SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.   20549

FORM 40-F

(Check One)

SUNCOR ENERGY INC.

(Exact name of registrant as specified in its charter)

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

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:

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:

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.

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

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

March 21, 2005

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

ii

iii

GLOSSARY OF TERMS

Bitumen/Heavy Oil

A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane, which 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.

Developed Reserves

Developed reserves are those proved reserves that are expected to be recovered from existing wells and installed facilities or, if facilities have not been installed, that would involve a low expenditure (e.g., when compared to the cost of drilling a well) to put the reserves on production.

Downstream

These business segments manufacture, distribute and market 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

Suncor’s undivided percentage interest in production/reserves, as the case may be, 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.

iv

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.

MD&A

Suncor’s Management’s Discussion and Analysis dated February 23, 2005, 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, 2004, which 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, 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⁽¹⁾

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely⁽²⁾ that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

(1)           We are subject to Canadian disclosure rules in connection with the reporting of reserves.  However, we have received exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S. disclosure practices.  In addition, although U.S. companies do not disclose probable reserves for non-mining properties, we voluntarily disclose probable reserves for our Firebag in-situ leases as we believe this information is useful to investors.  See “RESERVES ESTIMATES” on page 19 for a description of how our voluntary reserves disclosure differs from our U.S. required disclosure. 

(2)           In estimating our proved and probable reserves, our independent reserves evaluators, GLJ, have targeted the following levels of certainty: at least 90% probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and at least a 50% probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.  However, as our reserves have been prepared using deterministic, rather than probabilistic methods, consistent with industry practice, GLJ’s estimates do not provide a mathematically derived quantitative measure of probability.  In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods.

v

Proved oil and gas reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty(2) to be recoverable in future years from known reservoirs under assumed economic and operating conditions.  For a discussion of pricing assumptions see the tables under the headings “REQUIRED US OIL AND GAS AND MINING DISCLOSURE – Proved Conventional Oil and Gas Reserves” and under “VOLUNTARY OIL SANDS RESERVES DISLOSURE - Oil Sands Mining and In-Situ Firebag Reserves Reconciliation”.

(i)                                     Reservoirs are considered proved if economic producibility is supported by either actual production or conclusive formation test.  The area of a reservoir considered proved includes (A) that portion delineated by drilling and defined by gas-oil and/or oil-water contacts, if any; and (B) the immediately adjoining portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.  In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

(ii)                                  Reserves which can be produced economically through application of improved recovery techniques (such as fluid injection) are included in the “proved” classification when successful testing by a pilot project, or the operation of an installed program in the reservoir, provides support for the engineering analysis on which the project or program was based.

(iii)                               Estimates of proved reserves do not include the following:  (A) oil that may become available from known reservoirs but is classified separately as “indicated additional reserves”;  (B) crude oil, natural gas, and natural gas liquids, the recovery of which is subject to reasonable doubt because of uncertainty as to geology, reservoir characteristics, or economic factors;  (C) crude oil, natural gas, and natural gas liquids, that may occur in undrilled prospects; and (D) crude oil, natural gas, and natural gas liquids, that may be recovered from oil shales, coal, gilsonite and other such sources.

Proved Producing Reserves

Proved producing reserves are those reserves that are expected to be recovered from completion intervals open at the time of the estimate.  These reserves may be currently producing or, if shut in, they must have previously been on production, and the date of resumption of production must be known with reasonable certainty.

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.

vi

Undeveloped Oil and Natural Gas Lands

Undeveloped acreage is considered to be lands on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves.

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 the 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.  BOEs may be misleading, particularly if used in isolation.  A BOE conversion ratio of 6 mcf: 1 bbl is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

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.

vii

Return on Capital Employed (ROCE)

Net earnings adjusted for after-tax financing expenses or income for the twelve-month period ended December 31; divided by average capital employed.  Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt, less cash and cash equivalents, at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable).  See “Non GAAP Financial Measures”, on page ix.

Return on Average Shareholders’ Equity

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

CONVERSION TABLE

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 our current expectations, estimates, projections and assumptions that we’ve made in light of our experience.

All statements that address expectations or projections about the future, including statements about our strategy for growth, expected future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future commitments, are forward-looking statements.  Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “estimate”, “plans,” “intends, “believes,” “projects,” “indicates,” “could,” “vision,” “goal,” “target,” “objective” and similar expressions.  These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to our experience.  Our actual results may differ materially from those expressed or implied by our 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 the general economic, market and business conditions; fluctuations in supply and demand for our products; commodity prices and currency exchange rates; our ability to respond to changing markets, and to receive timely regulatory approvals;  the successful and timely implementation of capital projects including growth projects (for example the continued investment in our Firebag in-situ development project) and regulatory projects (for example, the clean fuels refinery modifications projects in our downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement of conception of the detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of our capital assets; the cumulative impact of other resource development; future environmental laws;  the

viii

accuracy of our reserve, resource and future production estimates and our success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies and from companies that provide alternative sources of energy;  the uncertainties resulting from the January 2005 fire at the oil sands facility and other uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties; changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as the recent fire, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us.  These 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 our MD&A, incorporated by reference herein.  Readers are also referred to the risk factors described in other documents we file 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, or by referring to SEDAR at www.sedar.com, or by referring to EDGAR at www.sec.gov.

References herein to our 2004 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, 2004.

NON GAAP FINANCIAL MEASURES

Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, ROCE, cash flow from operations per common share and Oil Sands cash and total operating costs per barrel, are described and reconciled in the “Non GAAP Financial Measures”, section of our MD&A, incorporated by reference herein.

ix

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, we amalgamated with a wholly-owned subsidiary under the Canada Business Corporations Act.  We amended our articles in 1995 to move our registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997, to adopt our current name, “Suncor Energy Inc.”.  In April 1997, May 2000 and May 2002, we amended our articles to divide our issued and outstanding shares on a two-for-one basis.

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

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

Intercorporate Relationships

We have three principal subsidiaries.

Suncor Energy Products Inc. (formerly Sunoco Inc.) is an Ontario corporation that is wholly-owned by Suncor Energy Inc.  This company refines and markets petroleum products and petrochemicals directly and indirectly through subsidiaries and joint ventures.  We operate a retail business under the Sunoco brand in Canada through this subsidiary.  Suncor Energy Products Inc. is unrelated to Sunoco, Inc. (formerly known as Sun Company, Inc.), headquartered in Philadelphia, Pennsylvania.

Suncor Energy Marketing Inc., wholly-owned by Suncor Energy Products Inc., is incorporated under the laws of Alberta.  We market, 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, through this indirect Suncor subsidiary.  We also market, through this subsidiary, certain third party products, and procure crude oil feedstocks for Suncor’s downstream businesses.  Suncor Energy Marketing Inc. also has a petrochemical marketing division that holds a 50% interest in Sun Petrochemicals Company (“SPC”), a petrochemical products joint venture.  In 2002, this subsidiary began procuring the natural gas supply for Suncor’s Oil Sands and Energy Marketing and Refining businesses, and administering Suncor’s energy trading activities.  In 2003, this subsidiary began marketing certain natural gas volumes produced by, and purchased from, Suncor’s Natural Gas business unit.

