SUNCOR ENERGY INC.

ANNUAL INFORMATION FORM

March 2, 2009

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

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GLOSSARY OF TERMS

In this Annual Information Form (AIF), references to “we”, “our”, “us”, “Suncor” or “the company” mean 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 thousand cubic feet:1 barrel ratio. BOEs may be misleading, particularly if used in isolation. The 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 mixture, consisting mainly of pentanes and heavier hydrocarbons, 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.

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.

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.

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Dry Hole

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

Feedstock

In the oil sands business, feedstock generally refers to raw bitumen required in the production of synthetic crude oil. In the downstream business segment, feedstock refers to 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 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

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 February 25, 2009, accompanying its audited consolidated financial statements, notes and auditors’ report, as at and for the three years in the period ended December 31, 2008.

Natural Gas

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

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Natural Gas Liquids

Those hydrocarbon components that can be recovered from natural gas as liquids including, but not limited to, ethane, propane, butanes, pentanes plus, condensate and small quantities of non-hydrocarbons.

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.

Reservoir

A porous and permeable subsurface rock formation that contains a separate accumulation of petroleum that is confined by impermeable rock or water barriers and is characterized by a single pressure system.

Synthetic Crude Oil (SCO)

A mixture of hydrocarbons derived by upgrading crude bitumen from oil sands; may contain sulphur or other non-hydrocarbon compounds and has many similarities to crude oil. Sour synthetic crude oil is produced from oil sands that requires only partial upgrading and contains a higher sulphur content than sweet synthetic crude oil. Sweet synthetic crude oil is produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking and purification of bitumen.

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 well drilled inside the established limits of an oil or gas reservoir, or in close proximity to the edge of the reservoir, to the depth of a stratigraphic horizon known to be productive.

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.

Certain other terms used in this AIF but not defined herein are defined in National Instrument 51-101 – Standards of Disclosure for Oil and Gas Activities (“NI 51-101”) and, unless the context otherwise requires, shall have the same meanings herein as in NI 51-101.

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CONVERSION TABLE

Notes:

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

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

CURRENCY

All references in this AIF to dollar amounts are in Canadian dollars unless otherwise indicated.

FORWARD-LOOKING STATEMENTS

This AIF 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: market instability affecting Suncor’s ability to borrow in the debt capital markets at acceptable rates; availability of third party bitumen; success of our hedging strategies; maintaining a desirable debt to cash flow ratio; 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 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

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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 review of the unintended consequences of the proposed New 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 in “Risk Factors”, and throughout this AIF and in our MD&A.  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 – 4th 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.

References to our 2008 Consolidated Financial Statements mean Suncor’s audited consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), the notes and the auditors’ report, as at and for the three years in the period ended December 31, 2008.

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this AIF that are not prescribed by GAAP, namely, cash flow from operations, cash and total operating costs per barrel and return on capital employed (“ROCE”).  These non-GAAP financial measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. We include cash flow from operations (dollars and per share amounts), cash and total operating costs per barrel data and ROCE because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with Canadian GAAP.

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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, May 2002, and May 2008, 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 petroleum products at our refinery in Sarnia, Ontario. Refined products and petrochemicals are marketed 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, natural gas liquids, sulphur, and crude volumes produced by, and purchased from, our natural gas business unit. Suncor Energy Marketing Inc. 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 ® -

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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, located near Fort McMurray, Alberta, produces bitumen recovered from oil sands through mining and in-situ technology 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, natural gas liquids, oil and by-products from reserves primarily in western Alberta and northeastern British Columbia. The sale of natural gas production offsets natural gas purchased for internal consumption at our oil sands operations.

Our refining and marketing business, refines crude oil at Suncor’s refineries in Sarnia, Ontario, and Commerce City, Colorado, into a broad range of petroleum and petrochemical products and produces ethanol at our plant in St. Clair, Ontario for blending into fuels. These products are then marketed to industrial, commercial and retail customers principally in Ontario 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.  The refining and marketing business also encompasses third-party energy marketing and trading activities, and provides marketing services for the sale of crude oil, natural gas, refined products and by-products from the oils sands and natural gas segments.

