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

ý Annual report pursuant to Section 13(a) or 15(d) of the Securities Exchange Act of 1934

For fiscal year ended:		December 31, 2002
Commission File Number:		No. 1-12384

SUNCOR ENERGY INC.

(Exact name of registrant as specified in its charter)

Canada		1311, 1321, 2911, 4613, 5171, 5172		Not Applicable
(Province or other jurisdiction of incorporation or organization)		(Primary standard industrial classification code number, if applicable)		(I.R.S. employer identification number, if applicable)

112 - 4^th Avenue S.W.

Box 38

Calgary, Alberta, Canada T2P 2V5

(403) 269-8100

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

CT Corporation System

111 Eighth Avenue

New York, New York, U.S.A. 10011

(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		448,971,543

Preferred Shares, Series A		none

Indicate by check mark whether the registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the “Exchange Act”). If “Yes” is marked, indicate the file number assigned to the registrant in connection with such rule.

Yes o No ý

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13(a) or 15(d) of the Exchange Act during the proceeding 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 in the past 90 days.

Yes ý No o

ANNUAL INFORMATION FORM

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

February 27, 2003

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

ANNUAL INFORMATION FORM
GLOSSARY OF TERMS
CONVERSION TABLE
CURRENCY
FORWARD-LOOKING STATEMENTS
CORPORATE STRUCTURE
Name and Incorporation
Intercorporate Relationships
GENERAL DEVELOPMENT OF THE BUSINESS
Three-Year Highlights
NARRATIVE DESCRIPTION OF THE BUSINESS
OIL SANDS
Operations
Competitive Conditions
Location of Production and Material Properties
Reserves Estimates
Reserves Reconciliation
Sales of Synthetic Crude Oil and Diesel
Capital Expenditures
Environmental Compliance
NATURAL GAS
Reserves and Reserves Reconciliation
Conventional Crude Oil
Natural Gas
Land Holdings
Drilling
Wells
Sales and Sales Revenues
Production Costs
Quarterly Volumes and Netback Analysis
Marketing, Pipeline and Other Operations
Competitive Conditions
Capital and Exploration Expenditures
Environmental Compliance
ENERGY MARKETING & REFINING
Procurement of Feedstocks
Refining Operations
Principal Products
Transportation and Distribution
Competitive Conditions
Capital Expenditures
SUNCOR EMPLOYEES
RISK/SUCCESS FACTORS
SELECTED CONSOLIDATED FINANCIAL INFORMATION
Selected Consolidated Financial Information
Dividend Policy and Record
Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas
MANAGEMENT’S DISCUSSION AND ANALYSIS
MARKET FOR THE SECURITIES OF THE ISSUER
DIRECTORS AND EXECUTIVE OFFICERS
Additional Disclosure for Directors and Executive Officers
ADDITIONAL INFORMATION

GLOSSARY OF TERMS

Bitumen/Heavy Oil

A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane, that is not recoverable at a commercial rate in its naturally occurring viscous state through a well without using enhanced recovery methods. When extracted bitumen/heavy oil can be upgraded into crude oil and other petroleum products.

Capacity

Maximum output that can be achieved from a facility in ideal operating conditions in accordance with current design specifications.

Coal Bed Methane

Natural gas produced from wells drilled into a coal formation. Also called coal seam methane.

Conventional Crude Oil

Crude oil produced through wells by standard industry recovery methods for the production of crude oil.

Conventional Natural Gas

Natural gas produced from all geological strata, excluding coal bed methane.

Crude Oil

Unrefined liquid hydrocarbons, excluding natural gas liquids.

Downstream

This business segment manufactures, distributes and markets refined products from crude oil.

Dry Hole/Well

An exploration or development well determined, on an economic basis, to be incapable of producing hydrocarbons that will be plugged, abandoned and reclaimed.

Gross Production/Reserves

Suncor’s undivided percentage interest in production/reserves before deducting Crown royalties, freehold and overriding royalty interests.

Gross Wells/Land Holdings

Total number of wells or acres, as the case may be, in which Suncor has an interest.

Heavy Fuel Oil

Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted.

In-situ Oil

In-situ or “in place” refers to methods of extracting heavy crude oil from deep deposits of oil sands with minimal disturbance of the ground cover.

iii

MD&A

Suncor’s Management’s Discussion and Analysis dated February 27, 2003, accompanying its audited consolidated comparative financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2002, which MD&A is incorporated by reference herein.

Natural Gas

Hydrocarbons that at atmospheric conditions of temperature and pressure are in a gaseous state.

Natural Gas Liquids

Hydrocarbon products recovered as liquids from raw natural gas by processing through extraction plants or recovered from field separators, scrubbers or other gathering facilities. These liquids include the hydrocarbon components ethane, propane, butane and pentane plus, or a combination thereof.

Net Production/Reserves

Suncor’s undivided percentage interest in total production or total reserves, as the case may be, after deducting Crown royalties and freehold and overriding royalty interests.

Net Wells/Land Holdings

Suncor’s undivided percentage interest in the gross number of wells or gross number of acres, as the case may be, after deducting interests of third parties.

Overburden

Material overlying oil sands that must be removed before mining. Consists of muskeg, glacial deposits and sand.

Probable Reserves

Those reserves which analysis of drilling, geological, geophysical and engineering data does not demonstrate to be proved under current technology and existing economic conditions, but where such analysis suggests the likelihood of their existence and future recovery. Probable additional reserves to be obtained by the application of enhanced recovery processes will be the increased recovery over and above proved estimates that can be realistically estimated for the pool on the basis of enhanced recovery processes which can be reasonably expected to be instituted in the future. Information on probable reserves included in this Annual Information Form is prepared in accordance with Canadian disclosure requirements. U.S. companies are prohibited in filings with the United States Securities and Exchange Commission to disclose estimates of probable reserves for non-mining properties. As a result our reserve estimates may not be comparable to those made by U.S. companies.

Proved Reserves

Those reserves estimated as recoverable with a high degree of certainty under current technology and existing economic conditions, from that portion of a reservoir which can be reasonably evaluated as economically productive on the basis of analysis of drilling, geological, geophysical and engineering data, including the reserves to be obtained by enhanced recovery processes demonstrated to be economic and technically successful in the subject reservoir.

Reservoir

Body of porous rock containing an accumulation of water, crude oil or natural gas.

Sour Synthetic Crude Oil

Crude oil produced from oil sands that requires only partial upgrading and contains a higher sulphur content than sweet synthetic crude oil.

Sweet Synthetic Crude Oil

Crude oil produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking and purifying of bitumen.

Synthetic Crude Oil

Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands leases and in-situ heavy oil leases.

Undeveloped Oil and Natural Gas Lands

Suncor’s undivided percentage interest in lands where no producing or commercially producible well has been drilled.

Upstream

These business segments include acquisition, exploration, development, production and marketing of crude oil, natural gas and natural gas liquids; and for greater clarity include the production of synthetic crude oil, bitumen and other oil products from oil sands.

Utilization

The average use of capacity taking into consideration planned and unplanned outages and maintenance.

Wells

Development Well

A crude oil or natural gas well drilled in a reservoir known to be productive and expected to produce in future.

Drilled Well

A well that has been drilled and has a defined status e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well.

Exploratory Well

A well drilled in unproved or semi-proved territory with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas.

ACCOUNTING TERMS

Barrel of Oil Equivalent (BOE)

Suncor converts natural gas to barrels of oil equivalent (BOE) at a 6:1 ratio (converted on the approximate energy equivalent basis that six million cubic feet of natural gas equals one thousand barrels of oil equivalent).

Development Costs

Includes all costs associated with moving reserves from other classes such as “proved undeveloped” and “probable” to the “proved developed” class.

Finding Costs

Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves.

Lifting Costs

Includes all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems.

Million Cubic Feet Equivalent (MMCF/E)

Converts crude oil to natural gas on the approximate energy equivalent basis that one thousand barrels of crude oil equals six million cubic feet natural gas.

Net Debt

Long-term borrowings (including the current portion) plus short-term borrowings, less cash and cash equivalents.

Operating Working Capital

Current assets (excluding cash and cash equivalents), less current liabilities (excluding borrowings).

Return on Capital Employed (ROCE)

Net earnings adjusted for after-tax long-term interest expense, divided by average capital employed. Average capital employed is the total of shareholders’ equity and short-term and long-term debt, less capitalized costs of major projects in progress, at the beginning and end of the year, divided by two.

Return on Average Shareholders’ Equity

Earnings as a percentage of average shareholders’ equity. Average shareholders’ equity is the aggregate of total shareholders’ equity at the beginning and end of the year, divided by two.

CONVERSION TABLE

1 cubic metre m(3) = 6.29 barrels		1 tonne = 0.984 tons (long)
1 cubic metre m(3) (natural gas) = 35.49 cubic feet		1 tonne = 1.102 tons (short)
1 cubic metre m(3) (overburden) = 1.31 cubic yards		1 kilometre = 0.62 miles
		1 hectare = 2.5 acres

Notes:

(1) Conversion using the above factors on rounded numbers appearing in this Annual Information Form may produce small differences from reported amounts.

(2) Some information in this Annual Information Form is set forth in metric units and some in imperial units.

CURRENCY

All references in this Annual Information Form to dollar amounts are in Canadian dollars unless otherwise indicated.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains certain forward-looking statements that are based on Suncor’s current expectations, estimates, projections and assumptions. Forward-looking statements are made by the Company in light of its experience and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about Suncor’s strategy for growth, expected future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future contractual commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “plans,” “intends,” “believes,” “projects,” “indicates,” “could”, “vision”, “goal”, “target”, “objective” and similar expressions. These statements are not guarantees of future performance as they are based on assumptions and involve a number of risks and uncertainties, some of which are similar to those that affect other oil and gas companies, and some of which are unique to Suncor. Therefore, Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements and you are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; fluctuations in commodity prices; fluctuations in currency exchange rates; Suncor’s ability to respond to changing markets; the ability of Suncor to receive timely regulatory approvals; the successful and timely implementation of its growth projects including the Firebag In-Situ Oil Sands Project and Voyageur; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other future resource developments; the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations, strategic partners and joint venture co-owners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of or changes to taxes, fees and royalties, and changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in Suncor’s MD&A, incorporated by reference herein. Readers are also referred to the risk factors described in other documents Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the Company at 112 — 4^th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by email request to info@suncor.com.

References herein to Suncor’s 2002 Consolidated Financial Statements mean Suncor’s audited consolidated comparative financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2002.

vii

CORPORATE STRUCTURE

Name and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act 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, Suncor amalgamated with a wholly-owned subsidiary under the Canada Business Corporations Act. Suncor’s articles were amended in 1995 to move its registered office from Toronto, Ontario, to Calgary, Alberta, and amended again in April 1997, to adopt its current name, “Suncor Energy Inc.”. In April 1997, May 2000 and May 2002, Suncor’s articles were amended to divide its issued and outstanding shares on a two-for-one basis.

Suncor’s registered and principal office is located at 112 - 4th Avenue, S.W. Calgary, Alberta, T2P 2V5.

In this Annual Information Form, references to “Suncor” or the “Company” include Suncor Energy Inc., its subsidiaries and joint venture investments unless the context otherwise requires.

Intercorporate Relationships

Suncor Energy Inc. has two principal subsidiaries.

Suncor Energy Products Inc. (“SEPI”) (formerly Sunoco Inc.) is an Ontario corporation that is wholly-owned by Suncor. SEPI refines and markets petroleum products and petrochemicals directly and indirectly through subsidiaries and joint ventures. SEPI operates its retail business under the Sunoco brand in Canada. SEPI is unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.), headquartered in Philadelphia, Pennsylvania.

Suncor Energy Marketing Inc., wholly-owned by SEPI, is incorporated under the laws of Alberta. Suncor Energy Marketing Inc. markets, mainly to customers in Canada and the United States, the crude oil, diesel fuel and byproducts such as petroleum coke, sulphur and gypsum, produced by Suncor’s Oil Sands business unit. It also markets certain third party products, and procures crude oil feedstocks for Suncor’s downstream business. Suncor Energy Marketing Inc. also has a petrochemical marketing division that holds a 50% interest in Sun Petrochemicals Company, a petrochemical products joint venture. Commencing in 2002, Suncor Energy Marketing Inc. procures the natural gas supply for Suncor’s Oil Sands and Energy Marketing and Refining (“EM&R”) businesses, and administers Suncor’s energy trading activities. Commencing in 2003, it will also market certain natural gas produced by Suncor’s Natural Gas (“NG”) business unit.

Suncor has a number of other subsidiary companies. However, the total assets of such subsidiaries combined, and their total sales and operating revenues, do not constitute more than 20 per cent of the consolidated assets, or consolidated sales and operating revenues, respectively, of Suncor.

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is a Canadian-based integrated energy company. Suncor explores for, acquires, develops, produces and markets crude oil and natural gas, refines crude oil and markets petroleum and petrochemical products. Periodically Suncor also markets third party petroleum products. In the fourth quarter of 2002, Suncor commenced energy trading activities focused principally on buying and selling futures contracts and other derivative instruments based on the commodities Suncor produces. These activities are intended to earn revenues for the Company and improve market intelligence as Suncor increases production levels.

