40-F

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SECURITIES AND EXCHANGE COMMISSION
Washington, D.C. 20549

Form 40-F

(Check One)
o	REGISTRATION STATEMENT PURSUANT TO SECTION 12 OF THE SECURITIES EXCHANGE ACT OF 1934
OR
ý	ANNUAL REPORT PURSUANT TO SECTION 13(a) OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For fiscal year ended: December 31, 2008        Commission File Number: No. 1-12384

SUNCOR ENERGY INC.
(Exact name of registrant as specified in its charter)

Canada
(Province or other
jurisdiction of incorporation
or organization) 1311,1321,2911,
4613,5171,5172
(Primary standard industrial
classification code number,
if applicable)
98-0343201
(I.R.S. employer
identification number,
if applicable)

112 - 4^th Avenue S.W.
Box 38
Calgary, Alberta, Canada T2P 2V5
(403) 269-8100
(Address and telephone number of registrant's principal executive office)

CT Corporation System
111 Eighth Avenue
New York, New York, U.S.A. 10011
(212) 894-8940
(Name, address and telephone number of agent for service in the United States)

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

Title of each class:	Name of each exchange on which registered:
Common shares	New York Stock Exchange

Securities registered or to be registered pursuant to Section 12(g) of the Act: None
Securities for which there is a reporting obligation pursuant to Section 15(d) of the Act: None

For annual reports, indicate by check mark the information filed with this form:
ý    Annual Information Form	ý    Annual Audited Financial Statements

Indicate the number of outstanding shares of each of the issuer's classes of capital or common stock as of the close of the period covered by the annual report:

Common Shares	As of December 31, 2008 there were 935,524,213 Common Shares issued and outstanding
Preferred Shares, Series A	None

Indicate by check mark whether the registrant by filing the information contained in this form is also thereby furnishing the information to the Commission pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934 (the "Exchange Act"). If "Yes" is marked, indicate the file number assigned to the registrant in connection with such rule.    Yes o            No ý

Indicate by check mark whether the registrant: (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the proceeding 12 months (or for such shorter period that the registrant was required to file such reports); and (2) has been subject to such filing requirements in the past 90 days.    Yes ý            No o

SUNCOR ENERGY INC.

ANNUAL INFORMATION FORM

March 2, 2009

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

TABLE OF CONTENTS	i
GLOSSARY OF TERMS	1
CONVERSION TABLE	5
CURRENCY	5
FORWARD-LOOKING STATEMENTS	5
NON-GAAP FINANCIAL MEASURES	6
CORPORATE STRUCTURE	7
Name and Incorporation	7
Intercorporate Relationships	7
GENERAL DEVELOPMENT OF THE BUSINESS	9
Overview	9
Three-Year History	10
NARRATIVE DESCRIPTION OF THE BUSINESS	14
Oil Sands	14
Natural Gas	18
Refining and Marketing	19
STATEMENT OF RESERVES DATA AND OTHER OIL AND GAS INFORMATION	26
Date of Statement	26
Disclosure of Reserves Data	26
Reserves Data (Forecast Prices and Costs)	27
Reconciliation Of Changes In Reserves	34
Additional Information Relating to Reserves Data	35
Other Oil and Gas Information	36
INDUSTRY CONDITIONS	41
RISK FACTORS	48
DIVIDENDS	60
DESCRIPTION OF CAPITAL STRUCTURE	60
General Description of Capital Structure	60
Ratings	60
MARKET FOR OUR SECURITIES	62
Price Range and Trading Volume of Common Shares	62
Prior Sales	62
DIRECTORS AND EXECUTIVE OFFICERS	63
Directors	63
Corporate Officers	65
Cease Trade Orders, Bankruptcies, Penalties or Sanctions	66
Conflicts of Interest	67
SUNCOR EMPLOYEES	67
AUDIT COMMITTEE INFORMATION	68
Audit Committee Charter	68
Composition of the Audit Committee	68
Financial Literacy	68
Audit Committee Financial Expert	69
Audit Committee Pre-Approval Policies for Non Audit Services	70
Fees Paid to Auditors	70
LEGAL PROCEEDINGS AND REGULATORY ACTIONS	71
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	71
TRANSFER AGENT AND REGISTRAR	71
MATERIAL CONTRACTS	72
INTERESTS OF EXPERTS	72

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DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE		72
ADDITIONAL INFORMATION		72
SCHEDULE “A” -	SUNCOR ENERGY INC. POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT AND NON-AUDIT SERVICES	A-1
SCHEDULE “B” -	AUDIT COMMITTEE CHARTER	B-1
SCHEDULE “C” -	FORM 51-101F3 REPORT OF MANAGEMENT AND DIRECTORS ON OIL AND GAS DISCLOSURE	C-1
SCHEDULE “D” -	FORM 51-101F2 REPORT ON RESERVES DATA BY INDEPENDENT QUALIFIED RESERVES EVALUATOR	D-1

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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

1 cubic metre m3 = 6.29 barrels	1 tonne = 0.984 tons (long)
1 cubic metre m3 (natural gas) = 35.49 cubic feet	1 tonne = 1.102 tons (short)
1 cubic metre m3 (overburden) = 1.31 cubic yards	1 kilometre = 0.62 miles
	1 hectare = 2.5 acres

Notes:

(1)Conversion using the above factors on rounded numbers appearing in this 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

12008 Canadian Crude Oil Forecast and Market Outlook – Appendix B.1

2Oilweek – 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.

Product:	2008		2007
	(thousands of barrels per day)	(% of operating revenues)	(thousands of barrels per day)	(% of operating revenues)
Light sweet crude oil / diesel	96.8	45	126.7	60
Light sour crude oil / bitumen	130.2	46	108.0	39
Total	227.0		234.7

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.

Product:	2008		2007
	(mmcf equivalent per day)	(% of operating revenues)(1)	(mmcf equivalent per day)	(% of operating revenues)
Natural gas	202	81	196	89
Crude oil and natural gas liquids	18	11	19	10
Total	220		215

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

Total Canadian and U.S. Refinery Capacity	2008	2007
Average daily crude input (barrels per day)	155,600	157,600
Average crude utilization rate (%)(1)	97	98

(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.

Product:	2008		2007
	(thousands of cubic meters per day)	(% of operating revenues)	(thousands of cubic meters per day)	(% of operating revenues)
Transportation Fuels
Gasoline
Retail	4.6	7	5.2	13
Joint Ventures	3.0	3	3.1	5
Other	8.3	13	8.5	24
Jet Fuel	2.0	3	2.3	4
Diesel	8.8	14	8.3	18
Sub-total – Transportation	26.7	40	27.4	64
Fuels
Petrochemicals	0.8	1	0.9	2
Asphalt	1.8	1	1.7	2
Other	2.2	2	3.5	5
Total Refined Products	31.5	44	33.5	73
Other Non-Refined Products(1)		1		2
Energy Marketing & Trading		55		25
Total %		100		100

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

	Oil(1)		Natural Gas		Natural Gas Liquids
	Working Interest MMbbl	Net MMbbl	Working Interests Bcf	Net Bcf	Working Interest MMbbl	Net MMbbl
Proved Producing
Conventional	2	2	459	352	5	4
SCO – Mining	1,571	1,335	-	-	-	-
SCO – In-Situ	94	91	-	-	-	-
Total Proved Producing	1,667	1,428	459	352	5	4
Proved Developed Non-Producing
Conventional	-	-	50	38	-	-
SCO – In-Situ	45	43	-	-	-	-
Total Proved Developed Non-Producing	45	43	50	38	-	-
Proved Undeveloped
Conventional	-	-	30	24	-	-
SCO –In-Situ	766	658	-	-	-	-
Total Proved Undeveloped	766	658	30	24	-	-
Total Proved
Conventional	2	2	539	414	5	4
SCO – Mining	1,571	1,335	-	-	-	-
SCO – In-Situ	905	792	-	-	-	-
Total Proved	2,478	2,129	539	414	5	4
Total Probable
Conventional	1	-	216	153	2	1
SCO – Mining	745	626	-	-	-	-
SCO – In-Situ	1,808	1,506	-	-	-	-
Total Probable	2,554	2,132	216	153	2	1
Total Proved Plus Probable
Conventional	3	2	755	567	7	5
SCO – Mining	2,316	1,961	-	-	-	-
SCO – In-Situ	2,713	2,298	-	-	-	-
Total Proved Plus Probable	5,032	4,261	755	567	7	5

(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

	Net Present Values of Future Net Revenue BEFORE Income Taxes – Discounted at %/year ($ millions)					Unit Value Before Income Tax Discounted at 10%/tear ($ millions)
	0%	5%	10%	15%	20%	$/Boe	$/Mcfe
PROVED
Producing	71,961	47,160	33,186	24,744	19,325	22.28	3.71
Developed Non-Producing	2,356	1,775	1,380	1,103	902	28.05	4.68
Undeveloped	26,833	11,304	4,967	2,085	651	7.50	1.25
Total Proved	101,150	60,239	39,533	27,932	20,878	17.96	2.99
Total Probable	126,456	39,370	14,052	5,140	1,486	6.51	1.08
TOTAL PROVED PLUS PROBABLE	227,606	99,609	53,585	33,072	22,364	12.29	2.05
	Net Present Values of Future Net Revenue AFTER Income Taxes – Discounted at %/year
	0%	5%	10%	15%	20%
PROVED
Producing	55,850	37,013	26,360	19,895	15,724
Developed Non-Producing	2,005	1,533	1,209	979	809
Undeveloped	20,009	8,238	3,443	1,264	178
Total Proved	77,864	46,784	31,012	22,138	16,711
Total Probable	94,627	29,052	10,008	3,294	538
TOTAL PROVED PLUS PROBABLE	172,491	75,836	41,020	25,432	17,249

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

($ millions)	Revenue	Royalties	Operating Costs	Capital Development Costs	Abandonment Costs	Future Net Revenue Before Income Taxes	Income Tax	Future Net Revenue After Income Taxes
PROVED
Producing	167,832	25,474	54,614	15,744	39	71,961	16,111	55,850
Developed Non-producing	4,614	319	1,675	258	6	2,356	351	2,005
Undeveloped	87,029	12,803	33,304	13,743	346	26,833	6,824	20,009
Total Proved	259,475	38,596	89,593	29,745	391	101,150	23,286	77,864
Total Probable	344,459	58,628	119,854	38,872	649	126,456	31,829	94,627
TOTAL PROVED PLUS PROBABLE	603,934	97,224	209,447	68,617	1,040	227,606	55,115	172,491

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

	Future Net Revenue BEFORE Income Taxes - Discounted at 10%/year
	$(millions)	$/Boe	$/Mcfe
Proved Producing
Light and Medium Oil	75	32.47	5.41
Natural Gas	1,365	22.19	3.70
Non-conventional activities (Oil Sands)
SCO-Mining	2,699	29.74	4.96
SCO-In-Situ	29,047	21.76	3.63
Total Proved Producing	33,186	22.28	3.71
Total Proved
Light and Medium Oil	76	32.33	5.39
Natural Gas	1,489	20.64	3.44
Non-conventional activities (Oil Sands)
SCO-Mining	8,920	11.27	1.88
SCO-In-Situ	29,048	21.76	3.63
Total Proved	39,533	17.96	2.99
Total Proved Plus Probable
Light and Medium Oil	85	29.58	4.93
Natural Gas	1,838	18.61	3.10
Non-conventional activities (Oil Sands)
SCO-Mining	15,522	6.76	1.13
SCO-In-Situ	36,140	18.43	3.07
Total Proved Plus Probable	53,585	12.29	2.05

(1)    The estimated future net revenue presented in the tables above do not reflect the fair market value of the reserves. The forecast prices and cost assumptions applied are estimates only, and actual reserve realizations may differ materially.

Definitions and Notes to Reserves Data Tables:

In the tables set forth above in “Disclosure of Reserves Data” and elsewhere in this AIF the following definitions and other notes are applicable:

1.“Gross” means:

(a)in relation to our interest in production and reserves, our interest (operating and non-operating) before deduction of royalties and without including any royalty interest of us;

(b)in relation to wells, the total number of wells in which we have an interest; and

(c)in relation to properties, the total area of properties in which we have an interest.

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2.“Net” means:

(a)in relation to our interest in production and reserves, our interest (operating and non-operating) after deduction of royalties obligations, plus our royalty interest in production or reserves;

(b)in relation to wells, the number of wells obtained by aggregating our working interest in each of our gross wells; and

(c)in relation to our interest in a property, the total area in which we have an interest multiplied by the working interest we owned.

3.Columns may not add due to rounding.

4.The oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook (“COGE Handbook”).  A summary of those definitions are set forth below. The synthetic crude oil reserves include our diesel sales volumes, as well as relatively immaterial volumes of bitumen sales.

Reserves Categories

Reserves are estimated remaining quantities of oil and natural gas and related substances anticipated to be recoverable from known accumulations, from a given date forward, based on analysis of drilling, geological, geophysical and engineering data; the use of established technology; and specified economic conditions.

Reserves are classified according to the degree of certainty associated with the estimates.

(a)Proved reserves are those reserves that can be estimated with a high degree of certainty to be recoverable. It is likely that the actual remaining quantities recovered will exceed the estimated proved reserves.

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

Other criteria that must also be met for the categorization of reserves are provided in the COGE Handbook.

Each of the reserves categories (proved and probable) may be divided into developed and undeveloped categories:

(c)Developed reserves are those 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 (for example, when compared to the cost of drilling a well) to put the reserves on production. The developed category may be subdivided into producing and non-producing.

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

(ii)Developed non-producing reserves are those reserves that either have not been on production, or have previously been on production, but are shut-in, and the date of resumption of production is unknown.

(d)Undeveloped reserves are those reserves expected to be recovered from known accumulations where a significant expenditure (for example, when compared to the cost of drilling a well) is required to render them capable of production. They must fully meet the requirements of the reserves classification (proved, probable) to which they are assigned.

In multi-well pools it may be appropriate to allocate total pool reserves between the developed and undeveloped categories or to subdivide the developed reserves for the pool between developed producing and developed non-producing. This allocation should be based on the estimator’s assessment as to the reserves that will be recovered from specific wells, facilities and completion intervals in the pool and their respective development and production status.

Levels of Certainty for Reported Reserves

The qualitative certainty levels referred to in the definitions above are applicable to individual reserves entities (which refers to the lowest level at which reserves calculations are performed) and to reported reserves (which refers to the highest level sum of individual entity estimates for which reserves are presented). Reported reserves should target the following levels of certainty under a specific set of economic conditions:

(a)at least a 90 per cent probability that the quantities actually recovered will equal or exceed the estimated proved reserves; and

(b)at least a 50 per cent probability that the quantities actually recovered will equal or exceed the sum of the estimated proved plus probable reserves.

A qualitative measure of the certainty levels pertaining to estimates prepared for the various reserves categories is desirable to provide a clearer understanding of the associated risks and uncertainties. However, the majority of reserves estimates will be prepared using deterministic methods that do not provide a mathematically derived quantitative measure of probability. In principle, there should be no difference between estimates prepared using probabilistic or deterministic methods. Additional clarification of certainty levels associated with reserves estimates and the effect of aggregation is provided in the COGE Handbook.

5.Forecast prices and costs

These are prices and costs that are generally acceptable as being a reasonable outlook of the future as of December 31,2008.  To the extent that there are fixed or presently determinable future prices or costs to which we are legally bound by a contractual or other obligation to supply a

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physical product, including those for an extension period of a contract that is likely to be extended, those prices or costs shall be incorporated into the forecast prices.

The forecast cost and price assumptions include increases in wellhead selling prices and take into account inflation with respect to future operating and capital costs.  Crude oil and natural gas benchmark reference pricing, as at December 31, 2008, inflation and exchange rates utilized in the GLJ Report were as follows:

Year	Inflation %	Bank of Canada Average Noon Exchange Rate $US/$Cdn	NYMEX WTI Crude oil at Cushing Oklahoma $US/bbl	Light, Sweet Crude Oil at Edmonton (40 API, 0.3%S) $Cdn/bbl	NYMEX Natural Gas at Henry Hub $US/mmbtu	Natural Gas at AECO $Cdn/mmbtu
2009	2.0	0.825	57.50	68.61	7.00	7.58
2010	2.0	0.850	68.00	78.94	7.50	7.94
2011	2.0	0.875	74.00	83.54	8.00	8.34
2012	2.0	0.925	85.00	90.92	8.75	8.70
2013	2.0	0.950	92.01	95.91	9.20	8.95
2014	2.0	0.950	93.85	97.84	9.38	9.14
2015	2.0	0.950	95.73	99.82	9.57	9.34
2016	2.0	0.950	97.64	101.83	9.76	9.54
2017	2.0	0.950	99.59	103.89	9.96	9.75
2018	2.0	0.950	101.59	105.99	10.16	9.95
2019+	2.0	0.950	+2%/yr	+2%/yr	+2%/yr	+2%/yr

The company’s weighted average historical prices realized for the year ended December 31, 2008 were $95.96/bbl for synthetic crude oil, $8.23/mcf for natural gas, and $70.89/bbl for natural gas liquids.

6.Future Development Costs

The following table sets forth development costs deducted in the estimation of our future net revenue attributable to the reserves categories noted below as at December 31, 2008.

($ millions)
	2009	2010	2011	2012	2013	Subtotal	Remainder	Total	10%Discounted
Total Proved	2,138	3,107	1,206	1,247	1,351	9,049	20,695	29,744	13,980
Total Proved Plus Probable	2,866	5,091	3,848	3,358	2,552	17,715	50,902	68,617	24,638

Management currently believes internally generated cash flows, existing credit facilities and access to capital debt markets are sufficient to fund growth plans. There can be no guarantee that funds will be available or that we will

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allocate funding to develop all of the reserves attributed in the GLJ Report.  Failure to develop those reserves would have a negative impact on future cash flow from operating activities.

The interest or other costs of external funding are not included in the reserves and future net revenue estimates and would reduce reserves and future net revenue to some degree depending upon the funding sources utilized.  We do not anticipate that interest or other funding costs would make development of any property uneconomic.

Costs associated with the Voyageur upgrader designed to process approximately 245,000 bbl/d of in-situ bitumen, were included only to the extent that the development plan for the Firebag reserves required additional upgrading, as the remaining costs are believed to be related to development of contingent resources. The proved undeveloped and proved plus probable undeveloped Firebag reserves utilize only 40,000 and 175,000 bbl/d, respectively, of the additional design capacity; for approximately 17 and 30 years, respectively.

7.Estimated future well abandonment costs related to reserves wells have been taken into account by GLJ in determining the aggregate future net revenue therefrom.

8.The forecast price and cost assumptions assumed the continuance of current laws and regulations.

9.All factual data supplied to GLJ was accepted as represented.  No field inspection was conducted.

10.The estimates of future net revenue presented in the tables above do not represent fair market value.

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Reconciliation of Changes in Reserves

Reconciliation of Gross Reserves as at December 31, 2008

	Oil (1)						Natural Gas						Natural Gas Liquids
					Proved Plus						Proved Plus					Proved Plus
	Proved		Probable		Probable		Proved		Probable		Probable		Proved		Probable	Probable
	(MMbbl)		(MMbbl)		(MMbbl)		(Bcf)		(Bcf)		(Bcf)		(MMbbl)		(MMbbl)	(MMbbl)
December 31, 2007
Conventional	2		-		2		573		232		805		6		2	8
SCO - Mining	1,634		740		2,374
SCO - In-Situ	854		1,837		2,691		-		-		-		-		-	-
	2,490		2,577		5,067		573		232		805		6		2	8
Extensions and Improved Recovery
Conventional	-		-		-		40		-		40		-		-	-
SCO - In-Situ	51		(51	)	-		-		-		-		-		-	-
	51		(51	)	-		40		-		40		-		-	-
Technical Revisions
Conventional	-		1		1		(4	)	(19	)	(23	)	-		-	-
SCO - Mining	9		5		14		-		-		-		-		-	-
SCO - In-Situ	11		22		33		-		-		-		-		-	-
	20		28		48		(4	)	(19	)	(23	)	-		-	-
Discoveries
Conventional	-		-		-		2		2		4		-		-	-
	-		-		-		2		2		4		-		-	-
Economic Factors
Conventional	-		-		-		1		1		2		-		-	-
	-		-		-		1		1		2		-		-	-
Production
Conventional	-		-		-		(73)		-		(73	)	(1	)	-	(1	)
SCO - Mining	(72	)	-		(72	)	-		-		-		-		-	-
SCO - In-Situ	(11	)	-		(11	)	-		-		-		-		-	-
	(83	)	-		(83	)	(73	)	-		(73	)	(1	)	-	(1	)
December 31, 2008
Conventional	2		1		3		539		216		755		5		2	7
SCO - Mining	1,571		745		2,316		-		-		-		-		-	-
SCO - In-Situ	905		1,808		2,713		-		-		-		-		-	-
	2,478		2,554		5,032		539		216		755		5		2	7

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

Note:  The presentation of infill drilling under SEC disclosures historically had been classified as a “Technical Revision”.  Under current NI 51-101 disclosures infill drilling balances are reported as “Extensions and Improved Recovery”.

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Additional Information Relating to Reserves Data

Undeveloped Reserves

The table below outlines the proved and probable undeveloped reserves, by product type, attributed to the company over the three most recent years specifically, and in aggregate for those beyond three years.

	Units	Prior	2006	2007	2008
Proved Undeveloped
Oil (1)	MMbbl	450.2	192.0	61.6	62.5
Conventional		0.1	-	0.1	-
SCO - Mining		-	-	-	-
SCO – In-Situ		450.1	192.0	61.5	62.5
Natural Gas	Bcf	63.8	13.8	43.4	7.5
Natural Gas Liquids	MMbbl	0.6	-	0.1	-
Total: Oil Equivalent	MMboe	461.4	194.3	68.9	63.7
Probable Undeveloped
Oil (1)	MMbbl	2,587.5	-	-	-
Conventional		0.1	-	-	-
SCO - Mining		488.0	-	-	-
SCO - In-Situ		2,099.4	-	-	-
Natural Gas	Bcf	35.3	20.8	70.8	21.4
Natural Gas Liquids	MMbbl	0.2	0.2	0.1	0.1
Total: Oil Equivalent	MMboe	2,593.6	3.6	11.9	3.6

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

Undeveloped reserves are attributed by GLJ in accordance with standards and procedures contained in the COGE Handbook. Proved undeveloped reserves are those reserves that can be estimated with a high degree of certainty and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.  Probable undeveloped reserves are those reserves that are less certain to be recovered than proved reserves and are expected to be recovered from known accumulations where a significant expenditure is required to render them capable of production.

In respect to mining and in-situ reserves, management uses integrated plans to forecast future development of reserves. The detailed plan aligns current production capacity, capital spending commitments and future development for the next 10 years, and is reviewed and updated continuously for internal and external factors affecting planned activity.

In developing our reserves we consider existing facility and gathering system capacity, capital allocation plans and remaining recoverable resources availability. Accordingly, in some cases it will take us longer than two years to develop all of the currently assigned reserves.  We plan to develop the majority of the proved undeveloped reserves over the next five years and the majority of the probable undeveloped reserves over the next seven years.

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Significant Factors or Uncertainties

The evaluation of reserves is a continuous process, one that can be significantly impacted by a variety of internal and external influences. Revisions are often required resulting from changes in pricing, economic conditions, regulatory changes, and historical performance.

While the above factors, and many others, can be considered, certain judgments and assumptions are always required. As new information becomes available these areas are reviewed and revised accordingly.

For a summary of risks and uncertainties affecting Suncor please refer to ”Industry Conditions” and “Risk Factors” in this AIF.

Other Oil and Gas Information

Oil and Gas Properties and Wells

Suncor’s oil sands business recovers bitumen through oil sands mining and in-situ development in northern Alberta.  Conventional activities are focused on the development and production of natural gas, and natural gas liquids from reserves in western Alberta.

Suncor has no proved non-producing reserves from either of its mining or in-situ reserves.  Within conventional reserves, specific properties are capable of producing (primarily gas) but are limited due to pending pipeline connections, or current pipeline capacity and processing restrictions.  The majority of these properties have been in their current non-producing state for less than 3 years, and it is anticipated that pipeline constraints will be satisfactorily addressed in the next 2 – 3 years.

A summary of “oil” and “gas” wells for the company’s reserves are outlined below:

	Oil Wells				Natural Gas Wells
	Producing		Non-Producing		Producing		Non-Producing
	Gross	Net	Gross	Net	Gross	Net	Gross	Net
Alberta	74	56	68	64	394	232	33	16
British Columbia	17	7	5	2	145	68	12	6
Total Canada	91	63	73	66	539	300	45	22

Properties with No Attributed Reserves

The company has a total of approximately 3,184,000 acres (net 1,994,000 acres) for current and future development related to its mining, in-situ and conventional properties.  The company has rights to explore, develop, and exploit approximately 137,000 net acres that could potentially expire by December 31, 2009. These net acres are entirely attributed to our conventional properties, no land tenure expiries are scheduled to occur for either mining or in-situ properties for 2009.

Forward Contracts

The company has hedged a portion of its forecasted US dollare denominated sales subject to US dollar West Texas Intermediate (WTI) price risk.  As of February 10, 2009, we have crude oil hedges for approximately 125,000 bpd of production from February 1 through December 31,

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2009.  These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US $60.00 per barrel from January 1 to December 31, 2009.  The combination of the previous options and new fixed-price hedges provides Suncor with an equivalent WTI floor price of about US $53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US $50.00 per barrel and a ceiling price of approximately US $68.00 per barrel.  This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US $60.00, which was effectively exited by selling similar contracts for gross proceeds to Suncor of approximately $250 million before tax.

Additional Information Concerning Abandonment and Reclamation Costs

The company completes an annual review of its forecast abandonment and reclamation costs as they relate to our overall corporate operations. The specific estimates established for forecasted abandonment and reclamation costs are based on available information, consistent with that assumed in our long range planning. These estimates consider the nature of all our forecasted abandonment and reclamation costs, where determinable, for our mining, in-situ and conventional operations. Assets with indeterminate lives have been excluded from the company’s abandonment and reclamation cost estimates.

At December 31, 2008 Suncor estimated its abandonment and reclamation costs for surface leases, wells and facilities to be approximately $4.1 billion (discounted at 10% approximately $1.3 billion). Of this $4.1 billion total, $1 billion (approximately 24%) has been deducted as abandonment costs in estimating the future net revenue from reserves. This $1 billion represents our abandonment obligations for reserve wells (in-situ and conventional activities).

The company anticipates approximately $630 million of its identified asset retirement obligations to be incurred during the next 3 years.

Tax Horizon

We expect to pay taxes in 2009.

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Costs Incurred

The table below summarized the company’s capital expenditures related to its reserve activities for the year ended December 31, 2008.

(Reported in millions)
Property Acquisitions	-
Exploration	133
Land
Proved	-
Unproved	19
Total	19
Development	2,398
Total Capital	22,550

Exploration and Development Activities

The table below outlines the gross and net exploratory and development wells the company participated in during the year ended December 31, 2008. These represent wells from both our in-situ and conventional activities.

	Exploratory Wells		Development Wells
	Gross	Net	Gross	Net
CANADA
Oil	-	-	24	24
NaturalGas	7	5	24	17
Dry	7	4	7	5
Other	-	-	1	-
Total	14	9	56	46

Production Estimates

The table below outlines the volume of the company’s production estimated for the year ended December 31, 2009, as is reflected in the estimate of future net revenues disclosed previously under “Reserves Data”.

	Oil (1)		Natural Gas		Natural Gas Liquids
	Working Interest	Net	Working Interest	Net	Working Interest	Net
	Mbbl/day	Mbbl/day	MMcf/day	MMcf/day	Mbbl/day	Mbbl/day
Total Proved	269	263	199	146	2	2
Total Proved Plus Probable	288	281	209	153	3	2

(1)Represents light and medium oil for our conventional reserves and SCO for our mining and in-situ reserves.

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Production History

The table below outlines the company’s historical production information, by product type, for each of the four financial quarters, and in aggregate as an average daily measure.

