QuickLinks -- Click here to rapidly navigate through this document

 

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, 2018
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:

  Name of each exchange on which
registered:

Common shares

 

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, 2018 there were
1,584,484,163 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 28, 2019, 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, 2018, 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








LOGO

    
ANNUAL
    INFORMATION
    FORM




    
Dated February 28, 2019
     













       
Suncor Energy Inc.































GRAPHIC









ANNUAL INFORMATION FORM DATED FEBRUARY 28, 2019

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

58   Risk Factors

68   Dividends

69   Description of Capital Structure

71   Market for Securities

72   Directors and Executive Officers

78   Audit Committee Information

80   Legal Proceedings and Regulatory Actions

80   Interests of Management and Others in Material Transactions

80   Transfer Agent and Registrar

80   Material Contracts

80   Interests of Experts

81   Disclosure Pursuant to the Requirements of the NYSE

81   Additional Information

82   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 2018 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.

References to the 2018 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, 2018. References to the MD&A mean Suncor's Management's Discussion and Analysis, dated February 28, 2019.

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.

2018 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.

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.

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

2  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


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 more paraffin is used, resulting in a higher quality bitumen that can be sold directly to market without further upgrading.

Production sharing contracts (PSC) 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.

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.

2018 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
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  2018 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 was owned 100%, directly or indirectly, by the company as at December 31, 2018, are as follows:

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 Suncor's upstream Canadian businesses is marketed. This subsidiary also administers Suncor's energy trading and power activities, markets certain third-party products, procures crude oil feedstock and natural gas for Suncor's downstream business, and procures and markets NGLs and LPG for Suncor's 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   This partnership 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 Suncor's U.S. refining and marketing operations are conducted.  

International operations          

Suncor Energy UK Limited   U.K.   A subsidiary through which the majority of Suncor's operations in the U.K. are conducted.  

The company's remaining subsidiaries each accounted for (i) less than 10% of the company's consolidated assets as at December 31, 2018, and (ii) less than 10% of the company's consolidated operating revenues for the fiscal year ended December 31, 2018. In aggregate, the remaining subsidiaries accounted for less than 20% of the company's consolidated assets as at December 31, 2018, and less than 20% of the company's consolidated operating revenues for the fiscal year ended December 31, 2018.

2018 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 and natural gas in Canada and internationally; the company transports and refines crude oil, and markets petroleum and petrochemical products primarily in Canada. The company also conducts energy trading activities focused principally on the marketing and trading of crude oil, natural gas, power and byproducts. Suncor also operates a renewable energy business as part of its overall portfolio of assets.

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 and either upgrades this production into SCO for refinery feedstock and diesel fuel, or blends the bitumen with diluent for direct sale to market. The Oil Sands segment is comprised of:

Oil Sands operations refer to Suncor's owned and operated mining, extraction, upgrading, in situ and related logistics 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, cogeneration units, energy and reclamation facilities.

In Situ operations include oil sands bitumen production from Firebag and MacKay River and supporting infrastructure, such as central processing facilities, cogeneration units, hot bitumen infrastructure – including insulated pipelines, diluent import lines and a cooling and blending facility – and associated storage assets such as Suncor's East Tank Farm (ETF) operations specific to In Situ. Production is either upgraded by Oil Sands Base, or blended with diluent and marketed directly to customers.

Fort Hills refers to Suncor's 54.11% interest in the Fort Hills mining project, where Suncor is the operator. During the first quarter of 2018, the company acquired an additional 1.05% interest in Fort Hills for consideration of $145 million, increasing its interest from its previous 53.06% as an outcome of the commercial settlement agreement reached among the Fort Hills partners in December 2017. The Fort Hills project includes the mine, primary and secondary extraction facilities, and supporting infrastructure. The ETF facility was expanded in July 2017 to support Fort Hills production. The expanded facilities that blend Fort Hills bitumen for Suncor and the other Fort Hills partners are described as the East Tank Farm Development (ETFD). On November 22, 2017, the company completed the disposition of a combined 49% ownership interest in the new ETFD to the Fort McKay First Nation and the Mikisew Cree First Nation through the creation of the Thebacha Limited Partnership.

Syncrude refers to Suncor's 58.74% working interest in the Syncrude joint operation in the Athabasca oil sands region. Syncrude consists of the Aurora and Mildred Lake mining and extraction operations, integrated upgrading facilities and the associated infrastructure for these assets – including utilities, energy and reclamation facilities. On February 23, 2018, Suncor acquired an additional 5% interest in Syncrude from Mocal Energy Limited (Mocal) for $923 million, increasing its interest from its previous 53.74%.

EXPLORATION AND PRODUCTION

Suncor's Exploration and Production (E&P) segment consists of offshore operations in Canada, the U.K. and Norway, 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, Suncor holds interests in several exploration licences and significant discovery licences offshore of Newfoundland and Labrador. E&P Canada previously included Suncor's northeast B.C. mineral landholdings; however, on March 23, 2018, the company completed the exchange of its northeast B.C. mineral landholdings, including associated production, along with additional cash consideration of $52 million with Canbriam Energy Inc. (Canbriam) for a 37% equity interest in the private natural gas company.

E&P International operations include Suncor's non-operated interests in Buzzard (29.89%), Golden Eagle Area Development (GEAD) (26.69%), the Rosebank future development project (40%), in which the company acquired an additional 10% interest during 2018 bringing Suncor's interest in the project to 40% from its

6  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


REFINING AND MARKETING

Suncor's Refining and Marketing segment consists of two primary operations:

Refining and Supply operations refine crude oil and intermediate feedstock into a broad range of petroleum and petrochemical products. Refining and Supply consists of:

Eastern North America operations include refineries located in Montreal, Quebec and Sarnia, Ontario.

Western North America operations include refineries located in Edmonton, Alberta and 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 in 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 Petro-Canada® and Sunoco® company-owned locations and branded-dealers, a nationwide commercial road transport network and a bulk sales channel in Canada, as well as through other retail stations and wholesale customers in Colorado and Wyoming.

CORPORATE, ENERGY TRADING AND ELIMINATIONS

The grouping Corporate, Energy Trading and Eliminations includes the company's investments in renewable energy projects, results related to energy marketing, supply and trading activities, and other activities not directly attributable to any other operating segment.

Renewable Energy investment activities include development, construction, and ownership of Suncor-operated and joint venture partner-operated renewable power facilities across Canada. This includes a portfolio of operating wind power facilities located in Alberta, Saskatchewan and Ontario, as well as a portfolio of optioned lands for future wind and solar power project development.

Energy Trading activities primarily involve the marketing, supply and trading of crude oil, natural gas, power and byproducts, and the use of midstream infrastructure and financial derivatives to optimize related trading strategies.