Suncor Energy (U.S.A.) Inc., indirectly wholly owned by Suncor Energy Inc., is incorporated under the laws of Delaware.  Through this U.S. subsidiary, headquartered in Denver, Colorado, we refine crude oil at our refinery in Commerce City, Colorado, near Denver, into a broad range of petroleum products, and market our refined products to industrial, wholesale and commercial customers principally in Colorado and to retail customers in Colorado through Phillips 66 - branded sites.  We also transport crude oil on our wholly or partly owned pipelines in Wyoming and Colorado.

Effective February 1, 2005, Suncor Energy Inc., as general partner and one of its wholly owned subsidiaries, as a limited partner, entered into a partnership, Suncor Energy Oil Sands Limited Partnership.  The partnership holds certain net profits interests related to our oil sands business and natural gas business.  This was an internal restructuring that has no effect on operations or on financial reporting.

We also have a number of other subsidiary companies.  However, the total assets of such subsidiaries and partnerships 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.

1

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

We are an integrated energy company, with corporate headquarters in Calgary, Alberta, Canada.  We explore for, acquire, develop, produce and market crude oil and natural gas, transport and refine crude oil and market petroleum and petrochemical products.  Periodically, we also market third party petroleum products.  We also carry on energy trading activities focused principally on buying and selling futures contracts and other derivative instruments based on the commodities we produce.

We have four principal operating business units:

Our Oil Sands business unit, based near Fort McMurray, Alberta, recovers bitumen, primarily through oil sands mining and in-situ development, and upgrades it into refinery feedstock and diesel fuel.  Bitumen feedstock is also occasionally supplemented by third party suppliers.

Our Natural Gas business unit, based in Calgary, Alberta, explores for, acquires, develops and produces natural gas from reserves in Western Alberta and Northeastern British Columbia. The sale of Natural Gas production provides a price hedge for natural gas purchased for consumption at our Oil Sands facility and our refineries in Sarnia, Ontario and near Denver, Colorado.  In addition, our U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., acquires land and explores for coal bed methane and conventional natural gas in the United States.

Our third business unit, Energy Marketing and Refining - Canada, headquartered in Toronto, Ontario, refines crude oil at Suncor’s refinery in Sarnia, Ontario, into a broad range of petroleum products.  These products are then marketed 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.  We also engage in third party energy marketing and trading activities through this business unit.

Our fourth business unit, Refining and Marketing – U.S.A., headquartered in Denver, Colorado, refines crude oil at our refinery in Commerce City, Colorado, near Denver, into a broad range of petroleum products, and markets our refined products to industrial, wholesale and commercial customers principally in Colorado and to retail customers in Colorado through Phillips 66 - branded sites.  We also transport crude oil on our wholly or partly owned pipelines in Wyoming and Colorado.

Finally, in addition to our hydrocarbon-based businesses, we pursue the development of low-emission and no-emission energy sources that have a reduced environmental impact.  For financial reporting purposes, we report segmented financial data for these activities under the results of Suncor’s “Corporate” segment.

In 2004, we produced approximately 263,300 BOE per day, comprised of 230,000 barrels per day (bpd) of crude oil and natural gas liquids and 200 million cubic feet per day of natural gas.  In 2003, the most recent period with published results, we were the 5th largest crude oil and natural gas liquids producer (approximately 9% of Canada’s crude oil production) and the 10th largest natural gas producer in Canada.

In 2004, we sold approximately 97,000 bpd (2003 – 94,400 bpd) or 15,400 m³ per day (2003 – 15,000 m³ per day) of refined products, mainly in Ontario but also in the United States and Europe through our Energy, Marketing & Refining business unit.  Our refined product sales in Ontario represented approximately 19% (2003-19%) of Ontario’s total refined product sales in 2004.  In 2004, our Refining & Marketing business unit sold approximately 58,500 bpd or 9,300 m³ of refined products in Colorado, including approximately 45,400 bpd or 7,200 m³ per day of light oils (gasoline and distillates) (from August 1, 2003 to December 31, 2003, 56,900 bpd or 9,100 m³ per day, including approximately 43,700 bpd or 7,000 m³ per day of light oils).  Our Refining & Marketing business unit supplies approximately 23% of Colorado’s light oil product demand.

2

Three-Year History

Oil Sands (OS)

OS growth – In 2001, we completed Project Millennium, a $3.4 billion expansion that nearly doubled the production capacity of our operation to 225,000 bpd.  During that same year, we also disclosed plans for a multi phased growth strategy designed to increase production capacity to 500,000 to 550,000 bpd by 2010 to 2012.  Key components of this strategy include:

•                                          Increasing bitumen supply through the development of the Firebag in-situ oil sands facility. The first phase of Firebag began producing bitumen in 2004 and we expect the second phase of Firebag to be completed in 2005.

•                                          Increasing production capacity to 260,000 bpd in 2005 through the construction and commissioning of a new vacuum unit.  The project, which is estimated to cost $425 million, is on schedule and on budget.

•                                          Increasing production capacity to 350,000 bpd in 2008.  This project is expected to reach several milestones during 2005 with fabrication and transport of major vessels expected to be completed during the year. The total cost of this project is estimated at $3.6 billion, including approximately $2.1 billion to expand Upgrader 2 and $1.5 billion to increase bitumen supply.

•                                          In planning for expansion beyond 2008 and reaching the goal of 500,000 to 550,000 bpd, OS filed a regulatory application in March 2005 to construct a third upgrader and other facilities.  Costs for this project are currently estimated at $5.9 billion.  Approval of our Board of Directors is also required before the project can proceed.

Petro-Canada agreement - Incremental bitumen to feed the expanded OS operation is also expected to be provided under a processing agreement between Suncor and Petro-Canada, slated to take effect in 2008.  Under the agreement, we will process at least 27,000 bpd of Petro-Canada bitumen on a fee-for-service basis.  Petro-Canada will retain ownership of the bitumen and resulting sour crude oil production of about 22,000 bpd.  In addition, we will sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada.  Both the processing and sales components of the agreement will be for a minimum 10-year term.

Mine Extension – In March 2005 we also filed for approval to construct and operate an extension of the Steepbank mine.  The proposed development would replace ore production that is expected to be depleted prior to the end of the decade.  Currently, capital development costs are estimated at $350 million.  Final approval from our Board of Directors is also required before construction can proceed.  To support the company’s mine development plan, we submitted a regulatory application in January 2005 to build a new primary extraction plant in closer proximity to our mining operations.  The cost of constructing the new extraction facility and decommissioning the existing plant is estimated at $320 million.

Operating license renewal - During 2005, we will be required to update our ten year operating license by filing a renewal application with regulators.  We do not expect the operating license renewal to affect our growth plans.