Suncor has three principal operating business units. Oil Sands (OS), based near Fort McMurray, Alberta, mines oil sands ore and extracts and upgrades bitumen into sweet and sour crude oil, diesel fuel and refinery feedstock. Natural Gas (“NG”), based in Calgary, Alberta, explores for, acquires, develops and produces natural gas. Energy Marketing and Refining (“EM&R”), headquartered in Toronto, Ontario, refines crude oil at Suncor’s refinery in Sarnia, Ontario, into a broad range of petroleum products, and markets the company’s refined products to industrial, wholesale and commercial customers principally in Ontario and Quebec, and to retail customers in Ontario through Sunoco-branded and joint venture operated retail networks.

While it provides hydrocarbon-based resources for the immediate energy needs of consumers, Suncor also pursues the development of low-emission and no-emission energy sources that have a reduced environmental impact. Segmented financial data for these activities is reported under the results of Suncor’s “Corporate” segment for financial reporting purposes.

In 2002, Suncor produced approximately 239,500 BOE per day, comprised of 209,700 barrels per day (bpd) of crude oil and natural gas liquids and 179 million cubic feet per day of natural gas. In 2001, the most recent period with published results, Suncor was the 5^thlargest crude oil (approximately 6% of Canada’s crude oil production) and natural gas liquids producer and the 21^st largest natural gas producer in Canada. Production in 2001 was 156,600 BOE per day and reflects the commissioning of Project Millennium in the fourth quarter, as described below under “Three Year History — Oil Sands”.

In 2002, Suncor sold approximately 91,100 bpd (2001 - 93,400 bpd) or 14,500 m³ per day (2001 - 14,800 m³per day) of refined products, mainly in Ontario but also in the United States and Europe. Suncor’s refined product sales in Ontario represented approximately 17% (2001-18%) of Ontario’s total refined product sales in 2002.

Three-Year Highlights

Oil Sands (OS)

In April 1999, following approval from Suncor’s Board of Directors and regulatory authorities, Suncor commenced construction of Project Millennium, an expansion of its Oil Sands plant near Fort McMurray, Alberta. Through an expanded mine, additional mining equipment, increased energy services support and twinning of the bitumen extraction and upgrading process, Project Millennium was completed in 2001 and increased total design capacity of Suncor’s Oil Sands plant to 225,000 bpd. The final capital cost of Project Millennium was $3.4 billion, up from the original estimate of $2 billion. The increase in project costs over earlier estimates was primarily attributable to rising labour, fabrication and material costs and a $150 million change in the project’s scope. The capital costs were financed by internally generated cash flow and additional borrowings.

In early 2000, Suncor announced a plan to further expand its Oil Sands operations beyond Project Millennium and in 2001 Suncor received regulatory approval to proceed with development of a four stage in-situ oil sands project on its Firebag oil sands leases (the “Firebag Project”). The approval is conditioned on providing the regulators with project updates at least six months prior to any development on each stage after stage one. The first stage of the Firebag Project is expected to begin commercial bitumen production in 2004. Full production from the first stage, targeted at 35,000 barrels per day of bitumen, is not expected until mid-2005. Combined with associated investments in the upgrading facility, the first stage of the Firebag Project is expected to contribute to a planned increase in total Oil Sands production capacity to 260,000 bpd in 2005. The first stage of the Firebag Project and associated addition of a vacuum unit to the Oil Sands Millennium upgrader are estimated to cost a total of approximately $1 billion. Engineering is underway on the second stage of the Firebag Project, with front-end engineering design specifications targeted for completion in the second quarter of 2003. Suncor plans to spend over $490 million on Oil Sands growth projects in 2003, primarily related to the Firebag Project and Millennium vacuum unit. Approval from Suncor’s Board of Directors is required before construction beyond the first stage of the Firebag Project can begin. The combined bitumen production potential of all four stages of the Firebag In-situ Oil Sands Project is 140,000 bpd.

In late 2001, Suncor issued a public disclosure document for its Voyageur growth strategy, which targets production between 500,000 bpd to 550,000 bpd in 2010 to 2012. When Suncor originally released these plans, the Company stated it would apply for regulatory approval in late 2002. Following initial stakeholder consultation and preliminary engineering, Suncor modified its Voyageur plan, deferring applications for regulatory approval until further details about each project stage are known and can be more fully discussed with stakeholders. Although the timing of Suncor’s regulatory approval strategy has changed, the Company’s goal of increasing production capacity to 500,000 to 550,000 in 2010 to 2012 remains unchanged. Suncor anticipates it will provide cost estimates for the Voyageur growth strategy once preliminary engineering is completed for each phase. Ultimate development of the Voyageur growth project requires approval of government regulators and Suncor’s Board of Directors.

In 2001, Suncor commenced a crude oil brokerage business to generate additional income by buying and selling the crude oil and bitumen production of other companies. The activity conducted by this business, which increased OS revenue by $146 million in 2002, did not have a significant impact on the Company’s earnings or cash flow in 2002.

On December 17, 2002, the Government of Canada announced its ratification of the Kyoto Protocol. For a discussion of the Kyoto Protocol and management’s assessment of its possible impact on Suncor, refer to the “Outlook — Climate Change” section under “Suncor Overview and Strategic Priorities”, in MD&A.

Natural Gas (NG)

In April 2000, Suncor’s Board of Directors approved a repositioning of Suncor’s conventional oil and gas business, to sharpen Suncor’s focus on natural gas production to meet growing demand, both internally and externally. During 2000, natural gas production was consolidated into three core natural gas areas in Western Canada, and Suncor sold most of its conventional crude oil properties. Since 2000, NG has decreased its annualized operating costs by approximately $20 million, through a focus on administrative cost controls and reduced lifting costs.

NG’s long-term goal is to achieve a sustainable return on capital employed (ROCE) of a minimum of 12% at mid-cycle natural gas prices (US$3.00 to US$3.50/mcf). In 2002 the return on capital employed was 9.2%. To help meet its ROCE target, management plans to increase production and continue work to improve base business efficiency, with a focus on reducing operating costs and capturing supply chain management benefits.

Energy Marketing & Refining (EM&R)

In 2001, EM&R entered into a 20-year energy supply agreement with TransAlta Corporation (“TransAlta”). Under the agreement, the TransAlta Sarnia Regional Co-generation Project, a multi-user cogeneration project in Sarnia, Ontario, that commenced operation in the fourth quarter of 2002, supplies all of the steam and electricity requirements of EM&R’s Sarnia Refinery. The agreement is expected to help mitigate EM&R’s exposure to increases in energy costs and supply steam to the Sarnia Refinery at a competitive cost, while eliminating the need for EM&R to build its own steam generating boilers.

Federal legislation passed in 1999 mandates sulphur levels in gasoline of an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. EM&R finalized an investment plan in 2001 to meet these sulphur content limits. Capital required to achieve compliance is expected to be approximately $40 million, which includes the addition of a desulphurization unit. Construction of the unit is in progress and is expected to be completed in 2003, more than a year in advance of the legislated deadline. As of the end of 2002, $17 million had been spent on the gasoline desulphurization project.

In 2002, the Canadian government also passed legislation limiting the concentration of sulphur in diesel fuel produced or imported for use in on-road vehicles to a maximum of 15 ppm after May 31, 2006. The current maximum is 500 ppm. The cost to comply with these requirements is currently estimated at $225 million.

In addition, EM&R is evaluating several strategic options including the potential to enhance integration of the Sarnia Refinery with production from Oil Sands, and to possibly increase value through integration with the diesel desulphurization facilities.

In the second quarter of 2002, to sharpen its focus on refining and marketing, EM&R sold its retail natural gas marketing business, resulting in an after-tax gain of $35 million. EM&R entered the retail natural gas marketing business in 1997. At the time of sale, the business was supplying natural gas to approximately 125,000 commercial and residential customer accounts in Ontario.

Other

Financing Activities

During 2000, the Company put in place a fully revolving 364 day borrowing facility for $500 million. In 2001 this facility was extended to June 2002 and increased to $550 million. The borrowing facility matured in June 2002 and was not renewed.

In 2001 Suncor issued $500 million of Series 2 Medium Term Notes with a ten-year maturity. The notes have a coupon of 6.7% and will yield 6.74%.

In January 2002, Suncor issued U.S. $500 million principal amount of 7.15% unsecured notes due February 1, 2032, to investors in the United States (the “U.S.”). The notes were sold at a price of 99.595% per note to yield 7.183% to maturity. The notes were sold under Suncor’s shelf prospectus dated January 10, 2002, which allows for the issuance of debt securities and common shares in an aggregate principal amount of up to U.S. $1 billion. Also in January 2002, Suncor filed a base shelf prospectus with Canadian securities regulatory authorities, enabling it to issue up to a further $500 million in medium term notes in Canada, if required. To date, no notes have been issued under this prospectus.

Sale of Stuart Oil Shale Project

In April 2001, Suncor sold its interest in the Stuart Oil Shale Project to its Australian joint venture co-owners, Southern Pacific Petroleum NL (“SPP”) and Central Pacific Minerals NL (“CPM”) (together, “SPP/CPM”). The first stage of the Queensland, Australia project, originally announced in 1997, was designed as a 4,500 barrel per day demonstration plant to test the commercial viability of producing crude oil from oil shale. Construction of the demonstration plant was completed and commissioning commenced in 1999. Operational issues were experienced during commissioning, including issues relating to plant reliability, noise, odours and the discovery of low levels of dioxin and other emissions. In the third quarter of 2000, Suncor recorded an after-tax write-down of $80 million, reflecting increased costs and delayed oil production, and thereafter, all future expenditures on the Project were expensed. Suncor’s investment in the Project up to the date of sale, excluding $4 million invested by Suncor in partially paid SPP/CPM shares that were cancelled as part of the sale transaction, and $5 million in shares acquired in 2001, as discussed below, was approximately $275 million.

Under the terms of the sale, Suncor retained a 5% royalty interest in the first stage of the project, and SPP/CPM and Suncor retained worldwide rights to the project technology. Suncor made total payments as part of the transaction in the amount of Aus$7 million (approximately Cdn$5 million) for which Suncor received 2.5 million SPP shares and 0.926 million CPM shares. In addition, SPP/CPM issued to Suncor 12.5 million SPP share options and 4.6 million CPM share options, and Suncor surrendered the partly paid SPP/CPM restricted class shares it had originally acquired in 1997.

As a result of the sale Suncor recorded an after-tax charge to earnings of $3 million in the second quarter of 2001. Since completion of this transaction, Suncor has written-down the carrying value of the shares acquired by $4 million, to an amount of less than $1 million, and as of February 27, 2003, has liquidated approximately half of its SPP/CPM shares.

Other Three Year Highlights

In 2000, Suncor announced plans to invest at least $100 million over five years to pursue renewable energy opportunities. As of December 31, 2002, Suncor had expended approximately $17 million with the majority of these funds related to the SunBridge Wind Power Project in Gull Lake, Saskatchewan. This project is a 50-50 partnership with Enbridge Inc. (“Enbridge”). In 2001, the first electricity was generated from this project.

In 2002, Suncor’s Board of Directors approved commencement of energy trading activities and after developing an appropriate control framework, Suncor began limited energy trading activities in November 2002. A separate risk management function directs and monitors practices and policies and provides independent verification and valuation of Suncor’s trading and marketing activities. Trading activities are principally focused on the commodities the Company produces, adding potential for new revenue and providing a new window into energy product markets. Net trading losses were negligible for the period ended December 31, 2002.

For further information on developments and issues referred to above and other highlights of 2002, and a discussion of other trends known to Suncor’s management that could reasonably be expected to have a material effect on Suncor, refer to the “Outlook” and other sections of Suncor’s MD&A, and to “Risk/Success Factors” in this Annual Information Form.

NARRATIVE DESCRIPTION OF THE BUSINESS

OIL SANDS

Suncor produces a variety of refinery feedstock and diesel fuel by mining the Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at its plant near Fort McMurray, Alberta. The Oil Sands operations, accounting for virtually all of Suncor’s conventional and synthetic crude oil production in 2002, represents a significant portion of Suncor’s 2002 capital employed (83%), cash flow (85%) and net earnings (89%).

Operations

Suncor’s integrated Oil Sands business involves four operations: a mining operation using trucks and shovels to mine the oil sand ore; extraction facilities to recover the bitumen from the oil sand ore; a heavy oil upgrading process, where bitumen is converted into crude oil products; and energy services facilities (operated by TransAlta), which together with TransAlta’s natural gas fired co-generation plant that commenced operations at the Oil Sands plant site in 2001, provides the site with steam and electric power. Suncor’s energy services plant primarily uses petroleum coke, a by-product of the coking process, as fuel. It also consumes natural gas. Suncor uses all of the steam and a portion of the power from the TransAlta cogeneration facility.

The first step of the open pit mining operation is to remove the overburden with trucks and shovels to access the oil sands - a mixture of sand, clay and bitumen. Oil sands ore is then excavated, and transported to one of five sizing plants by a fleet of trucks. The ore is dumped into sizers where it is crushed and sent to the ore preparation plants where it is mixed into a hot water slurry and pumped through hydrotransport pipelines to the extraction plant on the west side of the Athabasca River. The bitumen begins to separate from the sand as the slurry is pumped through the lines. Bitumen is extracted from the oil sands ore with a hot water process. After the final removal of impurities and minerals, naphtha is added to the bitumen as diluent to facilitate transportation to the upgrading plant. Periodically bitumen is sold rather than being upgraded. In 2001 approximately 8,500 bpd of bitumen were sold, representing approximately seven percent of 2001 production. In 2002 bitumen sales of 9,300 bpd represented five percent of sales.

