has served on the Boards of Shell Canada Limited, the Canada Advisory Board at Catalyst, Inc. and Trans Mountain Corporation. Ms. Mitchelmore holds a bachelor's of science in geophysics from Memorial University of Newfoundland, a master's of science in geophysics from the University of Melbourne, Australia and a MBA from Kingston Business School in London, England. |
Eira M. Thomas(1)(4) Chiswick, United Kingdom |  | Director since 2006 Independent |  | Eira Thomas is a Canadian geologist with over 25 years of experience in the Canadian diamond business. She is currently the chief executive officer and a director of Lucara Diamond Corp., a publicly traded diamond producing company. Previous roles include serving as chief executive officer and a director of Kaminak Gold Corporation, vice president of Aber Resources, now Dominion Diamond Corp., and as founder and CEO of Stornoway Diamond Corp. Ms. Thomas graduated from the University of Toronto with a bachelor of science degree. Her awards and recognition include: "Canada's Top 40 under 40" by the Caldwell Partners and Report on Business magazine; selected as one of "Top 100 Canada's Most Powerful Women"; and one of only four Canadians in 2008 to be named to the "Young Global Leaders" by the World Economic Forum. |
Michael M. Wilson Alberta, Canada |  | Director since 2014 Independent |  | Michael Wilson is former president and chief executive officer of Agrium Inc., a retail supplier of agricultural products and services and a wholesale producer and marketer of agricultural nutrients, a position he held from 2003 until his retirement in 2013. Prior thereto, he served as executive vice president and chief operating officer. Mr. Wilson has significant experience in the petrochemical industry, serving as president of Methanex Corporation, and holding various positions with increasing responsibility in North America and Asia with Dow Chemical Company. Mr. Wilson has a bachelor's degree in chemical engineering from the University of Waterloo and currently serves on the boards of Air Canada and Celestica Inc. |

(1)
  Human Resources and Compensation Committee
(2)
  Environment, Health, Safety and Sustainable Development Committee
(3)
  Audit Committee
(4)
  Governance Committee

78 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Executive Officers

The following individuals are the executive officers of Suncor:

Name |  | Jurisdiction of Residence |  | Office |
Mark Little |  | Alberta, Canada |  | President and Chief Executive Officer |
Alister Cowan |  | Alberta, Canada |  | Chief Financial Officer |
Bruno Francoeur |  | Alberta, Canada |  | Chief Transformation Officer |
Mike MacSween |  | Alberta, Canada |  | Executive Vice President, Upstream |
Steve Reynish |  | Alberta, Canada |  | Executive Vice President, Strategy & Operations Services |
Kris Smith |  | Alberta, Canada |  | Executive Vice President, Downstream |
Martha Hall Findlay(1) |  | Alberta, Canada |  | Chief Sustainability Officer |
Paul Gardner |  | Alberta, Canada |  | Chief People Officer |
Arlene Strom |  | Alberta, Canada |  | Chief Legal Officer and General Counsel |

(1)
  Effective January 6, 2020.

All executive officers have held positions with Suncor over the past five years with the exception of Martha Hall Findlay who, immediately prior to joining Suncor in 2019, was President and Chief Executive Officer of the Canada West Foundation.

As at February 21, 2020, the directors and executive officers of Suncor as a group beneficially owned, or controlled or directed, directly or indirectly, 398,419 common shares of Suncor, which represents 0.03% of the outstanding common shares of Suncor.

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

As at the date hereof, no director or executive officer of Suncor is or has been within the last 10 years a director, chief executive officer or chief financial officer of a company (including Suncor) that:

(a)
  was the subject of a cease trade or similar order, or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days, that was issued while the director or executive officer was acting in the capacity as director, chief executive officer or chief financial officer; or
(b)
  was subject to a cease trade order or similar order, or an order that denied the relevant company access to any exemption under securities legislation that was in effect for a period of more than 30 consecutive days, that was issued after the director or executive officer ceased to be a director, chief executive officer or chief financial officer and which resulted from an event that occurred while that person was acting in that capacity.

As at the date hereof, no director or executive officer of Suncor, or any of their respective personal holding companies, nor any shareholder holding a sufficient number of securities to affect materially the control of Suncor:

(a)
  is, or has been within the last 10 years, a director or executive officer of any company (including Suncor) that, while that person was acting in that capacity, or within a year of that person ceasing to act in that capacity, became bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than: (i) Mr. Benson, who was a director of Winalta Inc. (Winalta) when it obtained an order on April 26, 2010 from the Alberta Court of Queen's Bench providing for creditor protection under the Companies' Creditors Arrangement Act (Canada). A plan of arrangement for Winalta received court confirmation later that year, and Mr. Benson ceased to be a director of Winalta in May 2013, and (ii) Mr. Gass who was a director of Weatherford International plc (Weatherford) when it underwent a financial restructuring under chapter 11 of the U.S. Bankruptcy Code which was initiated on July 1, 2019. Mr. Gass ceased to be a director of Weatherford on December 13, 2019; or
(b)
  has, within the last 10 years, become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or become subject to or instituted any proceedings, arrangement or compromise with creditors, or had a receiver, receiver manager or trustee appointed to hold the assets of the director, executive officer or shareholder.

No director or executive officer of Suncor, or any of their respective personal holding companies, nor any shareholder holding a sufficient number of securities to affect materially the control of Suncor, has been subject to:

(a)
  any penalties or sanctions imposed by a court relating to securities legislation or by a securities regulatory authority or has entered into a settlement agreement with a securities regulatory authority; or
(b)
  any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 79

AUDIT COMMITTEE INFORMATION

The Audit Committee Mandate is attached as Schedule "A" to this AIF.

Composition of the Audit Committee

The Audit Committee is comprised of Ms. Bedient (Chair), Mr. MacDonald, Ms. McCaw and Ms. Mitchelmore. All members are independent and financially literate. The education and experience of each member that has led to the determination of financial literacy is described in the Directors and Executive Officers section of this AIF.

For the purpose of making appointments to the company's Audit Committee, and in addition to the independence requirements, all directors nominated to the Audit Committee must meet the test of financial literacy as determined in the judgment of the Board of Directors. Also, at least one director so nominated must meet the requirements of being an Audit Committee Financial Expert (as defined below) as determined in the judgment of the Board of Directors. The Audit Committee Financial Experts on the Audit Committee are Ms. Bedient and Mr. MacDonald.

