SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

March 3, 2008

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

GLOSSARY OF TERMS

In this Annual Information Form (AIF), 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.

Best Estimate Resources

Is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is generally prepared independent of the risks associated with achieving commercial production

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 may be upgraded into crude oil and other petroleum products.

Capacity

Maximum annual average output that may 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.

Contingent Resources

Those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

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.

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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

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

Dry Hole/Well

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

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 working 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.

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MD&A

Suncor’s Management’s Discussion and Analysis dated February 27, 2008, 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, 2007, which is incorporated by reference herein.

Natural Gas

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

Natural Gas Liquids

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

Net Production/Reserves

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

Net Wells/Land Holdings

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

Overburden

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

Oil Sands

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

Probable Reserves¹

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely² that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

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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 certainty² to be recoverable in future years from known reservoirs under assumed economic and operating conditions.

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 may 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.

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

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.

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 and Resources Disclosure - Oil Sands Mining and In-Situ Firebag Reserves Reconciliation”.

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.

Remaining Recoverable Resources

The sum of reserves and contingent resources.

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 purification of bitumen.

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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 lands are those 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 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.

Wells

Development Well

A crude oil or natural gas well drilled in, or adjacent to, 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.

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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 were made by the company in light of its experience, and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about 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,” “estimates,” “plans,” “scheduled,” “intends,” “may,” “believes,” “projects,” “indicates,” “could,” “focus,” “vision,” “goal,” “proposed,” “target,” “objective,” “continue” 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, many of which are beyond our control, 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, interest rates and currency exchange rates; our ability to respond to changing markets, and to receive timely regulatory approvals;  the successful and timely implementation of capital projects including growth projects (for example, the Voyageur project, including our Firebag in-situ development) and regulatory projects (for example, the emissions reduction modifications at our Firebag in-situ development); 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; the cost of compliance with existing and future environmental laws;  the accuracy of Suncor’s 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;  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 (for example, the Government of Alberta’s current review of the unintended consequences of the proposed Crown Royalty regime, and the Government of Canada’s current review of greenhouse gas emission 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, and is not incorporated into the AIF by reference.

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References herein to our 2007 Consolidated Financial Statements mean Suncor’s audited consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), the notes thereto and the auditor’s report thereon, as at and for the three years in the period ended December 31, 2007.

NON GAAP FINANCIAL MEASURES

Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, cash flow from operations, Oil Sands cash and total operating costs per barrel and Return on Capital Employed (ROCE), 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 four principal subsidiaries and partnerships.

Suncor Energy Oil Sands Limited Partnership is an Alberta limited partnership that is indirectly wholly owned by Suncor Energy Inc.  Effective February 1, 2005, Suncor Energy Inc., as general partner, and one of its wholly-owned subsidiaries, as a limited partner, formed the Suncor Energy Oil Sands Limited Partnership.  At this time the partnership held certain net profits interests related to our oil sands business and natural gas business.  Effective January 1, 2006, Suncor Energy Inc. contributed, subject to certain exceptions, its oil sands assets to the partnership.  This internal reorganization had no effect on operations or on our consolidated net earnings.

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.  We are 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.  This company markets, 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 our Oil Sands business.  Through this subsidiary we also administer Suncor’s energy trading activities, market certain third party products, and procure crude oil feedstocks and natural gas for our downstream business.  This subsidiary markets certain natural gas volumes produced by, and purchased from, our Natural Gas business unit.  Suncor Energy Marketing Inc. also has a petrochemical marketing division that holds a 50% interest in Sun Petrochemicals Company, a petrochemical products joint venture.

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 owned pipelines in Wyoming and Colorado.

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

Suncor is 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 three 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, diesel fuel and by-products.  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 and natural gas liquids 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 internal consumption.  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, Refining and Marketing, refines crude oil at Suncor’s refineries in Sarnia, Ontario, and Commerce City, Colorado, into a broad range of petroleum, petrochemical and biofuel products.  These products are then marketed to industrial, wholesale and commercial customers principally in Ontario, Quebec and Colorado.  In Ontario, our retail businesses are managed through Sunoco-branded and joint venture operated retail networks, and in Colorado our retail businesses are managed through Phillips 66 ® - branded sites.   We also transport crude oil on our wholly owned pipelines in Wyoming and Colorado, and engage in third party energy marketing and trading activities through this business.

For financial reporting purposes, we also report financial data for activities not directly attributable to an operating business under the results of Suncor’s “Corporate” segment.  This includes the activity of our self-insurance entity, as well as investments in wind energy.