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 and Eliminations” segment. This includes the activity of our self-insurance entity, as well as investments in wind energy.

In 2008, we produced approximately 264,700 boe per day, comprised of 228,000 barrels per day (bpd) of crude oil from our oil sands operations, and 220 million cubic feet equivalent per day (mmcfe/d) of natural gas and liquids from our natural gas business. In 2007, the most recent period with published results, we were the largest crude oil and natural gas liquids producer in the country (approximately 9%1 of Canada’s crude oil production in 2007) and were also Canada’s 16th largest natural gas producer.2

1 2008 Canadian Crude Oil Forecast and Market Outlook – Appendix B.1

2 Oilweek – July 2008, Top 100 Oil and Gas Producers

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In 2008, our refining and marketing business sold approximately 198,100 bpd or 31,500 m3 per day of refined products, mainly in Ontario and Colorado, but also in other parts of the United States and in Europe.

Three-Year History

Oil Sands

Over the past three years we have continued to advance our multi-phased growth strategy to increase production capacity. Key milestones and significant events that have affected our oil sands business during this time period include the following:

·                  Firebag Stage 2 – Firebag Stage 2 commenced commercial operations in the first quarter of 2006, furthering our plans to increase bitumen supply.

·                  Royalties – In November 2006, we exercised our option, under our royalty agreement with the Government of Alberta, to transition our base oil sands mining operations and associated upgrading from a royalty assessed on upgraded product values to a bitumen-based royalty starting on January 1, 2009. In January 2008, we entered into the Suncor Royalty Amending Agreement (the “Amending Agreement”) with the government of Alberta, which modifies the rates under the Government of Alberta’s recently enacted New Royalty Framework (the “New Royalty Framework”) which would otherwise apply to our base mining operations. Under the Amending Agreement, prior to January 1, 2010, we would pay a royalty in respect of our base operations at 25% of the difference between a project’s annual gross revenues net of related allowable transportation costs (R), less allowable costs (C) including allowable capital expenditures (the R-C Royalty), subject to a minimum royalty of 1% of R. In addition, the Amending Agreement provides Suncor with certainty for various matters, including the bitumen valuation methodology, allowed cost, royalty in-kind, and certain taxes. Under the New Royalty Framework enacted in December 2008, royalty rates will move to a sliding scale royalty of 25% - 40% of R-C, subject to minimum royalty of 1% - 9%, depending on oil price. In both cases, the sliding scale royalty would move with an increase in WTI prices from Cdn$55/bbl to the maximum rate at Cdn$120/bbl. From 2010 through 2015 royalty rates on our base mining operations are those in the New Royalty Framework, with a cap of 30% of R-C and a minimum royalty of 1.0% to 1.2% of R.  In 2016 and subsequent years, the royalty rates for all of our oil sand operations (our base mining project and our Firebag in-situ project) will be the rates prescribed under the New Royalty Framework, unless it is amended or superseded prior to that time.

·                  Voyageur South Extension of Mine – In July 2007, Suncor filed a regulatory application for the Voyageur South extension of mine. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility once operational.

·                  Operating Permit – We were issued a new 10-year operating approval in connection with our oil sands business in August 2007.

·                  Firebag Cogeneration – A capital project expanding Firebag Stages 1 and 2 in conjunction with the addition of a cogeneration facility was completed in 2007.

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·                  Coker Unit – A $2.3 billion expansion to one of two oil sands upgraders was completed in 2008. This new set of cokers is intended to increase design capacity by 90,000 bpd to a total of 350,000 bpd. Production in 2009 is targeted at 300,000 bpd (+ 5%/-10%).