Financial Literacy

Financial literacy can be generally defined as the ability to read and understand a balance sheet, an income statement and a cash flow statement. In assessing a potential appointee's level of financial literacy, the Board of Directors evaluates the totality of the individual's education and experience, including:

•
  The level of the person's accounting or financial education, including whether the person has earned an advanced degree in finance or accounting;
•
  Whether the person is a professional accountant, or the equivalent, in good standing, and the length of time that the person actively has practiced as a professional accountant, or the equivalent;
•
  Whether the person is certified or otherwise identified as having accounting or financial experience by a recognized private body that establishes and administers standards in respect of such expertise, whether that person is in good standing with the recognized private body, and the length of time that the person has been actively certified or identified as having this expertise;
•
  Whether the person has served as a principal financial officer, controller or principal accounting officer of a company that, at the time the person held such position, was required to file reports pursuant to securities laws and, if so, for how long;
•
  The person's specific duties while serving as a public accountant, auditor, principal financial officer, controller, principal accounting officer or position involving the performance of similar functions;
•
  The person's level of familiarity and experience with all applicable laws and regulations regarding the preparation of financial statements that must be included in reports filed under securities laws;
•
  The level and amount of the person's direct experience reviewing, preparing, auditing or analyzing financial statements that must be included in reports filed under provisions of securities laws;
•
  The person's past or current membership on one or more audit committees of companies that, at the time the person held such membership, were required to file reports pursuant to provisions of securities laws;
•
  The person's level of familiarity and experience with the use and analysis of financial statements of public companies; and
•
  Whether the person has any other relevant qualifications or experience that would assist him or her in understanding and evaluating the company's financial statements and other financial information and to make knowledgeable and thorough inquiries whether the financial statements fairly present the financial condition, results of operations and cash flows of the company in accordance with generally accepted accounting principles, and whether the financial statements and other financial information, taken together, fairly present the financial condition, results of operations and cash flows of the company.

Audit Committee Financial Expert

An "Audit Committee Financial Expert" means a person who, in the judgment of the Board of Directors, has the following attributes:

(a)
  an understanding of Canadian generally accepted accounting principles and financial statements;
(b)
  the ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves;
(c)
  experience preparing, auditing, analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Suncor's financial statements, or experience actively supervising one or more persons engaged in such activities;
(d)
  an understanding of internal controls and procedures for financial reporting; and
(e)
  an understanding of audit committee functions.

A person shall have acquired the attributes referred to in items (a) through (e) inclusive above through:

(a)
  education and experience as a principal financial officer, principal accounting officer, controller, public accountant

80 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

or auditor, or experience in one or more positions that involve the performance of similar functions;

(b)
  experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;
(c)
  experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or
(d)
  other relevant experience.

Audit Committee Pre-Approval Policies for Non-Audit Services

Suncor's Audit Committee has considered whether the provision of services other than audit services is compatible with maintaining the company's auditors' independence and has a policy governing the provision of these services. A copy of the company's policy relating to Audit Committee approval of fees paid to the company's auditors, in compliance with the Sarbanes-Oxley Act of 2002 and applicable Canadian securities laws, is attached as Schedule "B" to this AIF.

Fees Paid to Auditors

Fees paid or payable to the company's current auditors, KPMG LLP, in 2019 and to the company's predecessor auditors, PricewaterhouseCoopers LLP, in 2018 are as follows:

($ thousands) |  | 2019 |  | 2018 |
Audit Fees |  | 4 350 |  | 5 016 |
Audit-Related Fees |  | 410 |  | 449 |
Tax Fees |  | — |  | — |
All Other Fees |  | — |  | 15 |
Total |  | 4 760 |  | 5 480 |

Audit Fees were paid, or are payable, for professional services rendered by the auditors for the audit of Suncor's annual financial statements, or services provided in connection with statutory and regulatory filings or engagements. Audit-Related Fees were paid for professional services rendered by the auditors for the review of quarterly financial statements and for the preparation of reports on specified procedures as they relate to audits of joint arrangements and attest services not required by statute or regulation. All Other Fees were subscriptions to auditor-provided and supported tools. All services described beside the captions "Audit Fees", "Audit-Related Fees" and "All Other Fees" were approved by the Audit Committee in compliance with paragraph (c)(7)(i) of Rule 2-01 of Regulation S-X under the U.S. Securities and Exchange Act of 1934, as amended (the Exchange Act). None of the fees described above were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Regulation S-X under the Exchange Act.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 81

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings in respect of which Suncor is or was a party, or in respect of which any of the company's property is or was the subject during the year ended December 31, 2019, nor are there any such proceedings known by the company to be contemplated, that involve a claim for damages exceeding 10% of the company's current assets. In addition, there have not been any (a) penalties or sanctions imposed against the company by a court relating to securities legislation or by a securities regulatory authority during the year ended December 31, 2019, (b) any other penalties or sanctions imposed by a court or regulatory body against the company that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the company before a court relating to securities legislation or with a securities regulatory authority during the year ended December 31, 2019.

INTERESTS OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director or executive officer, or any associate or affiliate of these persons has, or has had, any material interest, direct or indirect, in any transaction or any proposed transaction that has materially affected, or is reasonably expected to materially affect, Suncor within the three most recently completed financial years or during the current financial year.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for Suncor's common shares is Computershare Trust Company of Canada at its principal offices in Calgary, Alberta, Montreal, Quebec, Toronto, Ontario and Vancouver, British Columbia, and Computershare Trust Company N.A. in Canton, Massachusetts, Jersey City, New Jersey and Louisville, Kentucky.

MATERIAL CONTRACTS

During the year ended December 31, 2019, Suncor did not enter into any contracts, nor are there any contracts still in effect, that are material to the company's business, other than contracts entered into in the ordinary course of business, which are not required to be filed by Section 12.2 of National Instrument 51-102 – Continuous Disclosure Obligations.

INTERESTS OF EXPERTS

Reserves contained in this AIF are based in part upon reports prepared by GLJ and Sproule, Suncor's independent qualified reserves evaluators. As at the date hereof, none of the partners, employees or consultants of GLJ as a group, through registered or beneficial interests, direct or indirect, held or are entitled to receive more than 1% of any class of Suncor's outstanding securities, including the securities of the company's associates and affiliates, and none of the partners, employees or consultants of Sproule, as a group, through registered or beneficial interests, direct or indirect, held or are entitled to receive more than 1% of any class of Suncor's outstanding securities, including the securities of the company's associates and affiliates.

Following the completion of a tender process in 2018, the Board (on the recommendation of the Audit Committee) approved the appointment of KPMG LLP as Suncor's auditor effective March 1, 2019. Pricewaterhouse Coopers LLP, the predecessor auditor, at the request of the company, resigned as auditor of the company effective March 1, 2019.

The company's independent auditors are KPMG LLP, Chartered Professional Accountants, who have issued an independent auditor's report dated February 26, 2020 in respect of the company's Consolidated Financial Statements, which comprise the Consolidated Balance Sheets as at December 31, 2019 and the Consolidated Statements of Comprehensive Income (Loss), Changes in Equity and Cash Flows for the year ended December 31, 2019, and the related notes, and the report on internal control over financial reporting as at December 31, 2019. KPMG LLP has advised that they are independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the United States Securities and Exchange Commission (SEC).

The company's predecessor independent auditors were Pricewaterhouse Coopers LLP, who were the auditors for the company for the year ended December 31, 2018. As of February 28, 2019 and throughout the period covered by the financial statements upon which they reported, PricewaterhouseCoopers LLP were independent with respect to the company within the meaning of the Rules of Professional Conduct of the Chartered Professional Accountants of Alberta and the rules of the SEC.