In 2007, we produced approximately 271,400 boe per day, comprised of 238,700 barrels per day (bpd) of crude oil and natural gas liquids and 196 million cubic feet per day (mmcf/d) of natural gas.  In 2006, the most recent period with published results, we were the second largest crude oil and natural gas liquids producer in Canada (approximately 10%³ of Canada’s crude oil production in 2006) and the 16th largest natural gas producer in Canada.⁴

In 2007, our Refining and Marketing business sold approximately 210,700 bpd (2006 – 185,600 bpd) or 33,500 m³ per day (2006 – 29,500 m³ per day) of refined products, mainly in Ontario and Colorado, but also in other states throughout the United States and in Europe.

 ³ CAPP Crude Oil Report – Table 1 Canadian Crude Oil Production Forecast

 ⁴ Oilweek – July 2007, Top 100 Oil and Gas Producers

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Three-Year History

Oil Sands (OS)

Over the past three years we have continued to advance our multi-phased growth strategy to increase production capacity to 550,000 bpd in 2012.  Key milestones and significant events that have affected our Oil Sands business during this time period include the following:

o        In September 2007, high emissions at our in-situ operations resulted in orders being issued by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has been capped at approximately 42,000 bpd.

o        In December 2007, high emissions at our base plant resulted in an order being issued by Alberta Environment.  Emissions at the oil sands plant exceeded air quality standards, and accordingly we are upgrading our emission control equipment and reducing discharges to the tailings ponds.  In addition, we have introduced processing changes and are undertaking a more comprehensive monitoring program.

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The following changes to our Oil Sands business have occurred, or are expected to occur in 2008:

·                Royalty Amending Agreement – In January 2008, we entered into the Suncor Royalty Amending Agreement with the government of Alberta, which modifies the rates under the Generic Regime which would otherwise apply to our base mining operations, assuming the government enacts their proposed framework.  Under this agreement, prior to January 1, 2010, we would expect to pay a royalty in respect of our base operations of 25% of the difference between a project’s annual gross revenues net of related transportation costs, less allowable costs including allowable capital expenditures (R-C), and from January 1, 2010 through to January 1, 2016, we would expect to pay royalties in accordance with the rates in the Generic Regime, subject to a cap of 30% of R-C. (See page 19 of our MD&A for more information.)

·                Voyageur Growth Plan – In January 2008, Suncor’s Board of Directors approved a $20.6 billion investment that is expected to boost crude oil production capacity at the company’s oil sands operation by 200,000 bpd, bringing the total capacity to 550,000 bpd in 2012. The expansion plans include constructing four additional stages of in-situ bitumen production, a new upgrader (Suncor’s third) to convert that bitumen into higher-value crude oil, and various infrastructure and utilities.

·                Petro-Canada Agreement – Incremental bitumen to feed the expanded Oil Sands operation is  expected to be partially obtained starting in 2008 under a processing agreement between Suncor and Petro-Canada.  Under the terms of the agreement, we will process a minimum of 27,000 bpd of Petro-Canada bitumen on a fee-for-service basis.  Petro-Canada retains ownership of the bitumen and resulting sour crude oil production of about 22,000 bpd.  In addition, Suncor has agreed to 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 are for a minimum 10-year term.

Natural Gas (NG)

Key milestones and significant events that have affected our Natural Gas business during the past three years include the following:

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

·                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.  We have a 37.5% ownership interest and continue to operate the Simonette gas plant.

·                South Rosevear Gas Plant – In January 2006, 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.

·                Acquisition – In March 2007, we acquired developed and undeveloped lands in British Columbia for approximately $160 million.

Refining and Marketing (R&M)

Consistent with the company’s organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment – Refining and Marketing.  Key milestones and significant events that have affected our Refining and Marketing business during the past three years include the following:

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·                Valero Acquisition – On May 31, 2005 we acquired a refinery from Valero Energy Corporation (“Valero”) in the Denver area adjacent to our existing refinery. The 30,000 bpd Valero refinery was purchased for $37 million (US$30 million) plus working capital and associated oil and product inventory adjustments, for a total acquisition cost of $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.  This facility was integrated with our existing U.S. refinery.  Our current combined refining capacity is approximately 90,000 bpd in the U.S.

·                Reduced Refinery Air Emissions – In connection with the acquisition of a 60,000 bpd refinery from ConocoPhillips on August 1, 2003, we assumed obligations at the refinery pursuant to a Consent Decree with the United States Environmental Protection Agency to reduce air emissions.  These obligations were met during a planned maintenance shutdown in 2006 for a total cost of approximately $60 million (approximately US$50 million).