After transfer of the diluted bitumen to the upgrading plant, the naphtha is removed and recycled to be used again as diluent. The bitumen is upgraded through a coking and distillation process. The upgraded product, referred to as sour crude oil, is either sold directly to customers or is further upgraded into sweet crude oil by removing the sulphur and nitrogen using a hydrogen treating process. Three separate streams of refined crude oil are produced: naphtha, kerosene and gas oil.

While there is virtually no finding cost associated with synthetic crude oil, mine development and expansion of production can entail significant outlays of funds. The costs associated with synthetic crude oil production are largely fixed for the same reason and, as a result, operating costs per unit are largely dependent on levels of production. Operating costs to produce synthetic crude oil are generally higher than lifting and administrative costs to produce conventional crude oil from the Western Canada Sedimentary Basin.

Transportation

Oil Sands entered into a transportation service agreement with a subsidiary of Enbridge for a term that commenced in 1999 and extends to 2028. Under the agreement Suncor has pipeline capacity for the initial shipment of 60,000 bpd in 1999, increasing to 170,000 bpd in 2005, of sour crude oil and bitumen from Fort McMurray, Alberta to Hardisty, Alberta. As the initial shipper on the pipeline, Suncor’s tolls payable under the agreement are subject to annual adjustments. The pipeline was initially operated by Suncor Energy Marketing Inc. and is now operated by Enbridge. This pipeline, together with Suncor’s proprietary oil sands pipeline, is expected to meet Suncor’s anticipated crude oil shipping requirements for expected future production levels up to 2008. Suncor Energy Marketing Inc., a subsidiary of Suncor, purchases all crude oil products from Suncor’s Oil Sands business at Hardisty and markets the product blends for sale and distribution to Suncor’s Sarnia, Ontario refinery, as well as other customers in Canada, the United States and periodically, to offshore markets.

Suncor has a 20 year agreement with TransCanada Pipeline Ventures Limited Partnership (“TCPV”), to provide Suncor with firm capacity on a natural gas pipeline that came into service in 1999. The natural gas pipeline ships natural gas to Suncor’s Oil Sands facility.

Suncor’s oil sands facilities are readily accessible by public road.

Competitive Conditions

Competitive conditions affecting Oil Sands are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.

Seasonal Impacts

Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs.

Location of Production and Material Properties

Set out in the table below is a summary of Suncor’s oil sands mining and in-situ leasehold interests as of December 31, 2002.

Description	Legal Description	Referred to as	Number of Gross Acres	Percentage of Proved Reserves (bbl of synthetic crude oil)(5)

Mining Leases:

Leases:	7280100T25	25	17,066	These Leases combined represent 100% of proved mining reserves
	7279080T19	19	18,760
	7597030T11	97	2,483
	7280060T23		36,954
	7498050014		243
	7400120007		22,773

Fee Lots(1)	1	N/A	1,894	(1)
	2	N/A	1,972	(1)
	3	N/A	1,967	(1)
	4	N/A	1,886	(1)
	5	N/A	1,881	(1)
	6	N/A	1,483	(1)
				(1)
Original Mine	7387060T04	86	4,522
Leases(2)	7279120092	17	1,619	None

Total Mining Leases			115,503

Firebag Leases:

Firebag(3)	7285100T85	85	39,594	25% of proved in-situ reserves
	7402110457	N/A	23,040	10% of proved in-situ reserves
	7402110458	N/A	22,720	65% of proved in-situ reserves
	7402110459	N/A	23,040	(1)
	7099120072	N/A	23,040	(1)
	7099120073	N/A	23,040	(1)
	7099120074	N/A	16,640	(1)
	7099120075	N/A	23,040	(1)
	7001100001	N/A	22,400	(1)
	7401100027	N/A	23,040	(1)
	7401100029	N/A	10,240	(1)
	7401100013	N/A	7,360	(1)

Firebag(3)	Various(4)	Various	84,480	(1)

Total Firebag Leases			341,674

Total Leases			457,177

Notes:

(1) No proved reserves are attributable to these leases.

(2) Mining on these leases was substantially complete at the end of 2002.

(3) Leases are principally in-situ.

(4) Suncor holds a beneficial interest in 13 leases totaling 84,480 gross and net acres.

(5) In 2002, 100% of Suncor’s Oil Sands production was from the mining leases referred to above, located adjacent to Suncor’s Oil Sands facilities north of Fort McMurray, Alberta.

The Government of Alberta is entitled to royalties under Leases 17, 19, 25, 86 and 97 and the Fee Lots at rates which the Government establishes from time to time. For a description of the Alberta Crown Royalty regime applicable to these leases, and other applicable royalties, refer to “Royalties” in the “Oil Sands Overview” section of MD&A.

Reserves Estimates

In a report dated January 15, 2003, Gilbert Laustsen Jung Associates Ltd. (“GLJ”), independent petroleum consultants, audited Suncor’s estimates of proved and probable reserves, as of December 31, 2002, of synthetic crude oil on its oil sands mining leases. In a report dated January 24, 2003, GLJ prepared an independent reserves and economic evaluation of Suncor’s in-situ oil sands Firebag Project leases, also as of December 31, 2002 (together, the “GLJ Oil Sands Reports”). In the GLJ Oil Sands Reports, GLJ estimates Suncor’s proved plus probable reserves of synthetic crude oil from oil sands mining and in-situ leases total 3.761 billion barrels. This total includes estimates from Suncor’s mining leases that account for 358 million barrels of proved and 1.563 billion barrels of probable reserves, as well as in-situ leases containing 144 million barrels of proved and 1.696 billion barrels of probable reserves. These values are before deduction of Crown and other royalties on the leases.

In the GLJ Oil Sands Reports, GLJ state that they believe there is a 90% and 50% probability under current economic conditions that the quantities actually recovered will equal or exceed the estimated proved and proved plus probable reserves estimates, respectively. GLJ’s estimates consider recovery from leases for which regulatory approvals have been granted.

The mining reserve estimates are based upon a detailed geological assessment and also consider drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, and regulatory constraints. The proved reserves estimate considers portions of the mines drilled up to a density of at least 10 holes per square kilometer, which are expected to be mined in the near future. For Firebag proved reserve estimates, GLJ considered similar factors such as Suncor’s regulatory approval, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects, and a required drilling density of at least 80 acre spacing plus 3D seismic control.

Suncor’s reserves estimates will continue to be impacted by both drilling data and operating experience, as well as technological developments and economic considerations.

Reserves Reconciliation

The following table sets out a reconciliation of Suncor’s proved and probable reserves of synthetic crude oil from December 31, 2001 to December 31, 2002, based on the GLJ Oil Sands Reports.

(millions of barrels of synthetic crude oil)(1)	Oil Sands Mining Leases						In-Situ Firebag Leases(2)			Total Mining and In-Situ

	Proved(3)		Probable(4)		Proved & Probable(4)		Proved(3)	Probable(4)	Proved & Probable(4)	Proved & Probable(4)

December 31, 2001	376		2,029		2,405		—	1,664	1,664	4,069
Revisions	54		(511	)(5)	(457	)(5)	—	—	—	(457	)
Additions	3		45		48		144	32	176	224
Production	(75	)	—		(75	)	—	—	—	(75	)
December 31, 2002	358		1,563		1,921		144	1,696	1,840	3,761

Notes:

(1) Synthetic crude oil reserves based upon a net coker, or synthetic crude oil yield of between 80% and 82%.

(2) Suncor has the option of selling the bitumen production from these leases and/or upgrading the bitumen to synthetic crude oil. The opening balance has been adjusted from a bitumen value of 2.029 billion barrels based on assumed coker (synthetic crude) yields. See note (1). The reserve estimates for the in-situ leases reflect reclassification of a portion of probable reserves to proved now that the first stage of construction of the Firebag Project is nearly complete. The increase also reflects data obtained from similar industry projects that have recently demonstrated commercial success of the in-situ oil sands development process. Suncor will continue to conduct its evaluation program in the Firebag area in 2003, utilizing a combination of seismic and corehole drilling. To date Suncor has drilled approximately 300 coreholes and acquired approximately 400 miles of seismic data in the Firebag area.

(3) All of Suncor’s proved mining reserves are classified as proved producing reserves; all of Suncor’s in—situ Firebag proved reserves are classified as proved non-producing reserves.

(4) In the GLJ Oil Sands Reports, GLJ state that they believe there is at least a 50% probability that proved plus probable oil sands reserves estimates will be exceeded. Accordingly, Suncor’s oil sands reserves have not been further reduced for risk associated with obtaining production from such reserves.

(5) Approximately half of this probable reserve revision reflects management’s decision not to mine less economic areas, as permitted by regulatory changes. The balance of the revision incorporates additional knowledge and understanding of the Millennium mine. For more details, see the information under “Critical Accounting Policies - Oil Sands Mining Reserves” in the Corporate Overview and Strategic Priorities section of Suncor’s MD&A. GLJ estimates that Suncor’s 1.921 billion barrels of proved plus probable mining reserves provide Suncor with approximately 24 years of operations at current production rates.

Sales of Synthetic Crude Oil and Diesel

Aside from onsite fuel use, all of Oil Sands’ production is sold to Suncor Energy Marketing Inc., a wholly owned subsidiary, which then markets all production.

In 1997 Suncor entered into a long-term agreement with Koch Oil Co. Ltd. (“Koch”) to supply Koch with up to 30,000 barrels per day (approximately 15% of Suncor’s average 2002 total production) of sour

crude from Suncor’s Oil Sands operation. Suncor began shipping the crude to Koch’s terminal at Hardisty (from which Koch ships the product to its refinery in Minnesota) under this long-term agreement effective January 1, 1999. The initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination after January 1, 2004, on twenty-four months’ notice.

In 2000, Suncor announced a long term sales agreement with Consumers’ Co-operative Refineries Limited (“CCRL”) under which Suncor expected to begin supplying CCRL with 20,000 barrels per day of sour crude oil production from its Project Millennium expansion facilities by late 2002. CCRL has experienced construction delays with an expansion of its refinery in Regina, Saskatchewan, and is expected to begin accepting delivery of sour crude in the second quarter of 2003.

Prices for sour crude oil under these agreements are set at agreed differentials to market benchmarks.

In 2001, Suncor announced a long-term agreement with Petro-Canada to supply up to 30,000 barrels per day of diluent to dilute bitumen produced by Petro-Canada. Deliveries under the contract have commenced. The agreement is for four years and may be extended unless terminated by either party.

In 2001 and 2002, Koch was the only customer that represented 10% or more of Suncor’s consolidated revenues.

A portion of Oil Sands production is used in connection with Suncor’s Sarnia refining operations. During 2002, the Sarnia refinery processed approximately 12% (2001 — 14%) of Oil Sands crude oil production.

The following table sets forth the average sales price received per barrel of synthetic crude oil from Oil Sands on a quarterly basis for the years 2002 and 2001, after the impact of hedging activities.

	2002				2001

$/bbl	4Q	3Q	2Q	1Q	4Q	3Q	2Q	1Q

Average sales price	35.12	35.79	33.43	29.66	24.43	31.43	31.40	30.84

Capital Expenditures

Capital spending at Oil Sands is expected to total approximately $710 million in 2003, comprising $496 million with respect to the in-situ phase of Suncor’s Oil Sands development and expansion of the upgrading facilities and $215 million in capital investments for the current facility, including approximately $70 million for the second quarter maintenance shutdown (see MD&A for details). Capital expenditures in 2002 were $630 million.

Suncor’s in-situ and expansion of upgrading facilities spending of $341 million in 2002 is part of $1 billion in total spending on in-situ projects planned for the period 2002 to 2005.

The following table sets out, for the quarters indicated, capital expenditures by Suncor’s Oil Sands business unit:

	2002					2001
Capital Expenditures by quarter	4Q		3Q	2Q	1Q	4Q	3Q	2Q	1Q
Property acquisitions	—		—	—	—	4	—	—	9
Drilling activity	(7	)	1	—	17	4	—	4	14
Capital Additions to Facilities(1)	208		149	114	135	305	384	392	363

Note:

(1) Includes capital spending on Project Millennium, Firebag Project, acquisition of mining equipment, and other capital spending.

Environmental Compliance

For a description of the impact of environmental protection requirements on Oil Sands, refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies” in the “Suncor Overview and Strategic Priorities” section of MD&A.

NATURAL GAS

Suncor’s Natural Gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas in western Canada, supplying it to markets throughout North America. The sale of NG production provides a price hedge for natural gas consumption at Suncor’s Oil Sands facility and its refinery in Sarnia, Ontario. In addition, Suncor’s U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is acquiring land and exploring for coal bed methane in the United States.

Exiting 2002, natural gas and natural gas liquids accounted for approximately 96% of the NG business unit’s production.

NG’s exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta. Suncor drills primarily medium to high-risk wells focusing on prospects that can be connected to existing infrastructure.

Commencing in 2003, all of NG’s natural gas production, excluding sales to aggregators, will be sold to Suncor’s marketing subsidiary, Suncor Energy Marketing Inc., which sells both Suncor’s proprietary natural gas and natural gas acquired from other producers.