82 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NYSE

As a Canadian issuer listed on the NYSE, Suncor is not required to comply with most of the NYSE's governance rules and instead may comply with Canadian requirements. As a foreign private issuer, the company is only required to comply with four of the NYSE's governance rules. These rules provide that (i) Suncor must have an audit committee that satisfies the requirements of Rule 10A-3 under the Exchange Act; (ii) the Chief Executive Officer of Suncor must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE rules; (iii) Suncor must provide a brief description of any significant differences between the company's corporate governance practices and those followed by U.S. companies listed under the NYSE; and (iv) Suncor must provide annual and, as required, written affirmations of compliance with applicable NYSE Corporate Governance Standards.

The company has disclosed in its 2020 management proxy circular, which is available on Suncor's website at www.suncor.com, significant areas in which the company does not comply with the NYSE Corporate Governance Standards. In certain instances, it is not required to obtain shareholder approval for material amendments to equity compensation plans under TSX requirements, while the NYSE requires shareholder approval of all equity compensation plans. Suncor, while in compliance with the independence requirements of applicable securities laws in Canada (specifically National Instrument 52-110 – Audit Committees) and the U.S. (specifically Rule 10A-3 of the Exchange Act), has not adopted, and is not required to adopt, the director independence standards contained in Section 303A.02 of the NYSE's Listed Company Manual, including with respect to its audit committee and compensation committee. The Board has not adopted, nor is it required to adopt, procedures to implement Section 303A.05(c)(iv) of the NYSE's Listed Company Manual in respect of compensation committee advisor independence. Except as described herein, the company is in compliance with the NYSE Corporate Governance Standards in all other significant respects.

ADDITIONAL INFORMATION

Additional information, including directors' and officers' remuneration and indebtedness, principal holders of Suncor's securities, and securities authorized for issuance under equity compensation plans, where applicable, is contained in the company's most recent management proxy circular for the most recent annual meeting of shareholders that involved the election of directors. Additional financial information is provided in Suncor's 2019 audited Consolidated Financial Statements and in the MD&A.

Further information about Suncor, filed with Canadian securities commissions and the SEC, including periodic quarterly and annual reports and the Form 40-F, is available online on SEDAR at www.sedar.com and on EDGAR at www.sec.gov. In addition, Suncor's Standards of Business Conduct Code is available online at www.suncor.com. Information contained in or otherwise accessible through the company's website does not form part of this AIF, and is not incorporated into the AIF by reference.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 83

ADVISORY – FORWARD-LOOKING INFORMATION
AND NON-GAAP FINANCIAL MEASURES

This AIF contains certain forward-looking statements and forward-looking information (collectively, forward-looking statements) within the meaning of applicable Canadian and U.S. securities laws and other information based on Suncor's current expectations, estimates, projections and assumptions that were made by the company in light of information available at the time the statement was made and consider Suncor's experience and its perception of historical trends, including expectations and assumptions concerning: the accuracy of reserves and resources estimates; commodity prices and interest and foreign exchange rates; the performance of assets and equipment; capital efficiencies and cost-savings; applicable laws and government policies; future production rates; the sufficiency of budgeted capital expenditures in carrying out planned activities; the availability and cost of labour, services and infrastructure; the satisfaction by third parties of their obligations to Suncor; the development and execution of projects; and the receipt, in a timely manner, of regulatory and third-party approvals. All statements and information that address expectations or projections about the future, and statements and information about Suncor's strategy for growth, expected and future expenditures or investment decisions, commodity prices, costs, schedules, production volumes, operating and financial results, future financing and capital activities, and the expected impact of future commitments are forward-looking statements. Some of the forward-looking statements may be identified by words like "expects", "anticipates", "will", "estimates", "plans", "scheduled", "intends", "believes", "projects", "indicates", "could", "focus", "vision", "goal", "outlook", "proposed", "target", "objective", "continue", "should", "may", "potential", "future", "opportunity", "would", "forecast" and similar expressions.

Forward-looking statements in this AIF include references to:

Suncor's strategy, business plans and expectations about projects, the performance of assets, production volumes, and capital expenditures, including:

•
  Expectations about the West White Rose Project, including the expectation that it will extend the life of the existing White Rose assets, the company's estimated share of peak oil production of 20 mbbls/d, the expectation that major development activity will continue in 2020, that first oil is targeted for the end of 2022, and the expectation of an update from the project operator in the first half of 2020;
•
  Expectations about Oda, including proposed development plans and that peak production is expected to reach 35 mbbls/d (11 mbbls/d, net to Suncor);
•
  Expectations about the Forty Mile Wind Power Project, including the expectation that it will drive value through low-carbon power generation and retention of the generated carbon credits, the estimated total capital spend of $300 million with an expected completion date of late 2021 and the expectation that the first phase will consist of 45 4.5 MW wind turbines;
•
  Expectations about Hebron, including the expectation that, at peak, the project will produce 31.6 mbbls/d (net to Suncor) and the expectation that drilling activities will continue throughout 2020;
•
  Expectations about Suncor's coke-fired boiler replacement program, including the expectation that it will provide reliable steam generation, the expectation that it will reduce the GHG emissions intensity associated with steam production at Oil Sands Base operations by approximately 25% and the expectation that the project will cost approximately $1.4 billion with an expected in-service date in the second half of 2023;
•
  Expectations regarding Suncor's multi-year strategic alliance with Microsoft, including the expectation that this alliance will enable Suncor to utilize Microsoft's full range of cloud solutions and the expected benefits of the alliance;
•
  Suncor's expectation that it will file a regulatory application within the first quarter of 2020 to potentially replace Suncor's Millennium and North Steepbank mines and that a final sanctioning decision for this project is not expected until 2030 at the earliest;
•
  The belief that the opportunities identified by Suncor could potentially add up to an additional 30 mbbls/d above nameplate capacity;
•
  Expectations about the Meadow Creek East project, including the expectation that the project will be developed in two stages and the anticipated gross production from the project of 40 mbbls/d up to 80 mbbls/d;
•
  Expectations about the Meadow Creek West project, including the expectation that the project will be developed in a single stage, anticipated gross production capacity of the project of 40 mbbls/d;
•
  Expectations about the Lewis project, including that the project is expected to be developed in stages, with anticipated peak production of 160 mbbls/d;
•
  Expectations about Syncrude, including the expectation that the Syncrude joint venture partners' plan to develop MLX-W and MLX-E which, subject to approvals, would extend the life of Mildred Lake by a minimum of 10 years, the expectation that the MLX-E program will follow MLX-W development, the expectation that the MLX-W program will sustain bitumen production levels at the Mildred Lake site after resource depletion at the North Mine, the plan to use existing mining and extraction facilities, the expectation that the remaining approvals will be obtained in 2020, efforts to achieve

84 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

sustained reliability improvements and reduce costs at Syncrude, the opportunity for cost management and collaboration between the company and Syncrude, expectations for the bi-directional interconnecting pipelines between Syncrude's Mildred Lake site and Suncor's Oil Sands Base, including that the pipelines will provide increased operational flexibility through the ability to transfer bitumen and gas oils between the two plants, enabling higher reliability and utilization, the expectation that the pipelines will be in-service by the second half of 2020, and the expectation that sustaining capital expenditures in 2020 at Syncrude will focus on a planned turnaround and reliability improvements;

