SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.  20549

FORM 40-F

(Check One)

o                                 Registration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

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

SUNCOR ENERGY INC.

(Exact name of registrant as specified in its charter)

112 - 4^th Avenue S.W.

Box 38

Calgary, Alberta, Canada T2P 2V5

(403) 269-8100

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

CT Corporation System

111 Eighth Avenue

New York, New York, U.S.A.  10011

(212) 894-8940

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

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

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.

ANNUAL INFORMATION FORM

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SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

March 1, 2006

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

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GLOSSARY OF TERMS

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

Barrel of Oil Equivalent (BOE)

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

Bitumen/Heavy Crude 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 crude 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.

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.

Development Costs

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

Downstream

These business segments manufacture, distribute and market refined products from crude oil.

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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.

Feedstock

Purchases of components required in the production of refined product other than crude oil.

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.

Gross Production/Reserves

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.

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. This product traditionally sells at less than the cost of crude oil.

In-situ Oil

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

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.

MD&A

Suncor’s Management’s Discussion and Analysis dated March 1, 2006, accompanying its audited consolidated financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2005, 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.

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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.

Oil Sands

Oil sands are a naturally occurring mixture of water, sand, clay and bitumen, a very heavy crude oil.

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.

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 U.S. 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

(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 reserves in accordance with U.S. disclosure practices. 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 20 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 Petroleum Consultants Ltd. (“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.

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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 anticipated date of resumption of production must be known.

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 oil sands/heavy oil leases.

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 as well as production using conventional methods.

Utilization

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

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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 a territory without existing proved reserves, with the intention to discover commercial reservoirs or deposits of crude oil and/or natural gas.

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,

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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 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; labour and material shortages; and other facilities 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 fires, 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 Suncor 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. Information contained in or otherwise accessible through our website does not form a part of this AIF. All such references are inactive textual references only.

References herein to our 2005 Consolidated Financial Statements mean Suncor’s audited consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2005.

NON GAAP FINANCIAL MEASURES

Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, cash flow from operations 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.

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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.

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 in Canada under the Sunoco brand 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, bitumen and byproducts such as petroleum coke, sulphur and gypsum, produced by Suncor’s Oil Sands business, through this indirect Suncor subsidiary. Through this subsidiary we also administer Suncor’s energy trading activities, market certain third party products, and procure crude oil feedstocks for Suncor’s downstream businesses and natural gas for our Oil Sands and Energy Marketing and Refining business. 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 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 the Suncor Energy Oil Sands Limited Partnership. The partnership held certain net profits interests related to our oil sands business and natural gas business and effective January 1, 2006, Suncor Energy Inc. contributed, subject to certain exceptions, its oil sands assets to the partnership. This internal reorganization has no effect on operations or on our consolidated net earnings.

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.

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GENERAL DEVELOPMENT OF THE BUSINESS

Overview

We are an integrated energy company, with corporate headquarters in Calgary, Alberta, Canada. We are strategically focused on developing one of the world’s largest petroleum resource basins – Canada’s Athabasca oil sands. In addition, 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 businesses:

Our Oil Sands business, 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, 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 natural 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 indirectly wholly-owned U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., acquires land and explores for coal bed methane in the United States.

Our third business, 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.

Our fourth business, 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.

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 2005, we produced approximately 206,100 BOE per day, comprised of 174,500 barrels per day (bpd) of crude oil and natural gas liquids and 190 million cubic feet per day (mmcf/d) of natural gas. In 2004, the most recent period with published results, we were the second largest crude oil and natural gas liquids producer in Canada (approximately 9%(3) of Canada’s crude oil production in 2004) and the 18th largest natural gas producer in Canada.(4)

In 2005, we sold approximately 96,000 bpd (2004 – 97,000 bpd) or 15,200 m3 per day (2004 – 15,400 m3 per day) of refined products, mainly in Ontario but also in the United States and Europe through our Energy, Marketing & Refining business. Our refined product sales in Ontario represented approximately 19% (2004 – 19%) of Ontario’s total refined product sales in 2005. In 2005, our Refining & Marketing business sold approximately 86,200 bpd or 13,700 m3 of refined products in Colorado, including approximately 69,200 bpd or 11,000 m3 per day of light oils (gasoline and distillates) (2004 - 58,500 bpd

(3)          CAPP Crude Oil Report – Table 9 Canadian Crude Oil Production and Supply

(4)          Oilweek – July 2005, Top 100 Oil and Gas Producers

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or 9,300 m3 per day, including approximately 45,300 bpd or 7,200 m3 per day of light oils).