Kyoto Protocol - On December 17, 2002, the Government of Canada announced its ratification of the Kyoto Protocol.  We continue to consult with governments about the impact of the Kyoto Protocol and plan to continue to actively manage our greenhouse gas emissions.  We currently estimate that in 2010 the impact of the Kyoto Protocol on Oil Sands cash operating costs will be an increase of approximately $0.20 to $0.27 per barrel.  Our estimates assume a reduction obligation of 15% from the 2010 business-

3

as-usual energy intensity⁽³⁾ and that the maximum price for carbon credits would, as the Government of Canada indicated in 2002, be capped at $15 per tonne of carbon dioxide equivalents until 2012.  Based on these assumptions, we do not currently anticipate that the cost implications of federal and provincial climate change plans will have a material effect on our business or future growth plans.  The ultimate impact of Canada’s implementation of the Kyoto Protocol remains subject to numerous risks, uncertainties and unknowns, and it is not possible to predict how these and other Kyoto related issues will ultimately be resolved.

Oil Sands Fire - A fire on January 4, 2005 caused significant damage to one of our two upgraders, reducing upgraded crude oil production capacity of 225,000 bpd from base operations to about 110,000 bpd.  Repair work is underway and we expect our Oil Sands operations to return to full production capacity in the third quarter of 2005.  The timeline for recovery work is preliminary and subject to change.  Further inspection of the damaged equipment will occur as the repairs progress.  Any new information could modify the timetable for returning to full production.  To mitigate the impact of reduced production during the recovery period, we plan to bring forward as many maintenance projects as possible, including all, or significant portions of, a maintenance shutdown previously planned for the fall of 2005.  Our preliminary findings into the cause of the fire suggest the issue was of an isolated nature.  For additional information on our insurance policies refer to note 11 to our consolidated financial statements as well as “Significant Developments in 2004 and Subsequent Event” in the “Suncor Overview and Strategic Priorities” section of our MD&A which is incorporated by reference herein.

Natural Gas (NG)

Simonette Gas Plant - In November 2004, our Natural Gas business unit divested of 62.5% of its interest in the Simonette gas plant for proceeds of $19 million.  We retain a 37.5% ownership and continue to operate the gas plant. We, along with our partner are in the process of expanding the capacity of the plant and building a new pipeline to connect the facility with volumes produced from the Cabin Creek and Solomon fields in the Alberta Foothills.

Land Acquisition - In December 2004, our Natural Gas business unit acquired assets in eastern British Columbia for $33 million.  These assets generate approximately 6 mmcf/d of production, and consist of developed and undeveloped land.

Frontier Disposition - During 2003, our Natural Gas business unit disposed of our interest in Frontier properties (the Arctic and Northwest Territories) including 28 long-term “significant discovery licenses”.  There was no production from these interests.

Other Events - Also in December 2004, our Natural Gas business unit paid $18 million as a final arbitrated settlement relating to the termination of gas marketing contracts related to Enron Corporation’s bankruptcy in December 2001.

Energy Marketing & Refining - Canada (EM&R)

Sarnia Regional Co-Generation Project - 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, supplies all of the steam and electricity requirements of EM&R’s Sarnia Refinery in excess of that produced on-site using waste energy.  The agreement mitigates EM&R’s exposure to increases in energy costs and provides a supply of steam to the Sarnia Refinery at a competitive cost, while eliminating the need for EM&R to build its own steam generating boilers.

Sale of Retail Natural Gas Marketing Business - In 2002, to focus on refining and marketing, EM&R sold its retail natural gas marketing business, resulting in an after-tax gain of $35 million.  At the time of sale, the business was supplying natural gas to approximately 125,000 commercial and residential customer

(3)                                  Reflects the level of greenhouse gas emissions that would have occurred in the absence of energy efficiency and process improvements after 2000.

4

accounts in Ontario.

Desulphurization Projects – Canadian 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.  Construction of the 10,250 barrels per day capacity gasoline desulphurization unit was completed in the fourth quarter of 2003 with the unit placed into service before the 2003 year-end, at a cost of $44 million.

In 2002, the Canadian government 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, by June 1, 2006.  The current maximum is 500 ppm. To meet these requirements, in October 2003, we and Shell Canada Products Inc. (“Shell”) entered into a 20-year agreement under which we will build hydrotreating facilities at our Sarnia refinery to process high-sulphur diesel from both Shell’s and our Sarnia refineries, to produce low sulphur diesel in compliance with the new on-road diesel limits.  Under the agreement Shell will pay us a processing fee. Operating a single hydrotreating unit, instead of two separate units, is expected to result in cost benefits to us and Shell, as well as environmental benefits for the Sarnia-Lambton community as one larger unit is expected to consume comparatively less energy and have lower greenhouse gas emissions. Construction of the diesel desulphurization facilities commenced in 2004, and project completion is expected in early 2006.

Regulations reducing sulphur in off-road diesel and light fuel oil are also expected to take effect later in the decade.  We believe that if the regulations are finalized as currently proposed, the new diesel desulphurization facilities for reducing sulphur in on-road diesel, should also allow us to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

In combination with the diesel desulphurization project, we are planning to expand the refinery’s throughput capacity, enabling it to process approximately 40,000 bpd of Oil Sands sour crude blends. These modifications, as currently envisioned, are expected to lower feedstock costs over the long term. When all components of this project are completed in 2007, Suncor expects this project will cost approximately $800 million.

Ethanol Plant - In 2004, Suncor completed pre-development engineering, formal public consultation, preliminary project plans and regulatory application submissions for the planned ethanol plant in the Sarnia region. We also finalized the site location for the development of the plant.  This facility is expected to produce ethanol at a capacity of 200 million litres per year for blending into our Sunoco-branded fuels and fuels sold through our joint venture operated networks. Construction of the facility is expected to begin in 2005 and the cost is currently estimated to be $120 million. In February 2004, we received approval from the Federal Government’s Natural Resources Canada’s Ethanol Expansion Program on our funding proposal for the project, which, subject to final approvals, will contribute $22 million towards our construction of the facility.

Energy Marketing & Trading - In 2001, we commenced a physical energy marketing business to generate additional income by marketing third party crude oil and bitumen. This activity resulted in net pretax gains of $12 million in 2004 compared to $2 million in 2003 and $6 million for the year ended December 31, 2002.

In 2002, Suncor’s Board of Directors approved commencement of financial derivatives trading activities (“energy trading”) and after developing an appropriate control framework, we began limited energy trading activities in November 2002.  A separate risk management function monitors practices and policies and provides independent verification and valuation of our trading and marketing activities.  Trading activities are principally focused on the commodities we produce, adding potential for increased revenue and providing increased insight into global energy markets.  Net financial trading losses, before taxes and general and administrative expenses, were negligible for the two month period ended December 31, 2002, $3 million for the year ended December 31, 2003, and net trading gains, before taxes and general and administrative expenses, were $11 million before tax for the year ended December 31, 2004.

5

Refining & Marketing – U.S.A. (R & M)

On August 1, 2003, we acquired a Denver refinery and related pipeline and retail assets from ConocoPhillips Company (“ConocoPhillips”).  The acquisition was made with the expectation of providing us with the flexibility to move additional Oil Sands production into the U.S. marketplace.  By December 31, 2004 we were processing approximately 6,000 bpd of Oil Sands crude oil at our Denver refinery.  We paid US$150 million (about Cdn$210 million) for the assets, plus approximately US$44 million (about Cdn$62 million) for crude oil, product inventories and other closing adjustments.  The acquisition included:

•                        a 60,000 bpd refinery located in the Denver area;

•                        43 Phillips 66 - branded retail stations, primarily in the Denver area, plus contract agreements with approximately 150 Phillips-branded marketer outlets throughout Colorado;  and

•                        the Rocky Mountain and Centennial pipeline systems, located in Wyoming and Colorado. Suncor has 100% ownership of the 480 kilometre (300 mile) Rocky Mountain pipeline system and 65% ownership of the 140 kilometre (87 mile) Centennial pipeline system.