•
  Expectations about Buzzard Phase 2, including that first oil is anticipated in early 2021, and that the development will be tied back to the existing Buzzard complex;
•
  Statements about the Terra Nova ALE, including the expectation that the project will extend the life of Terra Nova by approximately a decade, the timing of the project's execution and that the FPSO will be offline from April 2020 until approximately November 2020 while the ALE project is undertaken;
•
  Expectations about Rosebank, including timing of the sanction decision planned for 2022;
•
  Expectations about the Fenja development project, including the plan for development, first oil planned for 2021 and the expectation that peak production will be 34 mbbls/d (6 mbbls/d net to Suncor) and will be reached between 2021 and 2022;
•
  The estimated cost of Suncor's remaining exploration work program commitment in Libya at December 31, 2019 of US$359 million;
•
  Potential future wind and solar power projects;
•
  The potential for future in situ production to be supported at Meadow Creek, Lewis, OSLO and Chard;
•
  The expectation that turnaround maintenance will improve reliability and operational efficiency; and
•
  The expectation that capital investments with respect to Mining development activities will maintain the production capacity of existing facilities and reduce costs and that new well pairs and infill wells, at Firebag and MacKay River will maintain production levels in future years, as well as provide future growth.

Also:

•
  Expectations, goals and plans around technologies, including AHS, PASS, Zero-Impact Seismic and NAE, and expectations for the ISDF and partial upgrading;
•
  Statements about Suncor's reserves, including reserves volumes, estimates of future net revenues, commodity price forecasts, exchange and interest rate expectations, and production estimates;
•
  Significant development activities and costs anticipated to occur or be incurred in 2020, including those identified under the Future Development Costs table in the Statement of Reserves Data and Other Oil and Gas Information section of this AIF, Suncor's belief that internally generated cash flows, existing and future credit facilities, issuing commercial paper and accessing capital markets will be sufficient to fund future development costs and that interest expense or other funding costs on their own would not make development of any property uneconomic, plans for the development of reserves, and the estimated value of work commitments;
•
  Estimated abandonment and reclamations costs;
•
  The company's commitment to sustainability and to continuously optimize its asset portfolio and focus on core assets and ongoing balance sheet flexibility from the reduction of debt;
•
  Statements about Suncor's share repurchase program;
•
  Expectations about royalties and income taxes and their impact on Suncor;
•
  Expectations regarding tailings management plans and regulatory processes with respect thereto;
•
  Anticipated effects of and responses to environmental laws, including climate change laws, and Suncor's estimated compliance costs; and
•
  Expectations about changes to laws and the impact thereof.

Forward-looking statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor's actual results may differ materially from those expressed or implied by its forward-looking statements, so readers are cautioned not to place undue reliance on them.

The financial and operating performance of the company's reportable operating segments, specifically Oil Sands, Exploration and Production, and Refining and Marketing, may be affected by a number of factors.

Factors that affect Suncor's Oil Sands segment include, but are not limited to, volatility in the prices for crude oil and other production, and the related impacts of fluctuating light/heavy and sweet/sour crude oil differentials; changes in the demand for refinery feedstock and diesel fuel, including the possibility that refiners that process the company's proprietary production will be closed, experience equipment failure or other accidents; Suncor's ability to operate its Oil Sands facilities reliably in order to meet production targets; the output of newly commissioned facilities, the performance

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 85

of which may be difficult to predict during initial operations; Suncor's dependence on pipeline capacity and other logistical constraints, which may affect the company's ability to distribute products to market and which may cause the company to delay or cancel planned growth projects in the event of insufficient takeaway capacity; Suncor's ability to finance Oil Sands economic investment and asset sustainability and maintenance capital expenditures; the availability of bitumen feedstock for upgrading operations, which can be negatively affected by poor ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage, and in situ reservoir and equipment performance, or the unavailability of third-party bitumen; changes in operating costs, including the cost of labour, natural gas and other energy sources used in oil sands processes; and the company's ability to complete projects, including planned maintenance events, both on time and on budget, which could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on infrastructure in Alberta's Wood Buffalo region and the surrounding area (including housing, roads and schools).

Factors that affect Suncor's Exploration and Production segment include, but are not limited to, volatility in crude oil and natural gas prices; operational risks and uncertainties associated with oil and gas activities, including unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, uncontrollable flows of crude oil, natural gas or well fluids, and pollution and other environmental risks; adverse weather conditions, which could disrupt output from producing assets or impact drilling programs, resulting in increased costs and/or delays in bringing on new production; political, economic and socio-economic risks associated with Suncor's foreign operations, including the unpredictability of operating in Libya due to ongoing political unrest; and market demand for mineral rights and producing properties, potentially leading to losses on disposition or increased property acquisition costs.

Factors that affect Suncor's Refining and Marketing segment include, but are not limited to, fluctuations in demand and supply for refined products that impact the company's margins; market competition, including potential new market entrants; the company's ability to reliably operate refining and marketing facilities in order to meet production or sales targets; and risks and uncertainties affecting construction or planned maintenance schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.

Additional risks, uncertainties and other factors that could influence the financial and operating performance of all of Suncor's operating segments and activities include, but are not limited to, changes in general economic, market and business conditions, such as commodity prices, interest rates and currency exchange rates; fluctuations in supply and demand for Suncor's products; the successful and timely implementation of capital projects, including growth projects and regulatory projects; risks associated with the development and execution of Suncor's projects and the commissioning and integration of new facilities; the possibility that completed maintenance activities may not improve operational performance or the output of related facilities; the risk that projects and initiatives intended to achieve cash flow growth and/or reductions in operating costs may not achieve the expected results in the time anticipated or at all; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; labour and material shortages; actions by government authorities, including the imposition or reassessment of, or changes to, taxes, fees, royalties, duties, tariffs, quotas and other government-imposed compliance costs and mandatory production curtailment orders and changes thereto; changes to laws and government policies that could impact the company's business, including environmental (including climate change), royalty and tax laws and policies; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to the company; the unavailability of, or outages to, third-party infrastructure that could cause disruptions to production or prevent the company from being able to transport its products; the occurrence of a protracted operational outage, a major safety or environmental incident, or unexpected events such as fires (including forest fires), equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor; the potential for security breaches of Suncor's information technology and infrastructure by malicious persons or entities, and the unavailability or failure of such systems to perform as anticipated as a result of such breaches; security threats and terrorist or activist activities; the risk that competing business objectives may exceed Suncor's capacity to adopt and implement change; risks and uncertainties associated with obtaining regulatory, third-party and stakeholder approvals outside of Suncor's control for the company's operations, projects, initiatives, and exploration and development activities and the satisfaction of any conditions to approvals; the potential for disruptions to operations and construction projects as a result of Suncor's relationships with labour unions that represent employees at the company's facilities; the company's ability to find new oil and gas reserves that can be developed economically; the accuracy of Suncor's reserves, resources and future production estimates; market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates or to issue other securities at acceptable prices; maintaining an optimal debt to cash flow ratio; the success of the company's risk management activities using

86 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

derivatives and other financial instruments; the cost of compliance with current and future environmental laws, including climate change laws; risks relating to increased activism and public opposition to fossil fuels and oil sands; risks and uncertainties associated with closing a transaction for the purchase or sale of a business, asset or oil and gas property, including estimates of the final consideration to be paid or received; the ability of counterparties to comply with their obligations in a timely manner; risks associated with joint arrangements in which the company has an interest; risks associated with land claims and Indigenous consultation requirements; the risk that the company may be subject to litigation; the impact of technology and risks associated with developing and implementing new technologies; and the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering that is needed to reduce the margin of error and increase the level of accuracy. The foregoing important factors are not exhaustive.