Three-Year History

Oil Sands (OS)

OS growth – Since the completion of our Millennium project in 2001, which nearly doubled the production capacity of our operation to 225,000 bpd, our multi-phased growth strategy is to further increase production capacity to 500,000 to 550,000 bpd in 2010 to 2012. Key components of this strategy include:

•                                          Increasing bitumen supply through the development of the Firebag in-situ oil sands reserves. The first phase of Firebag began producing bitumen in 2004 and the second phase of Firebag is expected to commence commercial operations during the first quarter of 2006. The Firebag Stage 2 project cost $540 million.

•                                          Increasing production capacity to 260,000 bpd through the construction and commissioning of a new vacuum unit. Construction of the project began in 2002 with commissioning successfully completed in the fourth quarter of 2005. This project cost $450 million and was completed on time and on budget. In addition, we also completed a debottleneck of our Steepbank mine operation.

•                                          Increasing production capacity to 350,000 bpd in 2008, including approximately $2.1 billion for an additional coker unit to expand Upgrader 2. We currently estimate an additional $1.5 billion in costs 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. It is currently estimated that constructing the upgrader will cost approximately $5.9 billion. The estimated capital cost is provided at a very preliminary stage and is subject to a high level of uncertainty. The project scope and engineering detail will continue to evolve and will influence the estimated capital cost. Integration opportunities in the downstream, market analysis, advances in new technology, availability of labour and the cost of critical components such as steel and fabrication, among other factors, will also affect project scope and cost estimates. In respect to the increased bitumen feed portion of the project, estimated costs, and commencement date continue to be finalized. Approval of regulators and our Board of Directors is also required before the project can proceed.

Cost estimates for major projects involve uncertainties and evolve in stages. For a discussion of this process, an update on the status of our significant capital projects in progress and an explanation of “on time and on budget”, see page 26 of our MD&A, incorporated by reference herein. The $2.1 billion estimated cost for the coker unit has a range of uncertainty of +/- 10%. The $1.5 billion estimated cost for increased bitumen supply has a range of uncertainty of +30% / -20%. The $5.9 billion estimated cost for a third upgrader has a range of uncertainty of +50% / -30%.

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 our 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. In addition to regulatory

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approvals, both of these projects also require the approval of our Board of Directors before they can proceed.

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 we 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 would be an increase of about $0.20 to $0.27 per barrel. This estimate assumes a reduction obligation of 15% from 2010 business-as-usual energy intensity(5) 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 equivalent 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 impact on our business or future growth plans. The ultimate impact of Canada’s implementation of the Kyoto Protocol, however, remains subject to numerous risks, uncertainties and unknowns. These include the outcome of discussions between the federal and provincial governments, the form, impact and effectiveness of implementing legislation, the ultimate allocation of reduction obligations among economic sectors, and other details of Canada’s implementation plan, as well as international developments. Future federal legislation, together with provincial emission reduction requirements such as those required under the Climate Change and Emissions Management Act (Alberta) may require further reduction of emissions intensity from our operations. The Government of Canada has not yet indicated what, if any, limitations will be placed on the price of carbon credits after 2012. 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 122,000 bpd for the first nine months of the year. To mitigate the impact of reduced production during the recovery period,  certain maintenance projects, including a maintenance shutdown previously planned for fall 2005, were moved forward. Repair work and maintenance was completed in September 2005. Our findings into the cause of the fire indicate that it was likely a result of corrosion to a recycle line, causing it to rupture. Assessments indicate the issue related to the fire was an isolated case. We expect that our property loss and business interruption insurance policies will substantially mitigate the financial impact of the fire. For additional information on our insurance policies and recoveries to date refer to note 10(b) to our 2005 consolidated financial statements, and page 24 of our MD&A.

Bitumen Royalty Option Agreement – In September 2005, an agreement was reached with the Alberta Government on the terms and conditions of Suncor’s option to transition to the generic bitumen-based royalty regime in 2009. Should Suncor elect to transfer to the bitumen based royalty, we would pay a royalty based on 25% of bitumen revenues, minus allowable costs. We have until late 2008 to decide if we will exercise the option and move to the generic bitumen based royalty.