·                  Regulatory Requirements

·                  In September 2007, high emissions at our Firebag in-situ operations resulted in orders being issued by both Alberta Environment and the Alberta Energy and Utilities Board that capped production. The production cap was lifted on July 22, 2008 after Suncor demonstrated the ability to meet emissions restrictions.

·                  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.

·                  Progress on Growth Projects – At December 31, 2008, Suncor had spent approximately $7.0 billion on our planned $20.6 billion Voyageur growth strategy (comprised of $11.6 billion targeted for construction of a third upgrader and $9.0 billion for expanding bitumen supply at our Firebag in-situ operation), which involves the expansion of our Firebag in-situ operations and the construction of a third upgrader. Other current work includes construction of a naphtha unit intended to enhance product mix (60% complete at December 31, 2008), the Firebag Sulphur Plant intended to support our emissions abatement plan (55% complete as at December 31, 2008) and the Steepbank Extraction Plant which is expected to improve operational performance (70% complete at December 31, 2008). On January 20, 2009, Suncor’s Board of Directors approved a revised capital budget which deferred the company’s growth projects in light of recent market conditions. Suncor plans to complete the Steepbank Extraction Plant and Firebag Sulphur Plant, while placing all other growth projects in “safe mode” until market conditions improve. For further discussion of our significant capital projects, see page 14 of our MD&A.

The following changes to our oil sands business have occurred, or are expected to occur in 2009:

·                  Petro-Canada Agreement – Incremental bitumen to feed the expanded oil sands upgrader commenced January 1, 2009 under a processing agreement between Suncor and Petro-Canada.  Under the terms of the agreement, we will process an average of 27,000 bpd of Petro-Canada bitumen on a fee-for-service basis. Petro-Canada retains ownership of the bitumen which is processed into sour crude oil product 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.

·                  Steepbank Extraction Plant and Firebag Sulphur Plant – We are targeting completion of the Steepbank Extraction Plant and the Firebag Sulphur Plant during 2009.

The material factors used to develop target completion dates and cost estimates are: current capital spending plans, the current status of procurement, design and engineering phases of the projects, updates from third parties on delivery of services and goods associated with the project, and estimates from major project teams on completion of future phases of the project. 

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We have assumed that commitments from third parties will be honored and that material delays and increased costs related to the risk factors referred above will not be encountered.  For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see “Risk Factors – Major Projects” in this AIF.

Natural Gas

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

·                  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.

·                  Divestment of non-core assets – In May 2008, we disposed of Arctic properties for proceeds of $24 million.

·                  Offshore Permit - In September 2008, Suncor, together with a partner, successfully bid for a large offshore parcel in the Newfoundland and Labrador Offshore Area. This land is adjacent and complementary to an existing holding in the Bjarni area and provides Suncor with a long-term option for future potential natural gas growth. In order to retain the lands, the exploration license requires Suncor to commit to spend net $30 million in exploration work on the lands within six years.

Refining and Marketing

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

·                  Reduced Refinery Air Emissions – In connection with the acquisition of a 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 enables 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 construction of our St. Clair ethanol facility at a 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

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of $22 million includes a repayment obligation, of which $2 million has been repaid to date.

·                  Diesel Desulphurization and Oil Sands Integration – In November 2007, Suncor completed a multiphase three-year $950 million project at the Sarnia refinery with a 120-day shutdown to complete the tie-ins. 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.  During 2008, additional equipment improvements were identified that will be required before the refinery can achieve full benefit from these modifications.  We are currently evaluating our options relating to these capital expenditures.

·                  The observed performance of our Sarnia refinery in 2008, after completion of our diesel desulphurization and oil sands integration project in 2007, has enabled us to upwardly revise our nameplate capacity to 85,000 bpd from the previously disclosed 70,000 bpd. Starting January 1, 2009, refinery utilization will be calculated using the 85,000 bpd capacity. The Commerce City refining capacity has also been increased from 90,000 bpd to 93,000 bpd effective January 1, 2009.