	Q1	Q2	Q3	Q4
Synthetic Crude Oil
Average Production (mbbl/d)	248.00	174.60	245.60	243.80
Average Price Received ($/bbl)	96.16	121.12	116.32	61.53
Royalties ($/bbl)	12.50	8.18	11.02	2.41
Production Costs ($/bbl)	31.55	50.85	34.00	41.30
Netback	52.11	62.09	71.30	17.82
Natural Gas
Average Production (mmcf/d)	209.00	205.00	197.00	195.00
Average Price Received ($/mcf)	7.30	9.62	9.10	6.90
Royalties ($/mcf)	1.53	2.23	2.35	1.64
Production Costs ($/mcf)	1.27	1.45	1.60	1.21
Netback	4.50	5.94	5.15	4.05
Natural Gas Liquids
Average Production (mbbl/d)	3.30	3.40	2.60	3.10
Average Price Received ($/bbl)	64.14	86.14	96.88	39.31
Royalties ($/bbl)	24.64	20.73	24.91	5.32
Production Costs ($/bbl)	7.61	8.69	9.63	7.26
Netback	31.89	56.72	62.34	26.73

Average daily production for oilsands (mining and in-situ) was 22.8 Mbbl/day in 2008 and the average daily production volumes by product type for the year ended December 31, 2008 for conventional was:

	Year Ended December 31, 2008
Conventional	Nat Gas (mmcf/d)	Liquids (mmcfe/d)	Total (mmcfe/d)
Foothillls	99	1	100
Northern	65	11	76
Central Alberta	35	6	41
Other	3	0	3
Total	202	18	220

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Remaining Recoverable Resources

Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca region of Alberta.  Based on independent evaluations conducted by GLJ effective December 31, 2008, our estimate of remaining recoverable synthetic crude oil resources is as follows:

Remaining Recoverable Resources As at December 31, 2008 (millions of barrels of SCO)(1)	Mining	In-Situ	Total
Total Proved	1,600	900	2,500
Total Probable	700	1,800	2,500
Total Proved Plus Probable Reserves	2,300	2,700	5,000
Contingent Resources – Best Estimate(2)(3)	3,500	6,500	10,000
Remaining Recoverable Resources (unrisked)(4)	5,800	9,200	15,000

1)	Numbers in the above table are rounded to the nearest 100 million.
2)	Contingent resources are 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. There is no certainty that it will be commercially viable to produce the contingent resources.
3)	Best Estimate is considered to be the best estimate of the quantity 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.
4)	Remaining recoverable resources (unrisked) are the arithmetic sum of proved and probable reserves and best estimate contingent resources. Suncor has not quantified potentially recoverable volumes from either undiscovered accumulations or its carbonate leases. The contingent resources have not been adjusted for risk based on the chance of development. It is not an estimate of volumes that may be recovered. Actual recovery may be less.

Remaining recoverable resources were 15,500 millions of barrels of SCO at December 31, 2007. The decrease in 2008 was primarily due to additional drilling and modeling for the Audet leases.

The contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable timeframe, and in some cases due to higher uncertainty as a result of lower core-hole drilling density. Our Voyageur South development area, for which we submitted a regulatory application in 2007, is part of our mining contingent resources. Significant mining contingent resources are also associated with our Audet leases, located north of our Firebag in-situ leases and immediately adjacent to leases proposes for mining development by other operators. All of our in-situ leases are associated with our Firebag leases. While we consider the contingent resources to be potentially recoverable under reasonable economic operating conditions, there is no certainty that it will be commercially viable to produce any portion of the resources.

The company has not finalized the development basis for these contingent resources. The volumes assume that Suncor continues to treat and upgrade substantially all of its bitumen using current technologies. Future strategic decisions regarding marketability of bitumen versus synthetic crude oil and implementation of new upgrading technologies could impact actual recoveries and product type of the contingent resources.

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INDUSTRY CONDITIONS

The oil and natural gas industry is subject to extensive controls and regulations governing its operations (including land tenure, exploration, development, production, refining, transportation, and marketing) imposed by legislation enacted by various levels of government and with respect to export and taxation of oil and natural gas by agreements among the governments of Canada and Alberta, among others, all of which should be carefully considered by investors in the oil and gas industry. It is not expected that any of these controls or regulations will affect the company’s operations in a manner materially different than they would affect other oil and gas companies of similar size.  All current legislation is a matter of public record and the company is currently unable to predict what additional legislation or amendments may be enacted.  Outlined below are some of the principal aspects of legislation, regulations and agreements governing the oil and gas industry.

Pricing and Marketing - Oil and Natural Gas

The producers of oil are entitled to negotiate sales contracts directly with oil purchasers, with the result that the market determines the price of oil. Oil prices are primarily based on worldwide supply and demand. The specific price depends in part on oil quality, prices of competing fuels, distance to the markets, the value of refined products, the supply/demand balance, and other contractual terms. Oil exporters are also entitled to enter into export contracts with terms not exceeding one year in the case of light crude oil and two years in the case of heavy crude oil, provided that an order approving such export has been obtained from the National Energy Board of Canada (the “NEB”). Any oil export to be made pursuant to a contract of longer duration (to a maximum of 25 years) requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

The price of natural gas is also determined by negotiation between buyers and sellers.  Natural gas exported from Canada is subject to regulation by the NEB and the Government of Canada.  Exporters are free to negotiate prices and other terms with purchasers, provided that the export contracts must continue to meet certain other criteria prescribed by the NEB and the Government of Canada.  Natural gas (other than propane, butane and ethane) exports for a term of less than two years or for a term of two to 20 years (in quantities of not more than 30,000 m3/day), must be made pursuant to an NEB order.  Any natural gas export to be made pursuant to a contract of longer duration (to a maximum of 25 years) or a larger quantity requires an exporter to obtain an export licence from the NEB and the issuance of such licence requires a public hearing and the approval of the Governor in Council.

The government of Alberta also regulates the volume of natural gas that may be removed from the province for consumption elsewhere based on such factors as reserve availability, transportation arrangements, and market considerations.

Pipeline Capacity

Although pipeline expansions are ongoing, the pro-rationing of capacity on the inter-provincial pipeline systems can occur from time to time due to pipeline and downstream operating problems that can affect the ability to market western Canadian crude oil and natural gas.

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The North American Free Trade Agreement

The North American Free Trade Agreement (“NAFTA”) among the governments of Canada, the United States of America, and Mexico became effective on January 1, 1994.  NAFTA carries forward most of the material energy terms that were contained in the Canada/United States Free Trade Agreement, which has been in place since October 1988.  In the context of energy resources, Canada continues to remain free to determine whether exports of energy resources to the United States or Mexico will be allowed, provided that any export restrictions do not: (i) reduce the proportion of energy resources exported relative to domestic use (based upon the proportion prevailing in the most recent 36 month period); (ii) impose an export price higher than the domestic price subject to an exception with respect to certain voluntary measures which only restrict the volume of exports; and (iii) disrupt normal channels of supply.  Under NAFTA all three countries are prohibited from imposing minimum or maximum export or import price requirements, provided, in the case of export price requirements, any circumstances in which any other form of quantitative restrictions could be imposed is also prohibited, and in the case of import-price requirements, such requirements do not apply with respect to enforcement of countervailing and anti-dumping orders and undertakings.

NAFTA contemplates the reduction of Mexican restrictive trade practices in the energy sector by 2010 and prohibits discriminatory border restrictions and export taxes.  NAFTA also contemplates clearer disciplines on regulators to ensure fair implementation of any regulatory changes and to minimize disruption of contractual arrangements and avoid undue interference with pricing, marketing and distribution arrangements, which is important for Canadian natural gas exports.  NAFTA may become subject to renegotiation and in such event, there can be no guarantees that the company will not face material trade restrictions, including in respect of pricing by NAFTA participants on its oil and gas products..

Royalties and Incentives

General

In addition to federal regulation, each province has legislation and regulations which govern land tenure, royalties, production rates, environmental protection, and other matters. The royalty regime is a significant factor in the profitability of crude oil, natural gas liquids, sulphur, and natural gas production.  Royalties payable on production from lands other than Crown lands are determined by negotiations between the mineral freehold owner and the lessee, although production from such lands may be subject to certain provincial taxes. Crown royalties are determined by governmental regulation and are generally calculated as a percentage of the value of the gross production. The rate of royalties payable generally depends in part on prescribed reference prices, well productivity, geographical location, field discovery date, method of recovery, depth of well, and the type or quality of the petroleum product produced. Other royalties and royalty-like interests are, from time to time, carved out of the working interest owner’s interest through non-public transactions. These are often referred to as overriding royalties, gross overriding royalties, net profits interests, or net carried interests.

Occasionally the governments of the western Canadian provinces create incentive programs for exploration and development. Such programs provide for royalty rate reductions, royalty holidays, and tax credits, and are generally introduced when commodity prices are low. The programs are designed to encourage exploration and development activity by improving earnings and cash flow within the industry. Royalty holidays and reductions would reduce the amount of Crown royalties paid by oil and gas producers to the provincial governments and would increase the net income and funds from operations of such producers. However, the

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trend in recent years has been for provincial governments to revise existing incentive programs and royalty structures, which have generally resulted in increases to the amounts of royalties ultimately payable..

The Canadian federal corporate income tax rate levied on taxable income is 22.1% effective January 1, 2007 for active business income including resource income.  With the elimination of the corporate surtax effective January 1, 2008 and other rate reductions introduced in the October 2007 Economic Statement, the federal corporate income tax rate will decrease to 15% in five steps: 19.5% on January 1, 2008, 19% on January 1, 2009, 18% on January 1, 2010, 16.5% on January 1, 2011 and 15% on January 2012.

Alberta

In Alberta, companies are granted the right to explore, produce and develop petroleum and natural gas resources in exchange for royalties, bonus bid payments and rents. On October 25, 2007, the Alberta government released a report entitled “The New Royalty Framework” containing the government’s proposals for Alberta’s new royalty regime, and was followed by the Mines and Minerals (New Royalty Framework) Amendment Act, 2008, which was given Royal Assent on December 2, 2008. The New Royalty Framework and the applicable new legislation became effective on January 1, 2009. Prior to the New Royalty Framework, the amount of conventional oil royalties that were payable was influenced by the oil production, density of the oil, and the vintage of the oil (the “Generic Regime”). Originally, the vintage classified oil was “new oil” and “old oil” depending on when the oil pools were discovered.  If the pool was discovered prior to March 31, 1974 it was considered “old oil”, and if it was discovered after March 31, 1974 and before September 1, 1992, it was considered “new oil”. The Alberta government introduced in 1992 a Third Tier Royalty with a base rate of 10% and a rate cap of 25% for oil pools discovered after September 1, 1992. The new oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 30%. The old oil royalty reserved to the Crown had a base rate of 10% and a rate cap of 35%. The New Royalty Framework eliminates this classification and establishes new royalty rates for conventional oil, natural gas and oil sands. At that time, the new royalty rates for conventional oil are set by a single sliding rate formula which is applied monthly and increases the old royalty from 30%-35% applied to the old and new tiers, to up to 50% and with rate caps once the price of conventional oil reaches Cdn.$120 per barrel. The sliding rate formula includes in its calculation the price of oil and well production.

With respect to natural gas, and similar to the conventional oil framework, the royalties outlined in the New Royalty Framework are set by a single sliding rate formula ranging from 5% to 50% with a rate cap once the price of natural gas reaches Cdn$16.59/Gigajoule. The New Royalty Framework determined rate is based on well depth, production rate, gas price and gas quality. Prior to the New Royalty Framework, the royalty reserved to the Crown in respect of natural gas production, subject to various incentives, was up to 30%, in the case of new natural gas, and up to 35%, in the case of old natural gas, depending upon a prescribed or corporate average reference price. In response to the drop in commodity prices experienced during the second half of 2008, the Government of Alberta announced on November 19, 2008, the introduction of a five year program of transitional royalty rates with the intent of promoting new drilling, which program became effective January 1, 2009.  Under this new program companies drilling new natural gas or conventional oil deep wells (between 1,000 and 3,500 metres) will be given a one-time option, on a well by well basis, to adopt either the new transitional royalty rates or those outlined in the New Royalty Framework.  In order to qualify for this program wells must be drilled during the period starting on January 1, 2009 and ending in December 31, 2013.  Following this period all new wells drilled will automatically be subject to the New Royalty Framework.

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Oil sands projects are now subject to the New Royalty Framework, and regulated by, among others, the Oil Sands Royalty Regulation, 2009 approved by the Government of Alberta on December 10, 2008. Royalties on our current Firebag In-Situ project were under the 1997 Generic Regime until the end of 2008, and assessed based on bitumen value.  In December 2008, the Government of Alberta enacted the New Royalty Framework, which increased royalty rates from the 1997 Generic Regime to a sliding-scale royalty of 25% to 40% of R – C, subject to minimum royalty of 1% to 9% of R, depending on oil price.  In both cases, a sliding-scale royalty moves with increases in WTI prices from Cdn$55\bbl to the maximum rate at a WTI price of Cdn$120\bbl.  Royalty on our base oil sands mining and associated upgrading operations are modified by Crown agreements and assessed on the R - C royalty subject to a minimum royalty as follows: (a) based on upgraded product values until December 31, 2008 with rates at 25% of R - C subject to the 1% minimum royalty of R; (b) commencing January 1, 2009, a bitumen-based royalty applies pursuant to Suncor’s exercise of its option to transition to the bitumen-based Generic Regime.  The royalty rates will remain at 25% of the R-C, subject to the 1% minimum royalty of R, but will apply to a revised R - C where R will be based on bitumen value and C would exclude substantially all upgrading costs; (c) from January 1, 2010 through December 31, 2015, pursuant to our January 2008 royalty amending agreement with the Government of Alberta, the New Royalty Framework rates described above will apply to the bitumen royalty for current production levels, subject to a cap of 30% of R-C, and a minimum royalty of 1% to 1.2% of R.  In addition, the Suncor Royalty Amending Agreement provides Suncor with a level of certainty for various matters, including the bitumen valuation methodology, allowed cost, royalty in kind and certain taxes; and (d) in 2016 and subsequent years, the royalty rates for all of our oil sands operations, our base operations and our Firebag In-Situ project, will be the rates prescribed under the New Royalty Framework, unless as amended or superseded prior to that time.

On April 10, 2008, the Government of Alberta introduced two new royalty programs to encourage the development of deep oil and gas reserves, and these are:  (a) a five-year oil program for exploration wells over 2,000 metres that will provide royalty adjustments to offset higher drilling costs and provide a greater incentive for producers to continue to pursue new, deeper oil plays (these oil wells will qualify for up to a $1 million or 12 months of royalty offsets, whichever comes first); and (b) a five-year natural gas deep drilling program that will replace the existing program in order to encourage continued deep gas exploration for wells deeper than 2,500 metres (the program will create a sliding scale of royalty credit according to depth, of up to $3,750 per metre).  These new programs are to be implemented along with the New Royalty Framework.

Regulations made pursuant to the Mines and Minerals Act (Alberta) provided various incentives for exploring and developing oil reserves in Alberta.  However, the Alberta Government announced in August of 2006 that four royalty programs were to be amended, a new program was to be introduced and the Alberta Royalty Tax Credit Program was to be eliminated, effective January 1, 2007.  The programs affected by this announcement were: (i) Deep Gas Royalty Holiday; (ii) Low Productivity Well Royalty Reduction; (iii) Reactivated Well Royalty Exemption; and (iv) Horizontal Re-Entry Royalty Reduction.  The program introduced was the Innovative Energy Technologies Program (the “IETP”) which has a stated objective of promoting the producers’ investment in research, technology and innovation for the purposes of improving environmental performance while creating commercial value.  The IETP provides royalty reductions which are presumed to reduce financial risk.  Alberta Energy decides which projects qualify and the level of support that will be provided.  The deadline for the IETP’s final round of applications was September 20, 2008.  The successful applicants for the first two rounds have been announced, and those for the third round selection are scheduled to be announced in the

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first half of 2009.  The technical information gathered from this program is to be made public once a two-year confidentiality period expires.

The New Royalty Framework includes a policy of “shallow rights reversion”.  The Government of Alberta stated that it will implement this policy in order to maximize the development of currently undeveloped resources that is consistent with the Government of Alberta’s objective of maximizing recovery of known gas resources, while increasing royalty revenues.  The policy’s stated objective is for the mineral rights to shallow gas geological formations that are not being developed to revert back to the government and be made available for resale, and in the event of non-productive shallow wells, to sever the rights from shallow zones and encourage increased production from up-hole zones. In December 2008, the Government of Alberta proclaimed an amendment to the Mines and Minerals Act (Alberta) with respect to shallow rights reversion. This amendment affects leases issued after January 1, 2009, with phased-in application for leases entered into prior to January 1, 2009.

Land Tenure

Crude oil and natural gas located in the western provinces is owned predominantly by the respective provincial governments.  Provincial governments grant rights to explore for and produce oil and natural gas pursuant to leases, licences, and permits for varying terms from two years, and on conditions set forth in provincial legislation including requirements to perform specific work or make payments.  Oil and natural gas located in such provinces can also be privately owned and rights to explore for and produce such oil and natural gas are granted by lease on such terms and conditions as may be negotiated.

Environmental Regulation

The oil and natural gas industry is currently subject to environmental regulations pursuant to a variety of provincial and federal legislation.  Such legislation provides for restrictions and prohibitions on the release or emission of various substances produced in association with certain oil and gas industry operations.  In addition, such legislation requires that well and facility sites be abandoned and reclaimed to the satisfaction of provincial authorities.  Compliance with such legislation can require significant expenditures and a breach of such requirements may result in suspension or revocation of necessary licenses and authorizations, civil liability for pollution damage, and the imposition of material fines and penalties.

Environmental legislation in the Province of Alberta has been consolidated into the Environmental Protection and Enhancement Act (Alberta) (the “EPEA”), which came into force on September 1, 1993, and the Oil and Gas Conservation Act (Alberta) (the “OGCA”). The EPEA and OGCA impose stricter environmental standards, require more stringent compliance, reporting and monitoring obligations, and significantly increased penalties. In 2006, the Alberta Government enacted regulations pursuant to the EPEA to specifically target sulphur oxide and nitrous oxide emissions from industrial operations including the oil and gas industry.

In 2007, the Alberta government introduced the Climate Change and Emissions Management Amendment Act (Alberta), which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of cap, carbon dioxide equivalent per year. Suncor’s oil sands are subject to this legislation. The act calls for intensity reductions of 12% commencing July 1, 2007

In compliance with this new legislation, Suncor filed applications in December 2007 to establish baseline intensities for our oil sands facility. In March 2009, Suncor must file compliance reports

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that show what actions the company took during the year to offset intensities. Compliance options available to Suncor include emission reductions, utilizing offset projects or contributing to a government climate change emission management fund.

For the compliance period of January 1 to December 31, 2008, the compliance costs to Suncor are estimated at between $7 million and $8 million. Final costs determined with the company’s March 2009 compliance report filing to the province.

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

On April 26, 2007, the Federal Government released its Action Plan to Reduce Greenhouse Gases and Air Pollution (the “Action Plan”) also known as ecoACTION which includes the regulatory framework for air emissions.  This Action Plan covers not only large industry, but regulates the fuel efficiency of vehicles and the strengthening of energy standards for a number of energy using products.

The Government of Canada and the Province of Alberta released on January 31, 2008 the final report of the Canada-Alberta ecoENERGY Carbon Capture and Storage Task Force, which recommends among other things: (i) incorporating carbon capture and storage into Canada’s clean air regulations; (ii) allocating new funding into projects through competitive process; and (iii) targeting research to lower the cost of technology.

On March 10, 2008, the Government of Canada released “Turning the Corner – Taking Action to Fight Climate Change” (the “Updated Action Plan”) which provides some additional guidance with respect to the Government’s plan to reduce greenhouse gas emissions by 20% by 2020 and by 60% to 70% by 2050.

The financial impact of these proposals will be dependent on the details of the final legislation. Subsequent to the introduction of the Updated Action Plan, the Canadian federal government committed to implement a North American cap and trade system with the United States, and therefore it is currently not certain that Updated Action Plan will be implemented as proposed or at all.

The Updated Action Plan is primarily directed towards industrial emissions from certain specified industries including the oil sands, oil and gas and refining.  The Updated Action Plan is intended to create a carbon emissions trading market, including an offset system, to provide incentive to reduce greenhouse gas emission and establish a market price for carbon.  For the oil sands, its proposed application will be process-specific, oil sands plants built in 2012 and later, those which use heavier hydrocarbons, up-graders and in-situ production will have mandatory standards in 2018 that will be based on carbon capture and storage.

The Updated Action Plan is proposed to apply only to facilities exceeding a minimum annual emissions threshold: (i) 50,000 tonnes of CO2 equivalent per year for natural gas pipelines; (ii) 3,000 tonnes of CO2 equivalent per upstream oil and gas facility; and (iii) 10,000 boe/d/company.  These proposed thresholds are significantly stricter than the current Alberta regulatory threshold of 100,000 tonnes of CO2 equivalent per year per facility.

Under the Updated Action Plan four separate compliance mechanisms are proposed in respect of the above targets: Technology Fund contributions, offset credits, clean development credits

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and credits for early action.  The most significant of these compliance mechanisms, at least initially, will be the Technology Fund and for which regulated entities will be able to contribute in order to comply with emissions intensity reductions.  The proposed contribution rate will increase over time, beginning at $15 per tonne for the 2010-12 period, rising to $20 per tonne in 2013, and thereafter increasing at the nominal rate of GDP growth.  Contribution limits will correspondingly decline from 70% in 2010 to 0% in 2018.  Monies raised through contributions to the Technology Fund will be used to invest in technology to reduce greenhouse gas emissions.  Alternatively, regulated entities may be able to receive credits for investing in large-scale and transformative projects at the same contribution rate and under similar requirements as mentioned above.

The proposed offset system is intended to encourage emissions reductions from activities outside of the regulated sphere, allowing non-regulated entities to participate in and benefit from emissions reduction activities.  In order to generate offset credits, project proponents must propose and receive approval for emissions reduction activities that will be verified before offset credits will be issued to the project proponent.  Those credits can then be sold to regulated entities for use in compliance or non-regulated purchasers that wish to either cancel the offset credits or bank them for future use or sale.

Under the Updated Action Plan, it is proposed that regulated entities will also be able to purchase credits created through the Clean Development Mechanism of the Kyoto Protocol.  The purchase of such Emissions Reduction Credits will be restricted to 10% of each firm’s regulatory obligation, with the added restriction that credits generated through forest sink projects will not be available for use in complying with the Canadian regulations.

There remains uncertainty around the outcome and impacts of climate change and environmental laws and regulations (whether currently in force or proposed laws and regulations as described herein or future laws and regulations); it is not currently possible to predict either the nature of any requirements or the impact on the company and its business, financial condition, results of operations and cash flow at this time.  We continue to actively work to mitigate our environmental impact, including taking action to reduce greenhouse gas emissions, investing in renewable forms of energy such as wind power and biofuels, accelerating land reclamation, installing new emission abatement equipment and pursuing other opportunities such as carbon capture and sequestration.

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RISK FACTORS

As a company, we identify risks in four principal categories: 1) Operational; 2) Financial; 3) Legal and Regulatory; and 4) Strategic. These categories are defined below, and identified risks have been classified accordingly. Please note, identified risks could relate to multiple risk categories; we have classified risks based on the primary category to which they apply to Suncor.

We are continually working to mitigate the impact of potential risks to our business. This process includes an entity-wide risk review. The internal review is completed annually to help ensure that all significant risks are identified and appropriately managed.

1)Operational Risks – Risks that directly affect our ability to continue normal operations within our identified businesses.

Operating Hazards and Other Uncertainties.  Each of our three principal operating businesses, oil sands, natural gas, and refining and marketing demand significant levels of investment and therefore carry economic risks and opportunities.  Generally, our operations are subject to hazards and risks such as fires, explosions, gaseous leaks, migration of harmful substances, blowouts, power outages and oil spills, any of which can cause personal injury, damage to property, IT systems and related data and control systems, equipment and the environment, as well as interrupt operations.  In addition, all of our operations are subject to all of the risks connected with transporting, processing and storing crude oil, natural gas and other related products.  Risks associated with access to skilled labour to support our operations in a safe and effective manner are also discussed in “Labour and Materials Supply”, below.

At oil sands, mining oil sand and producing bitumen through in-situ methods, extracting bitumen from the oil sands, and upgrading bitumen into synthetic crude oil and other products involve particular risks and uncertainties.  Oil sands is susceptible to loss of production, slowdowns, shutdowns or restrictions on our ability to produce higher value products due to the interdependence of its component systems.   Severe climatic conditions at oil sands can cause reduced production during the winter season and in some situations can result in higher costs.  While there are virtually no finding costs associated with oil sands resources, delineation of the resources, the costs associated with production, including mine development and drilling wells for SAGD operations and the 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.

There are risks and uncertainties associated with natural gas operations, including all of the risks normally associated with drilling for natural gas wells, the operation and development of such properties, including encountering unexpected formations or pressures, premature declines of reservoirs, fires, blow-outs, equipment failures and other accidents, sour gas releases, uncontrollable flows of crude oil, natural gas or well fluids, adverse weather conditions, pollution and other environmental risks.

Our downstream business is subject to all of the risks normally inherent in the operation of a refinery, terminals, pipelines and other distribution facilities as well as service stations, including loss of product, slowdowns due to equipment failures, unavailability of feedstock, price and quality of feedstock or other incidents.

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We are also subject to operational risks such as sabotage, terrorism, trespass, related damage to remote facilities, theft and malicious software or network attacks.

Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Major Projects.  There are certain risks associated with the execution of our major projects.  These risks include: our ability to obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; our ability to finance growth if commodity prices were to decline and stay at low levels for an extended period; risks relating to restarting projects placed in “safe mode”, including increased capital costs; and the effect of changing government regulation and public expectations in relation to the impact of oil sands development on the environment.  The commissioning and integration of new facilities within our existing asset base could cause delays in achieving targets and objectives.  Management believes the execution of major projects presents issues that require prudent risk management.  There are also risks associated with project cost estimates provided by us. Some cost estimates are provided at the conceptual stage of projects and prior to commencement or completion of the final scope design and detailed engineering needed to reduce the margin of error.  Accordingly, actual costs can vary from estimates and these differences can be material.  Losses resulting from the occurrence of any of these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Insurance.   Our involvement in the exploration for and development of oil and natural gas properties may result in the company becoming subject to liability for pollution, blow-outs, property damage, personal injury or other hazards.  Although we maintain a risk management program, which includes an insurance component, such insurance may not provide adequate coverage in all circumstances, nor are all such risks insurable.  Losses beyond the scope of insurance could have a material adverse effect on our business, financial condition, results of operations and cash flow.  In late 2005 we formed a self-insurance entity to provide additional business interruption coverage for potential losses.  In 2006, one of our external business interruption service providers discontinued operations.

In December 2006, insurers impacted by the January 4, 2005 fire at oil sands filed a statement of claim against various parties alleged to be potentially responsible, seeking to recover amounts paid to Suncor under our insurance contract.  As required by our insurance contract, we are named as Plaintiff. However, the action will not have an impact on the insurance settlements we have already reached with our insurers or on our future revenues.

Confidentiality.  Breach of confidentiality could place us at competitive risk if confidential operational information or proprietary intellectual property was improperly disclosed.

2)Financial Risks – Risks that directly affect our business and financial condition.

Capital Markets. Recent market events and conditions, including disruptions in the international credit markets and other financial systems and the deterioration of global economic conditions, have caused significant volatility in commodity prices and the rates at which we are able to borrow funds for our capital programs.  These conditions worsened in 2008 and are continuing in 2009, causing a loss of confidence in the broader Canadian, U.S. and global credit and financial markets and resulting in the collapse of, and government intervention in, major banks, financial institutions and insurers and creating a climate of greater volatility, less liquidity,

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widening of credit spreads, a lack of price transparency, increased credit losses and tighter credit conditions, including higher borrowing rates. Despite the various actions taken by governments around the world, concerns about the general condition of the capital markets, financial instruments, banks, investment banks, insurers and other financial institutions caused the broader credit markets to further deteriorate and stock markets to decline substantially.  These factors have negatively impacted company valuations and will impact the performance of the global economy going forward.

As a result of this weakened global economic situation, the company along with all other oil and gas entities will have restricted access to capital and increased borrowing costs. Although our business and asset base have not changed, the lending capacity of all financial institutions has diminished and risk premiums have increased. As future capital expenditures will be financed out of cash generated from operations, borrowings and possible future equity sales, our ability to do so is dependent on, among other factors, the overall state of the capital markets and investor appetite for investments in the energy industry generally and our securities in particular.