Natural Gas (NG)

South Rosevear Gas Plant – In January 2006, subsequent to year-end, we disposed of 15% of the total interest in the South Rosevear gas plant for proceeds of $12 million. We currently retain a 60.4% interest and continue to operate the gas plant.

Divestment of non-core properties – in 2005, we disposed of non-core properties for proceeds of $21 million.

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

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Simonette Gas Plant – In December 2005, we, along with our partner, completed a plant capacity expansion and a new pipeline to connect the Simonette plant with volumes produced from the Cabin Creek and Solomon fields in the Alberta Foothills. In November 2004, Natural Gas divested 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.

Land Acquisition - In December 2004, we acquired assets in eastern British Columbia for $33 million. These assets generated approximately 6 mmcf/d of production in 2005, and consist of developed and undeveloped land.

Settlement - Also in December 2004, we 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.

Frontier Disposition - During 2003, we 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.

Energy Marketing & Refining - Canada (EM&R)

Desulphurization Projects – Canadian federal legislation passed in 1999 mandated average sulphur levels in gasoline at 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 bpd 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. The project is currently on time and on budget.

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 modify the refinery’s processing 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.

Cost estimates for major projects involve uncertainties and evolve in stages. For a discussion of this process, an update on the status of our significant capital projects in progress and an explanation of “on time and on budget”, see page 26 of our MD&A, incorporated by reference herein.

Ethanol 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. In 2005 final environmental approval was received from Natural Resources Canada and the Ontario Ministry of the Environment. Construction of the facility began in 2005 and is expected to be completed in 2006 at

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an estimated cost of $120 million. Natural Resources Canada has contributed $19 million towards this project to date through their Ethanol Expansion Program. An additional $3 million contribution is due once the plant is operational.

Refining & Marketing – U.S.A. (R & M)

On August 1, 2003, we acquired a Denver area 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. During 2005 this refinery processed approximately 4,600 bpd of oil sands crude oil, including 2,150 bpd of oil sands crude oil from our Oil Sands operations at this refinery. We paid US$150 million (approximately Cdn$210 million) for the assets, plus approximately US$44 million (approximately 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 164 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, significantly completed during 2005 and expected to be fully completed during 2006, will total approximately Cdn$39 (approximately US$33 million). These expenditures, intended to reduce air emissions at the refinery, are primarily capital in nature.

On May 31, 2005 we acquired a second refinery from Valero Energy Corporation (“Valero”) in the Denver area adjacent to the refinery we acquired in 2003. The 30,000 bpd Valero refinery was purchased for Cdn$37 million (US$30 million) plus working capital and associated oil and product inventory adjustments, for a total acquisition cost of Cdn$62 million (US$50 million ). The refinery was acquired by purchasing all of the issued and outstanding stock of Valero’s indirect wholly-owned subsidiary, Colorado Refining Company (“CRC”). CRC was subsequently merged into Suncor Energy (USA) Inc. effective August 1, 2005. Our intention is to fully integrate the two operations, providing an expected combined refining capacity of approximately 90,000 bpd in the U.S..

Along with the purchase of the Valero assets, Suncor assumed environmental regulatory and contractual obligations of CRC at the refinery, including CRC’s obligation under a Consent Decree with the United States Environmental Protection Agency, the United States Department of Justice and the State of Colorado for alleged violations of air regulations prior to our purchase, as well as a Compliance Order on Consent with the State of Colorado, relating to groundwater and soil contamination. The Consent Decree obligations are expected to require expenditures of approximately Cdn$25 million (US$20 million) through 2011.

Desulphurization Projects - R&M estimates it will spend approximately Cdn$465 million (US$390 million) to meet requirements for 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 clean fuels legislation requires production of lower diesel sulphur levels (15 ppm) by June 2006 and lower gasoline sulphur levels (30 ppm average, 80 ppm cap) by 2009. Permit approval and construction of the diesel desulphurization facilities commenced in 2004 and is planned to be completed in early 2006. Project scope includes 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.

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

Cost estimates for major projects involve uncertainties and evolve in stages. For a discussion of this process, an update on the status of our significant capital projects in progress and an explanation of “on time and on budget”, see page 26 of our MD&A, incorporated by reference herein.

Other

Financing Activities

In 2005, we entered into a new $600 million credit facility agreement and also renewed $200 million of our available credit and term loan facilities. Our available credit facilities at December 31, 2005 totaled approximately $2.3 billion, of which $1.3 billion was undrawn. 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 2004, we repurchased an undivided interest in our Oil Sands energy service assets previously held under a lease financing arrangement with a third party for $101 million.