In June 2002, Suncor entered into a short-term agreement with UBS Warburg to provide Suncor with operational and administrative services related to its natural gas portfolio. UBS continues to provide these services under this agreement. Prior to the agreement with UBS Warburg, these services were provided by Enron Capital and Trade Resources Canada Corp.

Reserves and Reserves Reconciliation

GLJ reported January 22, 2003, on Suncor’s estimated proved and probable reserves of natural gas, natural gas liquids and crude oil (other than reserves from Suncor’s mining leases and the Firebag in-situ reserves), as of December 31, 2002. Information with respect to these reserves is set out in the tables below and in the tables under the headings “Conventional Crude Oil”, “Natural Gas Liquids” and “Natural Gas” (the “Reserves Tables”). GLJ’s determination of Suncor’s estimated proved and probable recoverable reserves are based on constant year-end prices and costs determined as of the dates indicated. The accuracy of any reserve estimate is a function of the quality and quantity of available data and of engineering interpretation and judgment. While reserve and production estimates presented are considered reasonable, the estimates should be viewed with the understanding that reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward.

In the Reserves Tables:

(1) Proved reserves and probable reserves have the meanings set out in the Glossary of Terms at the front of this Annual Information Form. All proved and probable reserves are in Canada.

(2) Proved producing reserves are on production, or reserves that could be recovered from existing wells or facilities, where the current non-producing status is the choice of Suncor.

(3) Gross reserves represent the aggregate of Suncor’s undivided percentage interest in reserves including the royalty interest of governments and others in such reserves and Suncor’s royalty interest in reserves of others. Net reserves are gross reserves less that royalty interest share of others including governments. Royalties can vary depending upon selling prices, production volumes, timing of initial production and changes in legislation. Net reserves have been calculated following generally accepted guidelines, on the basis of prices and the royalty structure in effect at year-end and anticipated production rates. Such estimates by their very nature are inexact and subject to constant revision.

The following tables set out a reconciliation of NG’s estimated proved reserves from December 31, 2001 to December 31, 2002.

Estimated Proved Reserves Reconciliation(1)

	Gross				Net
	Crude oil and Natural gas liquids		Natural gas		Crude oil and Natural gas liquids		Natural gas
	(millions of barrels)		(billions of cubic feet)		(millions of barrels)		(billions of cubic feet)
December 31, 2001	14	(1)	755		10		545
Revisions of previous estimates	—		(35	)	—		(18	)
Extension and discoveries	1		53		1		39
Production	(1	)	(65	)	(1	)	(48	)
Sales of minerals in place	—		(2	)	—		(2	)
December 31, 2002	14	(1)	706		10		516

Note:

(1) Includes 8.7 million barrels of natural gas liquids as at December 31, 2002 (8.6 million barrels as at December 31, 2001).

Estimated proved reserves are comprised of producing and non-producing reserves. The following tables show the breakdown between these categories.

Estimated Proved Producing Reserves Reconciliation

	Gross				Net
	Crude oil and Natural gas liquids		Natural gas		Crude oil and Natural gas liquids		Natural gas
	(millions of barrels)		(billions of cubic feet)		(millions of barrels)		(billions of cubic feet)
December 31, 2001	11		573		8		416
Revisions of previous estimates	—		—		—		3
Extension and discoveries	1		77		1		56
Production	(1	)	(65	)	(1	)	(48	)
Sales of minerals in place	—		(1	)	—		(1	)
December 31, 2002	11		584		8		426

Estimated Proved Non-Producing Reserves Reconciliation

	Gross			Net
	Crude oil and Natural gas liquids	Natural gas		Crude oil and Natural gas liquids	Natural gas
	(millions of barrels)	(billions of cubic feet)		(millions of barrels)	(billions of cubic feet)
December 31, 2001	3	182		2	129
Revisions of previous estimates	—	(35	)	—	(21	)
Extension and discoveries	—	(24	)	—	(17	)
Sales of minerals in place	—	(1	)	—	(1	)
December 31, 2002	3	122		2	90

The following table sets out a reconciliation of NG’s estimated probable reserves from December 31, 2001 to December 31, 2002.

Estimated Probable Reserves Reconciliation(1)

	Gross				Net
	Crude oil and Natural gas liquids		Natural gas		Crude oil and Natural gas liquids		Natural gas
	(millions of barrels)		(billions of cubic feet)		(millions of barrels)		(billions of cubic feet)
December 31, 2001	6		237		5		169
Revisions of previous estimates	(1	)	(33	)	(1	)	(21	)
Extension and discoveries	—		14		—		10
Sales of minerals in place	—		—		—		—
December 31, 2002	5		218		4		158

Note:

(1) The total probable reserves of natural gas shown in the above table have not been reduced for risk associated with the probability of obtaining production from such reserves. Application of a risk factor of 50% to the above reserves would reduce the reserves numbers in the table to 2.5 million barrels of crude oil and natural gas liquids (2 million net), and 109 billion cubic feet of natural gas (79 million net).

Conventional Crude Oil

The following table shows estimates of NG’s proved crude oil reserves before royalties as prepared by GLJ (see “Reserves and Reserves Reconciliation”) and Suncor’s average daily production of crude oil before royalties, in Alberta and British Columbia, represented by the conventional fields identified in this table.

	Proved Reserves		2002 Average
	Before Royalties		Daily Production
	December 31, 2002(1)		Before Royalties(1)
	(millions of		(barrels of
Fields	barrels)	%	oil per day)	%
Simonette	2.1	42	539	36
Blueberry	1.8	36	342	23
McKinley	0.4	8	359	24
Bonanza	0.2	4	41	3
Boundary Lake	0.2	4	28	2
Other(2)	0.3	6	177	12

Total — gross	5.0	100	1,486	100

Notes:

(1) The reserves and production in this table do not include natural gas liquids.

(2) Includes fields in which Suncor holds overriding royalty interests.

Most of the large conventional oil fields in the western provinces have been in production for a number of years and the rate of production in these fields is subject to natural decline. In some cases, additional amounts of crude oil can be recovered by using various methods of enhanced crude oil recovery, infill drilling and production optimization techniques. At the end of 2002, approximately 90% of Suncor’s proved conventional oil reserves were under enhanced oil recovery programs.

Natural Gas Liquids

The following table shows estimates of NG’s proved natural gas liquids reserves before royalties as prepared by GLJ (see “Reserves and Reserves Reconciliation”) and Suncor’s average daily production of natural gas liquids before royalties, in Alberta and British Columbia, represented by the conventional fields identified in this table.

	Proved Reserves		2002 Average
	Before Royalties		Daily Production
	December 31, 2002		Before Royalties
	(millions of		(barrels
Fields	barrels)	%	per day)	%
Simonette	2.4	27	505	21
Grande Prairie	1.5	17	197	8
Knopcik	0.9	10	278	12
Pine Creek	0.8	9	209	9
Glacier	0.6	7	175	7
Blueberry	0.5	6	164	7
Stolberg	0.4	4	65	3
Rosevear	0.4	4	216	9
Boundary Lake	0.3	3
Blackstone	0.2	2	65	3
Phoenix	0.2	2	35	1
George	0.1	1	235	10
Hinton	0.1	1	42	2
Other(1)	0.6	7	203	8

Total — gross	9.0	100	2,389	100

Note:

(1) Includes fields in which Suncor holds overriding royalty interests.

Natural Gas

The following table shows estimates of NG’s proved natural gas reserves, before royalties, as prepared by GLJ (see “Reserves and Reserves Reconciliation”) and Suncor’s average daily production of natural gas before royalties, in Alberta and British Columbia, represented by the major natural gas fields identified in the table.

	Proved Reserves		2002 Average
	Before Royalties		Daily Production
	December 31, 2002		Before Royalties
	(billions of		(millions of cubic
Fields	cubic feet)	%	feet per day)	%
Stolberg	228	32	34	19
Blackstone/Brown Creek	66	9	19	11
Grande Prairie area	55	8	6	3
Knopcik	47	7	14	8
Glacier	43	6	14	8
Simonette	42	6	9	5
Blueberry	38	5	9	5
Mountain Park	32	5	11	6
Rosevear	29	4	18	10
Pine Creek	19	3	6	3
Sinclair	19	3	5	3
Cutbank	13	2	9	5
Other(1)	75	10	25	14

Total — gross	706	100	179	100

Note:

(1) Includes fields in which Suncor holds overriding royalty interests.

Land Holdings

The following table sets out the undeveloped and developed lands in which the NG business unit held crude oil and natural gas interests at the end of 2002. Undeveloped lands are lands within their primary term upon which no well has been drilled. Developed lands are lands past their primary term or upon which a well has been drilled.

The petroleum and natural gas interests include Suncor’s undivided percentage interest in leases, licenses, reservations, permits and exploration agreements (collectively, the “Agreements”). In general, Agreements confer upon the lessee the right to explore for and remove crude oil and natural gas from the lands, with the lessee paying exploration and development costs, operating costs, abandonment costs and reclamation costs, subject to paying rentals, taxes and royalties. Interests in Agreements (excluding freehold agreements) are acquired from the federal or provincial governments through competitive bidding or by undertaking work commitments, or by joint venture agreements with industry companies.

	Undeveloped Acres
	Gross Acres(1)	Net Acres(1)
	(Thousands)
Canada
Western provinces	531	472

International(2)	1,205	698

Total Undeveloped Landholdings	1,736	1,170

Notes:

(1) “Gross Acres” means all of the acres in which Suncor has either an entire or undivided percentage interest in. “Net Acres” represents the acres remaining after deducting the undivided percentage interests of others from the gross acres.

(2) International includes undeveloped land holdings in the United States where coal bed methane exploration activities are currently being undertaken and in Australia, where previous coal bed methane activities were conducted. Subsequent to the end of 2002, Suncor sold its interest in the Australian acreage, reducing international undeveloped landholdings by 675 thousand gross acres (338 thousand net acres).

Drilling

The following table sets forth the gross and net exploratory and development wells in Western Canada, the United States and Australia, which were completed, capped or abandoned in which Suncor’s NG business unit participated during the years indicated.

	Year ended December 31,
	2002		2001
	Gross	Net	Gross	Net
Exploratory Wells
Crude oil	—	—	—	—
Gas	7	2	5	4
Dry (1)	22	19	22	16
Total Exploratory Wells	29	21	27	20

Development Wells
Crude oil	—	—	1	—
Gas	32	18	24	16
Dry	6	4	4	2
Total Development Wells	38	22	29	18

Total	67	43	56	38

Note:

(1) Includes 16 gross (15 net) coal bed methane wells in 2002 and 18 gross (14 net) coal bed methane wells in 2001.

Not included are earning wells completed by other companies under farm-out agreements relating to lands in which Suncor has an undivided percentage interest, since Suncor did not incur cash expenditures in connection with such wells. In addition to the above wells, Suncor had interests in 28 gross (17 net) exploratory wells in progress and 7 gross (3 net) development wells in progress at the end of 2002.

Suncor continues to hold interests in frontier properties (Arctic and Northwest Territories) including 28 long-term “significant discovery licences”.

Wells

The following table summarizes the wells in which the NG business unit has a working interest or a royalty interest as at December 31, 2002.

	Producing		Non-Producing
	Wells(1)(2)		Wells(1)(3)
	Gross	Net	Gross	Net
Conventional Crude Oil Wells
Alberta	44	29	39	18
British Columbia	22	10	1	1
Total Conventional Crude Oil Wells	66	39	40	19

Conventional Natural Gas Wells
Alberta	310	173	34	17
British Columbia	51	23	11	7
Total Conventional Natural Gas Wells	361	196	45	24

Total Wells	427	235	85	43

Notes:

(1) Gross wells represent the number of wells in which NG has an undivided percentage interest and net wells represent NG’s aggregate undivided percentage interest share in such wells.

(2) Producing wells are wells producing hydrocarbons or having the potential to produce, excluding shut-in wells. As at December 31, 2002 Suncor has interests in five oil fields and 29 gas fields.

(3) Non-Producing Wells represent management’s estimate of shut-in wells that could be capable of economic production but were not in production as at December 31, 2002.

Sales and Sales Revenues

The following table shows the breakdown of NG’s sources of revenues.

Gross Revenues(1)	Year ended December 31,
	2002	2001
	($ millions)
Crude oil and natural gas liquids	43	45
Natural gas	255	394
Pipeline	4	5
Other	13	14

Total	315	458

Note:

(1) Includes intersegment revenues.

Production Costs

The following table shows production (lifting) costs in connection with NG’s crude oil and natural gas operations.

Production (Lifting) Costs	Year ended December 31,
	2002	2001
	($ per BOE of gross production)
Average production (lifting) cost of conventional crude oil and gas(1)	3.15	2.96

Note:

(1) Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems. It does not include an estimate for future reclamation costs.

Quarterly Volumes and Netback Analysis

The following table shows Suncor’s average production volumes, pricing, royalties, operating expenses and netbacks for natural gas, conventional crude oil and natural gas liquids, for the periods indicated.