Corporate activities include stewardship of Suncor's debt and borrowing costs, expenses not allocated to the company's businesses, and the company's captive insurance activities that self-insure a portion of the company's asset base.

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.

Three-Year History

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

2016

Acquisition of Canadian Oil Sands Limited (COS). In the first quarter of 2016, Suncor acquired COS, which owned 36.74% of Syncrude. This acquisition has provided Suncor with an incremental 128,600 bbls/d of SCO production capacity through its additional ownership interest in Syncrude.

Acquisition of additional 5% interest in Syncrude. In June 2016, Suncor acquired an additional 5% interest in Syncrude from Murphy Oil Company Limited (Murphy), which added a further 17,500 bbls/d of SCO capacity, bringing Suncor's ownership interest in Syncrude at that time to 53.74%.

Completed a turnaround of the Upgrader 2 facilities. The first full turnaround of the Upgrader 2 facilities was completed since the company moved to a five-year cycle.

Executed an equity offering for net proceeds of $2.8 billion. The net proceeds were used to fund the acquisition of the additional 5% interest in Syncrude from Murphy and to reduce debt to provide ongoing balance sheet flexibility.

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  7


Oil Sands operations production returned safely to normal operating rates. Suncor's Oil Sands production, including Syncrude, was completely shut in during the forest fires in the Fort McMurray region. Suncor leveraged its capability to safely evacuate community members and workers from the region. No assets were damaged during the forest fires and operations subsequently returned to normal production rates by mid-July.

Purchased 30% participating interest in the Rosebank project. The Rosebank project is considered one of the largest remaining undeveloped resources in the U.K. North Sea. The project is expected to be complementary to Suncor's existing U.K. portfolio.

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). The sale of PCLI reinforced the company's commitment to continuously optimize its asset portfolio and focus on core assets.

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 at an average price of $42.61 per 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 20,000 bbls/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.

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, exceeding the company's target of 90%.

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 between May 4, 2018 and May 3, 2019. 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. 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. Subsequent to December 31, 2018, Suncor's Board of Directors approved a further share repurchase program of up to $2.0 billion.

Acquisition of additional 5% interest in Syncrude. On February 23, 2018, Suncor acquired an additional 5% interest in Syncrude from Mocal for $923 million, adding a further 17,500 bbls/d of SCO capacity and increasing the company's ownership interest to 58.74%.

Asset exchange with Canbriam. On March 23, 2018, Suncor completed the exchange of its northeast B.C. mineral landholdings, including associated production, along with additional cash consideration of $52 million for a 37% equity interest in Canbriam, a private natural gas company.

8  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


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 for acquisition costs of $70 million, plus interim settlements 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 project 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 continues to ramp up ahead of expectations, averaging 13.0 mbbls/d in 2018. At peak, Hebron is expected to produce 31.6 mbbls/d, net to Suncor.

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 COS with a coupon of 7.75%, originally scheduled to mature on May 15, 2019.

Syncrude bi-directional pipeline. During the fourth quarter of 2018, Suncor and its joint venture partners reached an agreement to build bi-directional interconnecting pipelines, which will connect Syncrude's Mildred Lake site and Suncor's Oil Sands Base plant. 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 operational by the end of 2020, subject to finalized commercial terms and regulatory approval.

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 technologies, offer a number of advantages over existing truck and shovel operations, including enhanced safety performance, better operating efficiency and lower operating costs. Implementation is planned at Millennium and Fort Hills over the next six years.

Government of Alberta Mandatory Production Curtailment. In December 2018, the Government of Alberta announced an overall production curtailment program which began on January 1, 2019. Suncor's estimate of the impact of the curtailment program on its business has been included in the company's production guidance for 2019 issued on December 14, 2018.

2018 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  
Upgrading  
Power and Steam Generation and Process Water Use  
Maintenance  
Reclamation  

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 2018, the company mined approximately 138 million tonnes of bitumen ore (2017 – 169 million tonnes) and processed an average of 259 mbbls/d of mined bitumen in its extraction facilities (2017 – 306 mbbls/d).

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

10  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.



hydrotreaters, two gas oil hydrotreaters, one diesel hydrotreater, and one kero hydrotreater.

During 2018, Suncor averaged 280 mbbls/d of upgraded (SCO and diesel) production net of the company's internal consumption (2017 – 318 mbbls/d), mainly sourced from bitumen provided by both Oil Sands Base and In Situ operations, as well as from bitumen froth production that was processed from Fort Hills in connection with testing the front end of the plant. The decrease in 2018 utilization compared to 2017 was primarily due to both planned and unplanned maintenance at Upgrader 2.

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  
Central Processing Facilities  
Power and Steam Generation  
Maintenance and Bitumen Supply  

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, 2018, Firebag had 15 well pads in operation, with 207 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 2018, Firebag exported approximately 287 MW of electricity to the Alberta power grid and Oil Sands Base plant. There are also 13 OTSGs at the site for additional steam generation.

During 2018, Firebag production averaged 204 mbbls/d (2017 – 182 mbbls/d) with a SOR of 2.7 (2017 – 2.7).

MacKay River

Production from Suncor's MacKay River operations commenced in 2002. As at December 31, 2018, MacKay River included seven well pads with 110 well pairs either producing or on initial steam injection. The MacKay River central processing facilities have debottlenecked bitumen processing capacity of 38 mbbls/d. TransCanada Energy Ltd. 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.

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  11


During 2018, MacKay River production averaged 36 mbbls/d (2017 – 31 mbbls/d) with a SOR of 2.9 (2017 – 3.1).

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 and Chard. Suncor holds a 100% working interest in Lewis, a 75% working interest in Meadow Creek, a 77.78% working interest in OSLO, and interests varying from 25% to 50% in Chard. 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. This approval is Suncor's first in situ development approval since Firebag. The project is expected to be developed in two stages with anticipated gross production of 40 mbbls/d up to 80 mbbls/d. Construction could begin as early as 2020, with first oil from the first phase expected as early as 2023.

In October 2017, Suncor submitted an application for the Meadow Creek West project to the AER. Meadow Creek West is expected to be developed in a single stage and has an anticipated gross production capacity of 40 mbbls/d. Construction is anticipated to begin in 2023, with first oil expected as early as 2025.

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. Construction could begin as early as 2024, with first oil expected as early as 2027.