·                Diesel Desulphurization and Oil Sands Integration – In July 2006, the Commerce City refinery completed its diesel desulphurization and oil sands integration project at a total cost of approximately $530 million (US$435 million).  The completion of the project allows the refinery to produce ultra low sulphur diesel to meet requirements of fuels desulphurization legislation, and enable the refinery to process up to 15,000 bpd of oil sands sour crude oil.  In addition, the modifications increased the refinery’s ability to process a broader slate of synthetic crude oil.

·                Ethanol Plant – In July 2006, we completed our St. Clair ethanol facility on time and on budget, for a final cost of $112 million, and with a production capacity of 200 million litres per year.  The ethanol produced is primarily blended into our Sunoco-branded fuels and fuels sold through our joint venture operated networks.  Natural Resources Canada contributed $22 million towards this project through their Ethanol Expansion Program.  This contribution of $22 million includes a repayment obligation and we have already repaid $2 million to date.

·                Diesel Desulphurization and Oil Sands Integration – In November 2007, Suncor completed the final phase of a three year $950 million project at the Sarnia refinery. A 120-day shutdown to complete the tie-ins was the last step in the multi-phased project. The project increased the amount of oil sands crude oil the refinery can upgrade, improved the facility’s environmental performance, and commencing in 2006 enabled the production of ultra low sulphur diesel fuel.

Other

Renewable Energy

In addition to renewable energy investments in ethanol production through our Refining and Marketing segment, Suncor also invests in renewable wind power. Suncor is a partner in four wind power projects, including two projects commissioned in the past three years.

In November 2006, we, along with our joint venture partners, Enbridge Income Fund and Acciona Wind Energy Canada Inc., officially opened a 30-megawatt wind power project near Taber, Alberta called the Chin Chute Wind Power Project.  The project includes 20 wind turbines with the capacity to produce enough zero-emission electricity to offset the equivalent of approximately 102,000 tonnes of carbon dioxide per year.

In September 2007, we, along with our joint venture partner Acciona Wind Energy Canada Inc, officially opened a 76-megawatt wind power plant near Ripley, Ontario.  The $176 million Ripley Wind Power Project consists of 38 wind turbines, a 27-km transmission line and two electrical substations.  The project is expected to displace at least 66,000 tonnes of carbon dioxide per year.

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Other Transactions

Throughout 2005, $40 million was received for the provision of training services associated with the sale of certain proprietary technology in 2004.  Amounts are being recognized into income over the term of the sale agreement.

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NARRATIVE DESCRIPTION OF THE BUSINESS

OIL SANDS (OS)

Suncor produces a variety of refinery feedstock, diesel fuel and by-products by developing the Athabasca oil sands in northeastern Alberta and upgrading the bitumen extracted at our plant near Fort McMurray, Alberta.  Our Oil Sands operations, accounting for virtually all of our conventional and synthetic crude oil production in 2007, represent a significant portion of our 2007 capital employed⁵ (65%), cash flow from operations⁵ (79%) and net earnings (87%).  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.

1)            Bitumen is supplied from a combination of a mining operation using trucks and shovels, an in-situ operation and third party bitumen supply.

2)            Extraction facilities recover the bitumen from the oil sands ore that is mined.  Since late 2005, bitumen from Firebag is being upgraded, with only a small portion of production being strategically sold directly into the market.

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

4)            Utilities for the operation (water, steam and electricity) are generated through facilities on site, some of which are owned and operated by Suncor, and others which are owned and operated by third parties.

Mining/Extraction - 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 a sizing plant followed by an ore preparation plant. Here, the oil sands ore 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. In extraction, bitumen is extracted from the oil sands ore using a hot water process.  After the final removal of impurities and minerals, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.

In-situ - 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 on-site steam generation facilities is injected through the top well into the oil sands.  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. For current stages of in-situ development, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.  Future stages propose to use a heated pipeline instead of naphtha dilution for transport.

Upgrading - After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and recycled to be used again as diluent. The bitumen from both SAGD and mining 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.  Four separate streams of refined crude oil are produced: diesel, naphtha, kerosene and gas oil.

 ⁵ Refer to “Non GAAP Financial Measures” on page ix of this AIF.

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We continue to explore and develop improved and alternative technologies to facilitate increased efficiency and processing within our operations.  For example, based on the results of testing performed during the past two years, we plan to utilize new mining technology and processes in our future mine development plans.  This technology is incorporated in the July 2007 regulatory application for the planned Voyageur South Mine extension.

While there is virtually no finding cost associated with synthetic crude oil, the delineation of the resource and development and expansion of production entail significant capital outlays.  For the same reason, the costs associated with synthetic crude oil production are largely fixed in the short term, 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 in SAGD production at our Firebag operations, and accordingly natural gas prices are a key variable component of synthetic crude oil production costs.