	2002										2001
	4Q		3Q		2Q		1Q		2002		4Q		3Q		2Q		1Q		2001
Natural Gas
Production Volume (mmcf/day)	182		181		179		175		179		180		176		177		177		177

Price ($/mcf)	4.91		3.56		3.92		3.21		3.91		3.10		3.90		6.78		10.73		6.09

Royalties ($/mcf)	(1.62	)	(0.81	)	(0.96	)	(0.63	)	(1.01	)	(0.54	)	(0.85	)	(1.58	)	(2.91	)	(1.46	)

Operating Expenses ($/mcf)(1)	(0.88	)	(0.96	)	(0.89	)	(0.93	)	(0.91	)	(0.97	)	(0.79	)	(0.95	)	(0.73	)	(0.86	)

Netback ($/mcf)	2.41		1.79		2.07		1.65		1.99		1.59		2.26		4.25		7.09		3.77

Conventional Crude Oil
Production Volume (kbbls/d)(2)	1.5		1.3		1.7		1.4		1.5		1.3		1.5		1.5		1.7		1.5

Price ($/bbl)	33.20		33.57		30.99		29.15		31.72		27.17		33.17		36.75		37.35		33.92

Royalties ($/ bbl)	(8.94	)	(9.02	)	(7.76	)	(6.46	)	(8.05	)	(1.84	)	(2.46	)	(2.60	)	(2.89	)	(2.45	)

Operating Expenses ($/ bbl)(1)	(5.34	)	(6.26	)	(4.72	)	(5.79	)	(5.48	)	(7.25	)	(4.76	)	(5.69	)	(3.85	)	(5.17	)

Netback ($/bbl)	18.92		18.29		18.51		16.90		18.19		18.08		25.95		28.46		30.61		26.30

Natural Gas Liquids

Production Volume (kbbls/d)(2)	2.4		2.3		2.5		2.5		2.4		2.4		2.4		2.3		2.3		2.4

Price ($/bbl)	35.14		31.66		28.25		22.53		29.35		23.47		30.26		39.32		45.07		34.38

Royalties ($/ bbl)	(11.13	)	(9.94	)	(7.67	)	(5.10	)	(8.44	)	(5.96	)	(10.26	)	(10.77	)	(12.86	)	(9.93	)

Operating Expenses ($/ bbl)(1)	(5.42	)	(5.98	)	(5.25	)	(5.30	)	(5.48	)	(5.83	)	(4.75	)	(5.72	)	(4.40	)	(5.17	)

Netback ($/bbl)	18.59		15.74		15.33		12.13		15.43		11.68		15.25		22.83		27.81		19.28

Notes:

(1) Operating expenses includes production (lifting) costs and administrative expenses.

(2) Thousands of barrels per day.

Marketing, Pipeline and Other Operations

Suncor operates natural gas processing plants at South Rosevear, Pine Creek, Boundary Lake South, Progress and Simonette with a total design capacity of approximately 206 mmcf/day. Suncor’s capacity interest in these gas processing plants is approximately 128 mmcf/day. Suncor also has varying undivided percentage interests in natural gas processing plants operated by other companies.

Approximately 69% of Suncor’s natural gas production is marketed under direct sales arrangements to customers in Alberta, British Columbia, eastern Canada, and the United States. Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price. Under these contracts, Suncor is responsible for transportation arrangements to the point of sale. Sales to the United States are made under a variety of arrangements with different transportation and pricing terms. NG’s direct sales arrangements include some of the natural gas consumed in Suncor’s Oil Sands plant at Fort McMurray and in the Company’s downstream operations.

Approximately 31% of Suncor’s natural gas production is sold under existing contracts to aggregators (“system sales”). Proceeds received by producers under these sales arrangements are determined on a netback basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated transportation charges and a marketing fee. Most of NG’s system sales volumes are contracted to TransCanada Gas Services and Pan-Alberta Gas Ltd. These companies resell this natural gas primarily to eastern Canadian and midwest and eastern United States markets.

To ensure ongoing direct sales access to markets in the United States, NG has entered into long-term gas pipeline transportation contracts. Suncor currently has 14 mmcf/day of firm capacity on the Northern Border Pipeline to the U.S. midwest that expires October 31, 2003. Suncor also has firm capacity of 40 mmcf/day on the Pacific Gas Transmission (“PGT”) pipeline to the California border extending to the year 2023.

NG’s conventional crude oil production is used in its refining operations, exchanged for other crude oil with Canadian or U.S. refiners, or sold to Canadian and U.S. purchasers. Sales are generally made under spot contracts or under contracts that are terminable on relatively short notice. Suncor’s conventional crude oil production is shipped on pipelines operated by independent pipeline companies. The NG business currently has no pipeline commitments related to the shipment of crude oil.

The Suncor-owned and operated Albersun pipeline was constructed in 1968 to transport natural gas to the Oil Sands plant. It extends approximately 300 kilometres south of the plant and connects with the TCPL Alberta intra-provincial pipeline system. The Albersun pipeline has the capacity to move in excess of 100 mmcf/day of natural gas. Suncor arranges for natural gas supply and controls most of the natural gas on the system under delivery based contracts. The pipeline moves natural gas both north and south for Suncor and other shippers. In 2002, throughput on the Albersun pipeline was 70 mmcf/day and revenues were approximately $4 million.

Competitive Conditions

Competitive conditions affecting Suncor’s Natural Gas business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.

Capital and Exploration Expenditures

The following table sets out, for the quarters indicated, capital expenditures by Suncor’s NG business unit:

	2002				2001
($ millions)	4Q	3Q	2Q	1Q	4Q	3Q	2Q	1Q
Property acquisition	2	-	-	-	—	-	—	—
Exploration	14	10	9	14	29	4	14	3
Development	18	22	31	43	19	20	17	26

NG expects to spend $160 million in 2003 to support the Company’s goal of increasing natural gas production.

Environmental Compliance

For a description of the impact of environmental protection requirements on NG, refer to “Environmental Regulation and Risk” and “Government Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies” in the “Suncor Overview and Strategic Priorities” section of MD&A..

ENERGY MARKETING & REFINING

Suncor’s EM&R business unit operates a refining and marketing business in Central Canada. Its refinery in Sarnia, Ontario, refines petroleum feedstock from Oil Sands and other sources into gasoline, distillates, and petrochemicals with the majority of them being distributed in its primary market of Ontario.

Approximately 62% of EM&R’s petroleum products sales in 2002 (2001 — 59%) was sold through a distribution network in Ontario that sells gasoline and diesel to retail customers. Approximately 33% (2001 — 38%) was sold to industrial, commercial, wholesale and refining customers in Ontario and Quebec, representing primarily jet fuels, diesel and gasoline. The remaining 5% (2001 — 3%) represents petrochemical sales to the United States and Europe through Sun Petrochemicals Company, a 50% joint venture between a Suncor subsidiary and a U.S. company.

Beginning in 2001, EM&R’s financial reporting is based on its Rack Back / Rack Forward organizational structure. The Rack-Back division procures and refines crude oil and feedstocks, and sells and distributes refined products to the Sarnia refinery’s largest industrial and reseller customers. The Rack-Forward division is comprised of retail operations, retail natural gas marketing (which was sold in the second quarter of 2002), cardlock and industrial / commercial sales, and the UPI Inc. (“UPI”) and Pioneer joint venture businesses. UPI is a joint venture company owned 50% by each of EM&R and GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative. Pioneer is a 50% joint venture partnership between Suncor and The Pioneer Group Inc.

Procurement of Feedstocks

EM&R’s refining operation uses both synthetic and conventional crude oil. Its Sarnia Refinery procured approximately 58% (2001 — 47%) of its synthetic crude oil feedstock from Suncor’s Oil Sands production in 2002. In 2002, 65% (2001 — 55%) of the crude oil refined at the Sarnia Refinery was synthetic crude oil. The balance of the refinery’s synthetic crude oil, as well as its conventional and condensate feedstocks, were purchased from others under month to month contracts. In the event of a significant disruption in the supply of synthetic crude oil, the refinery has the flexibility to substitute other sources of sweet or sour conventional crude oil.

Suncor procures conventional crude oil feedstock for its refinery primarily from western Canada, supplemented from time to time with crude oil from the United States and other countries. Foreign crude oil is delivered to Sarnia via pipeline from the United States Gulf Coast or via the Interprovincial Pipeline from Montreal. Suncor has not made any firm commitments for capacity on these pipeline systems. Crude oil is procured from the market on a spot basis or under contracts terminable on short notice.

In 1998, EM&R signed a 10-year synergistic feedstock agreement with a Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd. Under this buy/sell agreement, EM&R obtains feedstock that is more suitable for production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking. EM&R also enters into reciprocal buy/sell or exchange arrangements with other refining companies from time to time as a means to minimize transportation costs, balance product availability and enhance refinery utilization. EM&R also purchases refined products in order to meet customer requirements.

Refining Operations

The Sarnia Refinery produces transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well as the petrochemicals A-100 and A-150 that are used in the manufacture of paint and chemicals.

The refinery has the capacity to refine 70,000 barrels of crude oil per day. Refining sales in 2002 averaged approximately 91,100 barrels per day (2001 — 93,400). The Sarnia Refinery is configured to allow for operational flexibility. In addition to conventional sweet and sour crudes, the refinery is capable of processing sweet synthetic crude oil, which yields a more valuable product mix. A hydrocracker, jet fuel tower and low-sulphur diesel tower further increase the refinery’s ability to produce premium-value transportation fuels, distillates and naphtha, and its flexibility to vary the gasoline/distillate ratio. The hydrocracker has a capacity to process approximately 23,300 barrels per day. Additional flexibility in gasoline, octane and petrochemical production is provided by the complementary operations of an alkylation unit with a capacity of 5,400 barrels per day. The petrochemical facilities have a capacity of 13,100 barrels per day and produce benzene, toluene, mixed xylenes, orthoxylene and A-100 and A-150.

The refinery has a cracking capacity of 40,200 barrels per day from a Houdry catalytic cracker (“catcracker”) and a hydrocracker. Approximately 40% of the cracking capacity is attributable to the catcracker, which uses older cracking technology.

In 2002, EM&R completed a planned maintenance shutdown on a portion of the refinery, involving a crude unit, vacuum unit, BTX unit, reformer unit, and pretreater unit. However, the refinery also experienced unplanned outages involving the hydrogen plant, the hydrocracker, and the catalytic cracker. Following the planned and unplanned maintenance work, the refinery operated with improved utilization rates in the last two quarters of the year.

Overall, crude utilization averaged 95% for the year, compared with 92% in 2001. The following chart sets out daily crude input, average refinery utilization rates, and cracking capacity utilization of the Sarnia Refinery over the last two years.

Sarnia Refinery Capacity	2002	2001
Average daily crude input (barrels per day)	66,400	64,200
Average crude utilization rate (%)(1)	95	92
Average cracking capacity utilization (%)(2)	91	88

Notes:

(1) Based on crude unit capacity and input to crude units.

(2) Based on cracking capacity and input to the hydrocracker and catalytic cracker.

The refinery’s steam and electricity needs are currently being met by supply from the Sarnia Regional Co-generation Project. For more details, see the EM&R section under “Three Year Highlights” in this Annual Information Form.

Principal Products

Sales of gasolines and other transportation fuels represented 82% of EM&R’s consolidated operating revenues in 2002 compared to 80% in 2001. Set forth below is information on daily sales volumes and percentage of EM&R’s consolidated operating revenues contributed by product group for the last two years.

Product:	2002		2001
	(thousands of cubic meters per day)	(% of EM&R’s consolidated revenues)	(thousands of cubic meters per day)	(% of EM&R’s consolidated revenues)
Transportation Fuels
Gasoline
Retail	4.5	35	4.3	31
Joint Ventures	3.2	19	3.1	17
Other	1.2	11	1.3	11
Jet Fuel	0.4	2	0.7	4
Diesel	2.9	15	3.1	17
Sub-total — Transportation Fuels	12.2	82	12.5	80
Petrochemicals	0.6	5	0.5	4
Heating Fuels	0.4	4	0.4	2
Heavy Fuel Oils	0.6	1	0.8	2
Other	0.7	2	0.6	2
Total Refined Products	14.5	94	14.8	90
Other Non-Refined Products(1)	—	6	—	10
Total%	—	100	—	100

Note:

(1) Includes ancillary revenues including non-fuel retail sales.

Principal Markets

Approximately 62 % (2001 — 59%) of EM&R’s total sales volumes are marketed through retail networks, including the EM&R Sunoco-branded retail network, joint-venture operated retail stations and cardlock operations. This network is comprised of:

· 287 (2001 — 302) Sunoco-branded retail service stations

· 148 (2001 — 154) Pioneer-operated retail service stations

· 50 (2001 — 47) UPI-operated service stations and a network of 15 bulk distribution facilities for rural and farm fuels

· 18 (2001 — 18) Sunoco branded Fleet Fuel Cardlock sites

Refined petroleum products (excluding petrochemicals) are marketed under several brands, including the Company’s Canadian “Sunoco” trademark. EM&R’s other principal trademarks include “Ultra 94” in respect of its premium high octane gasoline, and “Gold Diesel” used in respect of its premium low sulphur diesel product.

Approximately 33% (2001 — 38%) of EM&R’s total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Ontario. EM&R also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners, or through Group Petrolier Norcan Inc., a 25% EM&R-owned fuels terminal and product supply business in Montreal.

EM&R markets toluene, mixed xylenes, orthoxylene and petrochemicals, primarily in Canada and the U.S., through Sun Petrochemicals Company. Suncor Energy Marketing Inc. has a 50% interest in Sun Petrochemicals Company, a petrochemical marketing joint venture that markets products from EM&R’s Sarnia Refinery and from a Toledo, Ohio, refinery owned by the joint venture partner. Sun Petrochemicals Company markets petrochemicals used to manufacture plastics, rubber, synthetic fibres, industrial solvents and agricultural products, and as gasoline octane enhancers. All benzene production is sold directly to other petrochemical manufacturers in Sarnia.