In December 2003 we issued US$500 million of 5.95% unsecured Notes, utilizing the remaining capacity of our US$1 billion shelf prospectus. 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 to redeem our 9.05% and 9.125% Preferred Securities in March 2004 for total cash consideration of $493 million.

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 we 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 for the sale of certain proprietary technology.  Throughout 2005 $40 million was received for the provision of associated training services. Amounts are being recognized into income over the term of the sale agreement.

During 1999, we completed an offering of preferred securities the proceeds of which totaled Canadian $507 million after issue. We redeemed these securities on March 15, 2004 for the original principal amount plus accrued and unpaid interest as at March 15, 2004. See Note 1(a) to our Consolidated Financial Statements, which is incorporated by reference herein.

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Renewable Energy

In November 2005, we, along with our joint venture partner Acciona Wind Energy Canada Inc., were selected by the Ontario government to build a 76-megawatt wind power project near Ripley, Ontario. The Ripley Wind Power project is expected to include 38 wind turbines and offset approximately 66,000 tonnes of carbon dioxide annually. The project cost is estimated at approximately $165 million.

In August 2005, we, along with our joint venture partners, a subsidiary of Enbridge Inc. and Acciona Wind Energy Canada Inc., received approval from the Alberta Energy and Utilities Board (EUB) to build a 30-megawatt wind power project near Taber, Alberta called the Chin Chute Wind Power Project. The project is expected to cost approximately $60 million and is scheduled to be commissioned in late 2006. The project plans include approximately 20 wind turbines with the capacity to produce enough zero-emission electricity to offset the equivalent of approximately 88,000 tonnes of carbon dioxide per year.

In September 2004, we, along with our joint venture partners, a subsidiary of Enbridge Inc. and Acciona Wind Energy 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. In 2005 Suncor’s share of revenue from its investment in wind power projects was $3 million (2004 - $2 million).

For further information on developments and issues referred to above and other highlights of 2005, 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 Factors” in this Annual Information Form.

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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 or near our plant near Fort McMurray, Alberta. Our Oil Sands operations, accounting for virtually all of our conventional and synthetic crude oil production in 2004 and 2005, represent a significant portion of our 2005 capital employed (77%)(6), cash flow from operations(6) (70%) and net earnings (76%). These percentages have been determined excluding the corporate and eliminations segment information.

Operations

Our integrated Oil Sands business involves four operations located north of Fort McMurray, Alberta off Highway 63.

1.               Bitumen is supplied from a combination of a mining operation using trucks and shovels, an in-situ operation and third party bitumen supply. Commencing in 2004, the Firebag in-situ operation began producing bitumen which was initially sold into the market as diluted bitumen. Beginning in the fourth quarter of 2005 bitumen from Firebag is being upgraded, with only excess production, if any, sold into the market.

2.               Extraction facilities recover the bitumen from the oil sands ore that is mined.

3.               Heavy oil upgrading converts bitumen into crude oil products.

4.               Our energy service needs are primarily met through facilities operated by TransAlta that provide steam and electricity to the operations.

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.

Our in-situ operation uses an extraction technology called Steam Assisted Gravity Drainage (“SAGD”) to extract bitumen from oil sands deposits that are too deep to be mined economically. The first step of the SAGD process is to drill a pair of horizontal wells with one well located above the other. Steam produced by our steam generation facilities is injected through the top well into the oil sand. Heated bitumen and condensed steam drain into the bottom well and flow up the well to the surface. The bitumen is pumped to our oil/water separation facilities where the water is removed from the bitumen, treated, and recycled into the steam generation facilities. Naphtha is added to the bitumen to facilitate transportation and the blended bitumen is transported by pipeline to our upgrading facilities. Periodically excess diluted bitumen from our in-situ operations may be sold prior to being upgraded. In 2006, we anticipate upgrading virtually all our extracted bitumen.

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 synthetic crude oil, is either sold directly to customers as sour synthetic crude oil or is further upgraded into sweet synthetic 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.

There is virtually no finding cost associated with synthetic crude oil, the delineation of the resources and development and expansion of production can entail significant outlays of funds. The costs associated

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

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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 using the 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.

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 54% of Oil Sands consolidated operating revenues in 2005, compared to 67% in 2004. Sales of light sour synthetic crude oil and bitumen represented the remaining 46% of revenues in 2005 compared to 33% in 2004. 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.