To the extent that external sources of capital become limited or unavailable or available on onerous terms, our ability to make capital investments and maintain existing properties may be impaired, and our business, financial condition, results of operations and cash flow may be materially adversely affected as a result. At December 31, 2008, we had approximately $3.0 billion of unused credit available under  bank credit facilities. Based on current funds available and expected cash from operations, we believe that we have sufficient funds available to fund our currently projected capital expenditures in 2009. However, if cash flow from operations is lower than expected or 2009 capital expenditures exceed current estimates, or if we incur major unanticipated expenses related to development or maintenance of our existing properties, we may be required to seek additional capital to maintain our capital expenditures at planned levels and our debt ratings may be adversely affected. Failure to obtain the financing necessary for our capital expenditure plans may result in a delay in the planned development or production from our operations. This in turn, could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Issuance of Debt. From time to time we may finance capital expenditures in whole or in part with debt, which may increase our debt levels above industry standards for oil and natural gas companies of similar size.  Depending on future development plans, we may require additional debt financing that may not be available or, if available, may not be available on favourable terms.  Neither the company’s articles nor its by-laws limit the amount of indebtedness that we may incur.  The level of our indebtedness from time to time, could impair our ability to obtain additional financing on a timely basis to take advantage of business opportunities that may arise and could negatively effect our debt ratings. This in turn, could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Debt Covenants. We currently have a $3.75 billion syndicated credit facility with 16 banks expiring in 2013 and a bilateral credit facility of $480 million expiring in 2009. We are required to comply with financial and operating covenants under these credit facilities. We routinely review the covenants based on actual and forecast results and have the ability to make changes to our development plans and/or dividend policy to comply with covenants under the credit facilities. In the event that we do not comply with such covenants under the credit facilities, our access to capital could be restricted or repayment could be required, which could have a material adverse effect on our business, financial condition, results of operations and cash flow. In addition, our inability to refinance expiring credit facilities on favorable terms or at all or any restrictions imposed on our borrowings under these facilities due to covenant breaches or otherwise could

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have a material adverse effect on our business, financial condition, results of operations and cash flow.

Hedging. From time to time we may enter into agreements to receive fixed prices on our oil and natural gas production to offset the risk of revenue losses if commodity prices decline; however, if commodity prices increase beyond the levels set in such agreements, we will not benefit from such increases and we may be obligated to pay royalties on such higher prices, even though not received by us, after giving effect to such agreements. Similarly, from time to time we may enter into agreements to fix the exchange rate of Canadian to United States dollars in order to offset the risk of revenue losses if the Canadian dollar increases in value compared to the United States dollar; however, if the Canadian dollar declines in value compared to the United States dollar, we will not benefit from the fluctuating exchange rate.

Uncertainty of Reserve and Resource Estimates.   The reserves estimates for our oil sands and natural gas business units included in this AIF represent estimates only.  There are numerous uncertainties inherent in estimating quantities and quality of these proved and probable reserves and resources, including many factors beyond our control.

In general, estimates of economically recoverable reserves and the future net cash flow from these assets based upon a number of variable factors and assumptions, such as historical production from the properties, the assumed effect of regulation by governmental agencies, pricing assumptions, the timing and amount of capital expenditures, future royalties, future operating costs, yield rates for production of synthetic crude oil from bitumen, all of which may vary considerably from actual results.  The accuracy of any reserve estimate is a matter of engineering interpretation and judgment and is a function of the quality and quantity of available data, which may have been gathered over time.  In the oil sands business unit, reserve and resource estimates are based upon a geological assessment, including drilling and laboratory tests. These estimates also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints.  The Firebag reserves and resource estimates are based upon a geological assessment of data gathered from evaluation drilling, the testing of core samples and seismic operations and demonstrated commercial success of the in-situ process.  Our actual production, revenues, royalties, taxes and development and operating expenditures with respect to our reserves will vary from such estimates and such variances could be material.  Production performance subsequent to the date of the estimate may justify revision, either upward or downward, if material.  For these reasons, estimates of the economically recoverable reserves attributable to any particular group of properties, and classification of such reserves based on risk of recovery, prepared by different engineers or by the same engineers at different times, may vary substantially.

In accordance with applicable securities law, our independent reserves evaluator has used forecast prices and costs in estimating the reserves and future net cash flow as summarized herein.  Actual future net cash flow will be affected by other factors, such as actual production levels, supply and demand for oil and natural gas, curtailments or increases in consumption by oil and natural gas purchasers, changes in governmental regulation or taxation and the impact of inflation and other factors on costs.

Actual production cash flow is derived from our oil and gas reserves and will vary from the estimates contained in the reserve evaluation, and such variations could be material.  The reserve evaluation is based in part on the assumed success of activities we intend to undertake in future years.  The reserves and estimated cash flow to be derived from the reserves contained in the reserve evaluation will be reduced to the extent that such activities do not achieve the level of success assumed in the reserve evaluation.  The reserve evaluation is effective as of a specific

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effective date and has not been updated, and thus does not reflect changes in our reserves since that date.

Volatility of Crude Oil and Natural Gas Prices.  Our future financial performance is closely linked to crude oil prices, and to a lesser extent, natural gas prices. The prices of these commodities can be influenced by global and regional supply and demand factors. Worldwide economic growth, political developments, compliance or non-compliance with quotas imposed upon members of the Organization of the Petroleum Exporting Countries and weather, among other things, can affect world oil supply and demand. Our natural gas price realizations are affected primarily by North American supply and demand and by prices of alternate sources of energy. All of these factors are beyond our control and can result in a high degree of price volatility not only in crude oil and natural gas prices, but also fluctuating price differentials between heavy and light grades of crude oil, which can impact prices for sour crude oil and bitumen. Oil and natural gas prices have fluctuated widely in recent years and have decreased substantially over the last six months. Given the current global economic downturn, we expect continued volatility and uncertainty in crude oil and natural gas prices and prices may remain at depressed levels in the near term and beyond. A prolonged period of low crude oil and natural gas prices could affect the value of our crude oil and gas properties and the level of spending on growth projects, and could result in curtailment of production on some properties. Accordingly, low crude oil prices in particular could have a material adverse effect on our business, financial condition, results of operations and cash flow. A key component of our business strategy is to target production of sufficient natural gas to meet or exceed internal demands for natural gas purchased for consumption in our oil sands operations, creating a natural price hedge which reduces our exposure to gas price volatility. However, there are no assurances that we will be able to continue to increase production to keep pace with growing internal natural gas demands.

We conduct an assessment of the carrying value of our assets to the extent required by Canadian generally accepted accounting principles. If crude oil and natural gas prices decline further or remain at low levels, the carrying value of our assets could be subject to downward revisions, and our earnings could be materially adversely affected.

Volatility of Downstream Margins.  Our downstream business is sensitive to wholesale and retail margins for its refined products, including gasoline, diesel and asphalt. Margin volatility is influenced by, among other things, overall marketplace competitiveness, weather, the cost of crude oil (see “Volatility of Crude Oil and Natural Gas Prices” above) and fluctuations in supply and demand for refined products. We expect that margin and price volatility and overall marketplace competitiveness, including the potential for new market entrants, will continue.  As a result, our operating results for our refining and marketing business unit can be expected to fluctuate and may be materially adversely affected.

Energy Trading Activities.  The nature of energy trading activities creates exposure to significant financial risks. These include risks that: movements in prices or values could result in a financial loss to the company; a lack of counterparties, due to market conditions or otherwise could leave us unable to liquidate or offset a position, or unable to do so at or near the previous market price; we may not receive funds or instruments from our counterparty at the expected time; the counterparty could fail to perform an obligation owed to us; we may suffer a loss as a result of human error or deficiency in our systems or controls; or we may suffer a loss as a result of contracts being unenforceable or transactions being inadequately documented. A separate risk management function within the company develops and monitors practices and policies and provides independent verification and valuation of our trading and marketing activities. However, we may experience significant financial losses as a result of these risks, which may have a material adverse effect on our business, financial condition, results of operations and cash flow.

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Exchange Rate Fluctuations.  Our 2008 Consolidated Financial Statements are presented in Canadian dollars. Results of operations are affected by the exchange rates between the Canadian dollar and the U.S. dollar.  These exchange rates have varied substantially in the last five years.  A substantial portion of our revenue is received by reference to U.S. dollar denominated prices and a significant portion of our debt is denominated in U.S. dollars. In addition, we have subsidiary operations that are denominated in U.S. dollars, translated to Canadian dollars using the current rate approach, whereby revenues and expenses are recorded at the exchange rate at the time the transaction occurs, and assets and liabilities are translated at the exchange rate at the balance sheet date. Therefore, fluctuations in exchange rates between the U.S. and Canadian dollar may give rise to foreign currency exposure, either favourable or unfavourable, creating another element of uncertainty. To the extent such fluctuation is unfavourable, it may have a material adverse effect on our business, financial condition, results of operations and cash flow.

Dividends.  Our payment of future dividends on our common shares will be dependent on, among other things, our financial condition, results of operations, cash flow, the need for funds to finance ongoing operations, debt covenants and other business considerations as the board of directors of the company considers relevant.  There can be no assurance that we will continue to pay dividends in the future.

Interest Rate Risk.  We are exposed to fluctuations in short-term Canadian interest rates as a result of the use of floating rate debt.  We maintain a substantial portion of our debt capacity in revolving, floating rate bank facilities and commercial paper, with the remainder issued in fixed rate borrowings. To manage our interest rate exposures, we occasionally enter into interest rate swap agreements and exchange contracts to either effectively fix the interest rate on floating rate debt or to float the interest rate on fixed rate debt.

3)Legal and Regulatory Risks – Risks that affect our ability to comply with regulatory and statutory requirements under applicable law.

Environmental Regulation and Risk.  Environmental regulation affects nearly all aspects of our operations.  These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry.  The regulatory regimes require us to obtain operating licenses and permits in order to operate and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals.  Environmental assessments and regulatory approvals are required before initiating most new major projects or undertaking significant changes to existing operations.  In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air pollution (Criteria Air Contaminants) and greenhouse gases that will impose further requirements on companies operating in the energy industry.  See “Industry Conditions – Environmental Regulation” in this AIF.

·Some of the issues that are or may in future be subject to environmental regulation include:

·the possible cumulative regional impacts of oil sands development;

·manufacture, import, storage, treatment and disposal of hazardous or industrial waste and substances;

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·the need to reduce or stabilize various emissions to air;

·withdrawals, use of, and discharges to, water;

·issues relating to land reclamation, restoration and wildlife habitat protection;

·reformulated gasoline to support lower vehicle emissions; and

·U.S. implementation of regulation or policy to limit its purchases of oil to oil produced from conventional sources, or U.S. state or federal calculation and regulation of fuel lifecycle carbon content.

Changes in environmental regulation could have a material adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production, distribution costs and financial results. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important licenses and permits, which may in turn, have a material adverse effect on our business, financial condition, results of operations and cash flow.

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established to set legally binding targets to reduce nationwide emissions of carbon dioxide, methane, nitrous oxide and other so called “greenhouse gases”. Our exploration and production facilities and other operations and activities emit greenhouse gases and will require us to comply with the new regulatory framework announced on March 10, 2008 by the Federal Government which is intended to force large industries to reduce emissions of greenhouse gases, in addition to the Federal Government’s proposed Clean Air Act (Alberta) of 2006, Action Plan, Updated Action Plan and Alberta’s recently enacted Climate Change and Emissions Management Act and Specified Gas Emitters Regulation. The direct or indirect costs of these regulations may have a material adverse effect on our business, financial condition, results of operations and cash flow.  See “Industry Conditions – Environmental Regulation” in this AIF.

A new reclamation liability management program is under review by the Province of Alberta. The new program would involve increased reporting of progressive reclamation, an asset/liability based risk assessment and consideration of reserve life. Partial security could be required if reclamation targets are not met and full security may eventually be required.

Over the past few years legislation has been passed in Canada and the United States to reduce allowable levels of sulphur in transportation fuels.  For a discussion of projects completed at our refining and marketing operations, see the information under refining and marketing in the “Three-Year History” section of this AIF. Projects to retrofit existing facilities to comply with these standards are subject to all risks inherent in large capital projects, and to the additional risk that failure to meet legislated deadlines could have a material impact on the company’s

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ability to market its products, or subject the company to fines and penalties potentially having a material adverse effect on our business, financial condition, results of operations and cash flow.

Our refining and marketing unit’s U.S. operations are subject to Consent Decrees with the United States Environmental Protection Agency, the United States Department of Justice and the State of Colorado.  For a discussion of these Consent Decrees and the related obligations, see the information under the refining and marketing section of the “Three Year History” section in this AIF. The company is subject to the risk that failure to meet remaining obligations or the deadlines under these Consent Decrees could have a material impact on our ability to market our products, potentially having a material adverse effect on our business, financial condition, results of operations and cash flow.

In addition, our business could be materially adversely affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change. See “Industry Conditions – Environmental Regulation” in this AIF.

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

U.S. Policies.  The  U.S. government has passed legislation that may be interpreted as limiting the purchase of oil and related refined products by governmental agencies to oil and related refined products produced from conventional sources, rather than oil from the oil sands.  Although we continue to focus on mitigating our business impact to air, water and land, current and future U.S. environmental laws, regulations and policies may impact or limit our current business plans and/or reduce demand for our products. As a result, our business, financial condition, results of operations and cash flow could be adversely affected.

Land Claims.  First Nations peoples have claimed aboriginal title and rights to portions of western Canada. In addition, First Nations peoples have filed claims against industry participants relating in part to land claims, which may affect our business. However, at the present time, we are unable to assess the effect, if any, that these land claims may have on our business.

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Alberta Crown Royalties.  The following risk factors could cause royalty expenses to differ materially from current estimates and impact the royalties payable to the Crown:

·The New Royalty Framework has not yet finalized the measurement and valuation of heat transfers between project and non-project assets for integrated operators. The final determination of the business rules for heat transfer may have an impact on future royalties payable to the Crown; and

·Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project; changes to the New Royalty Framework by the Government of Alberta; changes in other legislation; and the occurrence of unexpected events.

See “Industry Conditions – Royalties and Incentives” in this AIF.

Contractual Obligations.  As a result of our reduced capital budget for 2009, we may be unable to fulfill all of our obligations under some of our contractual arrangements which may require us in some cases to pay fees or penalties for cancellation of such contractual arrangements and may result in the company becoming subject to litigation. This in turn, could adversely affect our business, financial condition, results of operations and cash flow.

4)Strategic Risks – Risks that affect our ability to meet long-term goals and planning initiatives.

Dependence on Oil Sands Business.  Our significant capital commitment to further our growth projects at oil sands may require us to forego investment opportunities in other segments of our operations.  The completion of future projects to increase production at oil sands will further increase our dependence on the oil sands segment of our business. For example, in 2008, the oil sands business accounted for approximately 86% of our upstream production (2007 - 87%), 95% of our net earnings (2007 - 87%) and 86% of our cash flow from operations (2007 - 79%). These percentages have been determined excluding the corporate and eliminations segment information.

Reclamation.  There are risks associated with our ability to complete reclamation work, specifically reclaiming tailings ponds which contain water, clay and residual bitumen produced through the extraction process. To reclaim tailings ponds, we are using a process referred to as consolidated tailings (“CT”) technology. At this time, no ponds have been fully reclaimed using this technology. The success of the CT technology and time to reclaim the tailings ponds could increase or decrease the current asset retirement cost estimates. We continue to monitor and assess other possible technologies and/or modifications to the consolidated tailings process now being used.  Regulatory approval of our North Steepbank extension of mine is subject to certain conditions related to the performance of CT technology. Our failure to adequately implement our reclamation plans could have a material adverse effect on our business, financial condition, results of operations and cash flow.

In February 2009, the Energy Resources Conservation Board (“ERCB”) released a directive, Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for CT operations, a requirement for specific approval and monitoring of CT ponds, a requirement for reporting tailings plans, and changes to the ERCB annual mine plan requirements and approval process to regulate tailings operations. We are currently assessing the impact of the directive.

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Interdependence of Oil Sands Systems. The oil sands plant is susceptible to loss of production due to the interdependence of its component systems. Through growth projects, we expect to further mitigate adverse impacts of interdependent systems and to reduce the production and cash flow impacts of complete plant-wide shutdowns.  For example, we added a second upgrader, which provides us with the flexibility to conduct periodic plant maintenance on one operation while continuing production and cash flow generation from the other.  Our inability to sufficiently manage these risks could have a material adverse effect on our business, financial condition, results of operations and cash flow.

Need to Replace Conventional Natural Gas Reserves.  Future natural gas reserves and production from our natural gas business unit are highly dependent on our successful discovery or acquisition of additional reserves and exploitation of our current reserve base.  This has the potential to impact our ability to maintain a price hedge against the growing consumption of natural gas in our operations.  Without natural gas reserve additions through exploration and development or acquisitions, our conventional natural gas reserves and production will decline over time as reserves are depleted.  For example, in 2008, our average natural gas reservoir decline rate was approximately 24% (2007 – 24%). Decline rates will vary with the nature of the reservoir, life-cycle of the well and other factors. Therefore, historical decline rates are not necessarily indicative of future performance. Exploring for, developing and acquiring reserves is highly capital intensive. To the extent cash flow from operations6 is unable to generate sufficient capital and external sources of capital become limited or unavailable, our ability to make the necessary capital investments to maintain and expand our conventional natural gas reserves could be impaired. In addition, the long-term performance of the natural gas business is dependent on our ability to consistently and competitively find and develop low-cost, high-quality reserves that can be economically brought on stream. Market demand for land and services can also increase or decrease finding and development costs. There can be no assurance that we will be able to find and develop or acquire additional reserves to replace production at acceptable costs.

Competition.  The petroleum industry is highly competitive in all aspects, including the exploration for, and the development of, new sources of supply, the acquisition of crude oil and natural gas interests and the refining, distribution and marketing of petroleum products and chemicals.  We compete in virtually every aspect of our business with other energy companies.  The petroleum industry also competes with other industries in supplying energy, fuel and related products to consumers.  We believe the primary competition for our crude oil production is other North American conventional and synthetic sweet and sour crude oil producers.

A number of other companies have entered or have indicated their intention to enter the oil sands business and begin producing bitumen and synthetic crude oil or expand their existing operations. While this activity has declined with the corresponding decline in economic conditions, it is expected to resume once there is more market certainty.  It is difficult to assess the number, level of production and ultimate timing of all potential new projects or when existing production levels may increase. The Canadian Association of Petroleum Producers estimates that Canada’s production of bitumen and upgraded synthetic crude oil could increase from approximately 1.2 million bpd in 2007 to more than three million bpd by 20207. Increasing industry consolidation, a global focus on oil sands and additional competitors with financial capacity has, over the past number of years: (a) materially increased the supply of bitumen and synthetic crude oil and other competing crude oil products in the marketplace; (b) exponentially

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

7 Canadian Association of Petroleum Producers’ Crude Oil Forecast - Interim Update, 11 December 2008

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increased land values and availability of new leases; and (c) placed stress on the availability and cost of all resources required to build and run new and existing oil sands operations.  If we are unable to transport our produced crude oil products, production levels may be adversely affected.

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

Labour and Materials Supply.  The expansion of the industry up to the third quarter of 2008 and the impact of new entrants to the business, had created the potential for risks related to the availability of, and competition for, skilled labour and materials supply. Although these risks were not exclusive to our oil sands operation, there were increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads, medical facilities, and schools). With today’s market conditions, these risks have not eroded; rather, with layoffs by some contractors and the corresponding move away from the Fort McMurray region by transient workers, there is a risk that we may have difficulty sourcing the required labour for current and future operations. As well, materials may be in short supply due to smaller labour forces in many manufacturing operations. Our ability to operate safely and effectively and complete all our projects on time and on budget has the potential to be significantly impacted by these risks. Risks associated with completion of significant capital projects are discussed in “Major Projects” above.

Oversupply. In the event that multiple major capital initiatives in the industry proceed simultaneously, there are risks associated with pipeline capacity and infrastructure which could negatively affect our sales mix, and ability to deliver oil sands crudes to Suncor refineries and ultimately crude oil netbacks.

Constraints. Pipeline capacity constraints combined with plant capacity constraints could negatively impact our ability to produce at capacity levels in our crude oil and natural gas business. See “Industry Conditions - Pipeline Capacity”.

Technology Risk. There are risks associated with growth and other capital projects that rely largely or partly on new technologies and the incorporation of such technologies into new or existing operations, particularly as the results of the technology in real-world applications may differ from test environments..  The success of projects incorporating new technologies, such as in-situ technology, cannot be assured.

In-Situ Recovery.  Current steam-assisted gravity drainage (SAGD) technologies for in-situ recovery of heavy oil and bitumen are energy intensive, requiring significant consumption of natural gas and other fuels in the production of steam which is used in the recovery process. The amount of steam required in the production process can also vary and impact costs. The performance of the reservoir can also impact the timing and levels of production using this technology.  While the technology is now being used by several producers, commercial application of this technology is still in the early stages relative to other methods of production and accordingly, in the absence of and extended operating history, there can be no assurances with respect to the sustainability of SAGD operations.

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Reliance on Key Personnel.  Our success depends in a large measure on certain key personnel. The loss of the services of such key personnel could have a material adverse effect on the company.  The contributions of the existing management team to the immediate and near-term operations of the company are likely to continue to be of central importance for the foreseeable future.  In addition, the competition for qualified personnel in the oil and natural gas industry is intense and there can be no assurance that we will be able to continue to attract and retain all personnel necessary for the development and operation of our business.

Labour Relations.  Hourly employees at our oil sands facility near Fort McMurray, Alberta, our London, Ontario terminal operation, our Sarnia, Ontario refinery, our Commerce City, Colorado refinery and at Sun-Canadian Pipeline Company Limited are represented by labour unions or employee associations.  Any work interruptions involving our employees, and/or contract trades utilized in our projects or operations, could have a material adverse effect on our business, financial condition, results of operations and cash flow.

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DIVIDENDS

Our Board of Directors has established a policy of paying dividends on a quarterly basis. We review our policy from time to time in light of our financial position, financing requirements for growth, cash flow and other factors which our Board of Directors considers relevant. Our Board of Directors approved an increase in the quarterly dividend to $0.05 per share* from $0.04 per share* in the second quarter of 2007, and an increase to $0.04 per share* from $0.03 per share* during the second quarter of 2006.

The following table sets forth the per share* amount of dividends we paid to shareholders during the last three years.

	Year Ended December 31,
	2008	2007	2006
Common Shares cash dividends	$0.20	$0.19	$0.15
Dividends paid in common shares	-	-	-

* Per share amounts have been adjusted to reflect a two-for-one share split in May 2008.

DESCRIPTION OF CAPITAL STRUCTURE

General Description of Capital Structure

Our authorized capital consists of an unlimited number of common shares without nominal or par value and an unlimited number of preferred shares without nominal or par value, issuable in series.  As at December 31, 2008, a total of 935,524,213 common shares were issued and outstanding and no preferred shares had been issued.

Each common share entitles the holder to receive notice of and to attend all meetings of our shareholders, other than meetings at which only the holders of another class or series are entitled to vote.  Each common share entitles the holder to one vote.  The holders of common shares, in the discretion of the Board of Directors, are entitled to receive out of any monies properly applicable to the payment of dividends, and after the payment of any dividends payable on preferred shares (if any), of any series or any other series ranking prior to the common shares as to the payment of dividends, any dividends declared and payable on the common shares.  Upon any liquidation, dissolution or winding-up of Suncor, or other distribution of our assets among our shareholders for the purposes of winding-up our affairs, the holders of the common shares are entitled to share on a share-for-share basis in the distribution, except for the prior rights of the holders of the preferred shares of any series, or any other class ranking prior to the common shares. There are no pre-emptive or conversion rights, and the common shares are not subject to redemption. All common shares currently outstanding and to be outstanding upon exercise of outstanding options are, or will be, fully paid and non-assessable.

Ratings

Our current long-term debt ratings are A(low) with a Negative Trend by Dominion Bond Rating Service Limited; Baa1  with a Stable Outlook by Moody’s Investors Service, Inc; and BBB+ with a Negative Outlook by Standard & Poor’s Rating Services, a division of the McGraw-Hill Companies, Inc.

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Dominion Bond Rating Service’s (“DBRS”) credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of A (low) by DBRS is the third highest of nine categories and is assigned to debt securities considered to be of satisfactory credit quality. Protection of interest and principal is still substantial, but the degree of strength is less than with AA rated entities. Entities in the A category may be more susceptible to adverse economic conditions and have greater cyclical tendencies than higher rated companies. The assignment of a “(high)” or “(low)” modifier within each rating category indicates relative standing within such category. The “high” and “low” grades are not used for the AAA category.

Moody’s credit ratings are on a long-term debt rating scale that ranges from AAA  to C, which represents the range from highest to lowest quality of such securities rated. A rating of Baa1 by Moody’s is the fourth highest of nine categories and is assigned to debt securities which are considered upper-medium grade obligations and are subject to low credit risk. Moody’s appends numerical modifiers 1, 2 or 3 to each generic rating classification. The modifier 1 indicates that the issue ranks in the higher end of its generic rating category, the modifier 2 indicates a mid-range ranking and the modifier 3 indicates that the issue ranks in the lower end of its generic rating category.

Standard and Poor’s (“S&P”) credit ratings are on a long-term debt rating scale that ranges from AAA to D, which represents the range from highest to lowest quality of such securities rated. A rating of BBB+ by S&P is the fourth highest of eleven categories and indicates that the obligor is somewhat more susceptible to adverse effects of changes in circumstances and economic conditions than obligors in the higher-rated categories. However, the obligor’s capacity to meet its financial commitment on the obligation is still strong. The addition of a plus (+) or minus (-) designation after a rating indicates the relative standing within a particular rating category.

DBRS’s commercial paper credit ratings are on a short-term debt rating scale that ranges from R-1(high) to D, which represent the range from highest to lowest quality of such securities rated. A rating of R-1(low) by DBRS is the third highest of ten categories and is assigned to debt securities considered to be of satisfactory credit quality. The overall strength and outlook for key liquidity, debt, and profitability ratios is not normally as favourable as with higher rating categories, but these considerations are still respectable, and any qualifying negative factors that exist are considered manageable, and the entity is normally of sufficient size to have some influence in its industry.

The credit ratings accorded to the notes by the rating agencies are not recommendations to purchase, hold or sell the notes inasmuch as such ratings do not comment as to the market price or suitability for a particular investor. Any rating may not remain in effect for any given period of time or may be revised or withdrawn entirely by a rating agency in the future if in its judgment circumstances so warrant.

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MARKET FOR OUR SECURITIES

Price Range and Trading Volume of Common Shares

Our common shares are listed on the Toronto Stock Exchange in Canada, and on the New York Stock Exchange in the United States.

Toronto Stock Exchange 2008	Price Range ($Cdn)		Trading Volume
	High	Low	(000’s)
January	56.14	40.92	91,478
February	52.10	45.13	54,787
March	54.73	46.11	72,828
April	61.10	47.78	69,135
May	73.10	53.96	77,431
June	71.25	58.75	79,826
July	62.30	51.32	87,330
August	62.37	51.28	64,491
September	57.21	39.61	114,560
October	43.78	21.85	174,816
November	29.89	18.80	121,190
December	28.14	19.90	100,674

New York Stock Exchange 2008	Price Range ($US)		Trading Volume
	High	Low	(000’s)
January	56.73	39.67	146,039
February	53.54	44.65	85,771
March	55.54	44.92	111,128
April	60.65	46.31	119,550
May	74.28	52.88	142,737
June	69.94	58.01	109,016
July	61.99	50.80	146,177
August	59.65	49.12	117,861
September	53.95	38.00	194,496
October	41.12	17.83	332,029
November	25.98	14.52	211,059
December	22.99	15.29	177,763

Prior Sales

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest at a rate of 5.80% per annum, which is paid semi-annually, and mature on May 22, 2018. The net proceeds were added to our general funds to repay outstanding commercial paper, which originally funded our working capital needs, sustaining capital expenditures and growth capital expenditures.