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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NARRATIVE DESCRIPTION OF THE BUSINESS

Oil Sands

Suncor produces a variety of refinery feedstock, diesel fuel and by-products by developing our resource leases in 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 2008, represent a significant portion of our 2008 cash flow from operations3 (86%), net earnings (95%) and capital employed3 excluding major projects in progress (68%). These percentages have been determined excluding the corporate and eliminations segment information.

Operations

Our integrated oil sands business involves four operations located near Fort McMurray, Alberta.

1)              Bitumen is supplied from a combination of open mining operations, in-situ operations and third-party supply.

2)              Primary extraction facilities recover the bitumen from the mined oil sands ore. In in-situ operations, primary extraction occurs in the ground. Both mined and in-situ bitumen also undergoes secondary extraction processes in preparation for upgrading.

3)              Heavy oil upgrading converts bitumen into crude oil products. Since late 2005, we have upgraded bitumen from Firebag, with only a small portion of non-upgraded production being strategically sold directly into the market.

4)              Required utilities (water, steam and electricity) are generated through facilities on site, some owned and operated by Suncor, and others 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 either transported to fixed sizing and extraction plants or fed directly to a mobile sizing and extraction operation at the mine face. In the primary extraction process, bitumen is separated from the oil sands ore using a hot water process.  After the final removal of impurities and minerals during secondary extraction, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.

In-Situ - Our in-situ operation (Firebag) uses an extraction technology called Steam Assisted Gravity Drainage (“SAGD”) to separate 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 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 back to 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.

3Refer to “Non-GAAP Financial Measures” on page 6 of this AIF.

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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 recovered from both in-situ 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.

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 may utilize new mining technology and processes in our future mine development plans.

While there is virtually no finding costs associated with oil sands resources, delineation of the resources, costs associated with production including mine development and drilling wells for SAGD operations, and costs associated with upgrading bitumen into synthetic crude oil, can entail significant capital outlays. The costs associated with production at oil sands 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 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. In May 2008, a planned shutdown of Upgrader 1 was undertaken to provide both preventative maintenance and capital replacement to improve operational efficiency.

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 45% of oil sands consolidated operating revenues in 2008, compared to 60% in 2007. The other significant component of our revenues were light sour synthetic crude oil and bitumen sales of 46% (2007 – 39%). Set forth below is information on daily sales volumes and the corresponding percentage of oil sands operating revenues by product for each of the last two years.

We anticipate that approximately 50% of oil sands sales volumes in 2009 will be light sweet synthetic crude and diesel products.

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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.

We have a transportation service agreement on the Enbridge Athabasca Pipeline for a term that commenced in 1999 and extends to 2028. Total line capacity is 600,000 bpd. Under this agreement, our current pipeline commitment is 182,000 bpd for the transportation of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta to Hardisty, Alberta.

We are a founding member of the Waupisoo pipeline that went into service on June 1, 2008. Under this agreement, our founding member status is for a minimum term of 25 years with options to extend. Total line capacity is 350,000 bpd with potential expansion to 535,000 bpd. Under this agreement our current pipeline commitment is 30,000 bpd for the transportation of synthetic crude oil and diluted bitumen from Cheecham to Edmonton, Alberta.

Suncor has entered into long-term service agreements with affiliates of TransCanada Corporation to transport 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. Linefill on the Keystone pipeline is targeted to occur in 2009, with transportation of crude oil expected to commence in early 2010. Our capacity on this pipeline in 2010 will be 25,000 bpd. In 2008, Suncor contracted additional storage facilities at both Patoka and Cushing, in order to provide further flexibility for trading strategies. Both contracts are for 1.1 million barrels of storage and for fixed five-year terms. On January 1, 2009, Suncor contracted storage facilities for an additional one million barrels at Nederland, Texas, for a fixed five-year term.