In the normal course of our operations we regularly complete planned maintenance shutdowns of our Oil Sands facilities.  These shutdowns are scheduled, and provide both preventative maintenance and capital replacement which are expected to improve our operational efficiency. In July 2007 a scheduled maintenance shutdown of Upgrader 2 occurred to facilitate the tie-in of new coker units, an important milestone in the capital expansion project to increase Oil Sands production capacity to 350,000 bpd in the second half of 2008. A 30-day planned shutdown of Upgrader 1 is expected to occur in 2008.

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 59% of Oil Sands consolidated operating revenues in 2007, compared to 53% in 2006.  The other significant component of our revenues were light sour synthetic crude oil and bitumen sales of 38% (2006 – 43%).  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.

We anticipate that approximately 47% of Oil Sands sales in 2008 will be light sweet synthetic crude and diesel products.

Principal Markets

We market our crude oil product blends principally to customers in Canada and 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 entered into a transportation service agreement with a subsidiary of Enbridge Inc. 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. In addition, in 2008 we committed to an additional 12,000 bpd that underpins current expansion plans for the pipeline.

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In 2005, Suncor 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 currently 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.

Suncor has entered into long term service agreements with affiliates of TransCanada Corporation for transportation of crude oil on the Keystone pipeline.  The agreements will provide for pipeline transportation of our crude oil from Hardisty, Alberta to both Patoka, Illinois and Cushing, Oklahoma.  Transportation of crude oil on the Keystone pipeline is targeted to commence in 2009.

We continue to evaluate additional pipeline agreements to support our expected production capacity of 550,000 bpd in 2012.

Periodically, we also enter into strategic short term cargo transport agreements to ship synthetic crude oil to the United States Gulf Coast.  These agreements have a term of less than one year, and are specific to individual shipments.

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.

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 mining facilities are readily accessible by public road.  Our Firebag in-situ facilities are currently accessible by private road.  We anticipate termination of such access in 2010, and are currently evaluating alternative means of access.

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 winter climatic conditions at Oil Sands can cause reduced production 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.  Primary markets for our crude oil products include refining operations in Alberta, Ontario, the U.S. Midwest and the U.S. Rocky Mountain region. Diesel products are sold primarily in Western Canada.

In 1997, we entered into a long-term agreement with Flint Hills Resources LLC (“Flint Hills”) to supply Flint Hills with up to 30,000 bpd (approximately 13% of our average 2007 total production (2006 – 11%)) of sour crude from the Oil Sands operation.  We began shipping the crude to Flint Hills at Hardisty, Alberta (from which Flint Hills ships the product to its refinery in Minnesota) on January 1, 1999.  The

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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 CCRL with 20,000 bpd of sour crude oil production.  In 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.  Both CCRL agreements extend through to 2011, with renewal options that could extend out to 2018 and beyond.  Both agreements continue until terminated by either party with twenty-four months notice.  Neither party has provided notice of termination at this time.

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 no later than January 1, 2009. Under the agreement, we will process a minimum of 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 are for a minimum 10-year term.

There were no customers that represented 10% or more of our consolidated revenues in 2007, 2006, or 2005.

A portion of our Oil Sands production is used in our Sarnia and Commerce City refining operations.  During 2007, the Sarnia refinery processed approximately 7% (2006 - 8%) of Oil Sands crude oil production and the Commerce City refinery processed approximately 6% (2006 – 3%) of Oil Sands crude oil production.

Environmental Compliance

For a discussion of environmental risks at our Oil Sands operations, refer to the “Legal and Regulatory Risks” outlined in the “Risk Factors” section of this Annual Information Form, as well as the “Asset Retirement Obligations” section 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 and natural gas liquids in Western Canada, supplying markets throughout North America.  The sale of NG’s production provides a natural price hedge for natural gas purchased for internal consumption.

In 2007, natural gas and natural gas liquids accounted for approximately 98% of the NG business unit’s production (2006 – 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.

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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 135 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 87% of our natural gas production is sold to Suncor Energy Marketing Inc. and then 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.

Approximately 13% 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 Northwest 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.  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 business currently has no pipeline commitments related to the shipment of crude oil.

Principal Products

Sales of natural gas represented 88% (2006 – 90%) of NG’s consolidated operating revenues in 2007, with the remaining 12% (2006 – 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 NG’s 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.

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Seasonal Impacts

Risks and uncertainties associated with weather conditions and wildlife restrictions can shorten the winter drilling season and impact the spring and summer drilling programs, potentially resulting in increased costs or reduced production.