2005 sales volumes and sales mix were impacted as a result of the fire at our Oil Sands operation that occurred January 2005. In 2006 we anticipate that approximately 55% of Oil Sands sales will be light sweet synthetic crude and diesel products.

Principal Markets

We market our crude oil product blends for sale and distribution to customers in Canada, the United States and periodically, to offshore markets.

Transportation

We own and operate a pipeline that transports synthetic crude oil from Fort McMurray, Alberta to Edmonton, Alberta. The pipeline has a capacity of approximately 110,000 bpd.

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 current pipeline capacity for the transport of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta, to Hardisty, Alberta is 170,000 bpd. 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.

In 2005 it was announced that Suncor had entered into a binding memorandum of understanding with Enbridge Pipelines (Athabasca) Inc, Petro-Canada, Total E&P Canada Limited, and ConocoPhillips Surmont Partnership for the transportation of crude oil, on a proposed new pipeline running from Cheecham, Alberta to Edmonton, Alberta. The expected in-service date of the line is targeted for July 1, 2008 with a 25 year term. Initial line capacity is expected to be 350,000 bpd with potential expansion of capacity to 600,000 bpd with the construction of additional pumping facilities. Our initial line commitment is 30,000 bpd. It is expected that the pipeline will provide an enhanced ability to access new markets on the West coast and offshore.

We have a 20 year agreement with TransCanada Pipeline Ventures Limited Partnership 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.

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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 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.

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 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.

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 18% of our average 2005 total production (2004 – 13%)) of sour crude from the Oil Sands operation. We began shipping the crude to Koch 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 on twenty-four months notice by either party. Neither party has provided notice of termination at this time.

Under a long term sales agreement with Consumers Co-operative Refineries Limited (“CCRL”) we supply 20,000 bpd of sour crude oil production from our Project Millennium expansion facilities. In the fourth quarter of 2005 we signed another contract with CCRL for an additional 12,000 bpd of sour crude oil. Prices for sour crude oil under both of these agreements are set at agreed differentials to market benchmarks.

In 2001, we announced an agreement with Petro-Canada to supply up to 30,000 bpd of diluent to dilute bitumen produced by Petro-Canada. Deliveries under the contract are expected to end when the bitumen processing and sour crude oil supply agreement with Petro-Canada, described below, takes 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 2005, 2004, or 2003.

A portion of our Oil Sands production is used in connection with our Sarnia refining operations. During 2005, the Sarnia refinery processed approximately 4% (2004 - 8%) of Oil Sands crude oil production.

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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 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 natural 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 in the United States.

In 2005, natural gas and natural gas liquids accounted for approximately 98% of the NG business unit’s production (2004 – 97%).

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 and for coal bed methane in the U.S..

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 315 mmcf/d. Our capacity interest in these gas processing plants is approximately 144 mmcf/d. 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 76% 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. A portion of our natural gas production is also used at our Sarnia, Ontario refining operations.

Approximately 24% 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).

We do not typically enter long-term supply arrangements for our conventional crude oil production, which in 2005 was less than 10,000 bpd. Instead, 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

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business currently has no pipeline commitments related to the shipment of crude oil.

Principal Products

Sales of natural gas represented 91% (2004 – 90%) of NG’s consolidated operating revenues in 2005, with the remaining 9% (2004 – 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.

Competitive Conditions

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

Seasonal Impacts

Risk and uncertainties associated with weather conditions can shorten the winter drilling season and impact the spring and summer drilling programs, with increased costs or reduced production.

Environmental Compliance

For a description of the impact of environmental protection requirements on NG, refer to “Environmental Regulation and Risk” and “Government Regulation” in the “Risk 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 Ontario. For information about EM&R’s energy marketing and trading business, refer to “Energy Marketing and Refining – Canada (EM&R)” under the “Three-Year Highlights”, “Energy Marketing & Trading” heading.