As part of the agreement to acquire these assets, Suncor assumed obligations of ConocoPhillips at the refinery pursuant to a Consent Decree with the United States Environmental Protection Agency, the United States Department of Justice and the State of Colorado.  These obligations are expected to require expenditures of Cdn$29 million (approximately US$24 million) through 2006. The expenditures, intended to reduce air emissions at the refinery, are expected to be primarily capital in nature.

Desulphurization Projects - R&M estimates it will spend a total of Cdn$360 million (approximately US$300 million) to meet requirements of fuels desulphurization legislation and to enable the refinery to process up to 15,000 bpd of Oil Sands sour crude oil, while also increasing the refinery’s ability to process a broader slate of bitumen based crude oil. The fuel desulphurization legislation requires lower diesel sulphur levels (15 ppm) by June 2006 and lower gasoline sulphur levels (30 ppm average, 80 ppm cap) by 2009. The environmental permit application for all these proposed changes has been approved. Construction for the diesel desulphurization facilities commenced in 2004 and is planned to be completed in early 2006,  including a new desulphurization unit, a new hydrogen plant, a new tail gas treating unit for the existing sulphur recovery plants, as well as modifications to other existing units.

We are currently assessing plans for potential additional refinery modifications after 2006 in order to have the potential to integrate up to an additional 30,000 bpd of Oil Sands crude oil. Cost estimates for this project are not yet available.

Other

Financing Activities

In 2000, we entered into a financing arrangement with a third party whereby we sold an undivided interest in our Oil Sands energy service assets for $101 million and leased the assets back from the third party.  We repurchased the assets in December 2004, with financing from existing revolving credit facilities.

In January 2002, we issued US$500 million principal amount of 7.15% unsecured Notes due February 1, 2032, to investors in the United States (the “US”) under our US$1 billion shelf prospectus.

In December 2003 we issued US$500 million of 5.95% unsecured Notes under the remaining capacity of the US$1 billion shelf prospectus. We have now utilized the complete capacity that was available under this shelf. The net proceeds of the debt offering, together with borrowings under our available credit and term loan facilities were used to repay our 7.4% Debentures maturing February 2004 ($125 million) and

6

to redeem our 9.05% and 9.125% Preferred Securities in March 2004 for total cash consideration of $493 million.

In 2004 we renewed our available credit facilities of approximately $1.7 billion.  Our undrawn lines of credit at December 31, 2004 were approximately $1.5 billion.  Our current long-term debt ratings are, A (low) by Dominion Bond Rating Service, A3 by Moody’s Investors Service and A- by Standard & Poor’s.  All debt ratings have a stable outlook.

In June 2004, we repurchased approximately 2.1 million barrels of crude oil originally sold to a Variable Interest Entity (“VIE”) in 1999, for net consideration of $49 million.  As the company economically hedged the repurchase of the inventory, the net consideration paid was equal to the original proceeds we received in 1999, when the inventory was sold to the VIE.

During the second quarter of 2004, we received $40 million from the sale of certain proprietary technology.

Other Highlights

In September 2004, we, along with our joint venture partners, a subsidiary of Enbridge Inc. and EHN Wind Power Canada, Inc. officially opened the 30-megawatt Magrath Wind Power Project (“Magrath”) in southern Alberta.  Magrath’s zero-emissions electricity production is expected to offset the equivalent of approximately 82,000 tonnes of carbon dioxide per year.  The project has benefited from the support of the Federal Government’s Wind Power Production Incentive

For further information on developments and issues referred to above and other highlights of 2004, and a discussion of other trends known to us that could reasonably be expected to have a material effect on the company, refer to the “Outlook” and other sections of Suncor’s MD&A, and to “Risk/Success Factors” in this Annual Information Form.

7

NARRATIVE DESCRIPTION OF THE BUSINESS

OIL SANDS (OS)

We produce a variety of refinery feedstock and diesel fuel by developing the Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at our plant near Fort McMurray, Alberta.  Our Oil Sands operations, accounting for virtually all of our conventional and synthetic crude oil production in 2003 and 2004, represent a significant portion of our 2004 capital employed (78%)⁽⁴⁾, cash flow from operations⁽⁴⁾ (76%) and net earnings (81%).  These percentages have been determined excluding the corporate and eliminations segment information.

Operations

Our integrated Oil Sands business involves four operations.  First, bitumen is supplied from a combination of a mining operation using trucks and shovels, and third party bitumen supply.  Commencing in 2004, the Firebag in-situ operation began producing bitumen which was primarily sold into the market as diluted bitumen.  We expect that bitumen from Firebag will be upgraded beginning in 2005, with only excess production sold into the market.  Second, extraction facilities recover the bitumen from the oil sands ore that is mined. Third, heavy oil upgrading process converts bitumen into crude oil products.  Fourth, our energy service needs are met through Oil Sands facilities (operated by TransAlta), that provide steam and electricity to the operations along with energy from TransAlta’s proprietary natural gas fired co-generation plant that commenced operations in 2001.  We use all of the steam and a portion of the power from the TransAlta co-generation facility. Our energy services facilities primarily use petroleum coke, a by-product of the upgrading process, as fuel.  They also consume natural gas.

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 extraction plants on the east and west sides 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 2004, approximately 8,400 bpd of bitumen were sold, representing approximately four percent of Oil Sands’ 2004 sales.  In 2003, bitumen sales of 6,400 bpd represented approximately three percent of Oil Sands’ sales.

After the diluted bitumen is transferred 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, delineation of the resources and 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.  Natural gas is used or consumed in the production of synthetic crude oil, particularly under the steam assisted gravity drainage (SAGD) method of bitumen production from our Firebag operations, and accordingly natural gas prices are a key variable component of synthetic crude oil production costs.  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.

(4)                                  Refer to “Non GAAP Financial Measures” on page ix of this AIF.

8

Principal Products

Sales of light sweet crude oil represented 55% of Oil Sands’ consolidated operating revenues in 2004, compared to 56% in 2003.  Sales of other products including light sour crude, diesel and bitumen represented the remaining 45% of revenues in 2004 compared to 44% in 2003.  Set forth below is information on daily sales volumes and the corresponding percentage of Oil Sands consolidated operating revenues by product for each of the last two years.

Transportation

Our Oil Sands business unit has 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, our initial pipeline capacity for the transport of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta, to Hardisty Alberta was 60,000 bpd in 1999, increasing to 170,000 bpd in 2005. This pipeline, together with our proprietary pipeline, is expected to meet our anticipated crude oil shipping requirements for expected future production levels up to 2008.  We, along with other industry shippers, are assessing Athabasca region pipeline options beyond 2008.

The company markets its crude oil product blends for sale and distribution to customers in Canada, the United States and periodically, to offshore markets.