In June 2008, the company issued 6.10% Notes with a principal amount of US$1.25 billion and 6.85% Notes with a principal amount of US$750 million under an amended US$3.65 billion debt shelf prospectus. These notes bear interest at a rate of 6.10% per annum and 6.85% per annum, respectively, which is paid semi-annually, and mature on June 1, 2018, and June 1, 2039, respectively. The net proceeds were added to our general funds, which are used for our

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working capital needs, sustaining capital expenditures, growth capital expenditures and to repay outstanding commercial paper borrowings.

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are directors of Suncor.

Name and Jurisdiction of Residence	Period Served and Independence	Principal Occupations During Past Five Years
Mel E. Benson (3)(4) Alberta, Canada	Director since 2000 Independent	Mel Benson is president of Mel E. Benson Management Services Inc., an international management consulting firm based in Calgary, Alberta. In 2000, Mr. Benson retired from a major international oil company. Mr. Benson is a director of Tenax Energy Inc., chair of Winalta Homes Inc., director of Tarpon Energy Services and director of the Fort McKay Group of companies. He is active with several charitable organizations including Hull Family Services. He is also a member of the board of governors for the Northern Alberta Institute of Technology.
Brian A. Canfield (1)(2) Washington, USA	Director since 1995 Independent	Brian Canfield is the chairman of TELUS Corporation, a telecommunications company. Mr. Canfield is a member of the Order of Canada, a member of the Order of British Columbia, and a fellow of the Institute of Corporate Directors.
Bryan P. Davies (3)(4) Ontario, Canada	Director 1991 to 1996 and since 2000 Independent	Bryan Davies is chairman of the Canada Deposit Insurance Corporation. He is also a director of the General Insurance Statistical Agency and is past superintendent of the Financial Services Commission of Ontario. Previously, he was senior vice president, regulatory affairs with the Royal Bank Financial Group. Mr. Davies is also active with a number of not-for-profit charitable organizations.
Brian A. Felesky (1)(4) Alberta, Canada	Director since 2002 Independent	Brian Felesky is counsel to the law firm of Felesky Flynn LLP in Calgary, Alberta. Mr. Felesky also serves as a director on the board and is chair of the audit committee of Epcor Power LP. He is also a member of the board of Precision Drilling Trust and Resin Systems Inc. and various private corporations. Mr. Felesky is co-chair of Homefront on Domestic Violence, vice chair of the Canada West Foundation, member of the senate of Athol Murray College of Notre Dame, board member of the Calgary Stampede Foundation and a council member of the Alberta Order of Excellence. Mr. Felesky is a Queen’s Counsel and member of the Order of Canada.

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Name and Jurisdiction of Residence	Period Served and Independence	Principal Occupations During Past Five Years
John T. Ferguson(2)(3) Alberta, Canada	Director since 1995 Independent	John Ferguson is founder and chairman of the board of Princeton Developments Ltd. and Princeton Ventures Ltd. Mr. Ferguson is also a director of Fountain Tire Ltd., the Royal Bank of Canada and Strategy Summit Ltd. In addition, he is a director of the C.D. Howe Institute and the Alberta Bone and Joint Institute, an advisory member of the Canadian Institute for Advanced Research and chancellor emeritus and chairman emeritus of the University of Alberta. Mr. Ferguson is also a fellow of the Alberta Institute of Chartered Accountants and of the Institute of Corporate Directors.
W. Douglas Ford(1)(2) Florida, USA	Director since 2004 Independent	W. Douglas Ford was chief executive, refining and marketing for BP p.l.c. from 1998 to 2002 and was responsible for the refining, marketing and transportation network of BP as well as the aviation fuels business, the marine business and BP shipping. Mr. Ford currently serves as a director of USG Corporation and Air Products and Chemicals, Inc. He is also a member of the board of trustees of the University of Notre Dame.
Richard L. George Alberta, Canada	Director since 1991 Non-independent, management	Richard George is the president and chief executive officer of Suncor Energy Inc. Mr. George is also a director of the Swiss offshore and onshore drilling company Transocean. He currently serves as the Canadian chair of the North American Competitiveness Council and he chaired the 2008 Governor General’s Canadian Leadership Conference. Mr. George was named a member of the Order of Canada in 2007.
John R. Huff (2)(3) Texas, USA	Director since 1998 Independent	John Huff is chairman of Oceaneering International Inc., an oil field services company. He also serves as director of BJ Services Company, KBR Inc. and Rowan Companies Inc. Mr. Huff is a member of the National Petroleum Council, a trustee of the Houston Museum of Natural Science and is a director of St. Luke’s Episcopal Hospital System in Houston.
M. Ann McCaig (3)(4) Alberta, Canada	Director since 1995 Independent	Mrs. McCaig is a trustee of the $400 million Killam Estate, a director of the Gairdner Foundation, the Chair of the Calgary Health Trust and the Chair of the Alberta Adolescent Recovery Centre, as well as the Honorary Chair of the Alberta Bone and Joint Institute. She is a director of the Calgary Stampede Foundation. She is Chancellor Emeritus at the University of Calgary having served as Chancellor from 1994 to 1998. Mrs. McCaig has received numerous awards including an Honorary Doctor of Laws Degree from the University of Calgary and the University of Alberta, the University of Saskatchewan Alumni Humanitarian Award, the Queen Elizabeth Award, the 125th Confederation of Canada Award and the Alberta Order of Excellence. She is also a member of the Order of Canada.

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Name and Jurisdiction of Residence	Period Served and Independence	Principal Occupations During Past Five Years
Michael W. O’Brien(1)(2) Alberta, Canada	Director since 2002 Independent	Michael O’Brien served as executive vice president, corporate development, and chief financial officer of Suncor Energy Inc. before retiring in 2002. Mr. O’Brien serves on the board of Shaw Communications Inc. and is an advisor to CRA International. In addition, he is past chair of the board of trustees for Nature Conservancy Canada, past chair of the Canadian Petroleum Products Institute and past chair of Canada’s Voluntary Challenge for Global Climate Change.
Eira M. Thomas (1)(4) British Columbia, Canada	Director since 2006 Independent	Eira Thomas assumed the role of executive chairman of Stornoway Diamond Corporation, a mineral exploration company, on January 1, 2009, after serving as chief executive officer since July 2003. Previously, Ms. Thomas was president of Navigator Exploration Corporation and chief executive officer of Stornoway Ventures Ltd. She is also a director of Strongbow Exploration Inc. and Fortress Minerals Corp. In addition, Ms. Thomas is a director of the University of Toronto (U of T) Alumni Association, Lassonde Advisory Board of the U of T, Prospectors and Developers Association of Canada and the Northwest Territories and Nunavut Chamber of Mines. She also is a member of the U of T President’s Internal Advisory Council.

(1)Audit Committee

(2)Governance Committee

(3)Human Resources and Compensation Committee

(4)Environment, Health & Safety Committee

Corporate Officers

The following individuals are the executive officers of Suncor.

Name and Jurisdiction of Residence	Office(1)(2)
J. KENNETH ALLEY Alberta, Canada	Senior Vice President and Chief Financial Officer
MARLOWE ALLISON Alberta, Canada	Vice President and Treasurer
KIRK BAILEY Alberta, Canada	Executive Vice President, Oil Sands
JOEL CROTEAU Alberta, Canada	Senior Vice President, Natural Gas and In Situ Resources
BART DEMOSKY Alberta, Canada	Senior Vice President, Business Services
RICHARD L. GEORGE Alberta, Canada	President and Chief Executive Officer

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TERRENCE J. HOPWOOD Alberta, Canada	Senior Vice President and General Counsel
SUE LEE Alberta, Canada	Senior Vice President, Human Resources and Communications
MARK LITTLE Alberta, Canada	Senior Vice President, Strategic Growth and Energy Trading
KEVIN D. NABHOLZ Alberta, Canada	Executive Vice President, Major Projects
JANICE B. ODEGAARD Alberta, Canada	Vice President and Corporate Secretary
JAY THORNTON Alberta, Canada	Executive Vice President, Refining and Marketing
STEVEN W. WILLIAMS Alberta, Canada	Chief Operating Officer

Notes:

(1)Offices shown are positions held by the officers in relation to businesses of Suncor Energy Inc. and its subsidiaries. On a legal entity basis, Mr. Little is president of Suncor Energy Marketing Inc. and Mr. Thornton is president of Suncor Energy Products Inc., each of which are Suncor’s Canada-based downstream subsidiaries; and Mr. Nabholz, Ms. Lee and Mr. Demosky are officers of Suncor Energy Services Inc., which provides major projects management, human resources and communication, business services and other shared services to the Suncor group of companies.

(2)This information reflects the positions of officers as at December 31, 2008.

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

Cease Trade Orders, Bankruptcies, Penalties or Sanctions

To the best of our knowledge, having made due inquiry, we confirm that, as at the date hereof:

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

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

(ii)was subject to an event that resulted, after the director or executive officer ceased to be a director or executive officer, in the company being the subject of a cease trade or similar order or an order that denied the relevant company access to any exemption under securities legislation, for a period of more than 30 consecutive days; or

(iii)became bankrupt or made a proposal under any legislation relating to bankruptcy or insolvency or was subject to or instituted any proceedings, arrangement or compromise with creditors or had a receiver, receiver manager or trustee

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appointed to hold its assets, other than Mr. Ford, a director of Suncor who is currently a director of USG Corporation, which was in bankruptcy protection until June, 2006, and who was also a director of United Airlines (until February 2006) which was in Chapter 11 bankruptcy protection until February, 2006.

(b)no director or executive officer of Suncor has:

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

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

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

Conflicts of Interest

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

SUNCOR EMPLOYEES

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

	as at
	December 31,
	2008	2007
Oil Sands	3,903	3,575
Natural Gas	198	196
Refining and Marketing	1,112	1,151
Corporate(1)	1,585	1,543
Total (2)	6,798	6,465

Notes:

(1)Corporate employees includes employees from our Major Projects group, which supports all three of our business units.

(2)In addition to our employees, we also use independent contractors to supply a range of services.

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The Communications, Energy and Paperworkers Union Local 707 represent approximately 2,300 oil sands employees. A new collective agreement with the union was entered into effective May 1, 2007. The terms of the agreement include a wage increase of 7% in the first year and 6% in each of the following two years, as well as an initial lump sum payment.

Employee associations represent approximately 230 of refining and marketing’s Sarnia refinery, London terminal and Sun-Canadian Pipe Line Company employees. In 2008, a four-year agreement that will be renegotiated in 2012 was signed with the Sarnia employee association. In 2006, a three-year agreement was signed with the Canadian Auto Workers union at the London terminal, and expires March 1, 2009. In January 2009, management received formal notification from the Union of its intention to bargain. The agreement with the employee association of Sun-Canadian Pipe Line Company was signed in 1993, and is renewed automatically each year unless terminated by written notice by either party at least 60 days prior to the anniversary date of the agreement. No notice has been received or given to date, and management believes the agreement will be automatically renewed on its anniversary.

The United Steel Workers union represents approximately 250 employees at refining and marketing’s Denver refining facilities.  In February 2009, the union ratified a 3 year contract which will expire in January 2012.

AUDIT COMMITTEE INFORMATION

Audit Committee Charter

The Audit Committee Charter is attached as Schedule “B” to this AIF.

Composition of the Audit Committee

The Audit Committee is comprised of Mr. Canfield (Chairman), Mr. Felesky, Mr. Ford, Mr. O’Brien and Ms. Thomas. All members are independent and financially literate. The education and expertise of each member is described under the heading “Directors and Executive Officers”.

For the purpose of making appointments to the Company’s Audit Committee, and in addition to the independence requirements, all directors nominated to the Audit Committee must meet the test of financial literacy as determined in the judgment of the board of directors. Also, at least one director so nominated must meet the test of financial expert as determined in the judgment of the board of directors. The designated financial expert on the Audit Committee is Michael W. O’Brien.

Financial Literacy

Financial literacy can be generally defined as the ability to read and understand a balance sheet, an income statement and a cash flow statement. In assessing a potential appointee’s level of financial literacy, the board of directors must evaluate the totality of the individual’s education and experience including:

·The level of the person’s accounting or financial education, including whether the person has earned an advanced degree in finance or accounting;

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·Whether the person is a professional accountant, or the equivalent, in good standing, and the length of time that the person actively has practised as a professional accountant, or the equivalent;

·Whether the person is certified or otherwise identified as having accounting or financial experience by a recognized private body that establishes and administers standards in respect of such expertise, whether that person is in good standing with the recognized private body, and the length of time that the person has been actively certified or identified as having this expertise;

·Whether the person has served as a principal financial officer, controller or principal accounting officer of a corporation that, at the time the person held such position, was required to file reports pursuant to securities laws, and if so, for how long;

·The person’s specific duties while serving as a public accountant, auditor, principal financial officer, controller, principal accounting officer or position involving the performance of similar functions;

·The person’s level of familiarity and experience with all applicable laws and regulations regarding the preparation of financial statements that must be included in reports filed under securities laws;

·The level and amount of the person’s direct experience reviewing, preparing, auditing or analyzing financial statements that must be included in reports filed under provisions of securities laws;

·The person’s past or current membership on one or more audit committees of companies that, at the time the person held such membership, were required to file reports pursuant to provisions of securities laws;

·The person’s level of familiarity and experience with the use and analysis of financial statements of public companies; and

·Whether the person has any other relevant qualifications or experience that would assist him or her in understanding and evaluating the corporation’s financial statements and other financial information and to make knowledgeable and thorough inquiries whether:

·The financial statements fairly present the financial condition, results of operations and cash flows of the corporation in accordance with generally accepted accounting principles; and

·The financial statements and other financial information, taken together, fairly present the financial condition, results of operations and cash flows of the corporation.

Audit Committee Financial Expert

An “Audit Committee Financial Expert” means a person who, in the judgment of the corporation’s board of directors, has the following attributes:

a.an understanding of Canadian generally accepted accounting principles and financial statements;

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b.the ability to assess the general application of such principles in connection with the accounting for estimates, accruals, and reserves;

c.experience preparing, auditing or analyzing or evaluating financial statements that present a breadth and level of complexity of accounting issues that are generally comparable to the breadth and complexity of issues that can reasonably be expected to be raised by Suncor’s financial statements, or experience actively supervising one or more persons engaged in such activities;

d.an understanding of internal controls and procedures for financial reporting; and

e.an understanding of audit committee functions.

A person shall have acquired the attributes referred to in items (a) through (e) inclusive above through:

a.education and experience as a principal financial officer, principal accounting officer, controller, public accountant or auditor or experience in one or more positions that involve the performance of similar functions;

b.experience actively supervising a principal financial officer, principal accounting officer, controller, public accountant, auditor or person performing similar functions;

c.experience overseeing or assessing the performance of companies or public accountants with respect to the preparation, auditing or evaluation of financial statements; or

d.other relevant experience.

Audit Committee Pre-Approval Policies for Non Audit Services

Our Audit Committee has considered whether the provision of services other than audit services is compatible with maintaining the auditors’ independence and has a policy governing the provision of these services. A copy of our policy relating to Audit Committee approval of fees paid to our auditors, in compliance with the Sarbanes Oxley Act of 2002, is attached as Schedule “A” to this AIF.

Fees Paid to Auditors

Fees payable to PricewaterhouseCoopers LLP in 2008 and 2007 are detailed below:

($)	2008	2007
Audit Fees	1,600,000	1,158,000
Audit-Related Fees	442,000	431,000
Tax Fees	7,000	2,000
All other Fees	13,000	-
Total	2,062,000	1,591,000

Prior year numbers have been restated to conform with current year presentation.

The nature of each category of fees is described below.

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Audit Fees

Audit fees were paid for professional services rendered by the auditors for the audit of Suncor’s annual financial statements or services provided in connection with statutory and regulatory filings or engagements.

Audit-Related Fees

Audit-related fees were paid for professional services rendered by the auditors for preparation of reports on specified procedures as they relate to joint venture audits and attest services not required by statute or regulation.

Tax Fees

Tax fees were paid for international tax planning, advice and compliance.

All Other Fees

Fees disclosed under “All Other Fees” were paid for subscriptions to auditor-provided and supported tools.

None of the services described under the captions “Audit-related Fees”, “Tax Fees” and “All Other Fees” were approved by the Audit Committee pursuant to paragraph (c)(7)(i)(C) of Rule 2-01 of Regulation S-X.

LEGAL PROCEEDINGS AND REGULATORY ACTIONS

There are no legal proceedings to which we are a party or of which any of our property is the subject, nor are there any proceedings known by us to be contemplated that involves a claim for damages exceeding 10% of our current assets.   In addition, there have not been any (a) penalties or sanctions imposed against the company by a court relating to securities legislation or by a securities regulatory authority during your financial year, (b) penalties or sanctions imposed by a court or regulatory body against the company that would likely be considered important to a reasonable investor in making an investment decision, or (c) settlement agreements entered into by the company before a court relating to securities legislation or with a securities regulatory authority during your financial year.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director, executive officer, or holder of 10% or more of our securities or any associate or affiliate of these persons has, or has had, any material interest in any transaction or any proposed transaction that has materially affected or will materially affect us or any of our affiliates, within the three most recently completed financial years or during the current financial year.

TRANSFER AGENT AND REGISTRAR

The transfer agent and registrar for our common shares is Computershare Trust Company of Canada at its principal offices in Calgary, Montreal, Toronto and Vancouver and Computershare Trust Company Inc. in Denver, Colorado.

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MATERIAL CONTRACTS

During the year ended December 31, 2008, 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, the Shareholder Rights Plan dated April 24, 2008 and the Royalty Amending Agreement dated January 29, 2008 between Suncor and Her Majesty the Queen in Right of Alberta.

INTERESTS OF EXPERTS

There is no person or company whose profession or business gives authority to a statement made by such person or company and who is named as having prepared or certified a report, valuation, statement or opinion described or included in a filing, or referred to in a filing, made under National Instrument 51-102 by Suncor during, or related to our most recently completed financial year other than GLJ, Suncor’s Independent Reserve Engineering Evaluators and PricewaterhouseCoopers LLP, Suncor’s auditors. As at the date hereof, none of the principals of GLJ as a group, directly or indirectly, owned more than 1% of our common shares, including the securities of our associates and affiliates, and PricewaterhouseCoopers LLP has advised Suncor’s Audit Committee that they are independent with respect to Suncor within the meaning of the Rules of Professional Conduct of the Institute of Chartered Accountants of Alberta.

DISCLOSURE PURSUANT TO THE REQUIREMENTS OF THE NEW YORK STOCK EXCHANGE

As a Canadian issuer listed on the New York Stock Exchange (the “NYSE”), we are not required to comply with most of the NYSE rules and listing standards and instead may comply with domestic requirements. As a foreign private issuer, we are only required to comply with three of the NYSE rules (i) have an audit committee that satisfies the requirements of the United States Securities Exchange Act of 1934; (ii) the Chief Executive Officer must promptly notify the NYSE in writing after an executive officer becomes aware of any material non-compliance with the applicable NYSE Rules; and (iii) provide a brief description of any significant differences between our corporate governance practices and those followed by U.S. companies listed under the NYSE. The company has disclosed in the corporate governance section of its website at www.suncor.com that it, in certain instances, it is not required to obtain shareholder approval for material amendments to equity compensation plans and that Suncor, while in compliance with the independence requirements of applicable securities laws in Canada (specifically National Instrument 52-110 Audit Committees) and the U.S. (specifically Rule 10A-3 of the Securities Exchange Act of 1934), it has not adopted the director independence standards contained in Section 303A.02 of the NYSE’s Listed Company Manual. Except as described, the company is in compliance with the NYSE corporate governance standards in all other significant respects.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of our securities, securities authorized for issuance under equity compensation plans and interests of insiders in material transactions, where applicable, is contained in our most recent management proxy circular for our most recent annual meeting of our shareholders that involved the election of directors.  Additional financial information is provided in our 2008 Consolidated Financial Statements and MD&A.

Further information about Suncor, filed with Canadian securities commissions and the United States Securities and Exchange Commission (SEC), including periodic quarterly and annual

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reports and the Annual Information Form (AIF/40-F) is available online at www.sedar.com and www.sec.gov.  In addition, our Standards of Business Conduct Code is available online at www.suncor.com.  Information contained in or otherwise accessible through our website does not form part of this AIF, and is not incorporated into the AIF by reference.

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SCHEDULE “A”

***Approved and Accepted April 28, 2004***

SUNCOR ENERGY INC.
POLICY AND PROCEDURES FOR PRE-APPROVAL OF AUDIT
AND NON-AUDIT SERVICES

Pursuant to the Sarbanes-Oxley Act of 2002 and Multilateral Instrument 52-110, the Securities and Exchange Commission and the Ontario Securities Commission respectively has adopted final rules relating to audit committees and auditor independence.  These rules require the Audit Committee of Suncor Energy Inc (“Suncor”) to be responsible for the appointment, compensation, retention and oversight of the work of its independent auditor.  The Audit Committee must also pre-approve any audit and non-audit services performed by the independent auditor or such services must be entered into pursuant to pre-approval policies and procedures established by the Audit Committee pursuant to this policy.

I.STATEMENT OF POLICY

The Audit Committee has adopted this Policy and Procedures for Pre-Approval of Audit and Non-Audit Services (the “Policy”), which sets forth the procedures and the conditions pursuant to which services proposed to be performed by the independent auditor will be pre-approved.  The procedures outlined in this Policy are applicable to all Audit, Audit-Related, Tax Services and All Other Services provided by the independent auditor.

II.RESPONSIBILITY

Responsibility for the implementation of this Policy rests with the Audit Committee.  The Audit Committee delegates its responsibility for administration of this policy to management.  The Audit Committee shall not delegate its responsibilities to pre-approve services performed by the independent auditor to management.

III.DEFINITIONS

For the purpose of these policies and procedures and any pre-approvals:

a)“Audit services” include services that are a necessary part of the annual audit process and any activity that is a necessary procedure used by the auditor in reaching an opinion on the financial statements as is required under generally accepted auditing standards (“GAAS”), including technical reviews to reach audit judgment on accounting standards;

The term “audit services” is broader than those services strictly required to perform an audit pursuant to GAAS and include such services as:

i)the issuance of comfort letters and consents in connections with offerings of securities;

ii)the performance of domestic and foreign statutory audits;

iii)Attest services required by statute or regulation;

iv)Internal control reviews; and

v)Assistance with and review of documents filed with the Canadian Securities administrators, the Securities and Exchange Commission and other regulators having jurisdiction over Suncor and its subsidiaries, and responding to comments from such regulators;

b)“Audit-related services” are assurance (e.g. due diligence services) and related services traditionally performed by the external auditors and that are reasonably related to the performance of the audit or review of financial statements and not categorized under “audit fees” for disclosure purposes.

“Audit-related services” include:

i)employee benefit plan audits, including audits of employee pension plans;

ii)due diligence related to mergers and acquisitions;

iii)consultations and audits in connection with acquisitions, including evaluating the accounting treatment for proposed transactions;

iv)internal control reviews;

v)attest services not required by statute or regulation; and

vi)consultations regarding financial accounting and reporting standards;

Non-financial operational audits are not “audit-related” services;

c)“Tax services” include but are not limited to services related to the preparation of corporate and/or personal tax filings, tax due diligence as it pertains to mergers, acquisitions and/or divestitures and tax planning;

d)“All other services” consist of any other work that is neither an Audit service, nor an Audit-Related service nor a Tax service, the provision of which by the independent auditor is not expressly prohibited by Rule 2-01(c)(7) of Regulation S-X under the Securities and Exchange Act of 1934, as amended. (See Appendix A for a summary of the prohibited services.)

IV.GENERAL POLICY

The following general policy applies to all services provided by the independent auditor:

·All services to be provided by the independent auditor will require specific pre-approval by the Audit Committee.  The Audit Committee will not approve engaging the independent auditor for services which can reasonably be classified as “tax services” or “all other services” unless a compelling business case can be

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made for retaining the independent auditor instead of another service provider.

·The Audit Committee will not provide pre-approval for services to be provided in excess of twelve months from the date of the pre-approval, unless the Audit Committee specifically provides for a different period.

·The Audit Committee has delegated authority to pre-approve services with an estimated cost not exceeding $100,000 in accordance with this Policy to the Chairman of the Audit Committee. The delegate member of the Audit Committee must report any pre-approval decision to the Audit Committee at its next meeting.

·The Chairman of the Audit Committee may delegate his authority to pre-approve services to another sitting member of the Audit Committee provided that the recipient has also been delegated the authority to act as Chairman of the Audit Committee in the Chairman’s absence.  A resolution of the Audit Committee is required to evidence the Chairman’s delegation of authority to another Audit Committee member under this policy.

·The Audit Committee will, from time to time, but no less than annually, review and pre-approve the services that may be provided by the independent auditor.

·The Audit Committee must establish pre-approval fee levels for services provided by the independent auditor on an annual basis.  On at least a quarterly basis, the Audit Committee will be provided with a detailed summary of fees paid to the independent auditor and the nature of the services provided and a forecast of fees and services that are expected to be provided during the remainder of the fiscal year.

·The Audit Committee will not approve engaging the independent auditor to provide any prohibited non-audit services as set forth in Appendix A.

·The Audit Committee shall evidence their pre-approval for services to be provided by the independent auditor as follows:

a)In situations where the Chairman of the Audit Committee pre-approves work under his delegation of authority, the Chairman will evidence his pre-approval by signing and dating the pre-approval request form, attached as Appendix B.  If it is not practicable for the Chairman to complete the form and transmit it to the Company prior to engagement of the independent audit, the Chairman may provide verbal or email approval of the engagement, followed up by completion of the request form at the first practical opportunity.

b)In all other situations, a resolution of the Audit Committee is required.

·All audit and non-audit services to be provided by the independent auditors shall be provided pursuant to an engagement letter that shall:

a)be in writing and signed by the auditors

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b)specify the particular services to be provided

c)specify the period in which the services will be performed

d)specify the estimated total fees to be paid, which shall not exceed the estimated total fees approved by the Audit Committee pursuant to these procedures, prior to application of the 10% overrun.

e)include a confirmation by the auditors that the services are not within a category of services the provision of which would impair their independence under applicable law and Canadian and U.S. generally accepted accounting standards.

·The Audit Committee pre-approval permits an overrun of fees pertaining to a particular engagement of no greater than 10% of the estimate identified in the associated engagement letter.  The intent of the overrun authorization is to ensure on an interim basis only, that services can continue pending a review of the fee estimate and if required, further Audit Committee approval of the overrun.  If an overrun is expected to exceed the 10% threshold, as soon as the overrun is identified, the Audit Committee or its designate must be notified and an additional pre-approval obtained prior to the engagement continuing.

V.RESPONSIBILITIES OF EXTERNAL AUDITORS

To support the independence process, the independent auditors will:

a)Confirm in each engagement letter that performance of the work will not impair independence;

b)Satisfy the Audit Committee that they have in place comprehensive internal policies and processes to ensure adherence, world-wide, to independence requirements, including robust monitoring and communications;

c)Provide communication and confirmation to the Audit Committee regarding independence on at least a quarterly basis;

d)Maintain registration by the Canadian Public Accountability Board and the U.S. Public Company Accounting Oversight Board;

e)Review their partner rotation plan and advise the Audit Committee on an annual basis.

In addition, the external auditors will:

a)Provide regular, detailed fee reporting including balances in the “Work in Progress” account;

b)Monitor fees and notify the Audit Committee as soon as a potential overrun is identified.

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VI.DISCLOSURES

Suncor will, as required by applicable law, annually disclose its pre-approval policies and procedures, and will provide the required disclosure concerning the amounts of audit fees, audit-related fees, tax fees and all other fees paid to its outside auditors in its filings with the SEC.

*     *     *

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Appendix A

Prohibited Non-Audit Services

An external auditor is not independent if, at any point during the audit and professional engagement period, the auditor provides the following non-audit services to an audit client.

Bookkeeping or other services related to the accounting records or financial statements of the audit client.  Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor’s financial statements, including:

·Maintaining or preparing the audit client’s accounting records;

·Preparing Suncor’s financial statements that are filed with the Securities and Exchange Commission (“SEC”) or that form the basis of financial statements filed with the SEC; or

·Preparing or originating source data underlying Suncor’s financial statements.

Financial information systems design and implementation.  Any service, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor’s financial statements, including:

·Directly or indirectly operating, or supervising the operation of, Suncor’s information system or managing Suncor’s local area network; or

·Designing or implementing a hardware or software system that aggregates source data underlying the financial statements or generates information that is significant to Suncor’s financial statements or other financial information systems taken as a whole.