EM&R’s share of total refined product sales in its primary market of Ontario was approximately 17% in 2002 (2001 — 18%), reduced by 1% from 2001 due mainly to reduced distillate sales that resulted from the non-renewal of jet fuel contracts. Transportation fuels accounted for over 83% of EM&R’s total sales volumes in 2002 (2001 — 84%); petrochemicals accounted for 5 % (2001 — 3%). The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to industrial users and resellers.

EM&R supplies refined petroleum products to the Pioneer and UPI joint ventures. The Pioneer supply agreement expires in the fourth quarter of 2003, and thereafter will be automatically renewed for one-year terms unless terminated upon 12 months’ prior written notice. No notice has been given or received.

The UPI supply agreement expired in the second quarter of 2002, and was renewed for a perpetual term subject to the right of either party to terminate the agreement on 120 days prior written notice to the other. The shareholder agreement governing the operation of the joint venture provides that UPI Inc. cannot unilaterally terminate the agreement as long as Suncor remains a shareholder.

Transportation and Distribution

EM&R uses a variety of transportation modes to deliver products to market, including pipeline, water, rail and road. EM&R owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia Refinery to core markets in Ontario is the Sun-Canadian Pipe Line, which is 55% owned by Suncor and 45% owned by another refiner. The pipeline operates as a private facility for its owners. It serves terminal facilities in Toronto, Hamilton and London, and has a capacity of 126,000 barrels per day (20,000 cubic metres). EM&R utilized 53% of this capacity in 2002. Total utilization of the pipeline was 83% in 2002.

EM&R also has direct pipeline access to petroleum markets in the Great Lakes region of the United States by way of connection to a pipeline system in Sarnia operated by a U.S.-based refiner. This link to the U.S. allows EM&R to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets.

EM&R believes that its own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet its current and foreseeable needs.

Competitive Conditions

Competitive conditions affecting Suncor’s EM&R business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.

Capital Expenditures

EM&R plans to spend approximately $145 million in 2003 compared with $78 million in 2002. The bulk of the 2003 spending will be allocated towards projects at Suncor’s Sarnia Refinery designed to meet pending gasoline and distillate desulphurization initiatives, and to integrate production streams from Suncor’s oil sands facility. Increased funds will also be available for investment in the Sunoco retail network. See “Risk/Success Factors Affecting Performance” in the EM&R section of MD&A and “Environmental Regulation and Risk” in the “Risk/Success Factors” section of this Annual Information Form.

Environmental Compliance

For a description of the impact of environmental protection requirements on EM&R, please refer to the sections entitled “Outlook” and “Risk/Success Factors Affecting Performance” in the EM&R section of MD&A. Also refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section and the EM&R “Three Year History” section, of this Annual Information Form, and “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies” in the “Suncor Overview and Strategic Priorities” section of MD&A.

SUNCOR EMPLOYEES

The following table shows the distribution of employees among Suncor’s three business units and its corporate office for the past two years.

	as at
	December 31,
	2002	2001
Oil Sands	2,459	2,367
Natural Gas	191	190
Energy Marketing & Refining(1)	576	561
Corporate	196	189
Total(3)	3,422	3,307

Notes:

(1) Excludes joint venture employees.

(2) Reflects inclusion of Calgary-based employees providing technical support to the Firebag Project.

(3) In addition to Suncor employees, independent contractors supply a range of services to the Company.

The Communications, Energy and Paperworkers Union Local 707 represents approximately 1,500 Oil Sands employees. Suncor entered into a three-year collective agreement with the union effective May 1, 2001. Management believes Suncor’s positive working relationship with the union will continue.

Employee associations represent approximately 171 of EM&R’s Sarnia refinery and Sun-Canadian Pipe Line Company employees. In March 2002, a three-year agreement was signed with the Sarnia employee association that will be renegotiated in 2005. The agreement with the employee association of Sun-Canadian Pipe Line Company was signed in 1993, and it is renewed automatically each year unless terminated by written notice by either party at least 60 days prior to the anniversary date of the agreement. No notice under such agreement has been received or given to date. Management believes Suncor’s positive working relationship with this association will continue and the agreement will be automatically renewed on its anniversary. The employees at EM&R’s London Terminal are currently

negotiating their first collective bargaining agreement. Currently there are 11 eligible employees for membership with Local #27 of the Canadian AutoWorkers (CAW), a private sector union in Canada.

RISK/SUCCESS FACTORS

Volatility of Crude Oil and Natural Gas Prices. Suncor’s future financial performance is closely linked to oil prices, and to a lesser extent natural gas prices. The price of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of Petroleum Exporting Countries and weather, among other things, can affect world oil supply and demand. Natural gas prices realized by Suncor are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond Suncor’s control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for sour crude oil. In 2002, the heavy-light differential narrowed and improved Suncor’s earnings. Management believes the differential will widen in 2003 from 2002 levels due to increased supply in the Canadian market and crude oil pricing. Oil and natural gas prices have fluctuated widely in recent years and Suncor expects continued volatility and uncertainty in crude oil and natural gas prices. A prolonged period of low crude oil prices could affect the value of Suncor’s crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production at some properties. Accordingly, low crude oil prices could have an adverse impact on Suncor’s financial condition and liquidity and results of operations.

Suncor cannot control the factors that influence supply and demand for, or the prices of, crude oil or natural gas. However, the Company has a hedging program that periodically fixes the price or a range of prices for its crude oil, natural gas, and the associated Canada/U.S. dollar exchange rate for a percentage of Suncor’s total production volume. Suncor’s objective is to manage exposure to market volatility and lend more certainty to the Company’s ability to finance growth. If an operational upset occurred that reduced or eliminated crude oil and/or natural gas production for a period of time, Suncor would be required to continue to make payments under its hedging program if the actual price was higher than the hedged price. In addition, Suncor’s hedging program is subject to many of the risks described under the heading, “Risks Associated with Energy Trading Activities”, below. For particulars of Suncor’s hedging position as of year-end 2002, see Note 5 of Suncor’s 2002 Consolidated Financial Statements, which note is incorporated by reference herein.

Suncor conducts an assessment of the carrying value of its assets to the extent required by Canadian generally accepted accounting principles. If crude oil and natural gas prices decline, the carrying value of Suncor’s assets could be subject to downward revisions, and Suncor’s earnings could be adversely affected.

Volatility of Downstream Margins. EM&R operations are sensitive to wholesale and retail margins for its refined products, including gasoline. Margin volatility is influenced by overall marketplace competitiveness, weather, the cost of crude oil (see “Volatility of Crude Oil and Natural Gas Prices”) and fluctuations in supply and demand for refined products. EM&R expects that margin and price volatility and overall marketplace competitiveness, including the potential for new market entrants, will continue.

Risk Factors Related to Firebag and Voyageur Projects. There are certain risks associated with the execution of the proposed Firebag Project and Voyageur, including: regulatory approvals, risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; Suncor’s ability to finance growth if commodity prices were to stay at low levels for an extended period; the impact of new entrants to the oil sands business which could take the form of competition for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads and schools) and price competition for products sold into the marketplace; the potential ceiling on the demand for synthetic crude oil; and the effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment. The

commissioning and integration of new facilities with the existing asset base could cause delays in achieving targeted production capacity. Suncor management believes the planned increases in Oil Sands production through these projects present issues that require prudent risk management.

Risks Associated with In-Situ Extraction. Current steam-assisted gravity drainage (SAGD) technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam which is used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using this technology. Suncor has been advised by GLJ that in 2002, a number of operational commercial SAGD projects were in service, although no such projects have been operational for any extended period of time. Commercial application of this technology is not yet commonplace.

Increased Dependence on Oil Sands business. The Company’s significant capital commitment to further its growth projects at Oil Sands, including the Firebag Project, and Voyageur if approved, may require Suncor to forego investment opportunities in other segments of its operations. The completion of future projects to increase production at Oil Sands will further increase the Company’s dependence on the Oil Sands segment of its business. For example, in 2002, the Oil Sands business accounted for approximately 86% (79% in 2001) of Suncor’s upstream production, 89% (59% in 2001) of Suncor’s net earnings and 85% (52% in 2001) of Suncor’s cash flow provided from operations.

Interdependence of Oil Sands Systems. The Oil Sands plant is susceptible to loss of production due to the interdependence of its component systems. For example, over the past four years, there have been a total of four outages, some of which were unplanned, of the 5C9 fractionator, an upgrading unit that separates hydrocarbon vapours into naphtha, kerosene and gas oil. These outages resulted in lost production of approximately 1.8 million barrels in each of 1999 and 2001, and approximately 0.8 million barrels in 2002. In 2003, Suncor plans to complete an $80 million project to replace the 5C9 fractionator with a larger unit that is expected to increase throughput, improve product quality and enhance reliability.

Through expansion projects like Millennium, Suncor expects to mitigate adverse impacts of its interdependent systems and to reduce the production and cash flow impacts of complete plant-wide shutdowns. For example, Millennium added a second complete processing operation, which provides Suncor with the flexibility to conduct periodic plant maintenance on one operation while continuing to generate production and cash flow from the other.

Competition. The petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of crude oil and natural gas interests, and the refining, distribution and marketing of petroleum products and chemicals. Suncor competes in virtually every aspect of its business with other energy companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers. Suncor believes that the competition for its custom blended synthetic crude oil production is other Canadian conventional and synthetic sweet and sour crude oil.

A number of other companies have entered or have indicated they are planning to enter the oil sands business and begin production of bitumen and synthetic crude oil, or expand existing operations. Recently some projects have been deferred. It is difficult to assess the number, level of production and ultimate timing of all of the potential new producers or where existing producers may increase production levels. Based on management’s knowledge of other projects derived from publicly available information, Canada’s production of bitumen and upgraded synthetic crude oil could increase to almost two million barrels (300,000 cubic metres) per day by the end of the decade. The trend toward industry consolidation has created more competitors with financial capacity who may enter into similar and competing oil sands businesses. The expansion of existing operations and development of new projects could materially increase the supply of bitumen and synthetic crude oil and other competing crude oil products in the marketplace. Depending on the levels of future demand, increased supplies could have a negative impact on prices.

In the western Canadian diesel market demand and supply can fluctuate. Currently there is excess supply of diesel fuel which has resulted in reduced margins. Margins for diesel are typically higher than the margins for synthetic and conventional crude oil. The above noted expansion plans of Suncor’s competitors could also result in an increase in the supply of diesel and further weakening of margins.

Historically, the industry-wide oversupply of refined petroleum products and the overabundance of retail outlets have kept pressure on downstream margins. Management expects that fluctuations in demand for refined products, margin volatility and overall marketplace competitiveness will continue. In addition, to the extent that Suncor’s downstream business unit, EM&R, participates in new product markets, it could be exposed to margin risk and volatility from either cost and/or selling price fluctuations.

Need to Replace Conventional Natural Gas Reserves. The future natural gas reserves and production of the Company’s NG business unit and, therefore, both Suncor’s cash flow from such production and Suncor’s ability to maintain a price hedge against growing consumption of natural gas in its Oil Sands and EM&R operations, are highly dependent on its success in discovering or acquiring additional reserves and exploiting its current reserve base. Without natural gas reserve additions through exploration and development or acquisition activities, Suncor’s conventional natural gas reserves and production will decline over time as reserves are depleted. For example, in 2002, Suncor’s average natural gas reservoir decline rates were in the 25% range (2001 — 28%), consistent with industry experience. Decline rates will vary with the nature of the reservoir, life-cycle of the well, and other factors. Therefore past decline rates are not necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly capital intensive. To the extent cash flow from operations is insufficient to generate sufficient capital and external sources of capital become limited or unavailable, Suncor’s ability to make the necessary capital investments to maintain and expand its conventional natural gas reserves could be impaired. In addition, the long term performance of Suncor’s NG business is dependent on its ability to consistently and competitively find and develop low cost, high-quality reserves that can be economically brought on stream. Market demand for land and services can also increase or decrease finding and development costs. There can be no assurance that Suncor will be able to find and develop or acquire additional reserves to replace production at acceptable costs.

Risks Related to Coal Bed Methane. Coal Bed Methane (CBM) exploration is being undertaken by Suncor in Canada, and in the U.S. through a wholly owned subsidiary, Suncor Energy (Natural Gas) America Inc. The identification of gas in coals is necessary but not sufficient for establishing commercial success. Effective production technology, water handling, well productivity and surface access, a requirement for large land blocks, and a pilot production period are risk elements unique to CBM. Other producers’ Canadian activities in CBM have progressed to the pilot test stage with several projects that have wells producing salable gas. Suncor views the ultimate viability and profitability of these plays as uncertain.

CBM is a commercial gas resource in the U.S. The risks associated with CBM activities in the U.S. vary by geographic region but can include: constraints on land access from federal, state and individual land holders; local opposition to well drilling and CBM development; high costs of treating water produced with CBM gas; limited regional pipeline exit capacity; and strong competition for mineral leases and services. The regulatory framework and stakeholder environment varies by region. The physical operation of drilling and ultimately producing gas in a location distant from Suncor’s key management presents risks of inadequate oversight of operations. Business activity in the U.S. has different political risk than in Canada, and is conducted in an environment where litigation and legal risk are more prevalent and substantial.