In 2008, we entered into new commitments for the transportation of crude oil on the Express New pipeline (30,000 bpd starting in 2008) and the Wamsutter pipeline (10,000 bpd expected to start in 2010). We continue to evaluate additional pipeline agreements to support planned increases in production capacity.

Periodically, we also enter into strategic short-term cargo transport agreements to ship synthetic crude oil internationally. 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 purchase 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.

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Our oil sands mining facilities are readily accessible by public road. Our Firebag in-situ facilities are currently accessible by air and private road. We anticipate termination of current road access in 2010, and continue to evaluate alternative means of access.

Competitive Conditions

For a discussion of the competitive conditions affecting our oil sands operations, refer to “Competition” in the Risk Factors section of this AIF.

Seasonal Impacts

Severe winter climatic conditions at our oil sands operations 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 2008 total production (2007 — 13%)) of sour crude from our oil sands operation. We began shipping the crude to Flint Hills at Hardisty, Alberta on 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 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. 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.

Effective January 1, 2009 the agreements with Petro-Canada for bitumen processing and sour crude oil supply commenced. As a result and effective January 1, 2009 our agreement to supply up to 30,000 bpd of diluent to Petro-Canada for bitumen blending expired. Under the bitumen processing agreement, we will process an average 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 approximately 22,000 bpd. In addition, under the sour crude oil supply agreement, we will supply up to 26,000 bpd of our proprietary sour crude oil production to Petro-Canada. Both the processing and supply agreements are for a minimum 10-year term.

A portion of our oil sands production is used in our Sarnia and Commerce City refining operations. During 2008, the Sarnia refinery processed approximately 18% (2007 - 7%) of our oil sands crude oil production and the Commerce City refinery processed approximately 4% (2007 – 6%).

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There were no customers that represented 10% or more of our consolidated revenues in 2008 or 2007.

Environmental Compliance

For a discussion of environmental risks at our oil sands operations, refer to the “Legal and Regulatory Risks” in the Risk Factors section of this AIF.

Natural Gas

Our natural gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas, natural gas liquids, oil and by-products primarily in western Canada, supplying markets throughout North America. The sale of this production provides a natural price hedge for natural gas purchased for internal consumption at our oil sands operations.

Our exploration program is primarily 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 (northwest Alberta).

Marketing, Pipeline and Other Operations

We operate natural gas processing plants at South Rosevear, Pine Creek, Progress and Simonette with a total design capacity of approximately 265 mmcf/d. Our capacity interest in these gas processing plants is approximately 115 mmcf/d. We also have varying undivided percentage ownership interests in natural gas processing plants operated by other companies and processing agreements in facilities where we do not hold an ownership interest.

Approximately 93% of our natural gas production in 2008 was 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 7% of our natural gas production in 2008 was sold under existing contracts to aggregators (“system sales”). Proceeds received by producers under these system 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. and Pan-Alberta Gas.

To provide exposure to the Pacific Northwest and California markets, we have a long-term gas pipeline transportation contract on the TCPL Gas Transmission Northwest Pipeline. Our contract, which started in 1995, is for 40,000 MMBtu/day and expires in 2023.

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. We currently have no pipeline commitments related to the shipment of conventional crude oil.

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Principal Products

Sales of natural gas represented 81% (2007  – 89%) of the business unit’s consolidated operating revenues in 2008, with 11% (2007  – 10%) comprised of sales of natural gas liquids and crude oil. The remaining 8% (2007  – 1%) related mainly to sales of sulphur by-product. Set forth below is information on daily sales volumes and the corresponding percentage of natural gas’s operating revenues by product for the last two years.

Note:

(1) The remaining 8% relates mainly to our sales of sulphur by-product.

Competitive Conditions

For a discussion of the competitive conditions affecting the natural gas business unit, refer to “Competition” in the Risk Factors section of this AIF.

Seasonal Impacts

Risks and uncertainties associated with weather conditions and wildlife restrictions can shorten the winter drilling season and can 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 natural gas operations, refer to the “Legal and Regulatory Risks” outlined in the Risk Factors section of this AIF.