Appraisal or valuation services, fairness opinions or contribution-in-kind reports.  Any appraisal service, valuation service or any service involving a fairness opinion or contribution-in-kind report for Suncor, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor’s financial statements.

Actuarial services.  Any actuarially-oriented advisory service involving the determination of amounts recorded in the financial statements and related accounts for Suncor other than assisting Suncor in understanding the methods, models, assumptions, and inputs used in computing an amount, unless it is reasonable to conclude that the results of these services will not be subject to audit procedures during an audit of Suncor’s financial statements.

Internal audit outsourcing services.  Any internal audit service that has been outsourced by Suncor that relates to Suncor’s internal accounting controls, financial systems, or financial statements, unless it is reasonable to conclude that the result of these services will not be subject to audit procedures during an audit of Suncor’s financial statements.

Management functions.  Acting, temporarily or permanently, as a director, officer, or employee of Suncor, or performing any decision-making, supervisory, or ongoing monitoring function for Suncor.

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Human resources.

·Searching for or seeking out prospective candidates for managerial, executive, or director positions;

·Engaging in psychological testing, or other formal testing or evaluation programs;

·Undertaking reference checks of prospective candidates for an executive or director position;

·Acting as a negotiator on Suncor’s behalf, such as determining position, status or title, compensation, fringe benefits, or other conditions of employment; or

·Recommending, or advising Suncor to hire a specific candidate for a specific job (except that an accounting firm may, upon request by Suncor, interview candidates and advise Suncor on the candidate’s competence for financial accounting, administrative, or control positions.)

Broker-dealer, investment adviser or investment banking services.  Acting as a broker-dealer (registered or unregistered), promoter, or underwriter, on behalf of Suncor, making investment decisions on behalf of Suncor or otherwise having discretionary authority over Suncor’s investments, executing a transaction to buy or sell Suncor’s investment, or having custody of Suncor’s assets, such as taking temporary possession of securities purchased by Suncor.

Legal services.  Providing any service to Suncor that, under circumstances in which the service is provided, could be provided only by someone licensed, admitted, or otherwise qualified to practice law in the jurisdiction in which the service is prohibited.

Expert services unrelated to the audit.  Providing an expert opinion or other expert service for Suncor, or Suncor’s legal representative, for the purpose of advocating Suncor’s interest in litigation or in a regulatory or administrative proceeding or investigation.  In any litigation or regulatory or administrative proceeding or investigation, an accountant’s independence shall not be deemed to be impaired if the accountant provides factual accounts, including testimony, of work performed or explains the positions taken or conclusions reached during the performance of any service provided by the accountant for Suncor.

A-7

Appendix B

Pre-approval Request Form

NATURE OF WORK	ESTIMATED FEES (Cdn $)
Total

Date Signature

A-8

SCHEDULE “B”

AUDIT COMMITTEE CHARTER

The Audit Committee

The by-laws of Suncor Energy Inc. provide that the Board of Directors may establish Board committees to whom certain duties may be delegated by the Board.  The Board has established, among others, the Audit Committee, and has approved this mandate, which sets out the objectives, functions and responsibilities of the Audit Committee.

Objectives

The Audit Committee assists the Board of Directors by:

·monitoring the effectiveness and integrity of the Corporation’s financial reporting systems, management information systems and internal control systems, and by monitoring financial reports and other financial matters.

·selecting, monitoring and reviewing the independence and effectiveness of, and where appropriate replacing, subject to shareholder approval as required by law, external auditors, and ensuring that external auditors are ultimately accountable to the Board of Directors and to the shareholders of the Corporation.

·reviewing  the effectiveness of the internal auditors, excluding the Operations Integrity Audit department which is specifically within the mandate of the Environment, Health & Safety Committee (references throughout this mandate to “Internal Audit” shall not include the Operations Integrity Audit department); and

·approving on behalf of the Board of Directors certain financial matters as delegated by the Board, include the matters outlined in this mandate.

The Committee does not have decision-making authority, except in the very limited circumstances described herein or where and to the extent that such authority is expressly delegated by the Board of Directors.  The Committee conveys its findings and recommendations to the Board of Directors for consideration and, where required, decision by the Board of Directors.

Constitution

The Terms of Reference of Suncor’s Board of Directors set out requirements for the composition of Board Committees and the qualifications for Committee membership, and specify that the chair and membership of the Committees are determined annually by the Board.  As required by Suncor’s by-laws, unless otherwise determined by resolution of the board of directors, a majority of the members of a committee constitute a quorum for meetings of committees, and in all other respects, each committee determines its own rules of procedure.

Functions and Responsibilities

The Committee has the following functions and responsibilities:

Internal Controls

1.Enquire as to the adequacy of the Corporation’s system of internal controls, and review the evaluation of internal controls by Internal Auditors, and the evaluation of financial and internal controls by external auditors.

2.Review management’s monitoring of compliance with the Corporation’s Code of Business Conduct.

3.Establish procedures for the confidential submission by employees of complaints relating to any concerns with accounting, internal control, auditing or Standards of Business Conduct Code matters, and periodically review a summary of complaints and their related resolution.

4.Review the findings of any significant examination by regulatory agencies concerning the Corporation’s financial matters.

5.Periodically review management’s governance processes for information technology resources, to assess their effectiveness in addressing the integrity, the protection and the security of the Corporation’s electronic information systems and records.

6.Review the management practices in effect over officers’ expenses and perquisites.

External and Internal Auditors

7.Evaluate the performance of the external auditors and initiate and approve the engagement or termination of the external auditors, subject to shareholder approval as required by applicable law.

8.Review the audit scope and approach of the external auditors, and approve their terms of engagement and fees.

9.Review any relationships or services that may impact the objectivity and independence of the external auditor, including annual review of the auditor’s written statement of all relationships between the auditor (including its affiliates) and the Corporation; review and approve all engagements for non-audit services to be provided by external auditors or their affiliates.

10.Review the external auditor’s quality control procedures including any material issues raised by the most recent quality control review or peer review and any issues raised by a government authority or professional authority investigation of the external auditor, providing details on actions taken by the firm to address such issues.

11.Review and approve the appointment or termination of the Director, Internal Audit, and annually review a summary of the remuneration and performance of the Director, Internal Audit.

12.Review the Internal Audit Department Charter, and the plans, activities, organisational structure and qualifications of the Internal Auditors, and monitor the department’s performance and independence.

13.Provide an open avenue of communication between management, the Internal Auditors or the external auditors, and the Board of Directors.

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Financial Reporting and other Public Disclosure

14.Review external auditor’s management comment letter and management’s responses thereto, and enquire as to any disagreements between management and external auditors or restrictions imposed by management on external auditors. Review any unadjusted differences brought to the attention of management by the external auditor and the resolution of same.

15.Review with management and external auditors the financial materials and other disclosure documents referred to in paragraph 16, including any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgements of management that may be material to financial reporting including alternative treatments and their impacts.

16.Review and approve the Corporation’s interim consolidated financial statements and accompanying management’s discussion and analysis (“MD&A”).  Review and make recommendations to the Board of Directors on approval of the Corporation’s annual audited financial statements and MD&A, Annual Information Form and Form 40-F.  Review other material annual and quarterly disclosure documents or regulatory filings containing or accompanying audited or unaudited financial information.

17.Review and approve the Corporation’s policy on external communication and disclosure of material information, including the form and generic content of any quarterly earnings guidance and of any financial disclosure provided to investment analysts and rating agencies.

18.Review any change in the Corporation’s accounting policies.

19.Review with legal counsel any legal matters having a significant impact on the financial reports.

Oil and Gas Reserves

20.Review with reasonable frequency Suncor’s procedures for:

(A)the disclosure in accordance with applicable law of  information with respect to Suncor’s oil and gas activities including procedures for complying with applicable disclosure requirements;

(B)providing information to the qualified reserves evaluators (“Evaluators”) engaged annually by Suncor to evaluate Suncor’s reserves data for the purpose of public disclosure of such data in accordance with applicable law.

21.Annually approve the appointment and terms of engagement of the company’s Evaluator, including the qualifications and independence of the Evaluator; Review and approve any proposed change in the appointment of the Evaluator, and the reasons for such proposed change including whether there have been disputes between the Evaluator and the Company’s management.

22.Annually review Suncor’s reserves data and the report of the Evaluator thereon; Annually review and make recommendations to the Board of Directors on the approval of (i) the content and filing by the Company of a statement of reserves data

B-3

(“Statement”) and report of management and the directors thereon to be included in or filed with the Statement, and (ii) the filing of the report of the Evaluator to be included in or filed with the Statement, all in accordance with applicable law.

Risk Management

23.Periodically review the policies and practices of the Corporation respecting cash management, financial derivatives, financing, credit, insurance, taxation, commodities trading and related matters.  Oversee the Board’s risk management governance model by conducting periodic reviews with the objective of appropriately reflecting the principal risks of the Corporation’s business in the mandate of the Board and its committees.

Pension Plan

24.Review the assets, financial performance, funding status, investment strategy and actuarial reports of the Corporation’s pension plan including the terms of engagement of the plan’s actuary and fund manager.

Security

25.Review on a summary basis any significant physical security management, IT security or business recovery risks and strategies to address such risks.

Other Matters

26.Conduct any independent investigations into any matters which come under its scope of responsibilities.

27.Review any recommended appointees to the office of Chief Financial Officer. Review and/or approve other financial matters delegated specifically to it by the Board of Directors.

Reporting to the Board

28.Report to the Board of Directors on the activities of the Committee with respect to the foregoing matters as required at each Board meeting and at any other time deemed appropriate by the Committee or upon request of the Board of Directors.

As adopted by resolution of the Board of Directors.

Revision Dated February 25, 2009

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SCHEDULE “C”

FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS

ON OIL AND GAS DISCLOSURE

Management of Suncor Energy Inc. (the “Company”) are responsible for the preparation and disclosure of information with respect to the Company’s oil and gas activities in accordance with securities regulatory requirements. This information includes reserves data which are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

An independent qualified reserves evaluator has evaluated the Company’s reserves data. The report of the independent qualified reserves evaluator is presented below.

The Audit Committee of the board of directors of the Company has:

(a)reviewed the Company’s procedures for providing information to the independent qualified reserves evaluator;

(b)met with the independent qualified reserves evaluator to determine whether any restrictions affected the ability of the independent qualified reserves evaluator to report without reservation; and

(c)reviewed the reserves data with management and the independent qualified reserves evaluator.

The Audit Committee of the board of directors has reviewed the Company’s procedures for assembling and reporting other information associated with oil and gas activities and has reviewed that information with management. The board of directors has, on the recommendation of the Audit Committee, approved:

(a)the content and filing with securities regulatory authorities of Form 51-101F1 containing reserves data and other oil and gas information;

(b)the filing of Form 51-101F2 which is the report of the independent qualified reserves Evaluator on the reserves data; and

(c)the content and filing of this report.

Because the reserves data are based on judgements regarding future events, actual results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

“RICHARD L. GEORGE”

RICHARD L. GEORGE

President and Chief Executive Officer

“J. KENNETH ALLEY”

J. KENNETH ALLEY

Senior Vice President and Chief Financial Officer

“JOHN T. FERGUSON”

JOHN T. FERGUSON

Chairman of the Board of Directors

“BRIAN A. CANFIELD”

BRIAN A. CANFIELD

Chairman of the Audit Committee

March 2, 2009

C-2

SCHEDULE “D”

FORM 51-101F2
REPORT ON RESERVES DATA
BY
INDEPENDENT QUALIFIED RESERVES
EVALUATOR

Report on Reserves Data

To the board of directors of Suncor Energy Inc. (the “Company”):

1. We have prepared an evaluation of the Company’s reserves data as at December 31, 2008. The reserves data are estimates of proved reserves and probable reserves and related future net revenue as at December 31, 2008, estimated using forecast prices and costs.

2. The reserves data are the responsibility of the Company’s management. Our responsibility is to express an opinion on the reserves data based on our evaluation.

We carried out our evaluation in accordance with standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) prepared jointly by the Society of Petroleum Evaluation Engineers (Calgary Chapter) and the Canadian Institute of Mining, Metallurgy & Petroleum (Petroleum Society).

3. Those standards require that we plan and perform an evaluation to obtain reasonable assurance as to whether the reserves data are free of material misstatement. An evaluation also includes assessing whether the reserves data are in accordance with principles and definitions presented in the COGE Handbook.

4. The following table sets forth the estimated future net revenue (before deduction of income taxes) attributed to proved plus probable reserves, estimated using forecast prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated by us for the year ended December 31, 2008, and identifies the respective portions thereof that we have evaluated and reported on to the Company’s management and Board of Directors:

Independent Qualified Reserves Evaluator	Description and Preparation Date of Evaluation Report	Location of Reserves (Country or Foreign Geographic Area)	Net Present Value of Future Net Revenue (before income taxes, 10% discount rate, million dollars)
			Audited	Evaluated	Reviewed	Total
GLJ Petroleum Consultants	February 6, 2009	Canada	-	53,484	101	53,585

5. In our opinion, the reserves data respectively evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook.

6. We have no responsibility to update our reports referred to in paragraph 4 for events  and circumstances occurring after their respective preparation dates.

7. Because the reserves data are based on judgments regarding future events, actual  results will vary and the variations may be material. However, any variations should be consistent with the fact that reserves are categorized according to the probability of their recovery.

Executed as to our report referred to above:

GLJ Petroleum Consultants Ltd., Calgary, Alberta, Canada,

ORIGINALLY SIGNED BY

James H. Willmon, P. Eng.

Vice-President

Calgary, Alberta, Canada

February 6, 2009

D-2

UNDERTAKING AND CONSENT TO SERVICE OF PROCESS

A.    Undertaking

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

B.    Consent to Service of Process

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

DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER
FINANCIAL REPORTING

        See pages 43 and 44 of Exhibit 99-1 and page 26 of Exhibit 99-2.

AUDIT COMMITTEE FINANCIAL EXPERT

        See pages 69 and 70 of Annual Information Form.

CODE OF ETHICS

        See page 72 of Annual Information Form.

FEES PAID TO PRINCIPAL ACCOUNTANT

        See page 70 of Annual Information Form.

AUDIT COMMITTEE PRE-APPROVAL POLICIES

        See Schedule "A" of Annual Information Form.

APPROVAL OF NON-AUDIT SERVICES

        See Schedule "A" of Annual Information Form.

OFF-BALANCE SHEET ARRANGEMENTS

        See page 77 of Exhibit 99-2.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

        See page 13 of Exhibit 99-2.

IDENTIFICATION OF THE AUDIT COMMITTEE

        See page 68 of Annual Information Form.

SIGNATURES

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

		SUNCOR ENERGY INC.
DATE:	March 2, 2009	PER:	/s/ "J. Kenneth Alley" J. KENNETH ALLEY Senior Vice President and Chief Financial Officer

EXHIBIT INDEX

Exhibit No.	Description
99-1	Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2008, including reconciliation to U.S. GAAP (Note 20)
99-2	Management's Discussion and Analysis for the fiscal year ended December 31, 2008, dated February 25, 2009
99-3	Consent of PricewaterhouseCoopers LLP
99-4	Consent of GLJ Petroleum Consultants Ltd.
99-5	Certificate of President and Chief Executive Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
99-6	Certificate of Senior Vice President and Chief Financial Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
99-7	Certificate of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
99-8	Certificate of the Senior Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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UNDERTAKING AND CONSENT TO SERVICE OF PROCESS
DISCLOSURE CONTROLS AND PROCEDURES AND INTERNAL CONTROL OVER FINANCIAL REPORTING
AUDIT COMMITTEE FINANCIAL EXPERT
CODE OF ETHICS
FEES PAID TO PRINCIPAL ACCOUNTANT
AUDIT COMMITTEE PRE-APPROVAL POLICIES
APPROVAL OF NON-AUDIT SERVICES
OFF-BALANCE SHEET ARRANGEMENTS
TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS
IDENTIFICATION OF THE AUDIT COMMITTEE
SIGNATURES
EXHIBIT INDEX

EX-99.1

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EXHIBIT 99-1

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SUNCOR ENERGY INC.
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008,
INCLUDING RECONCILIATION TO U.S. GAAP (NOTE 20)

MANAGEMENT'S STATEMENT
OF RESPONSIBILITY FOR FINANCIAL REPORTING

The management of Suncor Energy Inc. is responsible for the presentation and preparation of the accompanying consolidated financial statements of Suncor Energy Inc. on pages 47 to 86 and all related financial information contained in this Annual Report, including Management's Discussion and Analysis.

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. They include certain amounts that are based on estimates and judgments relating to matters not concluded by year-end. Financial information presented elsewhere in this Annual Report is consistent with that contained in the consolidated financial statements.

In management's opinion, the consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies adopted by management as summarized on pages 47 to 51. If alternate accounting methods exist, management has chosen those policies it deems the most appropriate in the circumstances. In discharging its responsibilities for the integrity and reliability of the financial statements, management maintains and relies upon a system of internal controls designed to ensure that transactions are properly authorized and recorded, assets are safeguarded against unauthorized use or disposition and liabilities are recognized. These controls include quality standards in hiring and training of employees, formalized policies and procedures, a corporate code of conduct and associated compliance program designed to establish and monitor conflicts of interest, the integrity of accounting records and financial information among others, and employee and management accountability for performance within appropriate and well-defined areas of responsibility.

The system of internal controls is further supported by the professional staff of an internal audit function who conduct periodic audits of the company's financial reporting.

The company retains independent petroleum consultants, GLJ Petroleum Consultants Ltd., to conduct independent evaluations of the company's oil and gas reserves and resources.

The Audit Committee of the Board of Directors, currently composed of five independent directors, reviews the effectiveness of the company's financial reporting systems, management information systems, internal control systems and internal auditors. It recommends to the Board of Directors the external auditors to be appointed by the shareholders at each annual meeting and reviews the independence and effectiveness of their work. In addition, it reviews with management and the external auditors any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material for financial reporting purposes. The Audit Committee appoints the independent petroleum consultants. The Audit Committee meets at least quarterly to review and approve interim financial statements prior to their release, as well as annually to review Suncor's annual financial statements and Management's Discussion and Analysis, Annual Information Form/Form 40-F, and annual reserves and resource estimates, and recommend their approval to the Board of Directors. The internal auditors and PricewaterhouseCoopers LLP have unrestricted access to the company, the Audit Committee and the Board of Directors.

Richard L. George	J. Kenneth Alley
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

February 25, 2009

SUNCOR ENERGY INC. 2008ANNUAL REPORT 43

The following report is provided by management in respect of the Company's internal control over financial reporting (as defined in Rule13a-15(f) under the U.S. Securities Exchange Act of 1934):

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

1.

Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting.

2.

Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework in Internal Control – Integrated Framework to evaluate the effectiveness of the Company's internal control over financial reporting.

3.

Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2008, and has concluded that such internal control over financial reporting was effective as of that date. Additionally, based on this assessment, management determined that there were no material weaknesses in internal control over financial reporting as of December 31, 2008. Because of inherent limitations, systems of internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

4.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

Richard L. George	J. Kenneth Alley
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

February 25, 2009

44 SUNCOR ENERGY INC. 2008ANNUAL REPORT

INDEPENDENT AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have completed integrated audits of Suncor Energy Inc.'s 2008, 2007 and 2006 consolidated financial statements and of its internal control over financial reporting as at December 31, 2008. Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated balance sheets of Suncor Energy Inc. ("the company") as at December 31, 2008 and December 31, 2007, and the related consolidated statements of earnings and comprehensive income, of cash flows and of changes in shareholders' equity for each of the years in the three year period ended December 31, 2008. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the company's financial statements as at December 31, 2008 and 2007 and for each of the years in the three year period ended December 31, 2008 in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the company as at December 31, 2008 and December 31, 2007 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.

Internal control over financial reporting

We have also audited the company's internal control over financial reporting as at December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 45

In our opinion, the company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2008 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 25, 2009

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA – U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company's consolidated financial statements, such as the changes described in Summary of Significant Accounting Policies and in Note 1 to the consolidated financial statements. Our report to the shareholders dated February 25, 2009 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in the Auditors' Report when the change is properly accounted for and adequately disclosed in the consolidated financial statements.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 25, 2009

46 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SUNCOR ENERGY INC.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Suncor Energy Inc. is a Canadian integrated energy company comprised of three operating segments: oil sands, natural gas, and refining and marketing.

Oil sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands in the Athabasca region of northeastern Alberta, and the marketing of these products substantially in Canada and the United States.

Natural gas includes the exploration, acquisition, development, production, transportation and marketing of natural gas, natural gas liquids and crude oil in Canada and the United States.

Refining and marketing includes the manufacturing, transportation and marketing of petroleum, petrochemical and biofuel products from our Canadian and United States operations. Canadian activities are conducted primarily in Ontario and Quebec, while activities in the United States are primarily in Colorado.

In addition to the operating segments outlined above, we also report a corporate segment which includes the activities not directly attributable to an operating segment, as well as those of our self-insurance entity.

The significant accounting policies of the company are summarized below:

(a) Principles of Consolidation and the Preparation of Financial Statements

These consolidated financial statements are prepared and reported in Canadian dollars in accordance with generally accepted accounting principles (GAAP) in Canada, which differ in some respects from GAAP in the United States. These differences are quantified and explained in note 20.

The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company's proportionate share of the assets, liabilities, equity, revenues, expenses and cash flows of its joint ventures. Subsidiaries are defined as entities in which the company holds a controlling interest, is the general partner or where it is subject to the majority of expected losses or gains.

The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Certain prior period comparative figures have been reclassified to conform to the current period presentation.

(b) Cash Equivalents and Investments

Cash equivalents consist primarily of term deposits, certificates of deposit and all other highly liquid investments with a maturity at the time of purchase of three months or less. Investments with maturities greater than three months and up to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments.

(c) Revenues

Crude oil sales from upstream operations (oil sands and natural gas) to downstream operations (refining and marketing) are based on actual product shipments. On consolidation, revenues and purchases related to these sales transactions are eliminated from operating revenues and purchases of crude oil and products.

The company also uses its natural gas production to offset purchases for internal consumption at its oil sands plant and Sarnia refinery. On consolidation, revenues from these sales are eliminated from operating revenues, crude oil and products purchases, and operating, selling and general expenses.

Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer and delivery has taken place. Revenues from oil and natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company's net working interest.

(d) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 47

Expenditures to acquire and develop oil sands mining properties are capitalized. Development costs to expand the capacity of existing mines or to develop mine areas substantially in advance of current production are also capitalized. Drilling and related seismic costs for regulatory approved mining areas are capitalized when planned future development timelines do not exceed 10 years. All other mining exploration costs are expensed as incurred.

The company follows the successful efforts method of accounting for its conventional natural gas and in-situ oil sands operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are initially capitalized. If it is determined that a specific well does not contain proved reserves, the related capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. Related land costs are expensed through the amortization of unproved properties as covered under the natural gas section of the depreciation, depletion and amortization policy below.

Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs.

Costs incurred after the inception of operations are expensed.

Interest Capitalization

Interest costs relating to major capital projects in progress and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of property, plant and equipment. Capitalization of interest ceases when the capital asset is substantially complete and ready for its intended productive use.

Leases

Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as capital leases and classified as property, plant and equipment with offsetting long-term debt. All other leases are classified as operating leases under which leasing costs are expensed in the period incurred.

Depreciation, Depletion and Amortization

OIL SANDS Property, plant and equipment are depreciated over their useful lives on a straight-line basis, commencing when the assets are placed into service. Mine and mobile equipment is depreciated over periods ranging from three to 20 years and plant and other property and equipment, including leases in service, primarily over four to 40 years. Capitalized costs related to the in-progress phase of projects are not depreciated until the facilities are substantially complete and ready for their intended productive use.

NATURAL GAS Acquisition costs of unproved properties that are individually significant are evaluated for impairment by management. Impairment of unproved properties that are not individually significant is provided for through amortization over the average projected holding period for that portion of acquisition costs not expected to become producing. The average projected holding period of five years is based on historical experience.

Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight-line basis over their useful lives, which average 12 years.

REFINING AND MARKETING Depreciation of property, plant and equipment is provided on a straight-line basis over the useful lives of assets. The Sarnia and Commerce City refineries and additions thereto are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and pipeline facilities and other equipment over three to 40 years.

Asset Retirement Obligations

A liability is recognized for future retirement obligations associated with the company's property, plant and equipment. The fair value of the Asset Retirement Obligation (ARO) is recorded on a discounted basis. This amount is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the company settles the obligation.

48 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Impairment

Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less future income taxes, may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset's fair value is recognized during the period, with a charge to earnings.

Disposals

Gains or losses on disposals of non-oil and gas property, plant and equipment are recognized in earnings. For oil and gas property, plant and equipment, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of a subsequently surrendered or abandoned unproved property that is not individually significant, or a partial abandonment of a proved property, is charged to accumulated depreciation, depletion and amortization.

(e) Deferred Charges and Other

The cost of major maintenance shutdowns is deferred and amortized on a straight-line basis over the period to the next shutdown, which varies from three to nine years. Normal maintenance and repair costs are charged to expense as incurred.

Deferred tax credits are government receivables, recognized when they are reasonably measurable and collectible, relating to eligible expenditures under various programs.

See also section (m) Recently Issued Accounting Standards.

(f) Employee Future Benefits

The company's employee future benefit programs consist of defined benefit and defined contribution pension plans, as well as other post-retirement benefits.

The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management's best estimates of demographic and financial assumptions, and such cost is accrued proportionately from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt instruments with cash flows that match the timing and amount of expected benefit payments. Company contributions to the defined contribution plan are expensed as incurred.

(g) Inventories

Inventories of crude oil and refined products are valued at the lower of cost (using the first-in, first-out (FIFO) method) and net realizable value.

Materials and supplies are valued at the lower of average cost and net realizable value.

Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location.

See also Note 1 – Changes in Accounting Policies.

(h) Financial Instruments

The company's financial instruments consist of cash and cash equivalents, accounts receivable, derivative contracts, substantially all current liabilities (except for the current portions of asset retirement and pension obligations, and future income taxes), and long-term debt.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies based on industry accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

Derivative contracts are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash flow hedges.

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 49

The company's fixed-term debt is accounted for under the amortized cost method with the exception of the portion of debt that has related financial hedges, which is accounted for under the fair value hedge methodology outlined above. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. Gains or losses on our U.S. dollar denominated long-term debt resulting from changes in the exchange rate are recognized in the period in which they occur.

See also Note 1 – Changes in Accounting Policies.

(i) Foreign Currency Translation

Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. The resulting exchange gains and losses are included in earnings. Other assets and related depreciation, depletion and amortization, other liabilities, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings.

United States operations of our refining and marketing business, and our corporate self-insurance operations are classified as self-sustaining and are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the period-end exchange rate, while revenues and expenses are translated using average exchange rates during the period. Translation gains or losses are included in other comprehensive income in the Consolidated Statements of Earnings and Comprehensive Income.

(j) Stock-Based Compensation Plans

Under the company's common share option programs (see note 12), common share options are granted to executives, employees and non-employee directors.

Compensation expense is recorded in the Consolidated Statements of Earnings and Comprehensive Income as operating, selling and general expense for all common share options granted to employees and non-employee directors on or after January 1, 2003, with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders' Equity. The expense is based on the fair values of the option at the time of grant and is recognized in the Consolidated Statements of Earnings and Comprehensive Income over the estimated vesting periods of the respective options. For employees eligible to retire prior to the vesting date, the compensation expense is recognized over the shorter period. In instances where an employee is eligible to retire at the time of grant, the full expense is recognized immediately. Consideration paid to the company on exercise of options is credited to share capital.

For common share options granted prior to January 1, 2003 ("pre-2003 options"), compensation expense is not recognized in the Consolidated Statements of Earnings and Comprehensive Income. The company continues to disclose the pro forma earnings impact of related stock-based compensation expense for pre-2003 options.

Stock-based compensation awards that are to be settled in cash are measured using the fair value based method of accounting. The expense is based on the fair values of the award at the time of grant and the change in fair value from the time of grant. The expense is recognized in the Consolidated Statements of Earnings and Comprehensive Income over the estimated vesting periods of the respective award.