As a marketing channel for our refined products, EM&R’s Ontario retail network generated approximately 57% of EM&R’s total 2005 sales volume of 96,000 bpd. The retail networks are comprised of 275 Sunoco-branded retail service stations, 28 Sunoco-branded Fleet Fuel Cardlock sites, and two 50% retail joint venture(7) businesses that operate 149 Pioneer-branded retail service stations, 50 UPI-branded retail service stations and 14 UPI bulk distribution facilities for rural and farm fuels. Approximately 39% of EM&R’s refined product sales in 2005 were wholesale and industrial sales. Sun Petrochemicals Company

(7)   Pioneer Group Inc., is an independent company that Suncor has a 50% joint venture partnership with.  UPI Inc. is a 50% joint venture Suncor has with GROWMARK Inc., a Midwest U.S. retail farm supply and grain marketing cooperative.

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(SPC), a 50% joint venture between a Suncor subsidiary and a Toledo, Ohio-based refinery, generated the remaining 4% of sales.

Procurement of Feedstocks

The Sarnia refinery uses both synthetic and conventional crude oil. In 2005, the Sarnia refinery procured approximately 16% (2004 – 41%) of its synthetic crude oil feedstock from our Oil Sands production. In 2005, 62% (2004 – 66%) 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.  During 2005, as a result of the fire at Oil Sands, EM&R was forced to purchase additional third party synthetic crude oil to meet customer demand.

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 2005 averaged approximately 90,700 bpd (2004 – 94,300 bpd). Sales volumes are higher than crude oil capacity due to often running more than 70,000 bpd, incremental volume from the addition of feedstocks in the production process, purchases of third-party products for resale and sales from joint venture partners that are not from production. 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 have 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 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 improvements and upgrades, it can continue to be operated economically and safely for up to 10 years. A range of replacement options for the catcracker were identified during a review in 2005. Further analysis of these options during 2006 is required to finalize the preferred option for the catcracker for the

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next 10 years.

During 2005, EM&R completed scheduled outages and slowdowns throughout the refinery’s plants, which affected production as expected. However, production in the third quarter was slightly lower than normal due to a heater fire and utilization rates in the fourth quarter were lower due to a power failure causing an unplanned catcracker outage.

Overall, crude utilization averaged 95% for the year, compared to 100% in 2004. 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 68% of EM&R’s consolidated operating revenues in 2005, compared to 72% in 2004. 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

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Principal Markets

Approximately 57% (2004 – 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 2005, this network was comprised of:

275 (2004 – 278) Sunoco-branded retail service stations

149 (2004 – 147) Pioneer-operated retail service stations

50 (2004 – 52) UPI-operated retail service stations and a network of 14 bulk distribution facilities for rural and farm fuels

28 (2004 – 23) Sunoco branded Fleet Fuel Cardlock sites

UPI Inc. 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.

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

Approximately 39% (2004 – 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, Quebec.

EM&R markets toluene, mixed xylenes, orthoxylene and other petrochemicals, primarily in Canada and the U.S., through Sun Petrochemicals Company (“SPC”). EM&R has a 50% interest in SPC, a petrochemical marketing joint venture that markets products from our Sarnia, Ontario 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, Ontario.

EM&R’s share of total refined product sales in its primary market of Ontario was approximately 19% in 2005 (2004 – 19%). Transportation fuels accounted for 82% of EM&R’s total sales volumes in 2005 (2004 – 82%); and petrochemicals accounted for 4% (2004 – 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 54% of this capacity in 2005 (2004 – 55%). Total utilization of the pipeline was 84% in 2005 (2004 - 88%).

EM&R also has pipeline access, subject to availability, to petroleum markets in the Great Lakes region of the United States by way of a pipeline system in Sarnia operated by a U.S. based refiner. This link to the

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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.

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 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 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 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 and expanded via acquisition of the Colorado Refining Company on May 31, 2005, operates a pipeline transportation, refining and marketing business primarily in Colorado and Wyoming. The Denver area refineries, located in Commerce City, Colorado, have a combined crude distillation capacity of 90,000 bpd. The majority of the refined products from the Denver refinery are distributed in Colorado.

Approximately 18% of R&M’s petroleum products sales in 2005 (2004 – 24%) were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers. Approximately 70% in 2005 (2004 – 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 comprised the remaining 12% of R&M’s refined product sales volumes for 2005 (2004 – 16%).

Procurement of Feedstocks

The Denver refining operation uses both conventional and synthetic crude oil. Approximately one-third of the 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 multi-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.

Refining Operations

Upgrading units at the refining operation include a 27,000 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 2005 averaged approximately 86,200 bpd (13,700 m3 per day) compared to 58,500 bpd (9,300 m3) in 2004.