Refining and Marketing

Our refining and marketing business consists of downstream operations in Canada and the United States and an energy marketing and trading business.

Our Canadian-based refining and marketing business operates in central Canada. Our refinery in Sarnia, Ontario, has a current crude oil capacity of 85,000 bpd, up from previous capacity of 70,000 bpd as the result of improvements made with the completion of our diesel desulphurization and oil sands integration project in 2007. The plant refines petroleum feedstock from oil sands and other sources into gasoline, distillates, and petrochemicals with the majority of these refined products distributed in Ontario. We also distribute product purchased from third parties. Our ethanol plant in St. Clair, Ontario produces ethanol from corn, which is used for blending into our fuels and is also sold to third parties and has a capacity of 200 million litres per year.

As a marketing channel for Canadian refined products, our Ontario retail networks sold approximately 52% of refining and marketing’s total Canadian sales volume in 2008 (2007  –

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51%). The retail networks include the Sunoco-branded retail network, joint venture retail and bulk distribution facilities and cardlock operations. Approximately 42% of our Canadian refined product sales in 2008 were wholesale and industrial sales (2007  – 44%). Sun Petrochemicals Company, a joint venture between a Suncor subsidiary and a Toledo, Ohio-based refinery, generated the remaining refined product 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 93,000 bpd, increased from 90,000 bpd previously reported.  The majority of the refined products from the Commerce City refinery are distributed in Colorado.

In 2008, approximately 78% (2007  – 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. Approximately 15% of our U.S. petroleum products sales in 2008 (2007  – 18%) were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers. Asphalt sales comprised the remaining 7% of U.S. refined product sales volumes for 2008 (2007  – 8%).

The energy marketing and trading business activities encompasses third-party energy marketing and trading activities, as well as providing marketing services for the sale of crude oil, natural gas, refined products and by-products and the use of financial derivatives.

Procurement of Feedstocks

Canada

The Sarnia refinery processes both synthetic and conventional crude oil. In 2008, 75% (2007  – 43%) of the crude oil refined at the Sarnia Refinery was synthetic crude oil, of which 71% was supplied from our oil sands operations (2007  – 50%). 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.

We continue to 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.

Diesel desulphurization and oil sands integration work at our Sarnia refinery was completed in 2007. During 2008, additional equipment improvements were identified that will be required before the refinery can achieve full benefit from these modifications.  We are currently evaluating our options relating to these capital expenditures.

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United States

The Commerce City refining operation processes both conventional and synthetic crude oil. Approximately 10% of the refinery’s crude oil is purchased from Canadian sources (2007  – 23%), 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 15,000 bpd of oil sands sour crude oil at our U.S. refining operation.

Refining Operations

Canada

The Sarnia refinery produces a wide range of products, including transportation fuels, heating fuels, liquefied petroleum gases, residual fuel oil, asphalt feedstock and petrochemicals.

The Sarnia refinery has capacity to refine 85,000 bpd of crude oil. Refining units include a 29,000 bpd hydrocracker and a 5,300 bpd alkylation unit. The petrochemical facilities have a capacity of 18,500 bpd and our gasoline desulphurization unit has the capacity to process 10,000 bpd. The distillate hydrotreater that became operational in July 2006 has a processing capacity of 43,600 bpd.

In 2008, the refinery had cracking capacity of 45,600 bpd from a Houdry catalytic cracker (“catcracker”). 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. A range of replacement options for the catcracker will continue to be analyzed.

The refinery’s external steam and electricity needs are primarily met through the Sarnia Regional Co-generation Project.

In July 2006, with the completion of our St. Clair ethanol facility, we began producing ethanol for use in our blended gasoline products, and for sale to third parties. Production capacity for this facility is 200 million litres per year.

United States

Refining units include two fluidized catalytic crackers with a 27,000 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 our marketing operations in Colorado.