Many of these risk factors and other assumptions related to Suncor's forward-looking statements are discussed in further detail throughout this AIF, including under the heading Risk Factors, and the company's MD&A dated February 26, 2020 and Form 40-F on file with Canadian securities commissions at www.sedar.com and the SEC at www.sec.gov. Readers are also referred to the risk factors and assumptions described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

The forward-looking statements contained in this AIF are made as of the date of this AIF. Except as required by applicable securities laws, we assume no obligation to update publicly or otherwise revise any forward-looking statements or the foregoing risks and assumptions affecting such forward-looking statements, whether as a result of new information, future events or otherwise.

Non-GAAP Financial Measures – Netback

Netback is a financial measure that is not prescribed by GAAP. Non-GAAP measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Netbacks are reconciled to GAAP measures in the Operating Metrics Reconciliation section of the Supplemental Financial and Operating Information within Suncor's Annual Report for the year ended December 31, 2019 and dated February 26, 2020.

Oil Sands Netbacks

Oil Sands operating netbacks are a non-GAAP measure, presented on a crude product and sales barrel basis, and are derived from the Oil Sands segmented statement of net earnings (loss), after adjusting for items not directly attributable to the revenues and costs associated with production and delivery. Management uses Oil Sands operating netbacks to measure crude product profitability on a sales barrel basis, and they may be useful to investors for the same reason.

Exploration and Production (E&P) Netbacks

E&P netbacks are a non-GAAP measure, presented on an asset location and sales barrel basis, and are derived from the E&P segmented statement of net earnings (loss), after adjusting for items not directly attributable to the costs associated with production and delivery. Management uses E&P operating netbacks to measure asset profitability by location on a sales barrel basis, and they may be useful to investors for the same reason.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. 87

SCHEDULE "A"
AUDIT COMMITTEE MANDATE

The Audit Committee

The by-laws of Suncor Energy Inc. provide that the Board of Directors may establish Board committees to whom certain duties may be delegated by the Board. The Board has established, among others, the Audit Committee, and has approved this mandate, which sets out the objectives, functions and responsibilities of the Audit Committee.

Objectives

The Audit Committee assists the Board by:

•
  monitoring the effectiveness and integrity of the Corporation's internal controls of Suncor's business processes, including: financial and management reporting systems, internal control systems;
•
  monitoring and reviewing financial reports and other financial matters;
•
  selecting, monitoring and reviewing the independence and effectiveness of, and where appropriate replacing, subject to shareholder approval as required by law, external auditors, and ensuring that external auditors are ultimately accountable to the Board of Directors and to the shareholders of the Corporation;
•
  reviewing the effectiveness of the internal auditors, excluding the Operations Integrity Audit department, which is specifically within the mandate of the Environment, Health & Safety Committee (references throughout this mandate to "Internal Audit" shall not include the Operations Integrity Audit department); and
•
  approving on behalf of the Board of Directors certain financial matters as delegated by the Board, including the matters outlined in this mandate.

The Committee does not have decision-making authority, except in the very limited circumstances described herein or where and to the extent that such authority is expressly delegated by the Board of Directors. The Committee conveys its findings and recommendations to the Board of Directors for consideration and, where required, decision by the Board of Directors.

Constitution

The Terms of Reference of Suncor's Board of Directors set out requirements for the composition of Board Committees and the qualifications for committee membership, and specify that the Chair and membership of the committees are determined annually by the Board. As required by Suncor's by-laws, unless otherwise determined by resolution of the Board of Directors, a majority of the members of a committee constitute a quorum for meetings of committees, and in all other respects, each committee determines its own rules of procedure.

Functions and Responsibilities

The Audit Committee has the following functions and responsibilities:

Internal Controls

1.
  Inquire as to the adequacy of the Corporation's system of internal controls of Suncor's business processes, and review the evaluation of internal controls by Internal Auditors, and the evaluation of financial and internal controls by external auditors.
2.
  Review audits conducted of the Corporation's Standards of Business Conduct-Compliance Program.
3.
  Establish procedures for the confidential submission by employees of complaints relating to any concerns with accounting, internal control, auditing or Standards of Business Conduct Code matters, and periodically review a summary of complaints and their related resolution.
4.
  Review the findings of any significant examination by regulatory agencies concerning the Corporation's financial matters.
5.
  Periodically review management's governance processes for information technology resources, to assess their effectiveness in addressing the integrity, the protection and the security of the Corporation's electronic information systems and records.
6.
  Review the management practices overseeing officers' expenses and perquisites.

External and Internal Auditors

7.
  Evaluate the performance of the external auditors and initiate and approve the engagement or termination of the external auditors, subject to shareholder approval as required by applicable law.
8.
  Review the audit scope and approach of the external auditors, and approve their terms of engagement and fees.
9.
  Review any relationships or services that may impact the objectivity and independence of the external auditor, including annual review of the auditor's written statement of all relationships between the auditor (including its affiliates) and the Corporation; review and approve all engagements for non-audit services to be provided by external auditors or their affiliates.
10.
  Review the external auditor's quality control procedures including any material issues raised by the most recent quality control review or peer review and any issues raised by a government authority or professional authority investigation of the external auditor, providing details on actions taken by the firm to address such issues.

A-1 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

11.
  Approve the appointment or termination of the VP Enterprise Risk and Audit, approve annually the performance assessment and resulting compensation of the VP Enterprise Risk & Audit as provided by the Chief Financial Officer. Periodically review the performance and effectiveness of the Internal Audit function including conformance with The Institute of Internal Auditors' International Standards for the Professional Practice of Internal Auditing and the Code of Ethics.
12.
  Approve the Internal Audit Department Charter, the annual Internal Audit schedule, as well as the Internal Audit budget and resource plan. Review the plans, activities, organizational structure, resource capacity and qualifications of the Internal Auditors, and monitor the department's independence.
13.
  Provide direct and unrestricted access by management, the Internal Auditors and the external auditors to the Board of Directors.

Financial Reporting and other Public Disclosure

14.
  Review the external auditor's management comment letter and management's responses thereto, and inquire as to any disagreements between management and external auditors or restrictions imposed by management on external auditors. Review any unadjusted differences brought to the attention of management by the external auditor and the resolution thereof.
15.
  Review with management and the external auditors the financial materials and other disclosure documents referred to in paragraph 16, including any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material to financial reporting including alternative treatments and their impacts.
16.
  Review and approve the Corporation's interim consolidated financial statements and accompanying management's discussion and analysis ("MD&A"). Review and make recommendations to the Board of Directors on approval of the Corporation's annual audited financial statements and MD&A, Annual Information Form and Form 40-F. Review other material annual and quarterly disclosure documents or regulatory filings containing or accompanying audited or unaudited financial information.
17.
  Authorize any changes to the categories of documents and information requiring audit committee review or approval prior to external disclosure, as set out in the Corporation's policy on external communication and disclosure of material information.
18.
  Review any change in the Corporation's accounting policies.
19.
  Review with legal counsel any legal matters having a significant impact on the financial reports.