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 project. The company's interest in Fort Hills increased from its previous 53.06% to 54.11% in the first quarter of 2018, pursuant to the agreement reached among the partners in December 2017 in connection with the resolution of their commercial dispute. Fort Hills began producing PFT bitumen from secondary extraction on January 27, 2018. The second and third trains of secondary extraction were subsequently completed in the first half of 2018 as per the original plan. Fort Hills achieved average utilization of 94% in the fourth quarter of 2018. Fort Hills has a nameplate capacity of 194 mbbls/d (gross) of bitumen (105 mbbls/d net to Suncor). During 2018, Suncor's share of Fort Hills production averaged 67.4 mbbls/d (2017 – nil) from approximately 38.9 million tonnes of bitumen ore mined (2017 – nil).

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). Suncor's interest in Syncrude increased during 2018 from its previous 53.74% to 58.74% as a result of the acquisition of Mocal's 5% interest. Syncrude began producing in 1978 and is operated by Syncrude Canada Ltd. (SCL). In 2006, SCL entered into a management services agreement with Imperial Oil Resources Limited (Imperial Oil) to provide business services. The project is located near Fort McMurray and includes mining operations at Mildred Lake and Aurora North. In 2012, the Syncrude joint venture 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), subject to final sanctioning and regulatory approvals, which would consequently extend the life of Mildred Lake by a minimum of 10 years. In 2015, a decision was made by the joint venture 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. Regulatory applications for these areas were submitted in 2014. A hearing with the AER and stakeholder groups began in early 2019. A decision by the AER is expected by mid-2019, with regulatory approvals expected to follow. Provided that economic conditions support such a project, sanctioning of MLX-W is expected in late 2019 or early 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. During the fourth quarter of 2018, Suncor and its joint venture partners reached an agreement to build bi-directional interconnecting

12  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.



pipelines, which will connect Syncrude's Mildred Lake site and Suncor's Oil Sands Base plant. 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 operational by the end of 2020, subject to finalized commercial terms and regulatory approval.

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 the following: freshwater capping, a composite tails mixture of fine tails and gypsum, and centrifuge technology that separates water from tailings. The updated tailings management plan for Syncrude Aurora North was approved by the AER in June 2018. The updated tailings management plan for Syncrude Mildred Lake is pending approval by the AER.

In 2018, Suncor's share of Syncrude production averaged 144.2 mbbls/d (2017 – 134.3 mbbls/d). Sustaining capital expenditures in 2019 for Syncrude are expected to focus on a planned turnaround and reliability improvements. Production in the third quarter of 2018 was significantly impacted by a site wide power outage that occurred late in the second quarter of 2018 and the staged return to service of the asset. Production at Syncrude returned to normal operating rates within the third quarter of 2018 following the required transformer repairs, accelerated planned maintenance and the planned upgrader turnaround.

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. On September 29, 2018, Suncor and the other working interest partners in Joslyn agreed to sell 100% of their respective working interests in the project to 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.

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 viability 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, the company began proceeding with the phased implementation of AHS at its operated mine sites. Full implementation was completed in 2018 at the North Steepbank mine, with implementation planned at Millennium and Fort Hills over the next six years. Autonomous haul trucks, which operate using GPS, wireless communication and perceptive technologies, have demonstrated an ability to maneuver safely, effectively and efficiently in Suncor's operating environment and offer a number of advantages over existing truck and shovel operations, including enhanced safety performance, better operating efficiency and lower operating costs. During 2018, the company moved a total of 387 million tonnes of ore and overburden 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 sequestration of fine tailings. The first pond, Pond 8B, commenced drainage using PASS technology in 2018.

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:

Electromagnetically Assisted Solvent Extraction (EASE) – This new method of in situ bitumen recovery uses radio frequency heating, in conjunction with a light hydrocarbon, with the goal of reducing energy, greenhouse gas (GHG) and water footprints. Testing of this technology will use Enhanced Solvent Extraction Incorporating Electromagnetic Heating (ESEIEH). The second phase of the pilot project began operations in the third quarter of 2015 and is expected to continue through 2019.

In Situ Demonstration Facility (ISDF) – The ISDF is expected to allow Suncor to test a suite of enhanced in situ technologies. This demonstration facility is intended to enable Suncor to accelerate the testing of in situ technologies that use a combination of injected light

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  13


Steam-Assisted Gravity Drainage Less Intensive Technology Enhanced (SAGD LITE) – Field trials are underway to evaluate new SAGD technologies such as non-condensable gas addition, where light hydrocarbons such as methane or other NGLs are added; solvent addition through a technology known as Expanding Solvent SAGD (ES-SAGD); flow control devices; and injection control devices. These technologies are expected to improve cost, SORs, ultimate recovery and productivity, while reducing water use and GHG emissions. Monitoring and evaluation will continue throughout 2019, including a commercial scale ES-SAGD pilot at Firebag.

Zero-Impact Seismic – Zero-Impact Seismic is a seismic technology that has the potential to reduce the surface disturbance of SAGD by up to 50% as it does not require cutlines. This has the potential to reduce impacts to wildlife habitats and reduce stress on caribou populations. The company is planning a commercial scale pilot for the 2019 to 2020 time frame.

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, which has the potential to eliminate tailings ponds while reducing costs and GHG emissions. The company is planning a commercial scale pilot for the 2021 to 2022 time frame.

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 2018 increased to 106 mbbls/d or 44% (2017 – 101 mbbls/d or 47%) of total in situ bitumen production.

    2018
  2017
   
 
Sales Volumes and Operating Revenues – Principal Products   mbbls/d   % operating
revenues
  mbbls/d   % operating
revenues
 

SCO and diesel (including Syncrude)   431.7   83   453.4   87  

Bitumen   191.3   15   110.6   12  

Byproducts and other operating revenues(1)   n/a   2   n/a   1  

    623.0       564.0      

(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, including Fort Hills, is gathered into Suncor's Fort McMurray facilities at the Athabasca Terminal, which is operated by Enbridge Inc. (Enbridge), or the ETF, 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.

To Cheecham, Alberta on the Enbridge Athabasca Pipeline or the Enbridge Wood Buffalo Pipeline. 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.

14  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


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 Athabasca Oil Sands Pipeline, which is operated by Pembina.

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 2018, Suncor incurred royalties at an average rate of 1% of gross revenue for Oil Sands Base (2017 – 1%) and at an average rate of 3% of gross revenue for Syncrude operations (2017 – 6%). 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 2018, Fort Hills incurred royalties at an average rate of 2% of gross revenue.

In 2018, Suncor incurred royalties for MacKay River, which is in the post-payout phase, at an average rate of 14% of gross revenue at the NRR (2017 – 2%), and royalties at an average rate of 5% of gross revenue for Firebag (2017 – 2%), 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 drilling will continue in 2019. As at December 31, 2018, there were 28 wells: 17 oil production wells, nine water injection wells and two gas injection wells.