The Denver area refining operation is a high conversion operation 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 approximately one-third heavy, high sulphur crude. Overall, crude utilization averaged 98% in 2005 (2004 – 92%). The following chart sets out daily crude input, average refinery utilization rates and cracking capacity utilization for 2005 and 2004.

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Notes:

(1)                                  30,000 bpd Valero refinery capacity acquired May 31, 2005.

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

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

Principal Products

Sales of gasoline and other transportation fuels represented 90% of R&M’s consolidated operating revenues in 2005 (2004 – 85%). 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 2005.

Note:

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

Principal Markets

Approximately 18% of R&M’s total sales volumes are marketed through Phillips 66 ® - branded retail outlets. This network is comprised of:

•                  43 owned Phillips 66 ® - branded retail sites, which account for approximately 5% of R&M’s sales volumes; and

•                  Supply agreements with 164 Phillips 66 ® branded marketer outlets throughout the state of Colorado, which account for approximately 13% 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.

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The Denver refining operation also supplies all of its asphalt production to SemMaterials, L.P.. Asphalt sales made up about 12% of R&M’s total 2005 sales volumes (2004 – 16%).

Approximately 70% of R&M’s total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Colorado, of which approximately 15% was sold under a long-term supply agreement with ConocoPhillips and 17% under a long-term supply agreement with Valero. Under the ConocoPhillips agreement, R&M supplies ConocoPhillips with gasoline and distillates, and 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. In connection with the purchase of CRC, R&M entered into a three year offtake agreement with Valero which expires in May 2008. Valero became R&M’s largest customer following the CRC acquisition.

R&M estimates its sales of total light fuels refined product in 2005 represented a market share, in its primary market of Colorado, of approximately 35% (2004 – 23%). Within this market, R&M’s Phillips 66 ® - branded sites represent a 18% market share (2004 – 24%).

Transportation and Distribution

Approximately two-thirds of crude oil processed at the Denver refining operation is transported via pipeline, with the remainder supplied via truck. 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 the Centennial pipeline. The other 35% owned by another area refiner. The Rocky Mountain crude system capacity 31,100 bpd in 2005 for the Guernsey to Cheyenne leg of the pipeline and 60,500 bpd for the Cheyenne to Denver leg of the pipeline. In 2005, the Rocky Mountain Crude system utilized approximately 115% (2004 – 109%) of capacity with average throughput of 35,400 bpd (2004 – 34,200 bpd) in the Guernsey to Cheyenne leg of the pipeline, and 70,150 bpd (2004 - 65,200 bpd) in the higher capacity Cheyenne to Denver leg. During the same period, the Centennial pipeline utilized approximately 102% (2004 – 97%) of capacity, with an average throughput of approximately 62,500 bpd (2004 – 59,100 bpd).

R&M has both truck and rail loading racks at the Denver area refineries with product loading capacity in excess of 30,000 bpd, 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 Factors” section of this Annual Information Form.

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Environmental Compliance

Due to increasingly stringent regulations regarding water discharges, the need to improve water treatment ability at our Denver refining operation we will require additional water treating equipment for the discharge of process waste water. It is estimated that this will cost approximately Cdn$19 to $23 million (US$16 to $20 million) and be completed in the 2006 to 2010 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 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 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, 2005 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, 2005.

RESERVES ESTIMATES

We are a Canadian issuer 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”). 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 and net proved and probable mining reserves. The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80%. During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves. The estimate of our net mining reserves reflect the relative value of Alberta Crown and freehold royalty burdens under constant December 31^st bitumen pricing and assumes Suncor will elect to transfer to a bitumen based Crown royalty effective at the beginning of 2009 (See “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE – Proved and Probable Oil Sands Mining Reserves” for both gross and net, proved and probable mining reserves). Our Firebag in-situ leases are subject to Crown royalty based on bitumen, rather than synthetic crude oil (for a full discussion of our oil sands Crown royalties, see “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:

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(a)                                  Gross and net proved and probable mining reserves, on the same basis as disclosed pursuant to U.S. disclosure requirements (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil yield from bitumen of 80%);  and

(b)                                 Gross and net 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 at 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 aggregation purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 80%.

Accordingly, our voluntary disclosures of reserves from our Firebag in-situ leases will differ from our required U.S. disclosure in four ways. Reserves from our Firebag in-situ leases under our voluntary disclosure:

(a)                                  are disclosed on a gross basis as well as the required net basis under U.S. disclosure requirements;

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

(c)                                  are evaluated based on 2005 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; and

(d)                                 include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements.