Oil and Gas Reserves

20.
  Review with reasonable frequency Suncor's procedures for:
  (A)
    the disclosure, in accordance with applicable law, of information with respect to Suncor's oil and gas activities including procedures for complying with applicable disclosure requirements;
  (B)
    providing information to the qualified reserves evaluators ("Evaluators") engaged annually by Suncor to evaluate Suncor's reserves data for the purpose of public disclosure of such data in accordance with applicable law.
21.
  Annually approve the appointment and terms of engagement of the Evaluators, including the qualifications and independence of the Evaluators; review and approve any proposed change in the appointment of the Evaluators, and the reasons for such proposed change including whether there have been disputes between the Evaluators and management.
22.
  Annually review Suncor's reserves data and the report of the Evaluators thereon; annually review and make recommendations to the Board of Directors on the approval of (i) the content and filing by the Company of a statement of reserves data ("Statement") and the report thereon of management and the directors to be included in or filed with the Statement, and (ii) the filing of the report of the Evaluators to be included in or filed with the Statement, all in accordance with applicable law.

Risk Management

23.
  Periodically review the policies and practices of the Corporation respecting cash management, financial derivatives, financing, credit, insurance, taxation, commodities trading and related matters. Oversee the Board's risk management governance model and processes by conducting periodic reviews with the objective of appropriately reflecting the principal risks of the Corporation's business in the mandate of the Board and its committees. Conduct periodic review and provide oversight on the specific Suncor Principal Risks which have been delegated to the Committee for oversight.

Pension Plan

24.
  Review the assets, financial performance, funding status, investment strategy and actuarial reports of the Corporation's pension plan including the terms of engagement of the plan's actuary and fund manager.

Security

25.
  Review on a summary basis any significant physical security management and strategies to address such risks.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. A-2

Other Matters

26.
  Conduct any independent investigations into any matters which come under its scope of responsibilities.
27.
  Review any recommended appointees to the office of Chief Financial Officer.
28.
  Review and/or approve other financial matters delegated specifically to it by the Board of Directors.

Reporting to the Board

29.
  Report to the Board of Directors on the activities of the Audit Committee with respect to the foregoing matters as required at each Board meeting and at any other time deemed appropriate by the Committee or upon request of the Board of Directors.

Approved by resolution of the Board of Directors on November 14, 2017

A-3 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

SCHEDULE "B" – SUNCOR ENERGY INC. POLICY AND PROCEDURES
FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES

Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-110, the Securities and Exchange Commission and the Ontario Securities Commission respectively has adopted final rules relating to audit committees and auditor independence. These rules require the Audit Committee of Suncor Energy Inc. ("Suncor") to be responsible for the appointment, compensation, retention and oversight of the work of its independent auditor. The Audit Committee must also pre-approve any audit and non-audit services performed by the independent auditor or such services must be entered into pursuant to pre-approval policies and procedures established by the Audit Committee pursuant to this policy.

I. Statement of Policy

The Audit Committee has adopted this Policy and Procedures for Pre-Approval of Audit and Non-Audit Services (the "Policy"), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor will be pre-approved. The procedures outlined in this Policy are applicable to all Audit, Audit-Related, Tax Services and All Other Services provided by the independent auditor.

II. Responsibility

Responsibility for the implementation of this Policy rests with the Audit Committee. The Audit Committee delegates its responsibility for administration of this policy to management. The Audit Committee shall not delegate its responsibilities to pre-approve services performed by the independent auditor to management.

III. Definitions

For the purpose of these policies and procedures and any pre-approvals:

(a)
  "Audit services" include services that are a necessary part of the annual audit process and any activity that is a necessary procedure used by the auditor in reaching an opinion on the financial statements as is required under generally accepted auditing standards ("GAAS"), including technical reviews to reach audit judgment on accounting standards;
The
  term "audit services" is broader than those services strictly required to perform an audit pursuant to GAAS and include such services as:
  (i)
    the issuance of comfort letters and consents in connections with offerings of securities;
  (ii)
    the performance of domestic and foreign statutory audits;
  (iii)
    Attest services required by statute or regulation;
  (iv)
    Internal control reviews; and
  (v)
    Assistance with and review of documents filed with the Canadian Securities administrators, the Securities and Exchange Commission and other regulators having jurisdiction over Suncor and its subsidiaries, and responding to comments from such regulators;
(b)
  "Audit-related services" are assurance (e.g. due diligence services) and related services traditionally performed by the external auditors and that are reasonably related to the performance of the audit or review of financial statements and not categorized under "audit fees" for disclosure purposes.

"Audit-related services" include:

(i)
  employee benefit plan audits, including audits of employee pension plans;
(ii)
  due diligence related to mergers and acquisitions;
(iii)
  consultations and audits in connection with acquisitions, including evaluating the accounting treatment for proposed transactions;
(iv)
  internal control reviews;
(v)
  attest services not required by statute or regulation; and
(vi)
  consultations regarding financial accounting and reporting standards.

Non-financial operational audits are not "audit-related" services.

(c)
  "Tax services" include, but are not limited to, services related to the preparation of corporate and/or personal tax filings, tax due diligence as it pertains to mergers, acquisitions and/or divestitures, and tax planning;
(d)
  "All other services" consist of any other work that is neither an Audit service, nor an Audit-Related service nor a Tax service, the provision of which by the independent auditor is not expressly prohibited by Rule 2-01(c)(7) of Regulation S-X under the Securities and Exchange Act of 1934, as amended. (See Appendix A for a summary of the prohibited services.)

IV. General Policy

The following general policy applies to all services provided by the independent auditor.

•
  All services to be provided by the independent auditor will require specific pre-approval by the Audit Committee. The Audit Committee will not approve engaging the independent auditor for services which can reasonably be classified as "tax services" or "all other services" unless a compelling business case can be made for retaining the independent auditor instead of another service provider.
•
  The Audit Committee will not provide pre-approval for services to be provided in excess of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period.
•
  The Audit Committee has delegated authority to pre-approve services with an estimated cost not exceeding $100,000 in accordance with this Policy to the Chairman of the Audit Committee. The delegate member of the Audit Committee must report any pre-approval decision to the Audit Committee at its next meeting.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. B-1