In 2018, Suncor's share of Terra Nova production averaged 11.7 mbbls/d (2017 – 11.5 mbbls/d). Annual turnaround maintenance was completed at the Terra Nova facility in August 2018, which lasted approximately four weeks.

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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  15



facility reliability. Hibernia commenced production in November 1997. As at December 31, 2018, 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 2018, there were seven 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 2018, Suncor's share of Hibernia production averaged 22.1 mbbls/d (2017 – 28.5 mbbls/d). Production in 2018 was impacted by turnaround maintenance which lasted approximately five weeks and was completed in October.

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, 2018, there were 44 wells: 24 oil production wells, 16 water injection wells, three gas storage wells, and one gas injection well.

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 originally targeted for 2022; however, due to the delay in the tow-out schedule by one year, achieving this first oil date is uncertain. An update from the project operator is expected in the first half of 2019. 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 2019.

In 2018, Suncor's share of White Rose production averaged 6.6 mbbls/d (2017 – 11.4 mbbls/d). Turnaround maintenance was completed at White Rose in June 2018, 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. Return to normal production rates is expected to occur in a phased approach which began in January 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 2018, drilling activities continued at Hebron and will continue throughout 2019. In 2018, Suncor's share of production averaged 13.0 mbbls/d (2017 – 0.4 mbbls/d). As at December 31, 2018, there were seven wells: four oil production wells, one water injection well, one gas injection well, and one cuttings reinjection well.

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 three exploration licences offshore in this area.

North America Onshore

During 2018, Suncor completed an exchange of its northeast B.C. mineral landholdings, including associated production, along with additional cash consideration of $52 million to Canbriam for a 37% equity interest in the private natural gas company.

16  2018 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 2018. As at December 31, 2018, there were 47 wells: 33 oil and gas production wells and 14 water injection wells. In 2018, Suncor's share of Buzzard production averaged 34.2 mboe/d (2017 – 43.8 mboe/d). In 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, with production anticipated in early 2021. The development 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 GEAD co-owners also hold adjacent exploration licences and continue to explore the region. The facilities have gross production capacity of approximately 76 mboe/d (20 mboe/d net to Suncor). Drilling activities took place at GEAD during 2018. As at December 31, 2018, there were 20 wells: 15 oil and gas production wells and five water injection wells. In 2018, Suncor's share of GEAD production averaged 12.4 mboe/d (2017 – 19.6 mboe/d).

Rosebank

During 2018, the company acquired a further 10% interest in the Rosebank project, bringing the company's participating interest in the project to 40% from its previous 30%. This project, which was discovered in December 2004 and is operated by Equinor U.K. Limited (Equinor), 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.

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. The project was sanctioned in November 2016, and the field is being developed with a subsea template tied back to the Ula field. Drilling activities were completed in 2018 and first oil is planned for as early as the second quarter of 2019, with peak production expected to reach 35 mbbls/d (11 mbbls/d net to Suncor). Suncor's share of the post-sanction project cost estimate is approximately $270 million. As at December 31, 2018, there were three wells: two oil and gas 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 Royal Norwegian 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. Suncor's share of the post-sanction, post-acquisition project cost estimate is approximately $280 million.

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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  17



expire on December 31, 2032, but include an initial five-year extension through the end of 2037. Libya is a member of the Organization of Petroleum Exporting Countries (OPEC) and is subject to quotas that can affect the company's production in Libya.

Since 2013, production and liftings in Libya have been intermittent due to political unrest, and the remaining value of Suncor's assets in Libya was impaired in 2015. Suncor had production and liftings from some of its oilfields in 2018, but others remain shut in due to political unrest. The timing of a return to normal operations in Libya remains uncertain. As a result, the remaining value of Suncor's assets in Libya were written off in 2015.

The estimated cost of Suncor's remaining exploration work program commitment at December 31, 2018, is US$359 million. Suncor declared force majeure for all exploration commitments in Libya effective December 14, 2014, and this declaration remains in effect. Subsequent to the end of 2018, the company received $300 million in risk mitigation proceeds for its Libyan assets (approximately $260 million after-tax). 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 entitlement basis averaged 2.9 mbbls/d in 2018 (2017 – 4.5 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:

    2018
  2017
   
 
Sales Volumes   mboe/d   % operating
revenues
  mboe/d   % operating
revenues
 

E&P Canada                  

  Crude oil and NGLs   52.8   52   51.1   43  

  Natural gas   0.5     1.8    

E&P International                  

  Crude oil and NGLs(1)   48.7   47   66.5   56  

  Natural gas   0.8   1   1.4   1  

Total Exploration and Production                  

  Crude oil and NGLs   101.5   99   117.6   99  

  Natural gas   1.3   1   3.2   1  

(1)
E&P International crude oil and NGLs includes production volumes for Libya on an entitlement 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-

18  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


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.

Royalties

East Coast Canada

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 (gross revenue adjusted for eligible costs). Tier two is an additional 12.5% of net revenue. During 2018, Terra Nova royalties averaged 20% of gross revenue (2017 – 16%).

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; however, the HSEU is currently at the net royalty stage and is subject to a royalty of the greater of 5% of gross revenue or 30% of net revenue.

During 2018, Hibernia (including the HSEU) royalties and NPI combined to average 23% of gross revenue (2017 – 26%).

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 2018, total White Rose royalties averaged 7% of gross revenue (2017 – 9%).

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 2018, Hebron royalties averaged 1% of gross revenue (2017 – 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 124.1 mbbls/d in 2018 (2017 – 113.7 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 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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  19



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 372,000 metric tonnes in 2018 (2017 – 368,000 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 2018, the plant produced 402 million litres of ethanol (2017 – 408 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  2018 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, 2018 and 2017.

Average Daily Crude Throughput              Montreal
             Sarnia
             Edmonton
             Commerce City
 
(mbbls/d, except as noted)   2018   2017   2018   2017   2018   2017   2018   2017  

Sweet synthetic   8.9   7.9   29.7   23.0   50.1   52.1      

Sour synthetic       25.7   35.7   32.8   41.7   9.2   11.2  

Diluted bitumen   22.1   24.3       35.6   42.1   11.2   7.9  

Sweet conventional   90.0   86.7   3.1   1.4       65.7   66.3  

Sour conventional   9.2   6.8   19.4   20.7   4.7   0.7   13.4   12.8  

Total   130.2   125.7   77.9   80.7   123.2   136.5   99.5   98.3  

Utilization (%)   95   92   92   95   87   96   102   100  

Equity Crude Processed(1)   7.0   7.6   45.0   48.9   99.3   103.8   9.2   11.2  

(1)
Includes Suncor's upstream operations, including its working interest in Syncrude.
 