(k) Transportation Costs

Transportation costs billed to customers are classified as revenues with the related transportation costs classified as transportation and other costs in the Consolidated Statements of Earnings and Comprehensive Income.

(l) Income Taxes

Suncor follows the liability method of accounting for income taxes. Future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using enacted or substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs. Investment tax credits are recorded as an offset to the related expenditures.

(m) Recently Issued Canadian Accounting Standards

Goodwill and Intangible Assets

In February 2008, the Canadian Institute of Chartered Accountants (CICA) approved Handbook section 3064 "Goodwill and Intangible Assets". Effective January 1, 2009, this new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs". The standard focuses on the criteria for asset recognition in the financial statements, including those internally developed. The new standard will not materially impact net earnings or financial position,

50 SUNCOR ENERGY INC. 2008ANNUAL REPORT

however will result in the reclassification and presentation of certain balances on the balance sheet. At December 31, 2008, $566 million of turnaround costs would have been reclassified as part of Property, Plant and equipment (December 31, 2007 – $296 million).

International Financial Reporting Standards

In February 2008, the Accounting Standards Board confirmed that International Financial Reporting Standards (IFRS) will replace Canadian GAAP in 2011 for publicly accountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP there are significant differences in accounting policies that must be evaluated. More disclosures will be required under IFRS.

The company's IFRS conversion project began in 2008. A formal project plan, governance structure, and a project team, including an external advisor, have been established. The project philosophy is to align with current accounting practices and policies, where possible, to minimize the impact of any changes to the business. Regular reporting is provided to senior management and the Audit Committee of the Board of Directors. Specific changes resulting from implementation of IFRS have not been determined at this time.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 51

CONSOLIDATED STATEMENTS OF EARNINGS
AND COMPREHENSIVE INCOME

For the years ended December 31 ($ millions)		2008	2007 (restated) (note 1)		2006 (restated) (note 1)
Revenues
	Operating revenues (notes 7, 17 and 19)	18 336	15 020		13 798
	Energy marketing and trading activities (note 7d)	11 725	3 515		2 299
	Net insurance proceeds	—	—		436
	Interest	28	30		13
		30 089	18 565		16 546
Expenses
	Purchases of crude oil and products	7 184	5 817		4 670
	Operating, selling and general	4 044	3 340		3 066
	Energy marketing and trading activities (note 7d)	11 717	3 467		2 261
	Transportation and other costs	275	182		203
	Depreciation, depletion and amortization	1 049	864		695
	Accretion of asset retirement obligations	64	48		34
	Exploration (note 19)	90	95		104
	Royalties (note 5)	890	691		1 038
	Taxes other than income taxes (note 19)	679	648		595
	Loss (gain) on disposal of assets	13	7		(1	)
	Project start-up costs	35	68		45
	Financing expenses (income) (note 15)	917	(211	)	39
		26 957	15 016		12 749
Earnings Before Income Taxes		3 132	3 549		3 797
Provision for income taxes (note 11)
	Current	514	382		20
	Future	481	184		808
		995	566		828
Net Earnings		2 137	2 983		2 969
Other comprehensive income (loss) (notes 7 and 18)		350	(190	)	10
Comprehensive Income		2 487	2 793		2 979
Net Earnings Per Common Share (dollars) (note 14)
Net earnings attributable to common shareholders
	Basic	2.29	3.23		3.23
	Diluted	2.26	3.17		3.16
Cash dividends		0.20	0.19		0.15

See accompanying Summary of Significant Accounting Policies and Notes.

52 SUNCOR ENERGY INC. 2008ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)			2008	2007 (restated) (note 1)
Assets
	Current assets
		Cash and cash equivalents	660	569
		Accounts receivable (notes 7, 12 and 19)	1 580	1 438
		Inventories (notes 1 and 16)	909	1 012
		Income taxes receivable	67	95
		Future income taxes (note 11)	21	46
	Total current assets		3 237	3 160
	Property, plant and equipment, net (note 3)		28 316	20 945
	Deferred charges and other (note 4)		975	404
	Total assets		32 528	24 509
Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	11	6
		Accounts payable and accrued liabilities (notes 7, 9, 10 and 13)	3 229	2 797
		Taxes other than income taxes	97	72
		Income taxes payable	81	244
		Future income taxes	111	37
	Total current liabilities		3 529	3 156
	Long-term debt (note 6)		7 875	3 811
	Accrued liabilities and other (notes 7, 9, 10 and 13)		1 986	1 434
	Future income taxes (note 11)		4 615	4 212
	Total liabilities		18 005	12 613
	Commitments and contingencies (note 12)
	Shareholders' equity
		Share capital (note 13)	1 113	881
		Contributed surplus (note 13)	288	194
		Accumulated other comprehensive income (loss) (notes 7 and 18)	97	(253	)
		Retained earnings (note 1)	13 025	11 074
	Total shareholders' equity		14 523	11 896
	Total liabilities and shareholders' equity		32 528	24 509

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board of Directors:

Richard L. George	Brian A. Canfield
Director	Director

February 25, 2009

SUNCOR ENERGY INC. 2008ANNUAL REPORT 53

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions)		2008		2007 (restated) (note 1)		2006 (restated) (note 1)
Operating Activities
Cash flow from operations (a)		4 463		4 009		4 524
Decrease (increase) in operating working capital
	Accounts receivable	(134	)	(387	)	53
	Inventories	103		(223	)	(57	)
	Accounts payable and accrued liabilities	140		248		87
	Taxes payable/receivable	(110	)	246		(43	)
Cash flow from operating activities		4 462		3 893		4 564
Cash Used in Investing Activities (a)		(7 590	)	(5 362	)	(3 489	)
Net Cash (Deficiency) Surplus Before Financing Activities		(3 128	)	(1 469	)	1 075
Financing Activities
Decrease in short-term debt		(1	)	(4	)	(42	)
Proceeds from issuance of long-term debt		2 704		1 835		—
Net increase (decrease) in long-term debt		422		(171	)	(622	)
Issuance of common shares under stock option plans		190		62		45
Dividends paid on common shares		(180	)	(162	)	(127	)
Deferred revenue		—		4		27
Cash flow provided by (used in) financing activities		3 135		1 564		(719	)
Increase in Cash and Cash Equivalents		7		95		356
Effect of Foreign Exchange on Cash and Cash Equivalents		84		(47	)	—
Cash and Cash Equivalents at Beginning of Year		569		521		165
Cash and Cash Equivalents at End of Year		660		569		521

(a)

See Schedules of Segmented Data on pages 58 and 59.

See accompanying Summary of Significant Accounting Policies and Notes.

54 SUNCOR ENERGY INC. 2008ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

For the years ended December 31 ($ millions)	Share Capital	Contributed Surplus		Accumulated Other Comprehensive Income (AOCI)		Retained Earnings
At December 31, 2005, as previously reported	732	50		(81	)	5 295
Retroactive adjustment for change in accounting policy, net of tax (note 1)	—	—		—		134
At December 31, 2005, as restated	732	50		(81	)	5 429
Net earnings	—	—		—		2 969
Dividends paid on common shares	—	—		—		(127	)
Issued for cash under stock option plans	52	(7	)	—		—
Issued under dividend reinvestment plan	10	—		—		(10	)
Stock-based compensation expense	—	53		—		—
Income tax benefit of stock option deductions in the U.S.	—	4		—		—
Change in AOCI related to foreign currency translation	—	—		10		—
At December 31, 2006, as restated	794	100		(71	)	8 261
Net earnings	—	—		—		2 983
Dividends paid on common shares	—	—		—		(162	)
Issued for cash under stock option plans	74	(12	)	—		—
Issued under dividend reinvestment plan	13	—		—		(13	)
Stock-based compensation expense	—	103		—		—
Income tax benefit of stock option deductions in the U.S.	—	3		—		—
Adjustment to opening retained earnings arising from ineffective portion of cash flow hedges at January 1, 2007	—	—		—		5
Adjustment to opening AOCI arising from effective portion of cash flow hedges at January 1, 2007	—	—		8		—
Change in AOCI related to foreign currency translation	—	—		(195	)	—
Change in AOCI related to derivative hedging activities	—	—		5		—
At December 31, 2007, as restated	881	194		(253	)	11 074
Net earnings	—	—		—		2 137
Dividends paid on common shares	—	—		—		(180	)
Issued for cash under stock option plans	226	(36	)	—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	120		—		—
Income tax benefit of stock option deductions in the U.S.	—	10		—		—
Change in AOCI related to foreign currency translation	—	—		350		—
Change in AOCI related to derivative hedging activities	—	—		—		—
At December 31, 2008	1 113	288		97		13 025

See accompanying Summary of Significant Accounting Policies and Notes.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 55

SCHEDULES OF SEGMENTED DATA ^(a)

	Oil Sands						Natural Gas						Refining and Marketing                      (note 2)
For the years ended December 31 ($ millions)	2008		2007		2006		2008		2007		2006		2008		2007		2006
EARNINGS
Revenues (b)
Operating revenues	8 077		6 195		6 259		696		541		554		9 543		8 278		6 981
Energy marketing and trading activities	—		—		—		—		—		—		11 827		3 522		2 324
Net insurance proceeds	—		—		436		—		—		—		—		—		—
Intersegment revenues (c)	1 309		580		712		58		12		23		—		—		—
Interest	—		—		—		—		—		1		1		5		5
	9 386		6 775		7 407		754		553		578		21 371		11 805		9 310
Expenses
Purchases of crude oil and products	574		157		89		—		—		—		8 074		6 250		5 297
Operating, selling and general (note 2)	3 124		2 384		2 212		155		151		119		715		693		669
Energy marketing and trading activities	—		—		—		—		—		—		11 725		3 473		2 292
Transportation and other costs	229		138		162		17		15		16		29		29		25
Depreciation, depletion and amortization	580		462		385		225		189		152		202		171		132
Accretion of asset retirement obligations	55		40		28		8		7		5		1		1		1
Exploration	17		13		22		73		82		82		—		—		—
Royalties (note 5)	715		565		911		175		126		127		—		—		—
Taxes other than income taxes	111		90		75		5		4		3		562		553		516
Loss (gain) on disposal of assets	36		1		—		(22	)	(1	)	(4	)	6		7		3
Project start-up costs	35		60		38		—		—		—		—		8		7
Financing expenses (income)	—		—		—		—		—		—		—		—		—
	5 476		3 910		3 922		636		573		500		21 314		11 185		8 942
Earnings (loss) before income taxes	3 910		2 865		3 485		118		(20	)	78		57		620		368
Income taxes	(1 035	)	(391	)	(710	)	(29	)	45		28		(6	)	(176	)	(124	)
Net earnings (loss)	2 875		2 474		2 775		89		25		106		51		444		244
As at December 31
TOTAL ASSETS	25 795		18 172		13 727		1 862		1 811		1 503		4 666		4 825		4 219

(a)

Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.

(b)

There were no customers that represented 10% or more of the company's 2008, 2007 or 2006 consolidated revenues.

(c)

Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties.

See accompanying Summary of Significant Accounting Policies and Notes.

56 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

	Corporate and                      Eliminations						Total
For the years ended December 31 ($ millions)	2008		2007		2006		2008		2007		2006
EARNINGS
Revenues (b)
Operating revenues	20		6		4		18 336		15 020		13 798
Energy marketing and trading activities	(102	)	(7	)	(25	)	11 725		3 515		2 299
Net insurance proceeds	—		—		—		—		—		436
Intersegment revenues (c)	(1 367	)	(592	)	(735	)	—		—		—
Interest	27		25		7		28		30		13
	(1 422	)	(568	)	(749	)	30 089		18 565		16 546
Expenses
Purchases of crude oil and products	(1 464	)	(590	)	(716	)	7 184		5 817		4 670
Operating, selling and general (note 2)	50		112		66		4 044		3 340		3 066
Energy marketing and trading activities	(8	)	(6	)	(31	)	11 717		3 467		2 261
Transportation and other costs	—		—		—		275		182		203
Depreciation, depletion and amortization	42		42		26		1 049		864		695
Accretion of asset retirement obligations	—		—		—		64		48		34
Exploration	—		—		—		90		95		104
Royalties (note 5)	—		—		—		890		691		1 038
Taxes other than income taxes	1		1		1		679		648		595
Loss (gain) on disposal of assets	(7	)	—		—		13		7		(1	)
Project start-up costs	—		—		—		35		68		45
Financing expenses (income)	917		(211	)	39		917		(211	)	39
	(469	)	(652	)	(615	)	26 957		15 016		12 749
Earnings (loss) before income taxes	(953	)	84		(134	)	3 132		3 549		3 797
Income taxes	75		(44	)	(22	)	(995	)	(566	)	(828	)
Net earnings (loss)	(878	)	40		(156	)	2 137		2 983		2 969
As at December 31
TOTAL ASSETS	205		(299	)	(490	)	32 528		24 509		18 959

SUNCOR ENERGY INC. 2008ANNUAL REPORT 57

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Oil Sands						Natural Gas						Refining and Marketing               (note 2)
For the years ended December 31 ($ millions)			2008		2007		2006		2008		2007		2006		2008		2007		2006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		2 875		2 474		2 775		89		25		106		51		444		244
	Exploration expenses		—		—		—		61		67		52		—		—		—
	Non-cash items included in earnings
		Depreciation, depletion and amortization	580		462		385		225		189		152		202		171		132
		Future income taxes	535		108		725		15		(43	)	(28	)	(7	)	77		69
		Loss (gain) on disposal of assets	36		1		—		(22	)	(1	)	(4	)	6		7		3
		Stock-based compensation expense	60		49		25		4		5		2		19		25		13
		Other	(54	)	1		14		(4	)	7		1		2		(5	)	(7	)
	Increase (decrease) in deferred credits and other		(194	)	48		(21	)	—		(1	)	—		5		(3	)	(3	)
Total cash flow from (used in) operations			3 838		3 143		3 903		368		248		281		278		716		451
Decrease (increase) in operating working capital			603		586		440		42		22		(27	)	(30	)	(254	)	(110	)
Total cash from (used in) operating activities			4 441		3 729		4 343		410		270		254		248		462		341
Cash from (used in) investing activities:
Capital and exploration expenditures			(7 051	)	(4 431	)	(2 463	)	(339	)	(531	)	(458	)	(172	)	(376	)	(665	)
Deferred maintenance shutdown expenditures			(340	)	(135	)	—		(3	)	(6	)	—		(54	)	(73	)	(80	)
Deferred outlays and other investments			(39	)	(18	)	(2	)	—		—		—		(11	)	—		7
Proceeds from disposals			—		3		2		26		5		15		—		1		4
Proceeds from property loss			—		—		36		—		—		—		—		—		—
Decrease (increase) in investing working capital			434		333		197		—		—		—		(19	)	(43	)	(53	)
Total cash (used in) investing activities			(6 996	)	(4 248	)	(2 230	)	(316	)	(532	)	(443	)	(256	)	(491	)	(787	)
Net cash surplus (deficiency) before financing activities			(2 555	)	(519	)	2 113		94		(262	)	(189	)	(8	)	(29	)	(446	)

(a)

Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.

See accompanying Summary of Significant Accounting Policies and Notes.

58 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Corporate and                      Eliminations						Total
For the years ended December 31 ($ millions)			2008		2007		2006		2008		2007		2006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		(878	)	40		(156	)	2 137		2 983		2 969
	Exploration expenses		—		—		—		61		67		52
	Non-cash items included in earnings
		Depreciation, depletion and amortization	42		42		26		1 049		864		695
		Future income taxes	(62	)	42		42		481		184		808
		Loss (gain) on disposal of assets	(7	)	—		—		13		7		(1	)
		Stock-based compensation expense	37		24		13		120		103		53
		Other	824		(236	)	(22	)	768		(233	)	(14	)
	Increase (decrease) in deferred credits and other		23		(10	)	(14	)	(166	)	34		(38	)
Total cash flow from (used in) operations			(21	)	(98	)	(111	)	4 463		4 009		4 524
Decrease (increase) in operating working capital			(616	)	(470	)	(263	)	(1	)	(116	)	40
Total cash from (used in) operating activities			(637	)	(568	)	(374	)	4 462		3 893		4 564
Cash from (used in) investing activities:
Capital and exploration expenditures			(28	)	(77	)	(27	)	(7 590	)	(5 415	)	(3 613	)
Deferred maintenance shutdown expenditures			—		—		—		(397	)	(214	)	(80	)
Deferred outlays and other investments			(1	)	(14	)	(2	)	(51	)	(32	)	3
Proceeds from disposals			7		—		—		33		9		21
Proceeds from property loss			—		—		—		—		—		36
Decrease (increase) in investing working capital			—		—		—		415		290		144
Total cash (used in) investing activities			(22	)	(91	)	(29	)	(7 590	)	(5 362	)	(3 489	)
Net cash surplus (deficiency) before financing activities			(659	)	(659	)	(403	)	(3 128	)	(1 469	)	1 075

SUNCOR ENERGY INC. 2008ANNUAL REPORT 59

SUNCOR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGES IN ACCOUNTING POLICIES

(a)   Inventories

On January 1, 2008 the company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook section 3031 "Inventories". Under the new standard, the use of a LIFO (last-in, first-out) based valuation approach for inventory has been eliminated. The standard also requires any impairment to net realizable value of inventory to be written down at each reporting period, with subsequent reversals when applicable. The company adopted a FIFO (first-in, first-out) based valuation approach for inventory effective January 1, 2008. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase/(decrease))	As at December 31 2008	As at December 31 2007
Inventories	110	404
Total assets	110	404
Future income taxes	30	121
Retained earnings	80	283
Total liabilities and shareholders' equity	110	404

Change in Consolidated Statements of Earnings (Loss) and Comprehensive Income

	Twelve months ended December 31
($ millions, increase/(decrease))	2008		2007		2006
Purchases of crude oil and products	270		(153	)	(5	)
Operating, selling and general	24		(51	)	14
Future income taxes	(91	)	53		(7	)
Net earnings (loss)	(203	)	151		(2	)
Per common share – basic (dollars)	(0.22	)	0.16		—
Per common share – diluted (dollars)	(0.22	)	0.16		—

(b)   Capital Disclosure

On January 1, 2008, the company adopted CICA Handbook section 1535 "Capital Disclosures". This section establishes disclosure requirements for management's policies and processes in defining and managing its capital. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard. See note 8 for disclosure of the new section.

(c)    Financial Instruments – Disclosures and Presentation

On January 1, 2008, the company adopted CICA Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard. See note 7 for disclosure of new sections.

2. CHANGE IN SEGMENTED DISCLOSURES

Consistent with the company's organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream refining and marketing operations have been combined into a single business segment – refining and marketing. Comparative figures have been reclassified to reflect the combination of the previously disclosed Energy Marketing & Refining – Canada (EM&R) and Refining & Marketing – U.S.A. (R&M) segments. The results of company-wide energy marketing and trading activities will continue to be included in this segment. The financial results relating to the sales of oil sands and

60 SUNCOR ENERGY INC. 2008ANNUAL REPORT

natural gas production will continue to be reported in their respective business segments. There was no impact to consolidated net earnings as a result of the restructuring.

Effective January 1, 2007, the company began allocating stock-based compensation expense to each of the reportable business segments. Comparative figures have been reclassified to reflect the allocation of stock-based compensation. There was no impact to consolidated net earnings as a result of the allocation.

3. PROPERTY, PLANT AND EQUIPMENT

		2008		2007
($ millions)		Cost	Accumulated Provision	Cost	Accumulated Provision
Oil sands
	Plant	15 229	2 282	11 049	1 962
	Mine and mobile equipment	1 777	469	1 423	388
	In-situ properties	2 881	301	2 566	222
	Pipeline	149	40	149	35
	Capital leases	102	10	102	6
	Major projects in progress (1)	6 582	—	3 830	—
		26 720	3 102	19 119	2 613
Natural gas
	Proved properties	2 542	1 239	2 213	1 042
	Unproved properties	146	30	139	32
	Other support facilities and equipment	102	38	92	30
	Wells in progress	211	—	291	—
		3 001	1 307	2 735	1 104
Refining and marketing
	Refinery	2 973	754	2 699	628
	Marketing	844	330	783	304
	Pipeline	87	7	53	4
		3 904	1 091	3 535	936
Corporate		329	138	305	96
		33 954	5 638	25 694	4 749
Net property, plant and equipment			28 316		20 945

(1)

This balance only includes certain major projects in progress. Total assets under construction not being depreciated at December 31, 2008 is $11.1 billion (2007 – $6.3 billion).

4. DEFERRED CHARGES AND OTHER

($ millions)	2008	2007
Deferred maintenance shutdown costs	566	296
Deferred government tax credits	35	36
Unrealized mark to market gains	273	6
Other	101	66
Total deferred charges and other	975	404

5. ROYALTIES

The company's current estimation of Alberta Crown royalties is based on regulations that were in effect until the end of 2008. Alberta Crown royalties for each oil sands project require payments to the Government of Alberta based on annual gross revenues less related allowable transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. Royalty expense for the company's oil sands operations for the year ended December 31, 2008, was $715 million (2007 – $565 million, 2006 – $911 million). The balance of the consolidated royalty expense is in respect of natural gas royalties of $175 million (2007 – $126 million, 2006 – $127 million).

The New Royalty Framework changes enacted by the Government of Alberta will increase royalty rates, effective January 1, 2009 to a sliding scale of 25% – 40% of R-C, subject to a minimum royalty of 1%-9% depending on oil price. In both cases, the

SUNCOR ENERGY INC. 2008ANNUAL REPORT 61

sliding scale royalty would move with increases in WTI prices from the minimum rates at Cdn $55 to the maximum rates at a WTI price of Cdn $120.

The New Royalty Framework changes and the new sliding scale royalty rates outlined above apply to our Firebag in-situ project effective January 1, 2009.

In January 2008, the company entered into a Royalty Amending Agreement with the government of Alberta to transition our base oil sands mining operations to the New Royalty Framework rates in the New Royalty Framework. Commencing January 1, 2010 until December 31, 2015, the new royalty rates will apply to the bitumen royalty for current production levels, subject to a cap of 30% of R-C, and a minimum royalty of 1% to 1.2% of R. In addition, the Suncor Royalty Amending Agreement provides the company with a level of certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind, and certain taxes. In 2016 and subsequent years, the limitations on royalty rates and other matters will no longer apply and our base mine operations will be subject to royalty under the terms of the New Royalty Framework, unless it is amended or superseded prior to that time.

6. LONG-TERM DEBT

A.    Fixed-term debt, redeemable at the option of the company

($ millions)	2008		2007
6.85% Notes, denominated in U.S. dollars, due in 2039 (US$750) (i)	918		—
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150) (iii)	1 408		1 137
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	612		494
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	612		494
6.10% Notes, denominated in U.S. dollars, due in 2018 (US$1250) (i)	1 531		—
5.39% Series 4 Medium Term Notes, due in 2037 (iv)	600		600
5.80% Series 4 Medium Term Notes, due in 2018 (ii)	700		—
6.70% Series 2 Medium Term Notes, due in 2011 (v)	500		500
	6 881		3 225
Revolving-term debt, with interest at variable rates (see B. Credit facilities)
Commercial Paper (interest at December 31, 2008 – 2.2%, 2007 – 4.8%) (vi)	934		522
Total unsecured long-term debt	7 815		3 747
Secured long-term debt	13		1
Capital leases (vii), (viii)	103		102
Fair values of interest swaps	16		6
Deferred financing costs	(72	)	(45	)
Total long-term debt	7 875		3 811

(i)

In June 2008, the company issued 6.10% Notes with a principal amount of US$1.25 billion and 6.85% Notes with a principal amount of US$750 million under an amended US$3.65 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 1, 2018, and June 1, 2039, respectively. The net proceeds received were added to our general funds, which were used for our working capital needs, sustaining capital expenditures, growth capital expenditures and to repay outstanding commercial paper borrowings.

(ii)

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on May 22, 2018. The net proceeds received were added to our general funds to repay outstanding commercial paper, which originally funded our working capital needs, sustaining capital expenditures and growth capital expenditures.

(iii)

During the third quarter of 2007, the company issued additional 6.50% Notes with a principal amount of US$400 million under an outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

During the second quarter of 2007, the company issued 6.50% Notes with a principal amount of US$750 million under an outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

(iv)

During the first quarter of 2007, the company issued 5.39% Medium Term Notes with a principal amount of $600 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on March 26, 2037. The net proceeds were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

(v)

The company has entered into interest rate swap transactions. The swap transactions result in an average effective interest rate that is different from the stated interest rate of the related underlying long-term debt instruments.

	Principal Swapped		Effective Interest Rate
Description of Swap Transaction	($ millions)	Swap Maturity	2008	2007
Swap of 6.70% Medium Term Notes to floating rates	200	2011	4.8%	5.7%

62 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(vi)

The company is authorized to issue commercial paper to a maximum of $1,500 million having a term not to exceed 365 days. Commercial paper is supported by unutilized credit facilities (see B. Credit facilities).

(vii)

Equipment leases with interest rates between 6.5% and 13.4% and maturity dates ranging from 2009 to 2037.

(viii)

Future minimum amounts payable under capital leases and other long-term debt are as follows:

($ millions)	Capital Leases	Other Long-term Debt
2009	9	963 (a)
2010	9	—
2011	10	500
2012	10	—
2013	9	—
Later years	265	6 309
Total minimum payments	312	7 772
Less amount representing imputed interest	209
Present value of obligation under capital leases	103

(a)

Long-term debt due in the next year will be refinanced with available credit facilities

Long-term Debt (per cent)

	2008	2007
Variable rate	15	19
Fixed rate	85	81

B. Credit facilities

During 2008, the company's $330 million bilateral credit facility was amended and extended by one year to 2009 and the credit limit was increased by $150 million to $480 million total funds available. The company's $2 billion syndicated credit facility was renegotiated and extended by one year to have a five year term expiring in March 2013 and the credit limit was increased to $3.75 billion. Additionally, an $8 million demand credit facility was negotiated. At December 31, 2008, the company had available credit facilities of $4,283 million, of which $3,030 million was undrawn as follows:

($ millions)	2008
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2009	480
Facility that is fully revolving for a period of five years and expires in 2013	3 750
Facilities that can be terminated at any time at the option of the lenders	53
Total available credit facilities	4 283
Credit facilities supporting outstanding commercial paper	934
Credit facilities supporting standby letters of credit	319
Total undrawn credit facilities	3 030

7. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

Derivatives are financial instruments that either imitate or counter the price movements of stocks, bonds, currencies, commodities and interest rates. Suncor uses derivatives to reduce (hedge) its exposure to fluctuations in commodity prices and foreign currency exchange rates and to manage interest rate or currency-sensitive assets and liabilities. Suncor also uses derivatives for trading purposes. When used in a trading activity, the company is attempting to realize a gain on the fluctuations in the market value of the derivative.

Forwards and futures are contracts to purchase or sell a specific item at a specified date and price. When used as hedges, forwards and futures help to manage the exposure to losses that could result if commodity prices, foreign currency exchange rates, or interest rates change adversely.

An option is a contract where its holder, for a fee, has purchased the right (but not the obligation) to buy or sell a specified item at a fixed price during a specified period. Options used as hedges help to protect against adverse changes in commodity prices, interest rates, or foreign currency exchange rates.

A costless collar is a combination of two option contracts that limit the holder's exposure to changes in prices to within a specific range. The "costless" nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 63

A swap is a contract where two parties exchange commodity, currency, interest or other payments in order to alter the nature of the payments. For example, fixed interest rate payments on debt may be converted to payments based on a floating interest rate.

Hedge accounting is a method for recognizing the gains, losses, revenues and expenses associated with the items in a hedging relationship at the time when the underlying transaction impacts earnings. Suncor has elected to use hedge accounting on certain derivatives linked to future commodity and financial transactions.

See below for more technical details and amounts.

Financial Instruments

(a)   Balance Sheet Financial Instruments

The company's financial instruments in the Consolidated Balance Sheets consist of cash and cash equivalents, accounts receivable, derivative contracts, substantially all current liabilities (except for the current portions of asset retirement and pension obligations and future income taxes), and long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of recognized financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies based on industry accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

The company's fixed-term debt is accounted for under the amortized cost method. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. Gains or losses on our U.S. dollar denominated long-term debt resulting from changes in the exchange rate are recognized in the period in which they occur. At December 31, 2008, the carrying value of our fixed-term debt accounted for under the amortized cost method was $6.7 billion (December 31, 2007 – $3.0 billion) and the fair value at December 31, 2008 was $5.4 billion (December 31, 2007 – $3.1 billion).