Under the U.S. disclosure requirements described above, our Firebag in-situ reserves were determined to be entirely uneconomic at December 31, 2004. In 2005, Constant Cost and Pricing assumptions were again applied to assess economic viability of our in-situ reserves. This assessment resulted in the rebooking of proved reserves at December 31, 2005 (See “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE - Proved Conventional Oil and Gas Reserves”).

Under our voluntary disclosure, using 2005 Annual Average Differential Pricing, our Firebag in-situ reserves were also determined to be economic and accordingly, were disclosed under “VOLUNTARY OIL SANDS RESERVES DISCLOSURE - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations”.

Comparisons of reserve estimates under required U.S. Oil and Gas Mining Disclosure and Voluntary Oil Sands Reserve Disclosure will show material differences based on the pricing assumptions used, whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, whether probable reserves are included, and whether the reserves are reported on a gross or net basis.

All of our reserves have been evaluated as at December 31, 2005 by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (“GLJ”). In reports dated February 21, 2006 (“GLJ Oil Sands Reports”), GLJ evaluated our proved and probable reserves on our oil sands mining and Firebag in-situ leases, pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions, and pursuant to CSA Staff Notice 51-315, using 2005 Annual Average Differential Pricing assumptions.

Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory applications have been submitted and no anticipated impediment to the receipt of regulatory approval is expected. The mining reserve estimates are based on a detailed geological assessment and also consider industry

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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 or likely impediments to the receipt of pending regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects and drill density. Our proved reserves are delineated to within 80 acre spacing with 3D seismic control (or 40 acre spacing without 3D seismic control) while our probable reserves are delineated to within 320 acre spacing with 3D seismic control (or 160 acre spacing without 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 have not yet received final approval from our Board.

In a report dated February 21, 2006 (“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, 2005.

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

Net reserves represent Suncor’s undivided percentage interest in total reserves after deducting Crown Royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about future prices, production levels, operating costs and capital expenditures. These assumptions reflect market conditions, as required, at December 31, 2005 which could differ significantly from other points in time throughout the year, or future periods. These market conditions and assumptions can materially impact the estimation of net reserves.

REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE

Proved and Probable Oil Sands Mining Reserves

Notes:

(1)           Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80% (2004 – 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)           Net mining reserves reflect the relative value of Crown, freehold and overriding royalty burdens under constant December 31st pricing and assumes we will elect to transfer to a bitumen based Crown royalty effective at the beginning of 2009.

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Significant Mining Leases

(1)          These producing leases can be retained indefinitely so long as agreed minimum levels of production are maintained.

(2)           Annual lease rentals are required to maintain these leases until the indicated expiry dates for the primary term of the lease. Leases can be retained after these dates if:

a.               they are in production and sustain agreed minimum levels of production; or

b.              retained indefinitely if escalating rents are paid. Depending on area, such rents range from $3/acre/year in in-situ areas to $7/acre/year in surface mining zones and double every three years to a maximum of $96/acre/year in in-situ zones and $224/acre/year in surface mining areas.

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Oil Sands Mining Operating Statistics

The following table sets out certain operating statistics for our 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. Note, in 2004 and prior years, production equaled our “base operations” production statistics as included in the operating summaries filed with our annual financial statements. In 2005 and subsequent years, bitumen production from Firebag is upgraded and included in the base operations production. Therefore the mining production reported above will no longer agree to the operating statistics.

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.

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NET PROVED RESERVES(1)

Crude Oil, Natural Gas Liquids and Natural Gas

Notes:

(1)           Our undivided percentage interest in reserves, after deducting Crown royalties, freehold royalties and overriding royalty interests. Our Firebag leases are only subject to Crown royalties.

(2)           Although we are subject to Canadian disclosure rules in connection with the reporting of our 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 45.

(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. Under 2005 Constant Cost and Pricing we have rebooked our proved reserves.

(4)           We have the option of selling the bitumen production from these leases or upgrading the bitumen to synthetic crude oil. With the completion of upgrading expansion projects during 2005, all bitumen is expected to be processed into synthetic crude oil in the future.

(5)           Includes total infill drilling of 2005 - 23 billion cubic feet (bcf), (2004 – 20 bcf; 2003 – 15 bcf).

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, 2005. 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.

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Capitalized Costs Relating to Oil and Gas Activities (1)