Refined Petroleum Production Yield Mix              Montreal
             Sarnia
             Edmonton
             Commerce City
 
(%)   2018   2017   2018   2017   2018   2017   2018   2017  

Gasoline   41   42   51   49   44   45   48   48  

Distillates   37   34   37   39   50   50   35   35  

Other   22   24   12   12   6   5   17   17  

Distribution Terminals and Pipelines

Suncor owns and operates 13 major refined product terminals across Canada (including terminals adjacent to refineries) and two 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.

Suncor has ownership interests in certain pipelines, including the following:

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, 2018, this network consisted of 1,528 outlets across Canada. 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 4.8 million litres per site in 2018 (2017 – 4.8 million litres) and attracted an estimated 17.9% share (2017 – 17.5%) of the national retail market.

Suncor's Colorado retail network consists of 44 owned or leased Shell™, Exxon™ or Mobil™ branded outlets. Suncor also has product supply agreements with 145 Shell®-branded sites in both Colorado and Wyoming, and with 49 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.

2018 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   2018   2017  

Retail Service Stations – Canada          

  Petro-Canada® branded   1 527   1 516  

  Sunoco® branded   1   1  

    1 528   1 517  

Retail Service Stations(1) – U.S.          

  Shell™ branded retail service stations – Colorado/Wyoming   180   196  

  Exxon™ branded retail service stations – Colorado   40   26  

  Mobil™ branded retail service stations – Colorado   18   10  

    238   232  

Wholesale Cardlock Sites – Canada          

  Petro-Canada®-branded cardlock sites (PETRO-PASS®)   307   305  

(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

    2018
  2017
   
 
Sales Volumes   mbbls/d   % operating
revenues
  mbbls/d   % operating
revenues
 

Gasoline (includes motor and aviation gasoline)                  

  Eastern North America   117.8       117.5      

  Western North America   127.8       125.4      

    245.6   47   242.9   46  

Distillates (includes diesel and heating oils, and aviation jet fuels)                  

  Eastern North America   95.8       86.8      

  Western North America   107.6       112.5      

    203.4   39   199.3   37  

Other (includes heavy fuel oil, asphalts, lubricants, petrochemicals, other)                  

  Eastern North America   52.7       62.4      

  Western North America   25.6       25.9      

    78.3   15   88.3   17  

    527.3       530.5      

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

22  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.



summer construction paving period. Suncor has the flexibility to modify refinery inputs and outputs to match production yields with anticipated product demands.

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

Other Suncor Businesses

Energy Trading

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

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

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 proposed Forty Mile Wind Power project located in southeast Alberta, on approximately 50,000 acres of private land, south and east of the town of Bow Island in the County of Forty Mile.

Suncor's wind power projects as at December 31, 2018:

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  

2018 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 of December 31   2018   2017  

Oil Sands(1)   6 289   6 196  

Exploration and Production   325   332  

Refining and Marketing   2 787   2 737  

Corporate, Energy Trading and Renewable Energy(2)   3 079   3 116  

Total   12 480   12 381  

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

(2)
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 32% or 4,216 of the company's employees were covered by collective agreements at the end of 2018. The company completed negotiations in 2018 and collective agreements are now in place with Teamsters Canada at the Burrard terminal and with Unifor for the ETFD. Negotiations are in progress for the 11 collective agreements, representing approximately 3,954 employees, set to expire in 2019, including: Oil Sands Base and Firebag, that represent approximately 3,056 employees; the Edmonton refinery; the Montreal refinery; the Commerce City refinery; the Burrard, Edmonton, London, Montreal and Oakville terminals; and Terra Nova.

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  2018 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 includes 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 Aboriginal Relations Policy, which affirms Suncor's desire to work in collaboration with Aboriginal Peoples to create shared value. The policy sets the foundation for a consistent approach to the company's relationships with Aboriginal 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 Aboriginal 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 Aboriginal 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 Aboriginal 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 ceremony highlights progress on safety 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 Aboriginal Relations Policy is available in Cree and Dene audio translations.

2018 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 28, 2019, with an effective date of December 31, 2018. 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 February 22, 2019.

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 22, 2019 (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 22, 2019 (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, hydro geology, 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  2018 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
Carbon Risk
Political Unrest
Abandonment and Reclamation costs
Government Action

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

2018 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, 2018
(forecast prices and costs)(2)

                      SCO(3)
                    Bitumen
              Light Crude &
            Medium Crude Oil(4)
              Conventional
            Natural Gas
                    Total

 

 

                  (mmbbls)

 

                  (mmbbls)

 

            (mmbbls)

 

            (bcfe)

 

                  (mmboe)

 

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Gross

 

Net

 

Proved Developed Producing                                          
  Mining   2 069   1 852   942   842           3 011   2 694  
  In Situ   180   160   118   104           298   264  
  E&P Canada           61   49       61   49  

Total Canada   2 249   2 011   1 059   947   61   49       3 370   3 007  

Offshore U.K. & Norway           43   43   1   1   43   43  

Total Proved Developed Producing   2 249   2 011   1 059   947   104   92   1   1   3 413   3 050  

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   548   453   653   532           1 201   985  
  E&P Canada           62   59       62   59  

Total Canada   548   453   653   532   62   59       1 263   1 044  

Offshore U.K. & Norway           8   8   13   13   10   10  

Total Proved Undeveloped   548   453   653   532   70   67   13   13   1 273   1 054  

Proved                                          
  Mining   2 069   1 852   942   842           3 011   2 694  
  In Situ   729   613   770   636           1 499   1 249  
  E&P Canada           123   108       123   108  

Total Canada   2 798   2 465   1 712   1 478   123   108       4 632   4 051  

Offshore U.K. & Norway           52   52   14   14   54   54  

Total Proved   2 798   2 465   1 712   1 478   174   159   14   14   4 686   4 105  

Probable                                          
  Mining   621   547   496   397           1 117   944  
  In Situ   1 175   923   387   284           1 562   1 207  
  E&P Canada           174   138       174   138  

Total Canada   1 796   1 469   883   681   174   138       2 853   2 288  

Offshore U.K. & Norway           37   37   17   17   40   40  

Total Probable   1 796   1 469   883   681   211   175   17   17   2 892   2 328  

Proved Plus Probable                                          
  Mining   2 690   2 398   1 438   1 239           4 128   3 638  
  In Situ   1 904   1 535   1 157   920           3 061   2 455  
  E&P Canada           297   246       297   246  

Total Canada   4 593   3 934   2 595   2 159   297   246       7 485   6 339  

Offshore U.K. & Norway           88   88   32   32   94   94  

Total Proved Plus Probable   4 593   3 934   2 595   2 159   385   334   32   32   7 579   6 433  