(b)   Hedges – Documented as Part of a Qualifying Hedge Relationship

Fair Value Hedges

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage its exposure to benchmark interest rate fluctuations. The interest rate swap contracts involve an exchange of floating rate versus fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in earnings as an adjustment to interest expense. The fair value of the underlying debt is adjusted by the fair value change in the derivative financial instrument with the offset to interest expense. At December 31, 2008, the company had interest rate swaps classified as fair value hedges outstanding for up to three years relating to fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the twelve month period ended December 31, 2008 (no ineffectiveness during the twelve month period ended December 31, 2007). The fair value of interest rate swap contracts outstanding at December 31, 2008 is detailed in note 6, Long-term debt.

The company periodically enters into derivative contracts to hedge risks specific to individual transactions. The differentials between the fair value of the hedged transactions and the fair value of the derivative contracts are recognized in earnings as an adjustment to operating revenues. The earnings impact associated with hedge ineffectiveness on derivative contracts to hedge risks specific to individual transactions during the twelve month period ended December 31, 2008 was a loss of $4 million, net of income taxes of $2 million (2007 – gain of $4 million, net of income taxes of $2 million).

Cash Flow Hedges

The company operates in a global industry where the market price of its petroleum and natural gas products is largely determined based on floating benchmark indices. The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude sales price variability by entering into West Texas Intermediate (WTI) derivative transactions, and manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate locks and foreign exchange forward contracts.

64 SUNCOR ENERGY INC. 2008ANNUAL REPORT

At December 31, 2008, the company had hedged a portion of its forecasted cash flows subject to natural gas price risk for the first quarter of 2009 related to our refinery natural gas consumption.

There was no earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the twelve month period ended December 31, 2008 (2007 – loss of $5 million, net of income taxes of $2 million).

Certain derivative contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company's sales revenues or crude oil purchase costs. For collars, if market rates are not different than, or are within the range of contract prices, the options contracts making up the collar will expire with no exchange of cash.

Contracts outstanding at December 31, were as follows:

Revenue Hedges

Strategic Crude Oil	Quantity (bpd)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007
Costless collars	10 000	59.85 – 101.06	216 – 365	2008
As at December 31, 2006
Costless collars	60 000	51.64 – 93.26	1 318 – 2 380	2007
Costless collars	10 000	59.85 – 101.06	255 – 431	2008

Natural Gas	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007	—	—	—	—
As at December 31, 2006
Swaps	4 000	6.11	9	2007

Consumption Hedges	Quantity (MMBtu/day)	Average Price (US$/MMBtu)	Consumption Hedged (Cdn$ millions) (b)	Hedge Period (c)
As at December 31, 2008
Natural Gas – fixed price purchases	25 000	6.92	19	2009	(d)
As at December 31, 2007	—	—	—	—
As at December 31, 2006	—	—	—	—

Foreign Currency Hedges	Notional (Euro Millions)	Average Forward Rate	Dollars Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007	—	—	—	—
As at December 31, 2006
Euro/Cdn forward	20.6	1.41	29.0	2007	(e)

(a)

Average price for crude costless collars is US$ WTI per barrel at Cushing, Oklahoma.

(b)

The revenue and consumption hedged is translated to Cdn$ at the respective year-end exchange rate for convenience purposes.

(c)

Original hedge term is for the full year unless otherwise noted.

(d)

For the period January to March 2009, inclusive.

(e)

Settlement for applicable forwards occurring within the period April to September 2007.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 65

Fair Value of Hedging Derivative Financial Instruments

The fair value of hedging derivative financial instruments as recorded, is the estimated amount that the company would receive (pay) to terminate the hedging derivative contracts. Such amounts, which also represent the unrealized gain (loss) on the contracts, were as follows:

($ millions)	December 31 2008		December 31 2007
Revenue and consumption hedges	(2	)	(11	)
Fixed to floating interest rate swaps	24		8
Specific hedges of individual transactions	(11	)	12
Fair value of outstanding hedging derivative financial instruments	11		9

Accumulated Other Comprehensive Income (AOCI)

A reconciliation of changes in AOCI attributable to derivative hedging activities for the twelve month period ending December 31 is as follows:

($ millions)	2008		2007
AOCI attributable to derivative hedging activities, beginning of the period, net of income taxes of $4 (2007 – $5)	13		8
Current year net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1)	(7	)	8
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $3 (2007 – $2)	7		(3	)
AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2007 – $4)	13		13

(c)    Hedges – Not Documented as Part of a Qualifying Hedge Relationship

The company also periodically enters into derivative financial instruments such as options, basis swaps, and heat rate swaps that either do not qualify for hedge accounting treatment or hedges that the company has not elected to document as part of a qualifying hedge relationship. These financial instruments are accounted for using the mark-to-market method and, as such, these derivative instruments are recorded at fair value at each balance sheet date. The earnings impact associated with these contracts for the twelve month period ended December 31, 2008, was a gain of $348 million, net of income taxes of $142 million (2007 – a loss of $3 million, net of income taxes of $1 million).

Significant contracts outstanding at December 31, 2008 were as follows:

Crude Oil (d)	Quantity (bpd)	Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Purchased puts	55 000	60.00	1 475	2009
Purchased puts	55 000	60.00	1 475	2010

(a)

Price for crude puts is US$ WTI per barrel at Cushing, Oklahoma.

(b)

The revenue hedged is translated to Cdn$ at the December 31, 2008 exchange rate for convenience purposes.

(c)

Original hedge term is for the full year.

(d)

Premiums paid was US$59 million.

For information on significant contracts entered into subsequent to December 31, 2008, see page 77.

(d)   Energy Marketing and Trading Activities

In addition to the financial derivatives used for hedging activities, the company uses physical and financial energy contracts, including swaps, forwards and options to earn trading and marketing revenues. These energy contracts are comprised of crude oil, natural gas and refined products contracts. Financial energy trading activities are accounted for using the mark-to-market method. Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. The results of these activities are reported as revenue and as energy marketing and trading expenses in the

66 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Consolidated Statements of Earnings and Comprehensive Income. Net pretax earnings (loss) for the twelve month period ended December 31 for our energy and trading activities in our refining and marketing segment were as follows:

Net Pretax Earnings (Loss)

($ millions)	2008		2007		2006
Physical energy contracts trading activity	100		57		38
Financial energy contracts trading activity	7		(4	)	(3	)
General and administrative costs	(5	)	(4	)	(3	)
Total	102		49		32

(e)   Fair Value of Non-Designated Derivative Financial Instruments

The fair value of unsettled (unrealized) energy derivative assets and liabilities, which includes all financial contracts referenced in section (c) & (d) above are as follows:

($ millions)	December 31 2008	December 31 2007
Energy trading assets(a)	635	18
Energy trading liabilities(b)	14	21
Net energy trading assets (liabilities)	621	(3	)

(a)

As at December 31, 2008, $376 million is recorded in accounts receivable (2007 – $18 million) and $259 million is recorded in deferred charges and other (2007 – nil) in the Consolidated Balance Sheets.

(b)

As at December 31, 2008, $14 million is recorded in accrued liabilities and other (2007 – $21 million) in the Consolidated Balance Sheets.

Change in fair value of net assets

($ millions)	2008
Fair value of contracts at December 31, 2007	(3	)
Fair value of contracts realized during the period	(53	)
Fair value of contracts entered into during the period	673
Changes in fair value during the period	4
Fair value of contracts outstanding at December 31, 2008	621

Financial Risk Factors

The company is exposed to a number of different financial risks arising from normal course business exposures, as well as the company's use of financial instruments. These risk factors include market risks relating to commodity prices, foreign currency risk and interest rate risk, as well as liquidity risk and credit risk.

The company maintains a formal governance process to manage its financial risks. Our Risk Management Committee (RMC) is charged with the oversight of the company's risk management for trading risk management activities which are defined as strategic hedging, optimization trading, marketing and speculative trading. The RMC, acting under board authority, meets regularly to monitor limits on risk exposures, review policy compliance and validate risk-related methodologies and procedures. All risk management activity is carried out by specialist teams that have the appropriate skills, experience and supervision with the appropriate financial and management controls, and is unchanged from the prior year.

1) Market Risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of the business. The market price movements that could adversely affect the value of the company's financial assets, liabilities and expected future cash flows include commodity price risk (crude oil, natural gas and electricity price), foreign currency exchange risk and interest rate risk.

(a)   Commodity Price Risk

The company's financial performance is closely linked to crude oil prices (including pricing differentials for various product types), and to a lesser extent, natural gas and electricity prices. The company's policies permit the use of various financial instruments in managing these price exposures. Our strategic crude oil hedging program gives management approval to fix a price or range of

SUNCOR ENERGY INC. 2008ANNUAL REPORT 67

prices for portions of the total crude oil planned production for specified periods of time. Historically, the company has leveraged hedging instruments to stabilize cash flows during periods of growth and expansion. The company will consider additional strategic hedging opportunities as they become available.

A key component of our overall business strategy is to produce sufficient natural gas to meet or exceed internal demands for natural gas purchased for consumption in our oil sands operation, thus creating a price hedge which reduces our exposure to natural gas price volatility. In addition, existing corporate policies also permit the hedging of natural gas exposures to manage regional price differentials and pricing indexes as identified.

Changes in commodity prices on our financial contracts would have the following impact on our net earnings and other comprehensive income for the twelve months ended December 31, 2008:

Sensitivity Analysis

($ millions)		December 31, 2008 (1)	Change	Net Earnings		Other Comprehensive Income
Crude Oil		US$63.38/barrel
	Price increase		US$1.00/barrel	(32	)	—
	Price decrease		US$1.00/barrel	32		—
Natural Gas		US$6.22/mcf
	Price increase		US$0.10/mcf	(1	)	—
	Price decrease		US$0.10/mcf	1		—

(1)

Prices represent the average of the forward strip prices at December 31, 2008.

(b)   Foreign Currency Exchange Risk

The company is exposed to changes in foreign exchange rates as revenues, capital expenditures, or financial instruments may fluctuate due to changing rates. As crude oil, the company's primary product, is priced in U.S. dollars, fluctuations in US$/Cdn$ exchange rates may have a significant impact on revenues. The company's exposure is partially offset through the issuance of U.S. dollar denominated long-term debt (refer to note 6) and by sourcing capital projects in U.S. dollars. The company does not currently hedge foreign currency risk on estimated revenues. The effect of a $0.01 change in the US$/Cdn$ exchange rate on our U.S. dollar denominated long-term debt would change after-tax earnings by approximately $55 million for the twelve months ended December 31, 2008.

Where an operating unit has substantial exposure to capital expenditures in currencies other than the U.S. dollar, the company may hedge these risks through a combination of forward and option instruments. Transactions in the applicable financial market are executed consistent with established risk management policies.

(c)    Interest Rate Risk

The company is exposed to interest rate risk as changes in interest rates may affect future cash flows and the fair values of its financial instruments. The primary exposure is related to notes and commercial paper. The company seeks to optimize this risk through the use of interest rate swaps by swapping fixed rates of interest for variable rates (see – fair value hedges) and other derivative instruments.

To optimize the company's position with respect to interest expense, the company targets 30% to 50% of total debt to be exposed to floating interest rates. Over time this floating/fixed rate mix will fluctuate based on prevailing market conditions and management's assessment of overall risk.

The proportion of floating interest rate exposure inclusive of interest rate swaps at December 31, 2008 was 15% of total debt outstanding (December 31, 2007 was 19% of total debt outstanding). The weighted average interest rate on total debt for the year ending December 31, 2008 was 5.9% (December 31, 2007 – 6.1%).

The company's cash flows are sensitive to changes in interest rates on the floating rate portion of the company's debt. Given our current growth and expansion plans, all interest is currently being capitalized and therefore there is no earnings impact. If the interest rates applicable to floating rate instruments were to have increased by 1%, it is estimated that the company's cash flow for the twelve months ended December 31, 2008 would decrease by approximately $11 million. This assumes that the amount and mix of fixed and floating rate debt remains unchanged from December 31, 2008, and that the change in interest rates is effective from the beginning of the period.

68 SUNCOR ENERGY INC. 2008ANNUAL REPORT

2) Liquidity Risk

Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with financial liabilities. The company believes that it has access to sufficient capital through internally generated cash flows and external sources (bank credit markets and debt capital markets), and to undrawn committed borrowing facilities to meet current spending forecasts.

Surplus cash is invested into a range of short-dated money market securities and the company seeks to ensure the security and liquidity of those investments. Investments are only permitted in high credit quality government or corporate securities. Diversification of these investments is supported through maintaining counterparty credit limits.

The following table shows the timing of cash outflows relating to trade and other payables and finance debt.

	December 31, 2008		December 31, 2007
($ millions)	Trade and other payables (1)	Finance debt (2)	Trade and other payables (1)	Finance debt (2)
Within one year	3 181	1 378	2 843	764
1 to 3 years	335	1 377	347	427
3 to 5 years	—	822	—	917
Over 5 years	16	13 387	19	6 985
Total	3 532	16 964	3 209	9 093

(1)

These balances exclude non-financial liabilities (pension liabilities, asset retirement obligation, future income taxes and derivative financial instruments) totaling $1,972 million and $1,375 million at December 31, 2008 and December 31, 2007 respectively.

(2)

Finance debt includes long-term debt, capital leases and interest payments on fixed-term debt and commercial paper.

3) Credit Risk

Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial loss. We have a credit policy that is designed to ensure there is a standard credit practice throughout the company to measure and monitor credit risk. The policy outlines delegation of authority, the due diligence process required to approve a new customer or counterparty and the maximum amount of credit exposure per single entity. Before transactions begin with a new customer or counterparty, its creditworthiness is assessed, a credit rating is assigned and a maximum credit limit is allocated. The assessment process is outlined in the credit policy and considers both quantitative and qualitative factors. The company constantly monitors the exposure to any single customer or counterparty along with the financial position of the customer or counterparty. If it is deemed that a customer or counterparty has become materially weaker, the company will work to reduce the credit exposure and lower the credit limit allocated. Regular reports are generated to monitor credit risk and the Credit Committee meets quarterly to ensure compliance with the credit policy and review the exposures.

A substantial portion of the company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risk. At December 31, 2008 and December 31, 2007, substantially all of the company's trade receivables were current, and there were no counterparties that individually constituted more than 10% of the outstanding balance.

The company may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The company's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. At December 31, 2008, the company's exposure was $659 million (December 31, 2007 – $38 million).

8. CAPITAL STRUCTURE FINANCIAL POLICIES

The company's primary capital management objective is to maintain a solid investment-grade credit rating profile. This objective affords the company the financial flexibility and access to the capital it requires to execute on its growth objectives.

The company monitors capital through two key ratios: net debt to cash flow from operations and total debt to total debt plus shareholders' equity.

Net debt to cash flow from operations is calculated as short-term debt plus long-term debt less cash and cash equivalents divided by cash flow from operations for the year then ended.

Total debt to total debt plus shareholders' equity is calculated as short-term debt plus long-term debt divided by short-term debt plus long-term debt plus shareholders' equity.

The company's strategy during 2008, which was unchanged from 2007, was to maintain the measures set out in the following schedule. The company believes that maintaining our capital targets helps to provide the company access to capital at a

SUNCOR ENERGY INC. 2008ANNUAL REPORT 69

reasonable cost by maintaining solid investment-grade credit ratings. The company operates in a cyclical business environment and manages this through the business cycle.

At December 31, ($ millions)			Capital Measure Target	2008		2007
Components of ratios
	Short-term debt			11		6
	Long-term debt			7 875		3 811
		Total debt		7 886		3 817
	Cash and equivalents			660		569
		Net debt		7 226		3 248
	Shareholders' equity			14 523		11 896
	Total capitalization (total debt + shareholders' equity)			22 409		15 713
	Cash flow from operations			4 463		4 009
Net debt/cash flow from operations			<2.0 times	1.6		0.8
Total debt/total debt plus shareholders' equity				35	%	24 %

9. ACCRUED LIABILITIES AND OTHER

($ millions)	2008	2007
Asset retirement obligations (a)	1 444	882
Employee future benefits liability (see note 10)	191	176
Employee and director incentive plans (b)	67	173
Deferred revenue	161	164
Environmental remediation costs (c)	7	11
Other	116	28
Total	1 986	1 434

(a)   Asset Retirement Obligations (ARO)

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the total obligations associated with the retirement of property, plant and equipment.

($ millions)	2008		2007
Asset retirement obligations, beginning of year	1 072		808
Liabilities incurred	598		275
Liabilities settled	(134	)	(59	)
Accretion of asset retirement obligations	64		48
Asset retirement obligations, end of year	1 600		1 072

The portion of the ARO expected to be paid within one year is shown within current liabilities and amounts to an additional $156 million (2007 – $190 million).

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2008, was approximately $3.5 billion (2007 – $2.2 billion). The liability recognized in 2008 was discounted using the company's credit-adjusted risk-free rate of 9.0% (2007 – 6.0%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 30 years.

A significant portion of the company's assets, including the upgrading facilities at the oil sands operation and the two downstream refineries located in Sarnia and Commerce City, have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.

(b)   Employee and Director Incentive Plans

The portion of the employee and director incentive plans expected to be paid within one year is shown within current liabilities and amounts to an additional $8 million (2007 – $50 million).

70 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(c)    Environmental Remediation Costs

The portion of the environmental remediation costs expected to be paid within one year is shown within current liabilities and amounts to an additional $16 million (2007 – $19 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

10. EMPLOYEE FUTURE BENEFITS LIABILITY

Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire. The related Benefit Obligation or commitment that Suncor has to employees and retirees at December 31, 2008, was $955 million (2007 – $1,063 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of the pension obligations. The company funds its unregistered supplementary pension plan and supplementary senior executive retirement plan on a voluntary basis. The amount and timing of future funding for these supplementary plans is subject to capital availability and is at the company's discretion. At the end of December 2008, Plan Assets to meet the Benefit Obligation were $613 million (2007 – $684 million).

The excess of the Benefit Obligation over Plan Assets of $342 million (2007 – $379 million) represents the Net Unfunded Obligation.

See below for more technical details and amounts.

Defined Benefit Pension Plans and Other Post-Retirement Benefits

The company's defined benefit pension plans provide non-indexed pension benefits at retirement based on years of service and final average earnings. These obligations are met through funded registered retirement plans and through unregistered supplementary pensions and senior executive retirement plans that are voluntarily funded through retirement compensation arrangements, and/or paid directly to recipients. Company contributions to the funded plans are deposited with independent trustees who act as custodians of the plans' assets, as well as the disbursing agents of the benefits to recipients. Plan assets are managed by a pension committee on behalf of beneficiaries. The committee retains independent managers and advisors.

Funding of the registered retirement plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, depending on funding status, and every year in the United States. The most recent valuation for the Canadian plan was performed as at December 31, 2006.

The company's other post-retirement benefits programs are unfunded and include certain health care and life insurance benefits provided to retired employees and eligible surviving dependants.

The expense and obligations for both funded and unfunded benefits are determined in accordance with Canadian GAAP and actuarial principles. Obligations are based on the projected benefit method of valuation that includes employee service to date and present pay levels, as well as a projection of salaries and service to retirement.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 71

Obligations and Funded Status

The following table presents information about obligations recognized in the Consolidated Balance Sheets and the funded status of the plans at December 31:

		Pension Benefits				Other                      Post-Retirement                      Benefits
($ millions)		2008		2007		2008		2007
Change in benefit obligation
	Benefit obligation at beginning of year	901		866		162		158
	Service costs	56		51		4		4
	Interest costs	49		45		9		8
	Plan participants' contributions	9		5		—		—
	Foreign exchange	8		(5	)	4		(2	)
	Actuarial (gain) loss	(168	)	(28	)	(27	)	(3	)
	Benefits paid	(49	)	(33	)	(3	)	(3	)
Benefit obligation at end of year (a)(d)		806		901		149		162
Change in plan assets (b)
	Fair value of plan assets at beginning of year	684		616		—		—
	Actual return (loss) on plan assets	(107	)	7		—		—
	Employer contributions	69		88		—		—
	Foreign exchange	4		(2	)	—		—
	Plan participants' contributions	9		5		—		—
	Benefits paid	(46	)	(30	)	—		—
Fair value of plan assets at end of year (d)		613		684		—		—
Net unfunded obligation		(193	)	(217	)	(149	)	(162	)
Items not yet recognized in earnings:
	Unamortized net actuarial loss (c)	123		158		12		43
	Unamortized past service costs	—		—		(17	)	(20	)
Accrued benefit liability		(70	)	(59	)	(154	)	(139	)
	Current liability	(37	)	(41	)	(3	)	(3	)
	Long-term liability	(40	)	(40	)	(151	)	(136	)
	Long-term asset	7		22		—		—
Total accrued benefit liability		(70	)	(59	)	(154	)	(139	)

(a)

Obligations are based on the following assumptions:

	Pension Benefit               Obligations		Other Post-Retirement               Benefits Obligations
(percent)	2008	2007	2008	2007
Discount rate	6.50	5.25	6.50	5.25
Rate of compensation increase	5.00	5.00	4.75	4.75

A one percent change in the assumptions at which pension benefits and other post-retirement benefits liabilities could be effectively settled is as follows:

	Rate of Return        on Plan Assets			Discount Rate			Rate of Compensation        Increase
($ millions)	1% increase		1% decrease	1% increase		1% decrease	1% increase	1% decrease
Increase (decrease) to net periodic benefit cost	(6	)	6	(23	)	27	11	(9	)
Increase (decrease) to benefit obligation	—		—	(127	)	150	32	(29	)

In order to measure the expected cost of other post-retirement benefits, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2008 (2007 – 9%; 2006 – 9.5%). It is assumed that this rate will remain constant in 2009 and will decrease by 0.5% annually, to 5% by 2017, and remain at that level thereafter.

Assumed health care cost trend rates may have a significant effect on the amounts reported for other post-retirement benefit obligations. A one percent change in assumed health care cost trend rates would have the following effects:

($ millions)	1% increase	1% decrease
Increase (decrease) to total of service and interest cost components of net periodic post-retirement health care benefit cost	1	(1	)
Increase (decrease) to the health care component of the accumulated post-retirement benefit obligation	16	(13	)

72 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(b)

Pension plan assets are not the company's assets and therefore are not included in the Consolidated Balance Sheets.

(c)

The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 11 years for pension benefits (2007 – 11 years; 2006 – 11 years), and over the expected average future service life to full eligibility age of 11 years for other post-retirement benefits (2007 – 12 years; 2006 – 10 years).

(d)

The company uses a measurement date of December 31 to value the plan assets and accrued benefit obligation.

The above benefit obligation at year-end includes partially funded and unfunded plans, as follows:

	Pension Benefits		Other                      Post-Retirement                      Benefits
($ millions)	2008	2007	2008	2007
Partially funded plans	806	901	—	—
Unfunded plans	—	—	149	162
Benefit obligation at end of year	806	901	149	162

Components of Net Periodic Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other                      Post-Retirement Benefits
($ millions)	2008		2007		2006		2008	2007	2006
Current service costs	56		51		44		4	4	5
Interest costs	49		45		40		9	8	8
Expected return on plan assets (ii)	(45	)	(42	)	(32	)	—	—	—
Amortization of net actuarial loss	22		25		28		3	3	1
Net periodic benefit cost recognized (iii)	82		79		80		16	15	14

Components of Net Incurred Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other                      Post-Retirement Benefits
($ millions)	2008		2007		2006		2008		2007		2006
Current service costs	56		51		44		4		4		5
Interest costs	49		45		40		9		8		8
Actual (return) loss on plan assets (ii)	107		(7	)	(60	)	—		—		—
Actuarial (gain) loss	(168	)	(28	)	67		(27	)	(4	)	5
Net incurred benefit cost	44		61		91		(14	)	8		18

(i)

The net periodic benefit cost includes certain accounting adjustments made to allocate costs to the periods in which employee services are rendered, consistent with the long-term nature of the benefits. Costs actually incurred in the period (arising from actual returns on plan assets and actuarial gains and losses in the period) differ from allocated costs recognized.

(ii)

The expected return on plan assets is the expected long-term rate of return on plan assets for the year. It is based on plan assets at the beginning of the year that have been adjusted on a weighted-average basis for contributions and benefit payments expected for the year. The expected return on plan assets is included in the net periodic benefit cost for the year to which it relates, while the difference between it and the actual return realized on plan assets in the same year is amortized over the expected average remaining service life of employees of 11 years for pension benefits.

To estimate the expected long-term rate of return on plan assets, the company considered the current level of expected returns on the fixed income portion of the portfolio, the historical level of the risk premium associated with other asset classes in which the portfolio is invested and the expectation for future returns on each asset class. The expected return for each asset class was weighted based on the policy asset mix to develop an expected long-term rate of return on asset assumption for the portfolio.

(iii)

Pension expense is based on the following assumptions:

	Pension               Benefit Expense			Other Post-Retirement               Benefits Expense
(percent)	2008	2007	2006	2008	2007	2006
Discount rate	5.25	5.00	5.00	5.25	5.00	5.00
Expected return on plan assets	6.50	6.50	6.50	N/A	N/A	N/A
Rate of compensation increase	5.00	5.00	4.50	4.75	4.75	4.25

SUNCOR ENERGY INC. 2008ANNUAL REPORT 73

Plan Assets and Investment Objectives

The company's long-term investment objective is to secure the defined pension benefits while managing the variability and level of its contributions. The portfolio is rebalanced periodically as required, while ensuring that the maximum equity content is 65% at any time. Plan assets are restricted to those permitted by legislation, where applicable. Investments are made through pooled, mutual, segregated or exchange traded funds.

The company's weighted-average pension plan asset allocation based on market values as at December 31, 2008 and 2007, and the target allocation for 2009, are as follows:

	Target Allocation %	Plan Assets %
Asset Category	2009	2008	2007
Equities	60	57	58
Fixed income	40	43	42
Total	100	100	100

Equity securities do not include any direct investments in Suncor shares.

Cash Flows

The company expects that contributions to its pension plans in 2009 will be $76 million, including approximately $10 million for the company's supplemental executive and supplemental retirement plans. Expected benefit payments from all of the plans are as follows:

	Pension Benefits	Other Post-Retirement Benefits
2009	42	6
2010	45	6
2011	47	7
2012	50	8
2013	54	9
2014 – 2018	318	51
Total	556	87

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and a U.S. 401(k) savings plan, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $15 million in 2008 (2007 – $13 million; 2006 – $11 million).

74 SUNCOR ENERGY INC. 2008ANNUAL REPORT

11. INCOME TAXES

The assets and liabilities shown on Suncor's balance sheets are calculated in accordance with Canadian GAAP. Suncor's income taxes are calculated according to government tax laws and regulations, which results in different values for certain assets and liabilities for income tax purposes. These differences are known as temporary differences, because eventually these differences will reverse.

The amount shown on the balance sheets as future income taxes represent income taxes that will eventually be payable or recoverable in future years when these temporary differences reverse.

See below for more technical details and amounts.

The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the provision for income taxes is as follows:

		2008		2007		2006
($ millions)		Amount		Amount		Amount
Federal tax rate		924		1 119		1 253
Provincial abatement		(313	)	(308	)	(380	)
Federal surtax		—		34		43
Provincial tax rates		314		325		394
Statutory tax		925		1 170		1 310
Adjustment of statutory rate for future rate reductions		(101	)	(151	)	(150	)
		824		1 019		1 160
Add (deduct) the tax effect of:
	Capital gains and losses	136		(40	)	—
	Stock-based compensation	36		33		18
	Other	47		(18	)	16
	Assessments and adjustments	(48	)	(1	)	(9	)
	Tax rate changes on opening future income taxes (a)	—		(427	)	(419	)
	Crown royalties	—		—		125
	Large corporations tax	—		—		2
	Attributed Canadian royalty income	—		—		(23	)
	Resource allowance (b)	—		—		(42	)
Total provision for income taxes		995		566		828
Effective Rate		32	%	16	%	22	%

(a)

During 2007, the federal government enacted tax rate reductions totalling $427 million. During the fourth quarter of 2007 the federal government substantively enacted a 3.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $360 million related to the revaluation of its opening future income tax balances. During the second quarter of 2007 the federal government substantively enacted a 0.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $67 million related to the revaluation of its opening future income tax balances.