•
  The Chairman of the Audit Committee may delegate his authority to pre-approve services to another sitting member of the Audit Committee provided that the recipient has also been delegated the authority to act as Chairman of the Audit Committee in the Chairman's absence. A resolution of the Audit Committee is required to evidence the Chairman's delegation of authority to another Audit Committee member under this policy.
•
  The Audit Committee will, from time to time, but no less than annually, review and pre-approve the services that may be provided by the independent auditor.
•
  The Audit Committee must establish pre-approval fee levels for services provided by the independent auditor on an annual basis. On at least a quarterly basis, the Audit Committee will be provided with a detailed summary of fees paid to the independent auditor and the nature of the services provided, and a forecast of fees and services that are expected to be provided during the remainder of the fiscal year.
•
  The Audit Committee will not approve engaging the independent auditor to provide any prohibited non-audit services as set forth in Appendix A.
•
  The Audit Committee shall evidence their pre-approval for services to be provided by the independent auditor as follows:
  (a)
    In situations where the Chairman of the Audit Committee pre-approves work under his delegation of authority, the Chairman will evidence his pre-approval by signing and dating the pre-approval request form, attached as Appendix B. If it is not practicable for the Chairman to complete the form and transmit it to the Company prior to engagement of the independent audit, the Chairman may provide verbal or email approval of the engagement, followed up by completion of the request form at the first practical opportunity.
  (b)
    In all other situations, a resolution of the Audit Committee is required.
•
  All audit and non-audit services to be provided by the independent auditors shall be provided pursuant to an engagement letter that shall:
  (a)
    be in writing and signed by the auditors;
  (b)
    specify the particular services to be provided;
  (c)
    specify the period in which the services will be performed;
  (d)
    specify the estimated total fees to be paid, which shall not exceed the estimated total fees approved by the Audit Committee pursuant to these procedures, prior to application of the 10% overrun;
  (e)
    include a confirmation by the auditors that the services are not within a category of services the provision of which would impair their independence under applicable law and Canadian and U.S. generally accepted accounting standards.
•
  The Audit Committee pre-approval permits an overrun of fees pertaining to a particular engagement of no greater than 10% of the estimate identified in the associated engagement letter. The intent of the overrun authorization is to ensure on an interim basis only, that services can continue pending a review of the fee estimate, and, if required, further Audit Committee approval of the overrun. If an overrun is expected to exceed the 10% threshold, as soon as the overrun is identified, the Audit Committee or its designate must be notified and an additional pre-approval obtained prior to the engagement continuing.

V. Responsibilities of External Auditors

To support the independence process, the independent auditors will:

(a)
  Confirm in each engagement letter that performance of the work will not impair independence;
(b)
  Satisfy the Audit Committee that they have in place comprehensive internal policies and processes to ensure adherence, world-wide, to independence requirements, including robust monitoring and communications;
(c)
  Provide communication and confirmation to the Audit Committee regarding independence on at least a quarterly basis;
(d)
  Maintain registration by the Canadian Public Accountability Board and the U.S. Public Company Accounting Oversight Board; and
(e)
  Review their partner rotation plan and advise the Audit Committee on an annual basis.

In addition, the external auditors will:

(f)
  Provide regular, detailed fee reporting including balances in the "Work in Progress" account;
(g)
  Monitor fees and notify the Audit Committee as soon as a potential overrun is identified.

VI. Disclosures

Suncor will, as required by applicable law, annually disclose its pre-approval policies and procedures, and will provide the required disclosure concerning the amounts of audit fees, audit-related fees, tax fees and all other fees paid to its outside auditors in its filings with the SEC.

Approved and Accepted April 28, 2004

B-2 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

Appendix A – Prohibited Non-Audit Services

An external auditor is not independent if, at any point during the audit and professional engagement period, the auditor provides the following non-audit services to an audit client.

Bookkeeping or other services related to the accounting records or financial statements of the audit client. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:

•
  Maintaining or preparing the audit client's accounting records;
•
  Preparing Suncor's financial statements that are filed with the SEC or that form the basis of financial statements filed with the SEC; or
•
  Preparing or originating source data underlying Suncor's financial statements.

Financial information systems design and implementation. Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements, including:

•
  Directly or indirectly operating, or supervising the operation of, Suncor's information systems or managing Suncor's local area network; or
•
  Designing or implementing a hardware or software system that aggregates source data underlying the financial statements or generates information that is significant to Suncor's financial statements or other financial information systems taken as a whole.

Appraisal or valuation services, fairness opinions or contribution-in-kind reports. Any appraisal service, valuation service or any service involving a fairness opinion or contribution-in-kind report for Suncor, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Actuarial services. Any actuarially-oriented advisory service involving the determination of amounts recorded in the financial statements and related accounts for Suncor other than assisting Suncor in understanding the methods, models, assumptions, and inputs used in computing an amount, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Internal audit outsourcing services. Any internal audit service that has been outsourced by Suncor that relates to Suncor's internal accounting controls, financial systems or financial statements, unless it is reasonable to conclude that the result of these services will not be subject to audit procedures during an audit of Suncor's financial statements.

Management functions. Acting, temporarily or permanently, as a director, officer, or employee of Suncor, or performing any decision-making, supervisory, or ongoing monitoring function for Suncor.

Human resources. Any of the following:

•
  Searching for or seeking out prospective candidates for managerial, executive, or director positions;
•
  Engaging in psychological testing, or other formal testing or evaluation programs;
•
  Undertaking reference checks of prospective candidates for an executive or director position;
•
  Acting as a negotiator on Suncor's behalf, such as determining position, status or title, compensation, fringe benefits, or other conditions of employment; or
•
  Recommending, or advising Suncor to hire a specific candidate for a specific job (except that an accounting firm may, upon request by Suncor, interview candidates and advise Suncor on the candidate's competence for financial accounting, administrative, or control positions).

Broker-dealer, investment adviser or investment banking services. Acting as a broker-dealer (registered or unregistered), promoter, or underwriter, on behalf of Suncor, making investment decisions on behalf of Suncor or otherwise having discretionary authority over Suncor's investments, executing a transaction to buy or sell Suncor's investment, or having custody of Suncor's assets, such as taking temporary possession of securities purchased by Suncor.

Legal services. Providing any service to Suncor that, under circumstances in which the service is provided, could be provided only by someone licenced, admitted, or otherwise qualified to practice law in the jurisdiction in which the service is prohibited.

Expert services unrelated to the audit. Providing an expert opinion or other expert service for Suncor, or Suncor's legal representative, for the purpose of advocating Suncor's interest in litigation or in a regulatory or administrative proceeding or investigation. In any litigation or regulatory or administrative proceeding or investigation, an accountant's independence shall not be deemed to be impaired if the accountant provides factual accounts, including testimony, of work performed or explains the positions taken or conclusions reached during the performance of any service provided by the accountant for Suncor.

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. B-3

Appendix B – Pre-Approval Request Form

NATURE OF WORK |  | ESTIMATED FEES (Cdn$)
Total |  |

Date |  | Signature

B-4 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

SCHEDULE "C" – FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the board of directors of Suncor Energy Inc. (the "Company"):

1.
  We have evaluated the Company's reserves data as at December 31, 2019. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs.
2.
  The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.
  Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
5.
  The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2019, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and board of directors:

Independent Qualified |  | Effective Date of |  | Location of Reserves (Country or Foreign |  | Net Present Value of Future Net Revenue (before income taxes, 10% discount rate, $ millions)
Reserves Evaluator |  | Evaluation Report |  | Geographic Area) |  | Audited |  | Evaluated |  | Reviewed |  | Total |
GLJ Petroleum Consultants Ltd. |  | December 31, 2019 |  | Oil Sands In Situ, Canada |  | — |  | 25 850 |  | — |  | 25 850 |
GLJ Petroleum Consultants Ltd. |  | December 31, 2019 |  | Oil Sands Mining, Canada |  | — |  | 26 297 |  | — |  | 26 297 |
|  |  |  |  |  | — |  | 52 147 |  | — |  | 52 147 |