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

28  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


Reconciliation of Gross Reserves(1)
as at December 31, 2018
(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, 2017   2 134   608   2 741   929   581   1 510               3 062   1 189   4 251    

  Extensions & Improved Recovery(7)                                  

  Technical Revisions(8)   (11 ) (25 ) (36 ) 18   (94 ) (76 )             7   (120 ) (112 )  

  Discoveries(9)                                  

  Acquisitions(10)   73   38   112   19   10   29               92   48   140    

  Dispositions(11)                                  

  Economic Factors(12)                                  

  Production(13)   (127 )   (127 ) (24 )   (24 )             (151 )   (151 )  

December 31, 2018   2 069   621   2 690   942   496   1 438               3 011   1 117   4 128    

In Situ                                                                

December 31, 2017   751   1 216   1 967   805   342   1 147               1 557   1 558   3 114    

  Extensions & Improved Recovery(7)   1     1                     1     2    

  Technical Revisions(8)   9   (41 ) (32 ) 10   45   55               19   4   23    

  Discoveries(9)                                  

  Acquisitions(10)                                  

  Dispositions(11)                                  

  Economic Factors(12)                                  

  Production(13)   (33 )   (33 ) (45 )   (45 )             (78 )   (78 )  

December 31, 2018   729   1 175   1 904   770   387   1 157               1 499   1 562   3 061    

E&P Canada                                                                

December 31, 2017               98   227   326   21   6   28   102   228   330    

  Extensions & Improved Recovery(7)               2   2   5         2   2   5    

  Technical Revisions(8)               42   (56 ) (13 )       42   (56 ) (13 )  

  Discoveries(9)                                  

  Acquisitions(10)                                  

  Dispositions(11)                     20   6   27   3   1   4    

  Economic Factors(12)                                  

  Production(13)               (20 )   (20 ) (1 )   (1 ) (20 )   (20 )  

December 31, 2018               123   174   297         123   174   297    

Total Canada                                                                

December 31, 2017   2 885   1 823   4 708   1 734   923   2 657   98   227   326   21   6   28   4 721   2 975   7 696    

  Extensions & Improved Recovery(7)   1     1         2   2   5         4   3   6    

  Technical Revisions(8)   (2 ) (66 ) (68 ) 28   (50 ) (22 ) 42   (56 ) (13 )       68   (172 ) (103 )  

  Discoveries(9)                                  

  Acquisitions(10)   73   38   112   19   10   29               92   48   140    

  Dispositions(11)                     20   6   27   3   1   4    

  Economic Factors(12)                                  

  Production(13)   (160 )   (160 ) (69 )   (69 ) (20 )   (20 ) (1 )   (1 ) (249 )   (249 )  

December 31, 2018   2 798   1 796   4 593   1 712   883   2 595   123   174   297         4 632   2 853   7 485    

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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  29


Reconciliation of Gross Reserves(1) (continued)
as at December 31, 2018
(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, 2017               57   34   91   2   4   6   57   35   92    

  Extensions & Improved Recovery(7)               2   3   5   1   1   2   2   3   5    

  Technical Revisions(8)               3   (6 ) (3 ) 1   (1 )   3   (6 ) (3 )  

  Discoveries(9)                   1         1     1    

  Acquisitions(10)               6   5   11   12   14   26   8   7   15    

  Dispositions(11)                                  

  Economic Factors(12)               1     1         1     1    

  Production(13)               (17 )   (17 ) (2 )   (2 ) (17 )   (17 )  

December 31, 2018               52   37   88   14   17   32   54   40   94    

Other International (14)                                                                

December 31, 2017                                  

  Extensions & Improved Recovery(7)                                  

  Technical Revisions(8)               5     5         5     5    

  Discoveries(9)                                  

  Acquisitions(10)                                  

  Dispositions(11)                                  

  Economic Factors(12)                                  

  Production(13)(14)               (5 )   (5 )       (5 )   (5 )  

December 31, 2018                                  

Total                                                                

December 31, 2017   2 885   1 823   4 708   1 734   923   2 657   155   261   417   24   10   34   4 778   3 009   7 788    

  Extensions & Improved Recovery(7)   1     1         4   6   9   1   1   2   5   6   11    

  Technical Revisions(8)   (2 ) (66 ) (68 ) 28   (50 ) (22 ) 50   (61 ) (11 ) 1   (1 )   77   (178 ) (101 )  

  Discoveries(9)                   1         1     1    

  Acquisitions(10)   73   38   112   19   10   29   6   5   11   12   14   26   100   55   156    

  Dispositions(11)                     20   6   27   3   1   4    

  Economic Factors(12)               1     1         1     1    

  Production(13)   (160 )   (160 ) (69 )   (69 ) (42 )   (42 ) (3 )   (3 ) (272 )   (272 )  

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    

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

30  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


Notes to Reserves Data Tables
as at December 31, 2018

(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 15 mmbbls, Proved Undeveloped of 46 mmbbls, Proved of 61 mmbbls, Probable of 39 mmbbls and Proved Plus Probable of 100 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 14 mmbbls, Proved Undeveloped of 45 mmbbls, Proved of 59 mmbbls, Probable of 30 mmbbls and Proved Plus Probable of 90 mmbbls.

(5)
Light Crude & Medium Crude Oil Technical Revisions for E&P Canada include quantities of Heavy Crude Oil as follows: Proved of 29 mmbbls, Probable of (35) mmbbls and Proved Plus Probable of (5) mmbbls.

(6)
Conventional Natural Gas includes immaterial amounts of NGLs (0.7 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 2018 are primarily a result of E&P drilling activities.

(8)
Technical Revisions include changes in previous estimates resulting from new technical data or revised interpretations. Changes in 2018 are primarily due to new information obtained during the year, including drilling results and ongoing field performance, and the movement of a portion of E&P Canada volumes from Probable to Proved as a result of offshore drilling activity. 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. Additions in 2018 relate to GEAD within Offshore U.K. & Norway.

(10)
Acquisitions are additions to reserves estimates as a result of purchasing interests in oil and gas properties. Additions in 2018 within Mining relate to Suncor's acquisition of an additional 5% interest in Syncrude and an additional 1.05% interest in Fort Hills. Additions in 2018 within Offshore U.K. & Norway relate to the acquisition of a 17.5% interest in the Fenja development project.

(11)
Dispositions are reductions in reserves estimates as a result of selling all or a portion of an interest in oil and gas properties. During 2018, the company disposed of its northeast B.C. mineral landholdings, including associated production.

(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.

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  31


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.