Environmental Compliance

For a discussion of environmental risks at our NG operations, refer to the “Legal and Regulatory Risks” outlined in the “Risk Factors” section of this Annual Information Form, as well as the “Asset Retirement Obligations” section under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

REFINING AND MARKETING (R&M)

Consistent with the company’s organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment – Refining and Marketing.

Our Canadian-based refining and marketing business operates in Central Canada.  Our refinery in Sarnia, Ontario, has a crude oil capacity of 70,000 bpd and 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.  Our ethanol facility in St. Clair, Ontario, produces ethanol from corn, which is used for blending into our fuels and is also sold to third parties.

As a marketing channel for our Canadian refined products, our Ontario retail networks generated approximately 51% of R&M’s Canadian 2007 sales volume of 112,000 bpd.  The retail networks are comprised of Sunoco-branded retail service stations, Sunoco-branded Fleet Fuel Cardlock sites, and two 50% retail joint venture⁶ businesses that operate Pioneer-branded retail service stations, UPI-branded retail service stations and UPI bulk distribution facilities for rural and farm fuels.  Approximately 44% of R&M’s Canadian refined product sales in 2007 were wholesale and industrial sales. Sun Petrochemicals Company, a 50% joint venture between a Suncor subsidiary and a Toledo, Ohio-based refinery, generated the remaining 5% of sales.

Our U.S.-based refining and marketing business includes a refining facility, a retail network, and a pipeline transportation business primarily in Colorado and Wyoming.  The Commerce City, Colorado refining facility has a current combined crude distillation capacity of 90,000 bpd.  The majority of the refined products from the Commerce City refinery are distributed in Colorado.

Approximately 18% of R&M’s US petroleum products sales in 2007 (2006 – 18%) were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers.  In 2007, approximately 74% (2006 – 74%) of our U.S.-based 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 8% of R&M’s U.S. refined product sales volumes for 2007 (2006 – 8%).

In addition to our downstream refining and marketing operations, this business also includes an energy marketing and trading business.  Energy marketing and trading activities consist of both third party crude oil marketing, and financial and physical derivatives trading activities.

 ⁶ Pioneer Group Inc. is an independent company with which Suncor has a 50% joint venture partnership.  UPI Inc. is a 50% joint venture company Suncor has with GROWMARK Inc., a Midwest U.S. retail farm supply and grain marketing cooperative.

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Procurement of Feedstocks

The Sarnia refinery uses both synthetic and conventional crude oil.  In 2007, the Sarnia refinery procured approximately 50% (2006 – 55%) of its synthetic crude oil feedstock from our Oil Sands production.  In 2007, 43% (2006 – 60%) 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.

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 Enbridge Pipeline from Montreal.  We have not made any firm capacity commitments 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.

In July 2006, with the completion of our ethanol facility, we began producing ethanol for use in our blended gasoline products, and for sales to third parties.

The Commerce City refining operation uses both conventional and synthetic crude oil.  Approximately one-quarter of the refinery’s crude oil is purchased from Canadian sources, with the remainder supplied from sources in the United States, primarily from 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.

With the completion of our diesel desulphurization and oil sands integration projects, we are now capable of processing of up to 40,000 bpd and 15,000 bpd of Oil Sands sour crude oil at our Canadian and U.S. refineries, respectively.

Refining Operations

Canadian

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.

In 2007 the refinery had capacity to refine 70,000 bpd of crude oil.  Refining units include a 23,300 bpd hydrocracker and a 5,400 bpd alkylation unit. The petrochemical facilities have a capacity of 13,100 bpd, the aromatic solvents unit has a capacity of approximately 1,000 bpd, and our gasoline desulphurization unit has the capacity to process 10,250 bpd. The distillate hydrotreater that became operational in July 2006 has a processing capacity of 43,600 bpd.

In 2007 the refinery had cracking capacity of 40,200 bpd from a Houdry catalytic cracker (“catcracker”) and a hydrocracker.  Approximately 40% of the cracking capacity was attributable to the catcracker, which uses older technology. In 2004, a study to assess the catcracker concluded that, with planned improvements and upgrades, it can continue to be operated economically and safely for at least 10 years. 

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A range of replacement options for the catcracker was identified during a review in 2005. Analysis of these and other options will continue.

Overall, crude utilization averaged 98% for 2007, compared to 78% in 2006.  In 2007 the utilization rate was impacted by a shutdown to tie-in new facilities while in 2006 the utilization rate was impacted by a major maintenance shutdown.

The refinery’s external steam and electricity needs are currently being met primarily by supply from the Sarnia Regional Co-generation Project.