Operating Hazards and Other Uncertainties. Each of Suncor’s three principal business units, Oil Sands, NG and EM&R, require high levels of investment and have particular economic risks and opportunities. Generally, Suncor’s operations are subject to hazards and risks such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts and oil spills, any of which can cause personal injury, damage to property, equipment and the environment, as well as interrupt operations. In addition, all of Suncor’s operations are subject to all of the risks normally incident to the transportation, processing and storing of crude oil, natural gas and other related products.

At Oil Sands, mining oil sand, extracting bitumen from the oil sand, and upgrading bitumen into synthetic crude oil and other products, involve particular risks and uncertainties. Oil Sands is susceptible to loss of production, slowdowns, or restrictions on its ability to produce higher value products due to the interdependence of its component systems. Severe climatic conditions at Oil Sands can cause reduced production and in some situations result in higher costs. While there is virtually no finding cost associated with oil sands resources, the costs associated with production, including mine development and drilling of wells for SAGD operations, and the costs associated with upgrading bitumen into synthetic crude oil, can entail significant capital outlays. The costs associated with synthetic crude oil production at Oil Sands are largely fixed and, as a result, operating costs per unit are largely dependent on levels of production.

Aboriginal peoples have claimed aboriginal title and rights to a substantial portion of western Canada. Certain aboriginal peoples have filed a claim against the government of Canada, certain governmental entities and the Regional Municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta), claiming, among other things, a declaration that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which Oil Sands and most of the other oil sands operations in Alberta are situated. To Suncor’s knowledge the aboriginal peoples have made no claims against Suncor and Suncor is unable to assess the effect, if any, the claim would have on its Oil Sands operations.

In Suncor’s NG business unit, the risks and uncertainties associated with the exploration for, and the development, production, transportation and storage of crude oil, natural gas and natural gas liquids should not be underestimated or viewed as predictable. NG’s operations are subject to all of the risks normally incident to drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution, and other environmental risks.

Suncor’s downstream business unit, EM&R, is subject to all of the risks normally incident to the operation of a refinery, terminals and other distribution facilities, as well as service stations, including loss of product or slowdowns due to equipment failures or other accidents.

Although Suncor maintains a risk management program, including an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable. Losses resulting from the occurrence of these risks could have a material adverse impact on Suncor. Refer to Note 9(b) to Suncor’s 2002 Consolidated Financial Statements, which note is incorporated by reference herein, for further description of Suncor’s insurance coverage.

In addition, there are risks associated with growth projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations. The success of projects incorporating new technologies, such as the Firebag Project, cannot be assured.

There are also inherent risks, including political and foreign exchange risk, in investing in business ventures internationally. Currently, Suncor does not have material international investments but it continues to assess downstream integration and coal bed methane opportunities in the United States. Export sales in 2002 represented 10% of Suncor’s 2002 consolidated revenue (2001 — 14%).

Interest Rate Risk. Suncor is exposed to fluctuations in short-term Canadian interest rates as a result of the use of floating rate debt. Suncor maintains a substantial portion of its debt capacity in revolving, floating rate bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To minimize its exposure to interest rate fluctuations, Suncor occasionally enters into interest rate swap agreements and exchange contracts to either effectively fix the interest rate on floating rate debt or to float the interest rate on fixed rate debt. For more details, see the “Liquidity and Capital Resources” section of MD&A.

Exchange Rate Fluctuations. Suncor’s 2002 Consolidated Financial Statements are presented in Canadian dollars. Results of operations are affected by the exchange rates between the Canadian dollar and the U.S. dollar. These exchange rates have varied substantially in the last five years. A substantial portion of Suncor’s revenue is received by reference to U.S. dollar denominated prices, and a significant portion of Suncor’s debt is denominated in U.S. dollars. Crude oil and natural gas prices are generally based in U.S. dollars, while Suncor’s sales of refined products are primarily in Canadian dollars. Fluctuations in exchange rates between the U.S. and Canadian dollar may therefore give rise to foreign currency exposure, either favorable or unfavorable, creating another element of uncertainty. In the future, the strength of the Canadian dollar relative to foreign currencies could create additional uncertainties for Suncor.

Environmental Regulation and Risk. Environmental regulation affects nearly all aspects of Suncor’s operations. These regulatory regimes are laws of general application that apply to Suncor in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require Suncor to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new major projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, Suncor expects future changes to environmental legislation, including anticipated legislation to implement Canada’s ratification of the Kyoto Accord, will impose further requirements on companies operating in the energy industry. Some of the issues that are or may in future be subject to environmental regulation include the possible cumulative impacts of oil sands development in the Athabasca region; storage, treatment, and disposal of hazardous or industrial waste; the need to reduce or stabilize various emissions; issues relating to global climate change, land reclamation and restoration; Great Lakes water quality; and reformulated gasoline to support lower vehicle emissions. Changes in environmental regulation could have a potentially adverse effect on Suncor from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on Suncor. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important permits.

Suncor is required to and has posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced ($16 million as at December 31, 2002) as security for the estimated cost of its reclamation activity on Leases 86 and 17, and the Steepbank Mine. For Project Millennium, Suncor has posted an irrevocable letter of credit equal to approximately $27 million, representing security for the estimated cost of reclamation activities relating to Project Millennium up to the end of December 2002. Subsequent to year end, the face amount of these letters of credit was increased to approximately $70 million in aggregate. For the Firebag Project, Suncor has posted an irrevocable letter of credit equal to approximately $5 million, representing security for the estimated cost of reclamation activities relating to the project up to the end of December 2002. For more information about Suncor’s reclamation and environmental mediation obligations, refer to “Reclamation and Environmental Remediation Cost” under “Critical Accounting Policies” in the “Suncor Overview and Strategic Priorities” section of MD&A.

In 1999, the Canadian government passed legislation limiting sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm thereafter. The Canadian refining industry faces significant capital spending to construct sulphur removal facilities to meet these requirements. In 2001 EM&R finalized an investment plan to meet those limits. Capital spending to achieve compliance is expected to be approximately $40 million, and will involve the addition of a new desulphurization unit. The project has been progressing on schedule and construction of the unit is expected to be completed in 2003.

In 2002, the Canadian government also passed legislation limiting the concentration of sulphur in diesel fuel produced or imported for use in on-road vehicles to a maximum of 500 ppm until May 31, 2006, and a maximum of 15 ppm thereafter. Capital spending required to achieve compliance is estimated at approximately $225 million.

Regulations reducing sulphur in off-road diesel and light fuel oil are also expected to take effect later in the decade. At this time it is not possible to assess the impact these expected regulations may have on EM&R. The ultimate cost to comply may vary as details of the regulations are announced. In addition, EM&R is evaluating several strategic options including the potential to enhance integration of the Sarnia Refinery with production from Oil Sands, and to possibly increase value through integration with the diesel desulphurization facilities.

Uncertainty of Reserve and Resource Estimates. The reserve data and resource estimates for Suncor’s Oil Sands and NG business units, included in Suncor’s Annual Information Form, represent estimates only. There are numerous uncertainties inherent in estimating quantities and quality of these proved and probable reserves and other resources, including many factors beyond the control of Suncor.

In general, estimates of economically recoverable reserves are based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies and future operating costs, all of which may vary considerably from actual results. The accuracy of any reserve estimate is a matter of engineering interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time. In the Oil Sands business unit, reserve estimates are based upon a geological assessment, including drilling and laboratory tests, and also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints. The Firebag reserves and resource estimates are based upon a geological assessment based upon the data gathered from evaluation drilling, the testing of core samples and seismic operations and demonstrated commercial success of the in-situ process. In the NG business unit, reservoir performance subsequent to the date of the estimate may justify revision, either upward or downward. For these reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, and in NG the classification of such reserves based on risk of recovery prepared by different engineers or by the same engineers at different times, may vary substantially. At Oil Sands, the independent audit of mining reserves does not take into account the economic aspects of future reserves. Suncor’s actual production, revenues, taxes and development and operating expenditures with respect to its reserves will vary from such estimates, and such variances could be material.

Certain information included in this Annual Information Form to describe Suncor’s reserves, such as “probable reserves”, “proved plus probable reserves” and “resources” is presented in accordance with Canadian disclosure requirements, but would be prohibited in filings with the United States Securities and Exchange Commission by U.S. companies. The differences between Canadian and U.S. standards of reporting reserves and resources may make it difficult to compare Suncor’s reserve information with the reserve information of companies subject to the U.S. standards of reporting. For additional supplementary disclosures relating to Suncor’s oil and gas activities in accordance with Statement 69 of the U.S. Financial Accounting Standards Board, refer to the disclosures made pursuant to Exhibit 1 to Suncor’s Form 40-F, filed with the U.S. Securities and Exchange Commission and also filed with Canadian securities regulatory authorities, which Exhibit is incorporated by reference herein.

Labour Relations. Suncor’s hourly employees at its Oil Sands facility near Fort McMurray, its London terminal operation, its Sarnia refinery and Sun-Canadian Pipeline Company are represented by labour unions or employee associations. Any work interruptions involving Suncor’s employees, or contract trades utilized in its growth projects, could materially and adversely affect Suncor’s business and financial position.

Risk Associated with the Energy Trading Activities. The nature of trading activities creates exposure to financial risks. These include risks that movements in prices or values will result in a financial loss to the Company; a lack of counterparties will leave the Company unable to liquidate or offset a position, or

unable to do so at or near the previous market price; the Company will not receive funds or instruments from its counterparty at the expected time; the counterparty will fail to perform an obligation owed to the Company; the Company will suffer a loss as a result of human error or deficiency in its systems or controls; or that the Company will suffer a loss as a result of contracts being unenforceable or transactions being inadequately documented. A separate risk management function within Suncor directs and monitors practices and policies and provides independent verification and valuation of Suncor’s trading and marketing activities.

Governmental Regulation. The oil and gas industry in Canada, including the oil sands industry and the downstream segment of the Company, operates under federal, provincial and municipal legislation. This industry is also subject to regulation and intervention by governments in such matters as land tenure, royalties, government fees, production rates, environmental protection controls, the reduction of greenhouse gas emissions, the export of crude oil, natural gas and other products, the awarding or acquisition of exploration and production, oil sands or other interests, the imposition of specific drilling obligations, environmental protection controls, control over the development and abandonment of fields and mine sites (including restrictions on production) and possibly expropriation or cancellation of contract rights. Before proceeding with most major projects, including significant changes to existing operations, Suncor must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other things. In addition, regulatory approvals may be subject to conditions including security deposit obligations and other commitments. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment or restructuring of projects and increased costs, all of which could negatively affect future earnings and cash flow. Such regulations may be changed from time to time in response to economic or political conditions. The implementation of new regulations or the modification of existing regulations affecting the crude oil and natural gas industry could reduce demand for crude oil and natural gas, increase Suncor’s costs and have a material adverse affect on its financial condition.

SELECTED CONSOLIDATED FINANCIAL INFORMATION

Selected Consolidated Financial Information

The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2002 is derived from Suncor’s 2002 Consolidated Financial Statements. Suncor’s consolidated financial statements for each of the years in the three-year period ended December 31, 2002 have been audited by PricewaterhouseCoopers LLP, Chartered Accountants. The information set forth below should be read in conjunction with MD&A and Suncor’s 2002 Consolidated Financial Statements.

	Year ended December 31,(1)
	2002	2001	2000
	($ millions except per share amounts)
Revenues	4,904	4,199	3,388
Net earnings	761	388	377
Per common share(1) (undiluted)	1.64	0.79	0.78
Per common share(1) (diluted)	1.61	0.78	0.77
Cash flow provided from operations	1,440	831	958
Per common share(1)	3.11	1.76	2.06
Capital and exploration expenditures	877	1,678	1,998

	Year ended December 31,(1)
	2002	2001	2000
	($ millions except per share amounts)
Total assets	8,683	8,094	6,833
Long-term debt(2)	2,686	3,113	2,193
Accrued liabilities and other(3)	226	251	252
Common shareholders’ equity(4)	2,935	2,255	1,961

Notes:

(1) Per share amounts for all years reflect two-for-one share splits in 2002 and 2000, and dividend payments and foreign currency revaluation related to the Company’s preferred securities.

(2) Includes current portion.

(3) See Note 6 to Suncor’s 2002 Consolidated Financial Statements, which Notes are incorporated by reference herein.

(4) Excludes Preferred Securities issued in 1999. See Dividend Policy and Record.

The following table sets forth, for each of the two most recently completed financial years, the revenues for each category of Suncor’s principal products or services that accounted for 15 per cent or more of Suncor’s total consolidated revenues.

Revenues from	($ millions)		%	($ millions)		%
Transportation fuel sales	2,266		46	2,277		54
Crude oil sales	1,954		40	1,017		24
Other	682		14	900		22

Total	4,902	(1)	100	4,194	(1)	100

Note:

(1) Excludes interest income.

Dividend Policy and Record

Suncor’s Board of Directors has established a policy of paying dividends on a quarterly basis. This policy is reviewed from time to time in light of Suncor’s financial position, its financing requirements for growth, its cash flow and other factors considered relevant by Suncor’s Board of Directors.