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  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


Future Net Revenues Tables and Notes(1)

Net Present Values of Future Net Revenues Before Income Taxes
as at December 31, 2018
(forecast prices and costs)

    (in $ millions, discounted at % per year)
  Unit Value(2)  
   
 
    0%   5%   10%   15%   20%   ($/boe)  

Proved Developed Producing                          

  Mining   50 836   36 575   25 102   18 087   13 701   9.32  
  In Situ   8 430   7 609   6 897   6 297   5 793   26.14  
  E&P Canada   1 560   1 571   1 529   1 469   1 405   31.34  

Total Canada   60 826   45 755   33 528   25 854   20 899   11.15  

Offshore U.K. & Norway   1 984   1 936   1 858   1 771   1 685   42.78  

Total Proved Developed Producing   62 810   47 691   35 386   27 624   22 584   11.60  

Proved Developed Non-Producing                          

  Mining              
  In Situ              
  E&P Canada              

Total Canada              

Offshore U.K. & Norway   28   27   26   25   24   74.33  

Total Proved Developed Non-Producing   28   27   26   25   24   74.33  

Proved Undeveloped                          

  Mining                
  In Situ   33 449   18 369   10 850   6 802   4 465   11.02  
  E&P Canada   3 197   2 586   2 085   1 702   1 412   35.34  

Total Canada   36 646   20 955   12 936   8 505   5 877   12.39  

Offshore U.K. & Norway   341   247   172   114   68   16.97  

Total Proved Undeveloped   36 987   21 202   13 108   8 619   5 945   12.43  

Proved                          

  Mining   50 836   36 575   25 102   18 087   13 701   9.32  
  In Situ   41 879   25 978   17 748   13 099   10 258   14.21  
  E&P Canada   4 757   4 157   3 615   3 172   2 817   33.53  

Total Canada   97 472   66 711   46 464   34 358   26 776   11.47  

Offshore U.K. & Norway   2 354   2 209   2 056   1 910   1 777   38.12  

Total Proved   99 826   68 920   48 520   36 268   28 553   11.82  

Probable                          

  Mining   33 292   13 583   7 153   4 479   3 135   7.58  
  In Situ   74 178   21 661   8 602   4 511   2 900   7.13  
  E&P Canada   7 811   4 994   3 342   2 339   1 689   24.19  

Total Canada   115 281   40 238   19 098   11 329   7 724   8.35  

Offshore U.K. & Norway   2 333   1 922   1 589   1 332   1 133   39.96  

Total Probable   117 615   42 160   20 687   12 660   8 856   8.89  

Proved Plus Probable                          

  Mining   84 128   50 158   32 255   22 566   16 836   8.87  
  In Situ   116 057   47 640   26 350   17 611   13 158   10.73  
  E&P Canada   12 568   9 151   6 957   5 510   4 506   28.28  

Total Canada   212 753   106 948   65 562   45 687   34 500   10.34  

Offshore U.K. & Norway   4 687   4 131   3 645   3 241   2 910   38.90  

Total Proved Plus Probable   217 440   111 080   69 207   48 928   37 410   10.76  

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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  33


Net Present Values of Future Net Revenues After Income Taxes(1)
as at December 31, 2018
(forecast prices and costs)

    (in $ millions, discounted at % per year)
 
   
    0%   5%   10%   15%   20%  

Proved Developed Producing                      

  Mining   37 129   28 239   19 613   14 244   10 876  
  In Situ   6 306   5 718   5 193   4 744   4 365  
  E&P Canada   1 418   1 437   1 402   1 348   1 289  

Total Canada   44 853   35 394   26 207   20 335   16 530  

Offshore U.K. & Norway   938   964   952   924   890  

Total Proved Developed Producing   45 791   36 358   27 160   21 259   17 419  

Proved Developed Non-Producing                      

  Mining            
  In Situ            
  E&P Canada            

Total Canada            

Offshore U.K. & Norway   17   16   16   15   15  

Total Proved Developed Non-Producing   17   16   16   15   15  

Proved Undeveloped                      

  Mining            
  In Situ   24 127   13 048   7 564   4 637   2 962  
  E&P Canada   2 462   2 003   1 609   1 305   1 073  

Total Canada   26 589   15 051   9 174   5 942   4 035  

Offshore U.K. & Norway   327   239   169   114   71  

Total Proved Undeveloped   26 917   15 289   9 343   6 056   4 106  

Proved                      

  Mining   37 129   28 239   19 613   14 244   10 876  
  In Situ   30 433   18 766   12 757   9 381   7 326  
  E&P Canada   3 880   3 439   3 011   2 652   2 362  

Total Canada   71 442   50 445   35 381   26 277   20 564  

Offshore U.K. & Norway   1 282   1 219   1 137   1 054   976  

Total Proved   72 725   51 664   36 518   27 331   21 540  

Probable                      

  Mining   24 441   9 838   5 079   3 129   2 164  
  In Situ   53 964   15 660   6 243   3 310   2 151  
  E&P Canada   5 638   3 615   2 372   1 613   1 124  

Total Canada   84 043   29 113   13 694   8 051   5 440  

Offshore U.K. & Norway   1 222   1 078   932   807   706  

Total Probable   85 265   30 192   14 626   8 858   6 145  

Proved Plus Probable                      

  Mining   61 570   38 077   24 692   17 373   13 040  
  In Situ   84 397   34 426   19 000   12 691   9 477  
  E&P Canada   9 518   7 055   5 383   4 265   3 486  

Total Canada   155 485   79 558   49 075   34 329   26 004  

Offshore U.K. & Norway   2 505   2 298   2 069   1 861   1 681  

Total Proved Plus Probable   157 990   81 856   51 144   36 189   27 685  

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

34  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


Total Future Net Revenues(1)
as at December 31, 2018
(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   266 600   29 775   132 344   33 566   20 079   50 836   13 706   37 129  
  In Situ   20 524   2 321   7 557   1 717   499   8 430   2 124   6 306  
  E&P Canada   5 513   1 089   1 407   188   1 269   1 560   142   1 418  

Total Canada   292 636   33 185   141 307   35 470   21 848   60 826   15 973   44 853  

Offshore U.K. & Norway   3 871     1 238   76   572   1 984   1 047   938  

Total Proved Developed Producing   296 507   33 185   142 545   35 546   22 420   62 810   17 020   45 791  

Proved Developed Non-Producing                                  

  Mining                  
  In Situ                  
  E&P Canada                  

Total Canada                  

Offshore U.K. & Norway   29     1       28   11   17  

Total Proved Developed Non-Producing   29     1       28   11   17  

Proved Undeveloped                                  

  Mining                  
  In Situ   100 228   17 722   30 420   17 581   1 057   33 449   9 321   24 127  
  E&P Canada   5 784   265   1 053   686   584   3 197   735   2 462  