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 utilizes a crude slate containing approximately one-third heavy, high sulphur crude oil.

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The following chart sets out refining and marketing’s combined total daily crude input and average refinery utilization rates for both its Canadian and U.S. refinery operations in 2008 and 2007.

Combined U.S. and Canadian Capacity

(1)             Based on crude unit capacity of 70,000 bpd for Sarnia and 90,000 bpd for Commerce City 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 2008, a significant maintenance shutdown was successfully completed at our Sarnia refinery, and in 2007 significant maintenance shutdowns were successfully completed at both our Sarnia and Commerce City refining facilities.

Principal Products

Set forth below is information on daily sales volumes and the corresponding percentage of refining and marketing’s operating revenues by product category for the last two years.

Note:

(1)                                  Includes ancillary revenues

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Principal Markets

Canada

Approximately 52% (2007 – 51%) of our total Canadian sales volumes are marketed through retail networks. In 2008, this network was comprised of:

·                  276 Sunoco-branded retail service stations (2007  – 272)

·                  159 Pioneer-operated retail service stations (2007  – 151) 4

·                  52 UPI-operated retail service stations (2007  – 55) 5

·                  11 UPI-operated bulk distribution facilities for rural and farm fuels (2007  – 13)5

·                  47 Sunoco branded Fleet Fuel Cardlock sites  (2007  – 48)

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

Approximately 42% (2007  – 44%) of refining and marketing’s Canadian sales volumes are sold to industrial, commercial, wholesale and refining customers, primarily in Ontario. Refining and marketing also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners.

Refining and marketing 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. We sell our benzene production directly to other petrochemical manufacturers in Sarnia, Ontario.

Refining and marketing’s share of total refined product sales in its primary Canadian market of Ontario was approximately 18% in 2008 (2007  – 20%).

Transportation fuels accounted for 83% of our Canadian sales volumes in 2008 (2007  – 78%); and petrochemicals accounted for 6% (2007  – 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.

Refined petroleum products are also supplied to the Pioneer and UPI joint ventures. We have a separate supply agreement with both 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.

4 Pioneer is a 50% joint venture partnership with The Pioneer Group.

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

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United States

Approximately 78% (2007  – 74%) of refining and marketing’s U.S. sales volumes are sold to industrial, commercial, wholesale and refining customers, primarily in Colorado, of which approximately 10% was sold to ConocoPhillips (2007  – 10%) and 18% was sold to Valero (2007  – 23%).

Approximately 15% (2007  – 18%) of our total U.S. sales volumes are marketed through Phillips 66 ® - branded retail outlets.  In 2008, this network was comprised of:

·                  44 owned Phillips 66 ® - branded retail sites, which account for approximately 5% of refining and marketing’s U.S. sales volumes (2007  – 44 sites; 5% of sales volumes)

·                  Supply agreements with 200 additional Phillips 66 ® branded retail sites throughout Colorado, which account for approximately 10% of our U.S. sales volumes (2007  – 173 outlets; 13% of 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 U.S. refining operation supplied all of its asphalt production to SemMaterials, L.P. until SemMaterials’ bankruptcy protection filing in the summer of 2008. Subsequently, we now directly manage the sales of asphalt, which made up 7% of refining and marketing’s U.S. 2008 sales volumes (2007  – 8%).

We estimate our U.S. sales of total light fuels refined product in 2008 represented a 36% market share, in its primary market of Colorado (2007  – 40%). Within this market, our Phillips 66 ® - branded sites hold a 7% market share (2007  – 7%).

Transportation and Distribution

Canada

For our Canadian operations, refining and marketing owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia refinery to core markets in Ontario is the Sun-Canadian Pipe Line, which is 55% owned by Suncor and 45% owned by another refiner. The pipeline operates as a private facility for its owners, 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 refining and marketing’s Canadian operations to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets.