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

We also transport natural gas to our Oil Sands operations on the company-owned and operated Albersun pipeline, constructed in 1968.  It extends approximately 300 kilometres south of the plant and connects with the TransCanada Pipeline’s Alberta intra-provincial pipeline system.  The Albersun pipeline has the capacity to move in excess of 100 mmcf/day of natural gas.  We arrange for natural gas supply and control most of the natural gas on the system under delivery based contracts.  The pipeline moves natural gas both north and south for us and other shippers.  In 2004, throughput on the Albersun pipeline was approximately 46 mmcf/day.

Our 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 during the winter season and in some situations can result in higher costs.

9

Sales of Synthetic Crude Oil and Diesel

Aside from on site fuel use, all of Oil Sands’ production is sold to, and subsequently marketed by, Suncor Energy Marketing Inc.

In 1997, we entered into a long-term agreement with Koch Industries Inc. (“Koch”) to supply Koch with up to 30,000 bpd (approximately 13% of our average 2004 total production) of sour crude from the Oil Sands operation.  We began shipping the crude to Koch’s terminal at Hardisty, Alberta (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 by either party. Neither party has provided notice at this time.

In 2000, we announced a long term sales agreement with Consumers’ Co-operative Refineries Limited (“CCRL”) under which we expected to begin supplying CCRL with 20,000 bpd of sour crude oil production from our Project Millennium expansion facilities by late 2002.  After certain construction delays, CCRL began accepting delivery of sour crude in the first quarter of 2003.  Prices for sour crude oil under these agreements are set at agreed differentials to market benchmarks.

In 2001, we 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. The diluent supply agreement is expected to end when the bitumen processing and sour crude oil supply agreement, described below, takes effect.

The processing agreement between the company and Petro-Canada is expected to take effect in 2008. Under the agreement, we will process at least 27,000 bpd of Petro-Canada bitumen on a fee for service basis.  Petro-Canada will retain ownership to the bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, we will sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada.  Both the processing and sales components of the agreement will be for a minimum 10-year term.

There were no customers that represented 10% or more of our consolidated revenues in 2004 or 2003. There was one customer in 2002 that represented 10% or more of our consolidated revenues.

A portion of our Oil Sands production is used in connection with our Sarnia refining operations.  During 2004, the Sarnia refinery processed approximately 8% (2003 -10%) of Oil Sands crude oil production.

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 “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

NATURAL GAS (NG)

Our 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’s production provides a price hedge for natural gas purchased for consumption at our Oil Sands facility and our refineries in Sarnia, Ontario and near Denver, Colorado.  In addition, our U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., is acquiring land and exploring for coal bed methane and conventional natural gas in the United States.

In 2004, natural gas and natural gas liquids accounted for approximately 97% of the NG business unit’s

10

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.  We drill primarily medium to high-risk wells focusing on prospects that can be connected to existing infrastructure.  In addition, our U.S. affiliate, Suncor Energy (Natural Gas) America Inc. is exploring for natural gas in western Montana and for coal bed methane in several of the U.S. states.

Marketing, Pipeline and Other Operations

We operate 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.  Our capacity interest in these gas processing plants is approximately 103 mmcf/day.  We also have varying undivided percentage interests in natural gas processing plants operated by other companies and processing agreements in facilities where we do not hold an ownership interest.

Approximately 78% of our 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, we are responsible for transportation arrangements to the point of sale.  Some of the direct sales arrangements include some of the natural gas consumed in our Oil Sands plant at Fort McMurray and in our Sarnia refining operations.

Approximately 22% of our 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 our system sales volumes are contracted to Cargill Gas Marketing Ltd. (formerly TransCanada Gas Services) and Pan-Alberta Gas.  These companies resell this natural gas primarily to eastern Canadian and Midwest and eastern United States markets.

To provide exposure to the Pacific North West and California markets, we have a long-term gas pipeline transportation contract on the National Energy Group Transmission Pipeline (formerly Pacific Gas Transmission).

Our conventional crude oil production is generally sold under spot contracts or under contracts that can be terminated on relatively short notice.  Our 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.

Principal Products

Consistent with 2003, sales of natural gas represented 90% of NG’s consolidated operating revenues in 2004, with the remaining 10% comprised of sales of natural gas liquids and crude oil.  Set forth below is information on daily sales volumes and the corresponding percentage of Natural Gas’ consolidated operating revenues by product for the last two years.

11

Competitive Conditions

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

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 “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

ENERGY MARKETING & REFINING – CANADA (EM&R)

Our EM&R business unit operates a refining and marketing business in Central Canada, and an energy marketing and trading business.  Our refinery in Sarnia, Ontario, refines petroleum feedstock from Oil Sands and other sources into gasoline, distillates, and petrochemicals with the majority of these refined products being distributed in our primary market of Ontario.  For information about EM&R’s energy marketing and trading business, refer to “Energy Marketing and Refining – Canada (EM&R) Three-Year Highlights”, under the “Energy Marketing & Trading” heading.

Approximately 58% of EM&R’s petroleum products sales in 2004 (2003 – 58%) were sold through a distribution network in Ontario that sells gasoline and diesel fuel to retail customers.  Approximately 37% (2003 – 37%) was sold to industrial, commercial, wholesale and refining customers in Ontario and Quebec, representing primarily jet fuels, diesel and gasoline.  The remaining 5% (2003 - 5%) 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.

EM&R’s external financial reporting structure changed in 2004 so that its Rack Back and Rack Forward divisions (described as follows) are now reported on a consolidated basis.  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 and the SPC joint venture.  The Rack-Forward division is comprised of retail operations, 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 EM&R and The Pioneer Group Inc.

EM&R results also include the impact of Suncor’s energy marketing and energy trading activities, which is comprised of both third party crude oil marketing and financial and physical derivatives trading activities.

12

Procurement of Feedstocks

The Sarnia refinery uses both synthetic and conventional crude oil.  In 2004, the Sarnia refinery procured approximately 41% (2003 – 53%) of its synthetic crude oil feedstock from our Oil Sands production.  In 2004, 66% (2003 – 64%) 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.   As a result of the fire at Oil Sands, during 2005, EM&R may be required to purchase additional synthetic crude oil feedstock to meet customer demand, resulting in higher purchased product costs.

We procure conventional crude oil feedstock for our Sarnia 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.  We have 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 which can be terminated on short notice.

In 1998, EM&R signed a 10-year feedstock agreement with a Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd.  Under this buy/sell agreement, we obtain feedstock that is more suitable for production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking.  We also enter into reciprocal buy/sell or exchange arrangements with other refining companies from time to time as a means of minimizing transportation costs, balancing product availability and enhancing refinery utilization.  We also purchase 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 bpd of crude oil.  Sarnia refinery sales in 2004 averaged approximately 94,300 bpd (2003 – 92,100 bpd).  The 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 has the flexibility to vary the gasoline/distillate ratio.  The hydrocracker has capacity to process approximately 23,300 bpd.  Additional flexibility in gasoline, octane and petrochemical production is provided by the complementary operations of an alkylation unit with a capacity of 5,400 bpd. The alkylation unit produces a high octane gasoline blending component.  The petrochemical facilities have a charge capacity of 13,100 bpd and produce benzene, toluene, mixed xylenes, orthoxylene and raffinate.  The aromatic solvents unit produces about 1,000 bpd of A-100 and A-150.  A gasoline desulphurization unit that came into service in the fourth quarter of 2003 has a capacity to process 10,250 bpd of gasoline components.