Total Canada   106 012   17 987   31 473   18 266   1 640   36 646   10 057   26 589  

Offshore U.K. & Norway   911     171   341   58   341   14   327  

Total Proved Undeveloped   106 923   17 987   31 643   18 608   1 698   36 987   10 070   26 917  

Proved                                  

  Mining   266 600   29 775   132 344   33 566   20 079   50 836   13 706   37 129  
  In Situ   120 752   20 043   37 977   19 298   1 556   41 879   11 446   30 433  
  E&P Canada   11 297   1 353   2 460   873   1 853   4 757   877   3 880  

Total Canada   398 648   51 171   172 780   53 737   23 488   97 472   26 030   71 442  

Offshore U.K. & Norway   4 811     1 410   417   630   2 354   1 072   1 282  

Total Proved   403 459   51 171   174 190   54 154   24 119   99 826   27 101   72 725  

Probable                                  

  Mining   123 949   19 657   57 538   9 956   3 506   33 292   8 852   24 441  
  In Situ   202 574   43 021   54 461   29 556   1 358   74 178   20 214   53 964  
  E&P Canada   18 557   3 821   4 197   1 941   787   7 811   2 173   5 638  

Total Canada   345 079   66 498   116 197   41 452   5 651   115 281   31 239   84 043  

Offshore U.K. & Norway   3 754     988   282   150   2 333   1 111   1 222  

Total Probable   348 833   66 498   117 184   41 735   5 802   117 615   32 349   85 265  

Proved Plus Probable                                  

  Mining   390 549   49 432   189 882   43 521   23 585   84 128   22 558   61 570  
  In Situ   323 325   63 063   92 438   48 854   2 914   116 057   31 659   84 397  
  E&P Canada   29 853   5 174   6 657   2 814   2 640   12 568   3 051   9 518  

Total Canada   743 727   117 669   288 977   95 189   29 140   212 753   57 268   155 485  

Offshore U.K. & Norway   8 565     2 397   699   781   4 687   2 183   2 505  

Total Proved Plus Probable   752 292   117 669   291 374   95 888   29 920   217 440   59 451   157 990  

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

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  35


Future Net Revenues by Product Type(1)
as at December 31, 2018
(forecast prices and costs)

(before income taxes, discounted at 10% per year)   $ millions   Unit Value
$/boe(2)
 

Proved Developed Producing          

  SCO   24 155   12.01  

  Bitumen   7 844   8.29  

  Light Crude & Medium Crude Oil   2 620   33.69  

  Heavy Crude Oil   761   53.50  

  Conventional Natural Gas(3)   6   24.12  

Total Proved Developed Producing   35 386   11.60  

Proved          

  SCO   30 190   12.25  

  Bitumen   12 659   8.56  

  Light Crude & Medium Crude Oil   3 168   31.67  

  Heavy Crude Oil   2 466   41.59  

  Conventional Natural Gas(3)   36   15.06  

Total Proved   48 520   11.82  

Proved Plus Probable          

  SCO   44 114   11.21  

  Bitumen   14 491   6.71  

  Light Crude & Medium Crude Oil   7 278   29.72  

  Heavy Crude Oil   3 221   35.97  

  Conventional Natural Gas(3)   104   19.62  

Total Proved Plus Probable   69 207   10.76  

(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  2018 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 46% to 60% of Firebag bitumen production is estimated to be upgraded to SCO from 2019 to 2035 and 100% thereafter. These assumptions have resulted in a $2.7 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, 2019. 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 0.0% in 2019 and 2.0% in 2020 and thereafter.

2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.  37


Prices Impacting Reserves Tables

Forecast   Brent North
Sea(1)
  WTI
Cushing

Oklahoma
  WCS
Hardisty

Alberta(2)
  Light Sweet
Edmonton
Alberta(3)
  Pentanes
Plus
Edmonton
Alberta(4)
  AECO Gas(5)   National
Balancing
Point North
Sea(6)
 

Year   US$/bbl   US$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/bbl   Cdn$/mmbtu   Cdn$/mmbtu  

2018(7)   71.45   64.77   49.85   69.54   79.06   1.50   7.09  

2019   65.92   58.58   51.55   67.30   70.10   1.88   10.44  

2020   69.47   64.60   59.58   75.84   79.21   2.31   9.94  

2021   71.65   68.20   65.89   80.17   83.33   2.74   9.62  

2022   73.72   71.00   68.61   83.22   86.20   3.05   9.48  

2023   75.58   72.81   70.53   85.34   88.16   3.21   9.50  

2024   77.39   74.59   72.34   87.33   90.20   3.31   9.55  

2025   79.27   76.42   74.31   89.50   92.43   3.39   9.62  

2026   81.27   78.40   76.44   91.89   94.87   3.46   9.81  

2027   82.88   79.98   78.10   93.76   96.80   3.54   10.00  

2028   84.54   81.59   79.81   95.68   98.79   3.62   10.14  

2029   86.21   83.22   81.40   97.57   100.74   3.69   10.34  

2030   87.93   84.87   83.00   99.52   102.75   3.77   10.54  

2031   89.68   86.57   84.69   101.52   104.82   3.84   10.75  

2032   91.49   88.30   86.37   103.55   106.92   3.91   10.97  

2033   93.32   90.08   88.11   105.65   109.07   3.99   11.19  

2034+   +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 bitumen reserves presented as In Situ and Mining reserves, as well as for determining bitumen pricing for royalty calculation purposes.

(3)
Price used when determining SCO reserves presented as In Situ and Mining reserves.

(4)
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.

(5)
Price used when determining natural gas input costs for the production of SCO and bitumen reserves.

(6)
Price used when determining conventional natural gas reserves presented as Offshore U.K. & Norway reserves.

(7)
Prices for 2018 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              

2019   0.757   1.507   1.668  

2020   0.782   1.471   1.631  

2021   0.797   1.443   1.600  

2022   0.803   1.432   1.587  

2023   0.807   1.426   1.581  

2024+   0.808   1.423   1.577  

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 an individual asset level (for In Situ) or at a business area or legal entity level (for Mining, E&P Canada and Offshore U.K & Norway) 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 2018 audited Consolidated Financial Statements and the MD&A should be consulted for information on income taxes at the corporate entity level.

38  2018 ANNUAL INFORMATION FORM   Suncor Energy Inc.


Additional Information Relating to Reserves Data

Future Development Costs(1)
as at December 31, 2018
(forecast prices and costs)

($ millions)   2019   2020   2021   2022   2023