United States

Refining units include two fluidized catalytic crackers with a 29,500 bpd combined capacity, a 19,000 bpd distillate hydrotreater and a 26,000 bpd gas oil hydrotreater.  The refined gasoline products from the Commerce City refinery primarily supply R&M’s marketing operations in Colorado.  Refining sales in 2007 averaged approximately 99,600 bpd (15,800 m³ per day) compared to 90,600 bpd (14,400 m³ per day) in 2006.

The Commerce City refining operation is a high conversion operation that produces a full range of products, including gasoline, jet fuels, diesel and asphalt.  The refinery produces a crude slate containing approximately one-third heavy, high sulphur crude.  Overall, crude utilization averaged 99% in 2007 (2006 – 92%).

The following chart sets out R&M’s total daily crude input and average refinery utilization rates for both its combined Canadian and U.S. refinery operations in 2007 and 2006.

Notes:

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

In the normal course of our operations we regularly complete planned maintenance shutdowns of our refinery facilities.  These shutdowns are scheduled, and provide both preventative maintenance and capital replacement which is expected to maintain our operational efficiency.  During 2007, significant maintenance shutdowns were successfully completed at both our Sarnia and Commerce City area refining facilities.

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Principal Products

Set forth below is information on daily sales volumes and the corresponding percentage of R&M’s consolidated operating revenues by product for the last two years.

Note:

(1)                                  Includes ancillary revenues

Principal Markets

Canadian

Approximately 51% (2006 – 58%) of R&M’s Canadian sales volumes are marketed through retail networks, including the Sunoco-branded retail network, joint venture owned retail stations and cardlock operations.  In 2007, this network was comprised of:

o       272 (2006 – 272) Sunoco-branded retail service stations

o       151 (2006 – 151) Pioneer-operated retail service stations

o       55 (2006 – 53) UPI-operated retail service stations and a network of 13 bulk distribution facilities for rural and farm fuels

o       48 (2006 – 36) Sunoco branded Fleet Fuel Cardlock sites

UPI Inc. is a joint venture company owned 50% with GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative.  Pioneer is a 50% joint venture partnership with The Pioneer Group Inc.

Refined petroleum products (excluding petrochemicals) are marketed under several brands, including the Company’s Canadian “Sunoco” trademark.  R&M’s other principal trademarks include “Ecowash”, our award-winning car wash and “Gold Diesel”, our premium low-sulphur diesel product.

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Approximately 44% (2006 – 36%) of R&M’s Canadian sales volumes are sold to industrial, commercial, wholesale and refining customers, primarily in Ontario.  R&M also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners.

R&M Canadian operations market toluene, mixed xylenes, orthoxylene and other petrochemicals, primarily in Canada and the U.S., through Sun Petrochemicals Company.  R&M has a 50% interest in Sun Petrochemicals Company, 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.  Sun Petrochemicals Company markets petrochemicals used to manufacture plastics, rubber, synthetic fibres, industrial solvents and agricultural products, and gasoline octane enhancers.  All benzene production is sold directly to other petrochemical manufacturers in Sarnia, Ontario.

R&M’s share of total refined product sales in its primary Canadian market of Ontario was approximately 20% in 2007 (2006 – 18%).  Transportation fuels accounted for 78% of R&M’s Canadian sales volumes in 2007 (2006 – 82%); and petrochemicals accounted for 5% (2006 – 6%).  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.

Refined petroleum products are also supplied to the Pioneer and UPI joint ventures.  We have a separate supply agreement with each of UPI and Pioneer.  These supply agreements are evergreen and are subject to termination only in accordance with the terms of the various agreements between the parties.

United States

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

·     44 owned Phillips 66 ® - branded retail sites, which account for approximately 5% of R&M’s U.S. sales volumes; and

·      Supply agreements with 173 Phillips 66 ® branded marketer outlets throughout the state of Colorado, which account for approximately 13% of R&M’s U.S. sales volumes. These agreements are typically for three year terms with provision for automatic three year renewal periods on an evergreen basis.

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

The Denver refining operation also supplies all of its asphalt production to SemMaterials, L.P.  Asphalt sales made up about 8% of R&M’s U.S. 2007 sales volumes (2006 – 8%).

Approximately 74% of R&M’s U.S. sales volumes are sold to industrial, commercial, wholesale and refining customers, primarily in Colorado, of which approximately 10% was sold under a long-term supply agreement with ConocoPhillips (expiring in 2013) and 23% was sold under a supply agreement with Valero (expiring in 2008).

R&M estimates its U.S. sales of total light fuels refined product in 2007 represented a market share, in its primary market of Colorado, of approximately 40% (2006 – 40%).  Within this market, R&M’s Phillips 66 ® - branded sites represent a 13% market share (2006 – 15%).

Transportation and Distribution

R&M operations use a variety of transportation modes to deliver products to market, including pipeline, water, rail and road.