The refinery has a cracking capacity of 40,200 bpd 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 2004, a sustainability study to assess the catcracker concluded that, with planned 2005 improvements and upgrades, it can continue to be operated economically and safely for up to 10 years.  A second phase of the study, planned to be completed in 2005, will assess configuration and investment options for replacing the catcracker within 10 years.

During the second quarter of 2004, EM&R completed scheduled and unscheduled maintenance shutdowns on various units within one of the refinery’s plants.  As a result, the refinery operated with

13

lower than capacity utilization rates during the second quarter of 2004.

Overall, crude utilization averaged 100% for the year, up 5% from 2003.  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.

Notes:

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

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

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

Principal Products

Sales of gasoline and other transportation fuels represented 72% of EM&R’s consolidated operating revenues in 2004, unchanged from 2003.  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.

Note:

(1)           Includes ancillary revenues

14

Principal Markets

Approximately 58% (2003 – 58%) of EM&R’s total sales volumes are marketed through retail networks, including the Sunoco-branded retail network, joint-venture operated retail stations and cardlock operations.  In 2004, this network was comprised of:

278 (2003 – 279) Sunoco-branded retail service stations

147 (2003 – 147) Pioneer-operated retail service stations

52 (2003 – 53) UPI-operated service stations and a network of 14 bulk distribution facilities for rural and farm fuels

23 (2003 – 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 our premium high octane gasoline, and “Gold Diesel” used in respect of our premium low sulphur diesel product.

Approximately 37% (2003 – 37%) 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 other petrochemicals, primarily in Canada and the U.S., through SPC.  EM&R has a 50% interest in SPC, a petrochemical marketing joint venture that markets products from our Sarnia Refinery and from a Toledo, Ohio, refinery owned by the joint venture partner.  SPC 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 19% in 2004 (2003 – 19%).  Transportation fuels accounted for 82% of EM&R’s total sales volumes in 2004 (2003 – 82%); and petrochemicals accounted for 5% (2003 – 5%).  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.  We have a separate supply agreement with each of UPI and Pioneer.  These supply agreements are evergreen, subject to termination only in accordance with the terms of the various agreements between the parties.

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 us and 45% owned by another refiner.  The pipeline operates as a private facility for its owners, serving terminal facilities in Toronto, Hamilton and London, with a capacity of 126,000 bpd (20,000 cubic metres).  EM&R utilized 55% of this capacity in 2004.  Total utilization of the pipeline was 88% in 2004.

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.

15

We believe our own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet our current and foreseeable storage needs.

Competitive Conditions

Competitive conditions affecting our EM&R business are described under “Competition” 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, refer to the sections entitled “Outlook” and “Risk/Success Factors Affecting Performance” in the EM&R section of our 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 “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

REFINING & MARKETING – U.S.A. (R & M)

Our R&M business unit, which was acquired August 1, 2003, operates a pipeline transportation, refining and marketing business primarily in Colorado and Wyoming.  The Denver area refinery, located in Commerce City, Colorado, has a crude distillation capacity of 60,000 bpd, processing a mixture of Canadian heavy, high sulphur crudes, and domestic heavy, high sulphur and low sulphur crudes.  The majority of the refined products from our Denver refinery are distributed in its primary market of Colorado.

Approximately 24% of R&M’s petroleum products sales in 2004 were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers.  R&M’s retail network includes 43 Phillips 66-branded company operated sites, as well as contractual agreements with approximately 140 Phillips 66 - branded marketer outlets throughout Colorado.  Approximately 60% of R&M’s petroleum product sales volumes were to industrial, commercial, wholesale and refining customers in Colorado, representing primarily jet fuels, diesel and gasoline.  Asphalt sales comprise the remaining 16% of R&M’s refined product sales volumes for 2004.

Procurement of Feedstocks

The Denver refining operation uses conventional crude oil.  Approximately 45% of the Denver refinery’s crude oil is purchased from Canadian sources, with the remainder supplied from sources in the United States, primarily in the Rocky Mountain region.   The refinery’s crude oil purchase contracts have terms ranging from month-to-month to one year.  In the event of a significant disruption in the supply of crude oil, the refinery has the flexibility to substitute other sources of sweet or sour crude oil on a spot purchase basis.

R&M has a buy/sell agreement with a third party refinery located in Cheyenne, Wyoming, whereby R&M sells residual coke from its refinery to the third party refinery and purchases coker gas oil, which is then further processed into finished products at R&M’s Denver refinery.  This contract expires in July 2006.

Refining Operations

The Denver refinery has a crude distillation capacity of 60,000 bpd, processing a mixture of Canadian heavy, high sulphur crudes, and domestic heavy, high and low sulphur crudes. Upgrading units at the Denver refinery include a 19,000 bpd fluidized catalytic cracker, a 12,500 bpd distillate hydrotreater and a 14,000 bpd gas oil hydrotreater.  The refined gasoline products from the Denver refinery supply R&M’s marketing operations in Colorado.  Refining sales in 2004 averaged approximately 58,500 bpd (9,300 m³ per day).

16

The Denver refinery is a high conversion refinery that produces a full range of products, including gasoline, jet fuels, diesel and asphalt.  The refinery’s upgrading units enable it to process a crude slate containing nearly 50% heavy, high sulphur crude.  Overall, crude utilization averaged 92% in 2004.  The following chart sets out daily crude input, average refinery utilization rates and cracking capacity utilization for 2004 and the five month period in 2003 since acquisition.

Notes:

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

(2)           Based on cracking capacity and input to other units or sales made to customers.

Principal Products

Sales of gasoline and other transportation fuels represented 85% of R&M’s consolidated operating revenues in 2004.  Set forth below is information on daily sales volumes and percentage of R&M’s consolidated operating revenues contributed by product group for 2004 and the five-month period post acquisition in 2003.

Note:

(1)           Ancillary revenues include non-fuel retail sales.

Principal Markets

Approximately 24% of R&M’s total sales volumes are marketed through Phillips 66 - branded retail outlets.  This network is comprised of:

17

•      43 owned Phillips 66 - branded retail sites, which account for approximately 7% of R&M’s sales volumes.

•      Supply agreements with approximately 140 Phillips-66 branded marketer outlets throughout the state of Colorado, which account for approximately 17% of R&M’s sales volumes. These agreements are typically for three year terms with provision for automatic three year renewal periods on an evergreen basis.

We have an exclusive license from ConocoPhillips to use the Phillips-66 and related trademarks and brand names in Colorado until December 31, 2012.

The Denver refinery also supplies all of its asphalt production to KC Asphalt, a joint venture between ConocoPhillips and Koch Industries, Inc.  Asphalt sales made up about 16% of R&M’s total 2004 sales volumes.

Approximately 60% of R&M’s total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Colorado, of which approximately 40% was sold under a long-term supply agreement with ConocoPhillips in 2004.  Under this agreement, R&M supplies ConocoPhillips with gasoline and distillates. Under the terms of the agreement, the supplied volumes are to decrease over time until approximately half of the current volumes will be supplied in the 10th year of the agreement.