6.
  In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
7.
  We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.
8.
  Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada, February 26, 2020

"Tim R. Freeborn"

Tim R. Freeborn, P.Eng.
Vice President and Chief Financial Officer

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. C-1

SCHEDULE "D" – FORM 51-101F2 REPORT ON RESERVES DATA BY
INDEPENDENT QUALIFIED RESERVES EVALUATOR OR AUDITOR

To the board of directors of Suncor Energy Inc. (the "Company"):

1.
  We have evaluated the Company's reserves data as at December 31, 2019. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2019, estimated using forecast prices and costs.
2.
  The reserves data are the responsibility of the Company's management. Our responsibility is to express an opinion on the reserves data based on our evaluation.
3.
  We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook as amended from time to time (the "COGE Handbook") maintained by the Society of Petroleum Evaluation Engineers (Calgary Chapter).
4.
  Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.
5.
  The following table shows the net present value of future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended December 31, 2019, and identifies the respective portions thereof that we have evaluated and reported on to the Company's management and board of directors:

Independent Qualified |  | Effective Date of |  | Location of Reserves (Country or Foreign |  | Net Present Value of Future Net Revenue (before income taxes, 10% discount rate, $ millions)
Reserves Evaluator |  | Evaluation Report |  | Geographic Area) |  | Audited |  | Evaluated |  | Reviewed |  | Total |
Sproule Associates Limited |  | December 31, 2019 |  | East Coast Canada, Newfoundland Offshore, Canada |  | — |  | 7 134 |  | — |  | 7 134 |
Sproule International Limited |  | December 31, 2019 |  | Offshore, United Kingdom |  | — |  | 2 956 |  | — |  | 2 956 |
Sproule International Limited |  | December 31, 2019 |  | Offshore, Norway |  | — |  | 760 |  | — |  | 760 |
|  |  |  |  |  | — |  | 10 849 |  | — |  | 10 849 |

6.
  In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, consistently applied. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.
7.
  We have no responsibility to update our reports referred to in paragraph 5 for events and circumstances occurring after the effective date of our reports.
8.
  Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

EXECUTED as to our report referred to above:

Sproule Associates Limited and Sproule International Limited, Calgary, Alberta, Canada, February 26, 2020

"Cameron P. Six"

Cameron P. Six, P.Eng.
Chief Executive Officer

D-1 2019 ANNUAL INFORMATION FORM Suncor Energy Inc.

SCHEDULE "E" – FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON RESERVES DATA AND OTHER INFORMATION

Management of Suncor Energy Inc. (the "Company") are responsible for the preparation and disclosure of information with respect to the Company's oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data.

Independent qualified reserves evaluators have evaluated the Company's reserves data. The reports of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

The Audit Committee of the board of directors of the Company has:

(a)
  reviewed the Company's procedures for providing information to the independent qualified reserves evaluators;
(b)
  met with the independent qualified reserves evaluators to determine whether any restrictions affected the ability of the independent qualified reserves evaluators to report without reservation; and
(c)
  reviewed the reserves data with management and the independent qualified reserves evaluators.

The Audit Committee of the board of directors has reviewed the Company's procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Audit Committee, approved:

(a)
  the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;
(b)
  the filing of Form 51-101F2 which is the report of the independent qualified reserves evaluators on the reserves data; and
(c)
  the content and filing of this report.

Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

"Mark S. Little"

MARK S. LITTLE
President and Chief Executive Officer

"Alister Cowan"

ALISTER COWAN
Chief Financial Officer

"Michael M. Wilson"

MICHAEL M. WILSON
Chair of the Board of Directors

"Patricia M. Bedient"

PATRICIA M. BEDIENT
Chair of the Audit Committee

February 26, 2020

2019 ANNUAL INFORMATION FORM Suncor Energy Inc. E-1

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking

Suncor Energy Inc. (the "Registrant") undertakes to make available, in person or by telephone, representatives to respond to inquiries made by the staff of the Securities and Exchange Commission ("SEC"), and to furnish promptly, when requested to do so by the SEC staff, information relating to the securities in relation to which the obligation to file an annual report on Form 40-F arises, or transactions in said securities.

B. Consent to Service of Process

The Registrant has filed previously with the SEC a Form F-X in connection with the Common Shares.

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING

See pages 81 and 82 of Exhibit 99-1 and page 70 of Exhibit 99-2.

ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM

See pages 83 and 84 and 85 and 86 of Exhibit 99-1.

AUDIT COMMITTEE FINANCIAL EXPERT

See pages 80 and 81 of Annual Information Form.

CODE OF ETHICS

See pages 24 and 25 of Annual Information Form.

FEES PAID TO PRINCIPAL ACCOUNTANT

See page 81 of Annual Information Form.

AUDIT COMMITTEE PRE-APPROVAL POLICIES

See Schedule "B" of Annual Information Form.

APPROVAL OF NON-AUDIT SERVICES

See Schedule "B" of Annual Information Form.

OFF-BALANCE SHEET ARRANGEMENTS

See page 53 of Exhibit 99-2.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

See page 53 of Exhibit 99-2.

IDENTIFICATION OF THE AUDIT COMMITTEE

See page 80 of Annual Information Form.

EXHIBIT INDEX

Exhibit No. |  | Description
--- | --- | ---
| 99-1 |  | Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2019
| 99-2 |  | Management's Discussion and Analysis for the fiscal year ended December 31, 2019, dated February 26, 2020
| 99-3 |  | Consent of KPMG LLP
| 99-4 |  | Consent of PricewaterhouseCoopers LLP
| 99-5 |  | Consent of GLJ Petroleum Consultants Ltd.
| 99-6 |  | Consent of Sproule Associates Limited and Sproule International Limited
| 99-7 |  | Certificate of the Chief Executive Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
| 99-8 |  | Certificate of the Chief Financial Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
| 99-9 |  | Certificate of the Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 99-10 |  | Certificate of the Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
| 99-11 |  | Supplementary Oil and Gas Disclosures
| 101 |  | Interactive data files with respect to the Annual Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2019

SIGNATURES

Pursuant to the requirements of the Exchange Act, the registrant certifies that it meets all of the requirements for filing on Form 40-F and has duly caused this annual report to be signed on its behalf by the undersigned, thereto duly authorized.

|  | SUNCOR ENERGY INC.
DATE: February 27, 2020 |  |  |  |
|  | PER: |  | /s/ ALISTER COWAN Alister Cowan Chief Financial Officer

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INCORPORATION BY REFERENCE
ANNUAL INFORMATION FORM
UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
ATTESTATION REPORT OF THE REGISTERED PUBLIC ACCOUNTING FIRM
AUDIT COMMITTEE FINANCIAL EXPERT
CODE OF ETHICS
FEES PAID TO PRINCIPAL ACCOUNTANT
AUDIT COMMITTEE PRE-APPROVAL POLICIES
APPROVAL OF NON-AUDIT SERVICES
OFF-BALANCE SHEET ARRANGEMENTS
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
IDENTIFICATION OF THE AUDIT COMMITTEE
EXHIBIT INDEX
SIGNATURES