For our Canadian operations, R&M 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-

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Canadian Pipe Line, which is 55% owned by Suncor and 45% owned by another refiner. The pipeline operates as a private facility for its owners, serving terminal facilities in Toronto, Hamilton and London.

We also have 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 U.S. allows R&M’s Canadian operations to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets.

For our U.S. operations, approximately sixty percent 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 crude pipeline, the Centennial pipeline, from Guernsey, Wyoming to Cheyenne, Wyoming.  Until September 27, 2007, we owned approximately 65% of the Centennial pipeline.  Effective September 27, 2007, we purchased the remaining 35% interest from another area refiner, and are now the 100% owner of the Centennial pipeline.

The Rocky Mountain crude system had a capacity of 38,000 bpd in 2007 for the Guernsey to Cheyenne leg of the pipeline and 73,500 bpd for the Cheyenne to Denver leg of the pipeline.  In 2007, the Rocky Mountain Crude system utilized approximately 85% (2006 – 81%) of its capacity with average throughput of 27,600 bpd (2006 – 28,200 bpd) in the Guernsey to Cheyenne leg of the pipeline, and 67,700 bpd (2006 - 62,400 bpd) in the higher capacity Cheyenne to Denver leg.   During the same period, the Centennial pipeline utilized approximately 80% (2006 – 85%) of capacity, with an average throughput of approximately 50,800 bpd (2006 – 54,400 bpd).

R&M’s U.S. operations have both truck and rail loading racks at the Denver area refining facility 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.

In both our Canadian and U.S. operations, 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 R&M business are described under “Competition” in the “Risk  Factors” section of this Annual Information Form.

Environmental Compliance

Due to increasingly stringent regulations regarding water discharges, we are required to improve water treatment capability at our Commerce City refining operation, which will require additional water treating equipment for the discharge of process waste water. It is estimated this will cost approximately $44 million to $49 million (US$45 to $50 million) and is expected to be completed in the 2008 to 2010 timeframe.   During 2007 we spent approximately $12 million (US $11 million) on the ammonia phase waste water project.

The Ontario provincial, Colorado state and Canadian federal governments are in various stages of developing greenhouse gas management legislation and regulation. At this time, no such legislation has been tabled in any of these jurisdictions and any potential impacts are unknown.

For a discussion of environmental risks at our R&M operations, refer to the “Legal and Regulatory Risks” outlined in the “Risk Factors” section of this Annual Information Form, as well as the “Asset Retirement Obligations” section under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

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MATERIAL CONTRACTS

During the year ended December 31, 2007, 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

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).  However, we have received an exemption from Canadian securities regulatory authorities 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 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 78.5% for proven reserves, and 80% for proved plus probable reserves.  The lower yield rate applied to proven reserves reflects historical operational levels.  The 80% proved plus probable reserves yield rate reflects anticipated yield levels once operational performance issues have been addressed.

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 reflects the value of Alberta Crown, overriding, and freehold royalty burdens under constant December 31 pricing and our exercise of the option electing 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.  As there is currently no legislated methodology for determining bitumen value for Alberta Crown royalty purposes, bitumen value for determining royalties has been assumed to correspond to Firebag bitumen sales to our upgrader.  However, determination of bitumen value for royalty purposes is currently under review by the Government of Alberta.  In October 2007, the Government of Alberta proposed changes to the royalty regime.  In January 2008, Suncor entered into a Royalty Amending Agreement to transition to the new royalty framework assuming the government enacts their proposed changes.  Neither the governments  proposed changes, nor our Royalty Amending Agreement have been reflected in the following reserve estimates.  For a full discussion of our Crown royalties, see “Oil Sands Crown Royalties” and “Natural Gas Crown Royalties” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

In addition to reporting our reserves in accordance with U.S. disclosure requirements, the exemption issued by Canadian securities regulatory authorities permits us to provide voluntary additional disclosure.  We provide this voluntary additional disclosure to show aggregate proved and probable oil sands reserves, including both mining and Firebag reserves.  In our voluntary disclosure we report our aggregate reserves on the following basis:

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·                Gross and net proved and probable mining reserves are consistent with required US mining disclosures, however the voluntary disclosure reflects 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 CSA Staff Notice 51-315 (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves and 80% for proved plus probable reserves);  and

·                Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on Annual Average Differential Pricing.  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% for proved and proved plus probable reserves.

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;

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

(d)                               are evaluated based on 2007 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.

Comparisons of reserve estimates under “Required U.S. Oil and Gas Mining Disclosure” and “Voluntary Oil Sands Reserve Disclosure” may 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.  These differences were significant for 2005 and 2007 reporting given the considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing. Refer to “Voluntary Oil Sands Reserves and Resources Disclosure - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations”.