R&M estimates its sales of total light fuels refined product in 2004 represented a market share, in its primary market of Colorado, of approximately 23%.  Within this market, R&M’s Phillips 66 - branded sites represent a 13% market share.

Transportation and Distribution

Almost all crude oil processed at the Denver refinery is transported via pipeline.  R&M owns and operates the Rocky Mountain Crude system which runs from Guernsey, Wyoming to Denver, Colorado.  This pipeline is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers.  We also operate a joint venture crude pipeline, the Centennial pipeline, from Guernsey, Wyoming to Cheyenne, Wyoming.  We own approximately 65% of this joint venture pipeline, with, the other 35% owned by another area refiner.  In 2004, the Rocky Mountain Crude system utilized more than 100% of capacity due the use of a drag reducing agent, with average throughput of 34,200 bpd in the Guernsey to Cheyenne leg of the pipeline, and 65,200 bpd in the higher capacity Cheyenne to Denver leg.   During the same period, the joint venture pipeline utilized approximately 97% of capacity, with an average throughput of approximately 59,100 bpd.

R&M has its own 30,000 bpd capacity truck-loading terminal at the Denver area refinery where customers can pick up product, a one mile long 7,000 bpd jet fuel pipeline that connects to a common carrier pipeline system for deliveries to the Denver International Airport, and a four mile long 14,000 bpd diesel pipeline that delivers diesel product directly to the Union Pacific railroad yard in Denver, Colorado.

We believe our own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet our current and foreseeable storage needs.

Competitive Conditions

Competitive conditions affecting our Refining & Marketing – U.S.A. business are described under the heading “Competition” in the “Risk/Success Factors” section of this Annual Information Form.

18

Environmental Compliance

Due to increasingly stringent regulations regarding water discharges, the Denver Refinery will have to add additional water treating equipment for the discharge of process waste water.  It is estimated that this will cost approximately $3 million and be completed in the 2006 to 2008 timeframe.  For a description of other impacts of environmental protection requirements on Refining & Marketing – U.S.A., refer to the R&M section of “Three Year History” of this Annual Information Form, and the sections entitled “Outlook” and “Risk/Success Factors Affecting Performance” in the Refining & Marketing – U.S.A. section of our MD&A.  Also refer to “Environmental Regulation and Risk” and “Governmental Regulation” in the “Risk/Success Factors” section of this Annual Information Form, and “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

MATERIAL CONTRACTS

During the year ended December 31, 2004 we have not entered into any contracts, nor are there any contracts still in effect, that are material to our business, other than contracts entered into in the ordinary course of business and the Shareholder Rights Plan dated April 28, 2002.

RESERVES ESTIMATES

We are a Canadian issuer and are subject to Canadian reporting requirements, including rules in connection with the reporting of our reserves.  However, we have received an exemption from Canadian securities administrators permitting us to report our reserves in accordance with U.S. disclosure requirements.  Pursuant to U.S. disclosure requirements, we disclose net proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from our Firebag in-situ leases, using constant dollar cost and pricing assumptions.  As there is no recognized posted bitumen price, these assumptions are based on a posted benchmark oil price, adjusted for transportation, gravity and other factors that create the difference (“differential”) in price between the posted benchmark price and Suncor’s bitumen.  Both the posted benchmark price and the differential are generally determined as of a point in time, namely December 31 (“Constant Cost and Pricing”).  Our reserves from our Firebag in-situ leases are reported as barrels of bitumen, using these Constant Cost and Pricing assumptions (see “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE – Proved Conventional Oil and Gas Reserves” for net proved conventional oil and gas reserves).

Pursuant to U.S. disclosure requirements, we also disclose gross proved and probable mining reserves.  The estimate of our mining reserves is based in part on the current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing and cost assumptions.  In accordance with these rules, we report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80 to 81%.  We do not disclose our mining reserves on a net basis as we are continuing to discuss the terms of our option to transition to the Province of Alberta’s generic bitumen based royalty regime in 2009 and accordingly, the net mining reserves calculation cannot be estimated (see “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE – Proved and Probable Oil Sands Mining Reserves” for gross proved and probable mining reserves).  Our Firebag in-situ leases are already subject to royalty based on bitumen, rather than synthetic crude oil.  (For a full discussion of our oil sands crown royalties, see the “Oil Sands Crown Royalties and Cash Income Taxes” in the “Suncor Overview and Strategic Priorities” section of our MD&A.)

In addition to required disclosure, our exemption issued by Canadian securities administrators permits us to provide further disclosure voluntarily.  We provide this additional voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and reserves from our Firebag in-situ leases.  In our voluntary disclosure we report our aggregate reserves on the following basis:

(a)           Gross proved and probable mining reserves, on the same basis as disclosed pursuant to U.S.

19

disclosure requirements (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil yield from bitumen of 80% to 81%);  and

(b)           Gross proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on normalized constant dollar cost and pricing assumptions.  These assumptions use a posted benchmark oil price as of December 31, but apply a differential generally intended to represent a normalized annual average for the year (“Annual Average Differential Pricing”), rather than a point in time differential, in accordance with Canadian Securities Administrators Staff Notice 51-315 (“CSA Staff Notice 51-315”).  Bitumen reserves estimated on this basis are subsequently converted, for comparison purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 82%.

Accordingly, our voluntary disclosures of proved and probable reserves from our Firebag in-situ leases will differ from our required U.S. disclosure in three ways.  Reserves from our Firebag in-situ leases are:

(a)           disclosed on a gross basis versus a net basis under U.S. disclosure requirements;

(b)           converted from barrels of bitumen under U.S. disclosure requirements to barrels of synthetic crude oil for comparability purposes only; and

(c)           evaluated based on Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

Under the U.S. disclosure requirements described above, we announced on January 21, 2005 that we debooked our proved reserves from our Firebag in-situ leases.  December 31, 2004 point-in-time posted benchmark oil prices were unusually low and December 31, 2004 point-in-time diluent prices, which form part of the differential calculation, were unusually high.  This combination resulted in a determination that our proved Firebag in-situ reserves were uneconomic as at December 31, 2004 (see “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE - Proved Conventional Oil and Gas Reserves”).

Under our voluntary disclosure, using 2004 Annual Average Differential Pricing, our proved Firebag in-situ reserves were determined to be economic and accordingly, are disclosed under “VOLUNTARY OIL SANDS RESERVES DISCLOSURE - Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation”.  Comparisons of these two reserve estimates will show material differences based primarily on the pricing assumptions used, but will also show differences based on whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, and whether the reserves are reported on a gross or net basis.

All of our reserves have been evaluated as at December 31, 2004 by independent petroleum consultants, Gilbert Laustsen Jung Associates Ltd. (“GLJ”).  In reports dated February 9, 2005, and February 17, 2005 (“GLJ Oil Sands Reports”), GLJ evaluated our proved and probable reserves on our oil sands mining leases and Firebag in-situ leases respectively, pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions, and pursuant to CSA Staff Notice 51-315, using 2004 Annual Average Differential Pricing assumptions.

Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory approvals have been granted. The mining reserve estimates are based on a detailed geological assessment and also consider industry practice, drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, and regulatory constraints.

For Firebag in-situ reserve estimates, GLJ considered similar factors such as our regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects, and drill density.  Our proved and probable reserves are contained within the AEUB approval area.  Our proved reserves are delineated with 40 to 80 acre spacing plus 3D seismic control while our probable reserves are delineated with 80 to 160 acre

20

spacing plus 3D seismic control.  The major facility expenditures to develop our proved undeveloped reserves have been approved by our Board.  Plans to develop our probable undeveloped reserves in subsequent phases are under way but we have not yet received final approval from our Board.

In a report dated February 17, 2005 (“GLJ NG Report”), GLJ also evaluated our proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from our mining leases and the Firebag in-situ reserves) as at December 31, 2004.

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

REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE

Proved and Probable Oil Sands Mining Reserves

Notes:

(1)           Synthetic crude oil reserves are based on a net coker, or synthetic crude oil yield from bitumen of 80 to 81%.

(2)           Our gross mining reserves are based in part on our current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing and cost assumptions.

(3)           We do not disclose our mining reserves on a net, after royalty basis as we continue to discuss the terms of our option to transition to the Province of Alberta’s generic bitumen based royalty regime in 2009 and accordingly, the net mining reserves calculation cannot be estimated (see “Oil Sands Crown Royalties and Cash Income Taxes” in the “Suncor Overview and Strategic Priorities” section of our MD&A for a discussion of our royalty regime).

21

Oil Sands Mining Operating Statistics

The following table sets out certain operating statistics for the Oil Sands mining operations.  Statistics for the Oil Sands Firebag in-situ operations are not included but are addressed under the heading “Proved Conventional Oil and Gas Reserves” and “Sales, Production, Well Data, Land Holdings and Drilling - Conventional”.

Notes:

(1)           Includes pre-stripping of mine areas and reclamation volumes.

(2)           Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.

(3)           Cubic meters are converted to barrels at the conversion factor of 6.29.

Proved Conventional Oil and Gas Reserves

The following data is provided on a net basis in accordance with the provisions of the Financial Accounting Standards Board’s Statement No. 69 (Statement 69).  This statement requires disclosure about conventional oil and gas activities only, and therefore our Oil Sands mining activities are excluded, while in-situ Firebag reserves are included.

22

NET PROVED RESERVES(2)

Crude Oil, Natural Gas Liquids and Natural Gas

Notes:

(1)           Oil Sands business - Firebag net reserves means Suncor’s undivided percentage interest in total reserves after deducting Crown royalties, freehold and overriding royalty interests.  The calculation of these third party interests is uncertain and based on assumptions about future prices, production levels, operating costs and capital expenditures.

(2)           Although Suncor is subject to Canadian disclosure rules in connection with the reporting of its reserves, we have received exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S. disclosure practices.  See Reliance on Exemptive Relief on pg 44.

(3)           Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31.  In 2004, due to unusually low year-end posted benchmark oil prices, and unusually high year-end diluent prices, our proved reserves were determined to be uneconomic as at this year end point in time.

(4)           We have the option of selling the bitumen production from these leases and/or upgrading the bitumen to synthetic crude oil.

(5)           Natural Gas business net reserves means Suncor’s undivided percentage interest in total reserves after deducting the interest of third parties, including Crown royalties, freehold and overriding royalties, calculated following generally accepted guidelines, on the basis of prices and the royalty structure in effect at year end and anticipated production rates.  The calculation of these third party interests is uncertain and based on assumptions about future natural gas prices, production levels, operating costs and capital expenditures.  Royalties can vary, depending upon selling prices, production volumes, timing of initial production and changes in legislation.

All reserves are located in Canada. There has been no major discovery or other favourable or adverse event that caused a significant change in estimated proved reserves since December 31, 2004, other than the

23

potential effect of higher bitumen pricing subsequent to December 31, 2004, which may result in the re-booking of proved Firebag in-situ reserves. We do not have long-term supply agreements or contracts with governments or authorities in which we act as producer nor do we have any interest in oil and gas operations accounted for by the equity method.

Capitalized Costs Relating to Oil and Gas Activities (1)

Note:

(1)           In 2004, capitalized costs do not include costs related to the associated upgrading expansion projects.  Prior year amounts have been reclassified to conform to this presentation.

Costs Incurred in Oil and Gas Acquisition, Exploration and Developmental Activities (1)

Note:

(1)           In 2004, costs incurred do not include costs related to associated upgrading expansion projects.  Prior year amounts have been reclassified to conform to this presentation.

24

Results of Operations for Oil and Gas Production

Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes

In computing the standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes, assumptions other than those mandated by Statement 69 could produce substantially different results. We caution against viewing this information as a forecast of future economic conditions or revenues, and do not consider it to represent the fair market value of our Firebag in-situ and Natural Gas properties. Figures are based on our actual year-end commodity prices.  Readers are cautioned that commodity prices are volatile.  To illustrate this volatility, the following table sets out certain commodity benchmark prices over the past three years:

Actual future net cash flows may differ from those estimated due to, but not limited to, the following:

•      Production rates could differ from those estimated both in terms of timing and amount;

•      Future prices and economic conditions will likely differ from those at year-end;

•      Future production and development costs will be determined by future events and may differ from those at year-end; and

•      Estimated income taxes and royalties may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates and the impact of future expenditures on unproved properties.

The standardized measure of discounted future net cash flows is determined by using estimated quantities of proved reserves and taking into account the future periods in which they are expected to be developed and produced based on year-end economic conditions. The estimated future production is priced at year-end prices, except that future gas prices are increased, where applicable, for fixed and determinable price escalations provided by contract. The resulting estimated future cash inflows are reduced by estimated future costs to develop and produce the proved reserves based on year-end cost levels. In addition, we have also deducted certain other estimated costs deemed necessary to derive the estimated pretax future net cash flows from the proved reserves including direct general and administrative costs of exploration and production operations and estimated cash flows related to asset retirement obligations. Deducting future income tax expenses then further reduces the estimated pre-tax

25

future net cash flows further. Such income taxes are determined by applying the appropriate year-end statutory tax rates, with consideration of future tax rates already legislated, to the future pre-tax cash flows relating to our proved oil and gas reserves less the tax basis of the properties involved.  Royalties are determined based upon the appropriate royalty rates and regimes in effect at year end for Firebag and natural gas production, and in the case of Firebag, assumes that Firebag is classified as a separate operation for royalty purposes, as described in our MD&A., (See “Oil Sands Crown Royalties and Cash Income Taxes” in the “Suncor Overview and Strategic Priorities” Section of our MD&A). The resultant future net cash flows are reduced to present value amounts by applying the Statement 69 mandated 10% discount factor. The result is referred to as “Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes”.

Summary of Changes in the Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes

Sales, Production, Well Data, Land Holdings and Drilling Activity - Conventional

The following tables set out additional information on our conventional oil and gas producing activities, including our Firebag in-situ operation.  Information with respect to our Oil Sands mining operations is not covered by the information below but is addressed in the preceding information under “Oil Sands Mining Operations”.

26

Sales Prices(1), (2)