During 1999, the Company completed a Canadian offering of $276 million of 9.05% preferred securities and a U.S. offering of U.S.$162.5 million of 9.125% preferred securities, the proceeds of which totaled Canadian $507 million after issue costs of $17 million ($10 million after income tax credits of $7 million). The preferred securities are unsecured junior subordinated debt of the Company, due in 2048 and redeemable at the Company’s option on or after March 15, 2004 for proceeds equal to the original principal amount of the preferred securities plus any accrued and unpaid interest as at the date of redemption. Subject to certain conditions, the Company has the right to defer payment of interest on the securities for up to 20 consecutive quarterly periods. Deferred interest and principal amounts are payable in cash, or, at the option of the Company, from the proceeds on the sale of equity securities of the Company delivered to the trustee of the preferred securities. For accounting purposes, the preferred securities are classified as share capital in the consolidated balance sheet and the interest distributions thereon, net of income taxes, are classified as dividends in the Company’s 2002 Consolidated Financial

Statements, but generally treated as interest income to the recipient for Canadian or U.S. tax purposes.

The following table sets forth the per share amount of dividends paid by Suncor during the last three years.

	Year ended December 31,
	2002		2001		2000
Common Shares cash dividends(1)	$	0.17	$	0.17	$	0.17
Preferred securities cash interest distributions(1)(2)	$	0.11	$	0.11	$	0.11
Dividends paid in common shares	—		—		—

Note:

(1) Per share amounts have been adjusted to reflect a two-for-one share split in 2002.

(2) Per share preferred securities cash interest distributions are calculated as total preferred securities dividends divided by the weighted average outstanding common shares in the year.

Future Commitments to Buy, Sell, Exchange or Transport Crude Oil And Natural Gas

In order to ensure continued availability of, and access to, transportation facilities for the crude oil and natural gas products of its Oil Sands and Natural Gas business units, the Company has entered into long-term contracts for pipeline capacity on various third party systems.

The Company’s Oil Sands business unit has entered into a long-term commitment with Enbridge for the transportation of sour crude oil and bitumen from Suncor’s oil sands plant near Ft. McMurray, Alberta, to Hardisty, Alberta. Particulars of that commitment are described under the heading “Operations” in the “Oil Sands” section of this Annual Information Form.

Natural gas product pipeline commitments are described in the following table:

Nature of Commitments	Term	Volume (mmcf/day)	Aggregate Price/Cost ($ Millions)	Price Per mcf

Natural gas pipeline commitments:
Nova	1998-2008	**	25	$	0.17
Westcoast Energy	2001-2006	27	7	$	0.27
Foothills	1997-2003	16	1	$	0.08
Northern Border	1997-2003	14	2	$	0.48
Alberta Natural Gas	1991-2008	41	6	$	0.07
Pacific Gas Transmission	1995-2023	40	130	$	0.43

**volume varies on an annual basis.

The Company’s Natural Gas business has entered into numerous natural gas purchase and sale commitments, aggregating 50 mmcf/day and 180 mmcf/day, respectively. Purchase commitments are for one year terms with variable pricing, representing index-based pricing. Sales commitments consist of both short- and long- term contracts ranging from one to five years in duration, with variable pricing generally based on a combination of fixed and index-based terms.

Oil Sands has also entered into long-term contracts to sell crude oil products to customers, some of which are described under the heading, “Sales of Synthetic Crude Oil and Diesel” in the “Oil Sands” section of this Annual Information Form. In addition, the Company periodically enters into crude oil and foreign

currency swap and option contracts to protect its future Canadian dollar earnings and cash flows from the potential adverse impact of low petroleum prices and an unfavourable U.S./Canadian dollar exchange rate. For further particulars of these hedging arrangements, see the information under the heading “Hedging”, under “Risk/Success Factors Affecting Performance” in the “Suncor Overview and Strategic Priorities” section of the Company’s MD&A, and Note 5 to Suncor’s 2002 Consolidated Financial Statements, which note is incorporated by reference herein.

Also see Note 9(a) to Suncor’s 2002 Consolidated Financial Statements, which note is incorporated by reference herein, for a further description of the Company’s operating commitments for 2003 and subsequent years.

MANAGEMENT’S DISCUSSION AND ANALYSIS

Suncor’s MD&A is incorporated by reference into and forms an integral part of this Annual Information Form, and should be read in conjunction with Suncor’s 2002 Consolidated Financial Statements and the notes thereto.

MARKET FOR THE SECURITIES OF THE ISSUER

The common shares of Suncor are listed on The Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United States. To the best of management’s knowledge, approximately 40% of Suncor’s common shares are beneficially held by residents of the United States. Suncor’s 9.05% preferred securities are listed on The Toronto Stock Exchange in Canada, and Suncor’s 9.125% preferred securities are listed on the New York Stock Exchange in the United States.

DIRECTORS AND EXECUTIVE OFFICERS

Directors

Reference is made to the information under the heading, “Election of Directors” on pages 3 - 6 inclusive of Suncor’s Management Proxy Circular dated February 27, 2003 for information regarding Suncor’s directors, which information is incorporated by reference into this Annual Information Form.

Executive Officers

The following are the executive officers of the Corporation. Except where otherwise indicated, the persons named in the table below held the offices set out opposite their respective names as at December 31, 2002 and as of the date hereof.

Name and Municipality of Residence		Office(1)

RICHARD L. GEORGE		President and Chief Executive Officer
Calgary, Alberta

M.M. (MIKE) ASHAR		Executive Vice President, Oil Sands
Fort McMurray, Alberta

DAVID W. BYLER		Executive Vice President, Natural Gas and Renewable
M.D. of Rockyview, Alberta		Energy

STEVEN W. WILLIAMS		Executive Vice President, Corporate Development and
Calgary, Alberta		Chief Financial Officer

Name and Municipality of Residence		Office(1)

THOMAS L. RYLEY		Executive Vice President, Energy Marketing and Refining
Toronto, Ontario

TERRENCE J. HOPWOOD		Senior Vice President and General Counsel
Calgary, Alberta

SUE LEE		Senior Vice President, Human Resources and
Calgary, Alberta		Communications

KEVIN D. NABHOLZ		Senior Vice President, Major Projects
Calgary, Alberta

J. KENNETH ALLEY		Vice President, Finance
Calgary, Alberta

All of the foregoing executive officers of the Company have, for the past five years, been actively engaged as executives or employees of Suncor or its affiliates, except Mr. Williams, who joined the Company in May 2002. Prior to joining Suncor, Mr. Williams held various executive positions with Octel Corporation, a global chemicals company. Prior to joining Octel Corporation in 1995, Mr. Williams held executive positions with Esso Petroleum Company Limited, an affiliate of Exxon.

The percentage of Common Shares of Suncor owned beneficially, directly or indirectly, or over which control or direction is exercised by Suncor’s directors and executive officers, as a group, is less than 1%.

Additional Disclosure for Directors and Executive Officers

To the best of our knowledge, having made due inquiry, Suncor confirms that, as at December 31, 2002:

(i) in the last ten years, no director or executive officer of Suncor is or has been a director or officer of another issuer that, while that person was acting in that capacity,

(a) was the subject of a cease trade or similar order, or an order that denied the other issuer access to any exemptions under Canadian securities legislation for a period of more than 30 consecutive days; or

(b) became bankrupt or made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangements or compromises with creditors or had a receiver, receiver manager or trustee appointed to hold its assets, other than Mr. Canfield, a director of Suncor who was a director of Royal Trust Co. in 1994 when it entered into a plan of arrangement with creditors and Mr. Korthals, a director of Suncor who was a director of Anvil Range Mining Corporation, which sought protection under the Companies Creditors Arrangement Act (Canada) in 1998;

(ii) no director or executive officer of Suncor has

(a) been subject to any penalties or sanctions imposed by a court relating to Canadian securities legislation or by a Canadian securities regulatory authority or has entered into a settlement agreement with a Canadian securities regulatory authority; or

(b) has been subject to any other penalties or sanctions imposed by a court or regulatory body that would likely be considered important to a reasonable investor in making an investment decision;

(iii) no director or executive officer of Suncor nor any personal holding company controlled by such person has become bankrupt, made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee appointed to hold the assets of the director or executive officer; and

(iv) no director or executive officer has any direct or indirect material interest in respect of any matter that has materially affected or will materially affect Suncor or any of its subsidiaries.

ADDITIONAL INFORMATION

Copies of the documents set out below may be obtained by any person upon request to the Secretary of the Company at 112 - 4 Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by e-mail request to info@suncor.com.

(i) The current Suncor Annual Information Form together with any pertinent information incorporated by reference therein;

(ii) The current Suncor comparative financial statements for the most recently completed financial year and the report of the auditors relating thereon, together with any subsequent interim financial statements;

(iii) Suncor’s management proxy circular in respect of its most recent annual meeting of shareholders that involved the election of directors; and

(iv) Any other documents incorporated by reference into Suncor’s most recent preliminary short form prospectus or short form prospectus if securities of Suncor are in the course of distribution pursuant to such documents.

Copies of such documents will be made available without charge at any time when Suncor’s securities are in the course of distribution pursuant to a short form prospectus. At any other time Suncor reserves the right to impose a reasonable charge for requests by persons other than security holders. Such documents are available electronically on Suncor’s web site at www.suncor.com.

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of Suncor’s securities, options to purchase securities and interests of insiders in material transactions, where applicable, is contained in Suncor’s most recent management proxy circular for its most recent annual meeting of its shareholders that involved the election of directors. Additional financial information is provided in Suncor’s 2002 Consolidated Financial Statements.

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A. Undertaking

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

B. Consent to Service of Process

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

CONTROLS AND PROCEDURES

A. Evaulation

Based on their evaluation as of a date within 90 days of the filing date of this report, Registrant’s Chief Executive Officer and Chief Financial Officer had concluded that Registrant’s disclosure controls and procedures as defined in Rule 13(a)-14(c) and 15(d)-14(c) under the Exchange Act are effective to ensure that, information required to be disclosed by the Registrant in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

B. Changes in Internal Controls

There were no significant changes in the Registrant’s internal controls or in other factors that could significantly affect these controls subsequent to the date of their evaluation, nor were there any significant deficiencies or material weaknesses in the Registrant’s internal controls. As a result, no corrective actions were required or undertaken.

SIGNATURES

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

SUNCOR ENERGY INC.

DATE:	April 3, 2003	PER:	“RICHARD L. GEORGE”
			RICHARD L. GEORGE
			President and Chief Executive
			Officer

CERTIFICATIONS

I, RICHARD L. GEORGE, President and Chief Executive Officer of Suncor Energy Inc. (“Registrant”), certify that:

1. I have reviewed this annual report on Form 40-F of the Registrant;

2. Based on my knowledge, this annual report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this annual report;

3. Based on my knowledge, the financial statements, and other financial information included in this annual report, fairly present in all material respects the financial condition, results of operations and cash flows of the Registrant as of, and for, the periods presented in this annual report;

4. The Registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-14 and 15d-14) for the Registrant and have:

(a) designed such disclosure controls and procedures to ensure that material information relating to the Registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

5. The Registrant’s other certifying officer and I have disclosed, based on our most recent evaluation, to the Registrant’s auditors and the audit committee of Registrant’s board of directors (and persons performing the equivalent function):

(a) all significant deficiencies in the design or operation of internal controls which could adversely affect the Registrant’s ability to record, process, summarize and report financial data and have identified for the Registrant’s auditors any material weaknesses in internal controls; and

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls; and

6. The Registrant’s other certifying officer and I have indicated in this annual report whether there were significant changes in internal controls or in other factors that could significantly affect internal controls subsequent to the date of our most recent evaluation, including any corrective actions with regard to significant deficiencies and material weaknesses.

SUNCOR ENERGY INC.

DATE:	April 3, 2003	PER:	“RICHARD L. GEORGE”
			RICHARD L. GEORGE
			President and Chief Executive
			Officer

I, STEVEN W. WILLIAMS, Executive Vice President, Corporate Development and Chief Financial Officer of Suncor Energy Inc. (“Registrant”), certify that:

1. I have reviewed this annual report on Form 40-F of the Registrant;

(b) evaluated the effectiveness of the Registrant’s disclosure controls and procedures as of a date within 90 days prior to the filing date of this annual report (the “Evaluation Date”); and

(c) presented in this annual report our conclusions about the effectiveness of the disclosure controls and procedures based on our evaluation as of the Evaluation Date;

(b) any fraud, whether or not material, that involves management or other employees who have a significant role in the Registrant’s internal controls; and

SUNCOR ENERGY INC.

DATE:	April 3, 2003	PER:	“STEVEN W. WILLIAMS”
			STEVEN W. WILLIAMS
			Executive Vice President,
			Corporate Development and
			Chief Financial Officer

EXHIBIT INDEX

Exhibit No.		Description

1		U.S. Oil and Gas Data

2		Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2002, including reconciliation to U.S. GAAP (Note 19)

3		Management’s Discussion and Analysis for the fiscal year ended December 31, 2002, dated February 27, 2003

4		Excerpts from pages 2 to 6 inclusive of Suncor Energy Inc.’s Management Proxy Circular dated February 27, 2003

5		Consent of PricewaterhouseCoopers LLP

6		Consent of Gilbert Laustsen Jung Associates Ltd.

7		Certificate of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

8.		Certificate of the Executive Vice President, Corporate Development and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002