In addition to our required and voluntary reserves disclosures, we have also elected to disclose our best estimate remaining recoverable resources for both mining and in-situ at December 31, 2007.   These disclosures follow the requirements in NI 51-101.

All of our reserves and resources have been evaluated as at December 31, 2007 by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (“GLJ”).  In reports dated February 19, 2008 for Oil Sands Mining and February 11, 2008 for Oil Sands In-Situ (collectively referred to herein as “GLJ Oil Sands Reports”), GLJ evaluated our resources and our proved and probable reserves on our oil sands mining and Firebag in-situ leases pursuant to U.S. disclosure requirements using Constant Cost and Pricing assumptions.

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

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drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, project implementation commitments, 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 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 11, 2008 (“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, 2007.

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, capital expenditures, and the current Government of Alberta royalty regime.  These assumptions reflect market and regulatory conditions, as required, at December 31, 2007, which could differ significantly from other points in time throughout the year, or future periods.  Changes in market and regulatory 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 78.5% for proved reserves, and 80% for proved plus probable reserves.  The lower yield rate applied to proved reserves reflects historical operational levels that have fallen below management expectations. The 80% proved plus probable reserves yield rate reflects a return to management’s target levels once operational performance issues have been addressed.

(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 value of Crown, freehold and overriding royalty burdens under constant December 31 pricing and incorporates our exercised option to elect to transfer to a bitumen based Crown royalty effective at the beginning of 2009.  Neither the current proposed Alberta royalty regime changes, nor our Royalty Amending Agreement have been incorporated.  If enacted, at current oil prices we expect our future royalty payments to increase and our net reserves to decrease.  Refer to the “Alberta Crown Royalties” risk, as outlined in the “Risk Factors” section of this AIF.

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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 terms of the leases.  Upon application for continuation prior to the indicated expiry dates, leases can be retained beyond the indicated expiry dates if they meet the minimum level of evaluation and if:

a)     the leases are in production and sustain agreed minimum levels of production; or

b)    escalating rents are paid.  Escalating rents start at $7/hectare/year and double every three years to a maximum of $224/hectare/year.

3)     Annual rentals are required to maintain these permits until the indicated expiry dates for the terms of the permits.  Upon application prior to the indicated expiry dates, a permit can be converted to a 15 year term lease if the minimum level of evaluation criteria has been met.  Upon conversion of a permit to a lease, continuation of the resulting lease is as set out in (2) above.

4)     There is no undeveloped acreage subject to expiration in each of the next three years.

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Oil Sands Mining Operating Statistics

The following table sets out certain operating statistics for our Oil Sands mining operations.  Measurements are averages based on measurement statistics throughout the year and accordingly, should be read as approximations.  Statistics for the Oil Sands Firebag in-situ operations are addressed under the heading “Proved Conventional Oil and Gas Reserves” and “Sales, Production, Well Data, Land Holdings and Drilling Activity - 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.  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.

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Proved Conventional Oil and Gas Reserves

The following table 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 reserves are excluded, while in-situ Firebag reserves are included.

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 50.

(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. Since 2005 we have rebooked our proved reserves, and these continued to be economically viable through 2007.

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

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(5)           Natural gas infill drilling included in total revisions for 2007 was 16 billion cubic feet (bcf), (2006 – 11 bcf; 2005 – 23 bcf).

(6)           Improved recovery recognizes a portion of our Firebag Stage 3 expansion project.

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, 2007. We do not have long-term supply agreements or contracts with governments in which we act as producer nor do we have any interest in oil and gas operations accounted for by the equity method.

Capitalized Costs Relating to Oil and Gas Activities ⁽¹⁾

Note:

(1)                                  Capitalized costs do not include costs related to the associated upgrading expansion projects.

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

Note:

(1)                                  Costs incurred do not include costs related to associated upgrading expansion projects.

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Results of Operations for Oil and Gas Production

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

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

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

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

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

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

·                  Estimated income taxes and royalties may differ in terms of amounts and timing due to the above factors as well as changes in enacted rates, bitumen valuation methodology, and the impact of future expenditures on unproved properties;

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

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

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

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

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

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Sales Prices^{(1), (2)}

Notes:

(1)                                  Production is based in Western Canada.

(2)                                  Prices are calculated using our undivided percentage interest production before royalties.

Production Costs

Note:

(1)                                  Production (lifting) costs include all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems, and Firebag central facilities.  It does not include an estimate for future asset retirement costs. These costs represent a blended average of our Firebag and Natural Gas lifting costs.

Producing Oil and Gas Wells