United States

For our U.S. operations, approximately 60% of crude oil processed at the Denver refining operation is transported via pipeline, with the remainder supplied via truck. We own and operate the Rocky Mountain Crude pipeline system, which runs from Guernsey, Wyoming to Denver,

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Colorado. This is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers.  We also own and operate the Centennial pipeline, which transports crude from Guernsey, Wyoming to Cheyenne, Wyoming.

The Rocky Mountain Crude system had a capacity of 38,000 bpd in 2008 for the Guernsey to Cheyenne leg of the pipeline and 73,500 bpd for the Cheyenne to Denver leg of the pipeline. In 2008, it utilized approximately 43% (2007  – 73%) of its capacity with average throughput of 16,500 bpd (2007  – 27,600 bpd) in the Guernsey to Cheyenne leg of the pipeline, and utilized approximately 85% (2007 - 92%) with average throughput of 62,200 bpd (2007  – 67,700 bpd) in the higher capacity Cheyenne to Denver leg. During the same period, the Centennial pipeline utilized approximately 46% (2007  – 80%) of capacity, with an average throughput of approximately 29,400 bpd (2007  – 50,800 bpd).

Our U.S. operations have both truck and rail loading racks at the Commerce City 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

For a discussion of the competitive conditions affecting our refining and marketing business, refer to “Competition” in the Risk Factors section of this AIF.

Environmental Compliance

For a discussion of environmental risks at our refining and marketing operations, refer to the “Legal and Regulatory Risks” in the Risk Factors section of this AIF.

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STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION

Date of Statement

The statement of reserves data and other oil and gas information outlined below is dated February 6, 2009, with an effective date of December 31, 2008. The preparation date of the information is February 2, 2009.

Disclosure of Reserves Data

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”). Prior to 2008, we had presented our disclosures in accordance with U.S. disclosure requirements under an exemption from Canadian securities requirements which was not renewed by us following our December 31, 2007 annual disclosures. As a result, reserves information presented for comparative years has been restated to comply with NI 51-101, consistent with the presentation format for December 31, 2008 reserve disclosures.

The reserves and contingent resources data set forth below is based upon an evaluation by GLJ with an effective date of December 31, 2008 contained in the GLJ Report dated February 6, 2009.  The reserves data summarizes our oil, liquids and natural gas reserves and the net present values of future net revenue for these reserves using forecast prices and costs prior to provision for interest, general and administrative expenses, cost associated with environmental regulations, the impact of any hedging activities or the liability associated with certain abandonment and all well, pipeline, facilities and mine reclamation costs.  Future net revenues have been presented on a before and after tax basis.  The reserves data conforms with the requirements of NI 51-101.  We engaged GLJ to provide an evaluation of proved and proved plus probable reserves and contingent resources.  See also “Definitions and Notes to Reserves Data Tables” below.

The company’s reserves are located primarily in Alberta and British Columbia, Canada.

It should not be assumed that the estimates of future net revenues presented in the tables below represent the fair market value of the reserves.  There is no assurance that the forecast prices and costs assumptions will be attained and variances could be material.  The recovery and reserves estimates of crude oil, natural gas liquids and natural gas reserves provided herein are estimates only and there is no guarantee that the estimated reserves will be recovered.  Actual crude oil, natural gas and natural gas liquid reserves may be greater than or less than the estimates provided herein.  Readers should review the definitions and information contained in “Definitions and Notes to Reserves Data Tables” in conjunction with the following tables and notes.  For more

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information as to the risks involved, see “Risk Factors — Uncertainty of Reserve and Resource Estimates” in this AIF.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves as at December 31, 2008

(1)             Represents light and medium oil for our conventional reserves, and synthetic crude oil (“SCO”) for our mining and in-situ reserves.

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Net Present Value of Future Net Revenues as at December 31, 2008

Total Future Net Revenues as at December 31, 2008 – Undiscounted

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Future Net Revenue by Production Group as at December 31, 2008(1)