During 2006, there were both federal and provincial government rate reductions totalling $419 million. During the second quarter of 2006 the federal government substantively enacted a 3.1% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $292 million related to the revaluation of its opening future income tax balances. As well, the provincial government of Alberta substantively enacted a 1.5% reduction to its provincial corporate tax rates during the second quarter of 2006. Accordingly, the company recognized a reduction in future income tax expense of $127 million related to the revaluation of its opening future income tax balances.

(b)

The resource allowance was a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by GAAP in Canada, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate. Resource allowance has been phased out effective January 1, 2007.

In 2008, net income tax payments totalled $638 million (2007 – $152 million; 2006 – $36 million).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 75

At December 31, future income taxes were comprised of the following:

($ millions)		2008		2007
Future income tax liabilities:
	Excess of book values of assets over tax values	4 987		4 467
	Risk management	149		—
	Other	48		86
Future income tax assets:
	Asset retirement obligations	(400	)	(269	)
	Employee future benefits	(72	)	(118	)
	Inventories	(7	)	37
Net Future income tax liabilities		4 705		4 203
Less: Current portion of future income tax assets & liabilities		90		(9	)
Future income tax liabilities		4 615		4 212

12. COMMITMENTS, CONTINGENCIES, VARIABLE INTEREST ENTITIES, GUARANTEES AND SUBSEQUENT EVENT

(a)   Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2008, future minimum amounts payable under these leases and agreements are as follows:

($ millions)	Pipeline Capacity and Energy Services (1)	Operating Leases
2009	327	56
2010	341	49
2011	421	39
2012	409	28
2013	412	24
Later years	5 826	176
Total	7 736	372

(1)

Includes annual tolls payable under transportation service agreements with major pipeline companies to use a portion of their pipeline capacity and tankage, as applicable, for transportation of product within Canada and the USA.

Suncor has commitments under long-term energy agreements to obtain a portion of the power and the steam generated by certain cogeneration facilities owned by a major third-party energy company. Since October 1999, this third-party has also managed the operations of Suncor's existing energy services facility at its oil sands operations.

At December 31, 2008, Suncor had purchase commitments relating to crude oil predominately for refinery supply and natural gas for physical trading. Crude oil commitments consisted of market price evergreen contracts for a total volume of 148,000 barrels per day of crude oil (2007 – 148,000 bbls/day), of which most have industry standard 30-day cancellation clauses. Natural gas commitments consist of fixed price contracts with a total volume of 8 million GJ (2007 – 14 million) within a price range of Cdn $5.80 – $9.47 per GJ (2007 – $6.00-$7.67 per GJ) and having terms extending to December 2009 (2007 – December 2008), as well as market price contracts for a total volume of 17 million GJ (2007 – 40 million GJ) with terms extending to October 2009 (2007 – April 2009).

(b)   Contingencies

The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the recognition of estimated asset retirement obligations. Estimates of asset retirement obligation costs can change significantly based on such factors as operating experience and changes in legislation and regulations.

The company carries both property damage and business interruption insurance policies with a combined coverage limit of up to US$1.6 billion, net of deductible amounts or waiting periods. The primary property loss policy of US$250 million has a deductible of US$10 million per incident. Suncor has 100% ownership interest in Fort Insurance Limited, an insurance company which provides coverage to Suncor including business interruption coverage for oil sands with a limit of US$150 million and a deductible of the greater of 30 days or US$50 million. The excess coverage of US$1.2 billion can be used for either property damage or business interruption coverage for oil sands operations. Excess business interruption coverage begins the greater of

76 SUNCOR ENERGY INC. 2008ANNUAL REPORT

90 days from the date of the incident or US$250 million in gross earnings lost. For the purposes of determining loss for business interruption claims, the excess coverage has a ceiling of US$50 WTI and a lost production maximum of 150,000 barrels per day.

The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated financial position.

Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded from the company's cash flow from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, the impact may be material.

(c)    Guarantees, Variable Interest Entities (VIE), and Off-Balance Sheet Arrangements

At December 31, 2008, the company had various indemnification agreements with third parties as described below.

The company had a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2007 – $170 million) having a maturity of 45 days or less, to a third party. The third party was a multiple party securitization vehicle that provided funding for numerous asset pools. As at December 31, 2008, no outstanding accounts receivable had been sold under the program (2007 – nil) and the program had been allowed to expire. Although the company does not believe it had any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $57 million in 2008 and no contingent liability or earnings impact were recorded for this indemnification as the company believes it had no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2008, were $170 million and approximately $510 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2008 (2007 – $4 million; 2006 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE's sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term covered a period of seven years and had been accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2008 and 2007, the VIE did not have any assets or liabilities.

The company has agreed to indemnify holders of the 6.10% notes, 6.85% notes, 6.50% notes, 7.15% notes, and the 5.95% notes and the company's credit facility lenders (see note 6) for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to certain facility and equipment leases.

There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, Suncor has the option to redeem or terminate these contracts if additional costs are incurred.

(d)   Subsequent Event

Subsequent to December 31, 2008, the company entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds to Suncor of approximately $250 million before tax.

13. SHARE CAPITAL

Stock Split

In May 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares. Information related to common shares, stock-based compensation, and earnings per share has been restated to reflect the impact of the company's two-for-one stock split.

Authorized

Common Shares

The company is authorized to issue an unlimited number of common shares without nominal or par value.

Preferred Shares

The company is authorized to issue an unlimited number of preferred shares in series, without nominal or par value.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 77

Issued

	Common Shares
	Number (thousands)	Amount ($ millions)
Balance as at December 31, 2005	915 330	732
Issued for cash under stock option plans	4 294	52
Issued under dividend reinvestment plan	264	10
Balance as at December 31, 2006	919 888	794
Issued for cash under stock option plans	5 388	74
Issued under dividend reinvestment plan	290	13
Balance as at December 31, 2007	925 566	881
Issued for cash under stock options plan	9 823	226
Issued under dividend reinvestment plan	135	6
Balance as at December 31, 2008	935 524	1 113

Stock-Based Compensation

A common share option gives the holder the right, but not the obligation, to purchase common shares at a predetermined price over a specified period of time.

After the date of grant, employees and non-employee directors that hold options must earn the right to exercise them. This is done by the holder by fulfilling a time requirement for service to the company, and with respect to certain options, subject to accelerated vesting should the company meet predetermined performance criterion. Once this right has been earned, these options are considered vested.

The predetermined price at which an option can be exercised is equal to or greater than the market price of the common shares on the date the options are granted.

A performance vesting share unit is an award entitling employees to receive cash to varying degrees contingent upon Suncor's shareholder return relative to a peer group of companies.

A restricted share unit is a time-vested award with a three-year term entitling employees to receive cash.

See below for more technical details and amounts on the company's stock option plans:

(a)   Stock Option Plans

(i)    SunShare 2012 Performance Stock Option Plan

The company granted 2,637,000 options in 2008 (2007 – 15,686,000, 2006 – nil) to all eligible permanent full-time and part-time employees, both executive and non-executive, under its new employee stock option incentive plan ("SunShare 2012"). During the second quarter 2008, in connection with the achievement of a predetermined performance criterion, 25% of the outstanding options vested under the SunShare 2012 plan and will become exercisable on January 1, 2010. The remaining 75% of outstanding options may vest on January 1, 2013 if further specified performance targets are met. All unvested options at January 1, 2013, which have not previously expired or been cancelled will automatically expire.

(ii)   SunShare Performance Stock Option Plan

Granting of options under the company's previous employee stock option incentive plan ("SunShare") ended in December 2007 (the company granted 2,090,000 options during 2007 and 3,274,000 options during 2006). Final vesting of all unvested SunShare options occurred on April 30, 2008.

(iii)  Executive Stock Plan

Under this plan, the company granted 895,000 common share options in 2008 (2007 – 958,000; 2006 – 1,076,000) to non-employee directors and certain executives and other senior employees of the company. Options granted have a 10-year life and vest annually over a three-year period.

(iv)  Key Contributor Stock Option Plan

Under this plan, the company granted 2,375,000 common share options in 2008 (2007 – 2,370,000; 2006 – 2,100,000) to non-insider senior managers and key employees. Options granted have a 10-year life and vest annually over a three-year period.

78 SUNCOR ENERGY INC. 2008ANNUAL REPORT

The following tables cover all common share options granted by the company for the years indicated:

		Number (thousands)		Range of Exercise Prices Per Share ($)	Weighted-Average Exercise Price Per Share ($)
Outstanding, December 31, 2005		38 406		2.61 – 35.57	14.06
	Granted	6 448		36.68 – 50.90	44.98
	Exercised	(4 294	)	2.61 – 30.96	10.50
	Cancelled	(942	)	12.50 – 48.05	23.33
Outstanding, December 31, 2006		39 618		3.89 – 50.90	19.24
	Granted	21 104		35.28 – 53.51	46.68
	Exercised	(5 388	)	3.89 – 46.06	11.38
	Cancelled	(1 334	)	12.66 – 50.87	32.84
Outstanding, December 31, 2007		54 000		5.06 – 53.51	30.31
	Granted	5 907		23.30 – 69.97	50.78
	Exercised	(9 823	)	5.06 – 50.86	19.69
	Cancelled	(3 682	)	12.31 – 67.58	41.72
Outstanding, December 31, 2008		46 402		5.06 – 69.97	34.55
Exercisable, December 31, 2008		24 933		5.06 – 50.86	22.55

Common shares authorized for issuance by the Board of Directors that remain available for the granting of future options, at December 31:

(thousands of common shares)	2008	2007	2006
	12 345	14 570	15 940

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2008:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)
5.06 – 8.72	1 723	2	8.29	1 723	8.29
10.67 – 14.46	11 523	3	13.48	11 523	13.48
15.64 – 34.86	5 439	5	20.60	5 417	20.59
35.26 – 46.84	8 127	6	44.34	5 506	44.31
47.02 – 47.91	16 136	6	47.54	345	47.43
48.05 – 83.58	3 454	6	56.22	419	49.59
Total	46 402	5	34.55	24 933	22.55

Fair Value of Options Granted

The fair values of all common share options granted during the period are estimated as at the grant date using a Monte Carlo simulation approach for the SunShare 2012 option plan and the Black-Scholes option-pricing model for all other option plans. The weighted-average fair values of the options granted during the various periods and the weighted-average assumptions used in their determination are as noted below:

	2008	2007	2006
Annual dividend per share	$0.20	$0.19	$0.15
Risk-free interest rate	3.35%	4.22%	4.08%
Expected life	6 years	6 years	5 years
Expected volatility	30%	30%	29%
Weighted-average fair value per option	$13.86	$14.89	$14.59

Stock-based compensation expense recognized for the year ended December 31, 2008 related to stock option plans was $120 million (2007 – $103 million; 2006 – $53 million).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 79

Common share options granted prior to January 1, 2003 are not recognized as compensation expense in the Consolidated Statement of Earnings and Comprehensive Income. The company's reported net earnings attributable to common shareholders and earnings per share prepared in accordance with the fair value method of accounting for stock-based compensation would have been reduced for all common share options granted prior to 2003 to the pro forma amounts stated below:

($ millions, except per share amounts)		2008	2007	2006
Net earnings attributable to common shareholders – as reported		2 137	2 983	2 969
Less: compensation cost under the fair value method for pre-2003 options		4	8	15
Pro forma net earnings attributable to common shareholders for pre-2003 options		2 133	2 975	2 954
Basic earnings per share
	As reported	2.29	3.23	3.23
	Pro forma	2.29	3.23	3.22
Diluted earnings per share
	As reported	2.26	3.17	3.16
	Pro forma	2.26	3.16	3.14

(b)   Deferred Share Units (DSUs)

The company had 1,903,000 DSUs outstanding at December 31, 2008 (2,336,000 at December 31, 2007). DSUs were granted to certain executives under the company's former employee long-term incentive program. Members of the Board of Directors receive one-half, or at their option, all of their compensation in the form of DSUs. DSUs are only redeemable at the time a unitholder ceases employment or Board membership, as applicable.

In 2008, 473,000 DSUs were redeemed for cash consideration of $30 million (2007 – 40,000 redeemed for cash consideration of $2 million; 2006 – 118,000 redeemed for cash consideration of $5 million). Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments. Final DSU redemption amounts are subject to change depending on the company's share price at the time of exercise. Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period. As at December 31, 2008, the total liability related to the DSUs was $45 million (2007 – $126 million), of which $8 million (2007 – $5 million) was classified as current.

During 2008, total pretax compensation expense related to DSUs was a recovery of $51 million (2007 – $21 million; 2006 – $25 million).

(c)    Performance Share Units (PSUs)

During 2008, the company issued 795,000 PSUs (2007 – 830,000; 2006 – 794,000) under its Performance Share Unit Compensation Plan. PSUs granted replace the remuneration value of reduced grants under the company's stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor's performance (performance factor). Performance is measured by reference to the company's total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the anticipated performance factor. This expense is recognized on a straight-line basis over the term of the grant. Pretax recovery recognized for PSUs during 2008 was $30 million (2007 – expense of $60 million; 2006 – expense of $42 million).

(d)   SunShare 2012 Restricted Share Units (RSUs)

In 2008, the company issued 1,078,000 RSUs under the share unit portion of its new employee stock-based compensation plan ("SunShare 2012"). Expense recognized for the year ended December 31, 2008 was $8 million.

80 SUNCOR ENERGY INC. 2008ANNUAL REPORT

14. EARNINGS PER COMMON SHARE

The following is a reconciliation of basic and diluted net earnings per common share:

($ millions)		2008	2007	2006
Net earnings attributable to common shareholders		2 137	2 983	2 969
(millions of common shares)
Weighted-average number of common shares		932	922	918
Dilutive securities:
	Shares issued under stock-based compensation plans	13	20	22
Weighted-average number of diluted common shares		945	942	940
(dollars per common share)
Basic earnings per share (a)		2.29	3.23	3.23
Diluted earnings per share (b)		2.26	3.17	3.16

Note: An option will have a dilutive effect under the treasury stock method only when the average market price of the common stock during the period exceeds the exercise price of the option.

(a)

Basic earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of common shares.

(b)

Diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares.

15. FINANCING EXPENSES (INCOME)

($ millions)		2008		2007		2006
Interest expense on debt		352		189		150
Capitalized interest		(352	)	(189	)	(129	)
	Net interest expense	—		—		21
	Foreign exchange loss (gain) on long-term debt	919		(252	)	—
	Other foreign exchange (gain) loss	(2	)	41		18
Total financing expenses (income)		917		(211	)	39

Cash interest payments in 2008 totaled $328 million (2007 – $183 million; 2006 – $146 million).

16. INVENTORIES

($ millions)	2008	2007
Crude oil	459	542
Refined products	247	320
Materials, supplies and merchandise	203	150
Total	909	1 012

During 2008, inventories of $15.7 billion (2007 – $8.0 billion) were expensed which includes write-downs of inventories totaling $39.9 million (2007 – $15.2 million). No reversals of write-downs were recorded for the twelve month periods ending December 31, 2008 and 2007.

17. RELATED PARTY TRANSACTIONS

The following table summarizes the company's related party transactions after eliminations for the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.

($ millions)			2008	2007	2006
Operating revenues
	Sales to refining and marketing segment joint ventures:
		Refined products	368	329	294
		Petrochemicals	188	163	136

The company has supply agreements with two refining and marketing segment joint ventures for the sale of refined products. The company also has a supply agreement with a refining and marketing segment joint venture for the sale of petrochemicals.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 81

At December 31, 2008, amounts due from refining and marketing segment joint ventures were $13 million (2007 – $17 million).

Sales to and balances with refining and marketing segment joint ventures are established and agreed to by the various parties and approximate fair value.

18. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of accumulated other comprehensive income (loss), net of income taxes, are as follows:

As at December 31 ($ millions)	2008	2007
Unrealized foreign currency translation adjustment	84	(266	)
Unrealized gains and losses on derivative hedging activities	13	13
Total	97	(253	)

19. SUPPLEMENTAL INFORMATION

($ millions)			2008	2007	2006
Geographic areas
	Revenues
		Canada	25 043	14 365	12 930
		U.S.	4 945	4 091	3 532
		Other	101	109	84
			30 089	18 565	16 546
	Total assets
		Canada	29 178	21 615	16 227
		U.S.	2 840	2 556	2 439
		Other	510	338	293
			32 528	24 509	18 959
Export sales (a)			761	876	810
Exploration expenses
	Geological and geophysical		29	26	51
	Other		—	—	1
	Cash costs		29	26	52
	Dry hole costs		61	69	52
	Cash and dry hole costs (b)		90	95	104
	Leasehold impairment (c)		—	—	2
			90	95	106
Taxes other than income taxes
	Excise taxes (d)		570	568	538
	Production, property and other taxes		109	80	57
			679	648	595
Allowance for doubtful accounts			4	3	4

(a)

Sales of crude oil, natural gas and refined products from Canada to customers in the United States and sales of petrochemicals to customers in the United States and Europe.

(b)

Included in the Consolidated Statements of Earnings and Comprehensive Income as exploration expenses.

(c)

Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings and Comprehensive Income.

(d)

Included in operating revenues in the Consolidated Statements of Earnings and Comprehensive Income.

82 SUNCOR ENERGY INC. 2008ANNUAL REPORT

20. DIFFERENCES BETWEEN CANADIAN AND U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The consolidated financial statements have been prepared in accordance with Canadian GAAP. The application of United States GAAP (U.S. GAAP) would have the following effects on earnings and comprehensive income as reported:

($ millions)		Notes	2008		2007		2006
Net earnings as reported, Canadian GAAP			2 137		2 983		2 969
Adjustments
	Derivatives and hedging activities	(a)	—		—		11
	Stock-based compensation expense	(b)	(7	)	15		(19	)
	Research and development costs	(g)	(1	)	(34	)	—
	Income tax expense		1		4		(3	)
Net earnings from continuing operations, U.S. GAAP			2 130		2 968		2 958
	Cumulative effect of change in accounting principles, net of income taxes of $nil (2007 – $nil; 2006 – $2)	(b)	—		—		(4	)
Net earnings, U.S. GAAP			2 130		2 968		2 954
Derivatives and hedging activities, net of income taxes of $nil (2007 – $nil; 2006 – $3)		(a)	—		5		6
Minimum pension liability, net of income taxes of $nil (2007 – $nil; 2006 – $20)		(c)	—		—		39
Pension and Post-retirement obligation, net of income taxes of $20 (2007 – $8)		(c)	43		17		—
Foreign currency translation adjustment			350		(195	)	10
Comprehensive income, U.S. GAAP			2 523		2 795		3 009

Per common share (dollars)		2008	2007	2006
Net earnings per share from continuing operations, U.S. GAAP
	Basic	2.29	3.22	3.22
	Diluted	2.25	3.15	3.14
Net earnings per share, U.S. GAAP
	Basic	2.29	3.22	3.22
	Diluted	2.25	3.15	3.14

The application of U.S. GAAP would have the following effects on the consolidated balance sheets as reported:

				December 31, 2008		December 31, 2007
		Notes		As Reported	U.S. GAAP	As Reported		U.S. GAAP
Current assets				3 237	3 237	3 160		3 160
Property, plant and equipment, net		(g	)	28 316	28 281	20 945		20 911
Deferred charges and other		(i	)	975	1 047	404		449
	Total assets			35 528	32 565	24 509		24 520
Current liabilities				3 529	3 529	3 156		3 156
Long-term borrowings		(i	)	7 875	7 947	3 811		3 856
Accrued liabilities and other		(b,c	)	1 986	2 094	1 434		1 602
Future income taxes		(b,c,g	)	4 615	4 569	4 212		4 147
Share capital		(b	)	1 113	1 201	881		944
Contributed surplus		(b	)	288	313	194		240
Retained earnings		(b,g	)	13 025	12 894	11 074		10 950
Accumulated other comprehensive income (loss)		(c	)	97	18	(253	)	(375	)
	Total liabilities and shareholders' equity			35 528	32 565	24 509		24 520

The application of U.S. GAAP would have no material impact on statements of cash flow as reported.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 83

(a)   Derivative Financial Instruments

The adoption of CICA Handbook section 1530 "Comprehensive Income", section 3251 "Equity", section 3855 "Financial Instruments, Recognition and Measurement", and section 3865 "Hedging" on January 1, 2007 substantially aligned Canadian GAAP with U.S. GAAP for the treatment of the company's derivative financial instruments. As a result, there were no differences between Canadian and U.S. GAAP for the years ended December 31, 2008 and December 31, 2007. For comparative balances for the year ended December 31, 2006 disclosed under U.S. GAAP, the company accounted for its derivative financial instruments under the same method as described in note 7.

Under U.S. GAAP, for the year ended December 31, 2006, the company would have recognized $5 million of hedging gains relating to forecasted cash flows in 2007 and 2008. The net earnings impact of this ineffectiveness was recognized for Canadian GAAP purposes on January 1, 2007 as an adjustment to opening retained earnings.

Accumulated Other Comprehensive Earnings (AOCI) and U.S. GAAP Net Earnings Impacts

A reconciliation of changes in AOCI attributable to derivative hedging activities for the years ended December 31 is as follows:

($ millions)	2008		2007
AOCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $4 (2007 – $4)	13		8
Current period net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1)	(7	)	8
Net unrealized hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $3 (2007 – $2)	7		(3	)
AOCI attributable to derivatives and hedging activities, end of period, net of income taxes of $5 (2007 – $4)	13		13

For the year ended December 31, 2006, U.S. GAAP net earnings increased by $7 million, net of income taxes of $4 million to reflect the impact of ineffectiveness on derivative contracts classified as cash flow hedges.

(b)   Stock-Based Compensation

Following U.S. Financial Accounting Standards Board (FASB) Statement 123(R), "Share-Based Payment", using the modified-prospective approach, the company expenses common share options issued after January 1, 2003 in a manner consistent with Canadian GAAP. The statement requires the recognition of an expense for employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The cost is to be recognized over the period for which an employee is required to provide the service in exchange for the award. In addition, the statement requires recognition of compensation expense for the portion of outstanding unvested awards granted prior to the effective date.

Under Canadian GAAP, the company's Performance Share Units (PSUs) are measured using an intrinsic approach, a fair-value technique not permitted under U.S. GAAP. For U.S. GAAP, our PSUs have been measured using a Monte Carlo Simulation approach to determine fair value. The impact on net earnings for the year ended December 31, 2008 is an expense of $2 million, net of income taxes of $1 million (2007 – recovery of previously recognized stock-based compensation expense of $17 million expense, net of income taxes of $6 million; 2006 – $3 million expense, net of income taxes of $1 million).

Under Canadian GAAP, compensation expense related to common share options granted prior to January 1, 2003 ("pre-2003 options") is not recognized in the Consolidated Statements of Earnings and Comprehensive Income. FAS 123(R) requires the recognition of expense related to the company's pre-2003 options. This resulted in an increase to stock-based compensation expense of $4 million (2007 – $8 million; 2006 – $15 million). There was no impact on income taxes.

(c)    Accounting for Defined Benefit Pension and Other Post-Retirement Plans

On December 31, 2006, the Company adopted FAS 158, "Employers Accounting for Defined Benefit and Other Post Retirement Plans", requiring the recognition of the over funded or under funded status of a defined benefit post-retirement plan as an asset or liability on the balance sheet, with changes to funded status in the year recorded through comprehensive income, net of income taxes. The standard was applied prospectively effective December 31, 2006, as retrospective application was not permitted.

84 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Prior to the adoption of FAS 158, recognition of an additional minimum pension liability was required when the accumulated benefit obligation exceeded the fair value of plan assets to the extent that such excess was greater than accrued pension costs otherwise recorded. For the year ended December 31, 2006, the company would have recognized an increase in other comprehensive income of $39 million, net of income taxes of $20 million. No such adjustment was required under Canadian GAAP.

As required under FAS 158, the minimum pension liability adjustment recorded prior to December 31, 2006 was eliminated upon adoption.

Accumulated Other Comprehensive Income (AOCI) and U.S. GAAP Net Earnings Impacts

($ millions)	2008		2007
AOCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $59 million (2007 – $67 million)	(122	)	(139	)
Amortization of net actuarial loss, net of income taxes of $9 million (2007 – $10 million)	19		21
Amortization of past service costs, net of income taxes of $1 million (2007 – $1 million)	(2	)	(2	)
Adjustments to unamortized net actuarial loss, net of income taxes of $12 million (2007 – $2 million)	26		(2	)
AOCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $39 million (2007 – $59 million)	(79	)	(122	)

Total amount included in AOCI expected to be recognized as components of net periodic benefit cost during 2009 are as follows:

Amortization of net actuarial loss	$25 million
Amortization of past service costs	$(3) million

(d)   Cumulative Foreign Currency Translation

Prior to the adoption of CICA Section 1530 "Comprehensive Income" on January 1, 2007, under Canadian GAAP, foreign currency gains and losses arising on translation of the company's U.S. based foreign operations were recorded directly to shareholders' equity. Under the new Canadian standard, these foreign currency translation gains and losses are treated as they have been under U.S. GAAP, and included as a component of comprehensive income.

(e)   Suspended Exploratory Well Costs

Under U.S. GAAP, the company is permitted to continue the capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The table below provides details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.

Change in capitalized suspended exploratory well costs

($ millions)		2008		2007		2006
Balance, beginning of year		21		23		15
	Additions pending determination of proved reserves	35		14		21
	Charged to dry hole expense	(15	)	(6	)	—
	Reclassifications to proved properties	—		(10	)	(13	)
Balance, end of year		41		21		23
Capitalized for a period greater than one year ($ millions)		6		7		2
Number of projects that have exploratory well costs capitalized for a period greater than 12 months		2		3		3

(f)    Accounting for Purchases and Sales Inventory with the Same Counterparty

Emerging Issues Task Force (EITF) Abstract No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" addresses when it is appropriate to measure purchases and sales of inventory with the same counterparty at fair value and record them in revenues and cost of sales and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold (reported net versus gross). The EITF is effective for transactions entered into subsequent to April 1, 2006.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 85

As required by EITF 04-13, we record certain crude oil, natural gas, petroleum product and chemical purchases and sales entered into contemporaneously with the same counterparty on a net basis within the "purchases of crude oil and products" line in the Consolidated Statements of Earnings and Comprehensive Income. These transactions are undertaken to ensure that the appropriate crude oil is at the appropriate refineries when required and that the appropriate products are available to meet customer demands. These transactions take place in the oil sands and refining and marketing operating segments.

In addition, until 2006, the refining and marketing segment sold finished product and bought coker gas oil as a raw material to be used in the refining process from the same counterparty under terms specified in a single contract. These sales and purchases, as noted in the table below, were recorded at fair value in "revenue" and "purchases of crude oil and products" in the Consolidated Statements of Earnings and Comprehensive Income in accordance with the consensus for Issue 2 in EITF 04-13.

The purchase/sale of contract amounts included in revenue for 2008, 2007 and 2006 are shown below.

($ millions)	2008	2007	2006
Consolidated revenues	30 089	18 565	16 546
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	—	—	5

(1)

Associated costs are in "purchases of crude oil and products".

(g)   Research and Development Costs

Under Canadian GAAP, development expenditures are eligible to be capitalized when specific criteria are met. Under FAS 2, "Accounting for Research and Development Costs", development costs are required to be charged to expense when incurred. As a result, $1 million would have been charged to income during 2008 (2007 – $24 million, net of income taxes of $10 million; 2006 – nil).

(h)   Accounting for Uncertainties in Income Taxes

Effective January 1, 2007, the company adopted the FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 is an interpretation of FASB Statement 109 "Accounting for Income Taxes" and outlines the recognition and related disclosure requirements of uncertain tax positions determined to be more likely than not, defined as greater than 50%, to be sustained on audit.

The adoption of FIN 48 had no impact on net earnings or financial position.

(i)    Deferred Financing Costs

Effective January 1, 2007, under Canadian GAAP, deferred financing costs on long-term debt are included in the carrying value of the related debt. Under U.S. GAAP, these costs are recorded as a deferred charge. As a result, $72 million would have been reclassified from long-term debt to deferred charges and other at December 31, 2008 (December 31, 2007 – $45 million).

(j)    Inventory

Effective January 1, 2008, the company retroactively adopt a FIFO (first-in, first-out) based valuation approach for inventory under Canadian GAAP. We have retroactively adopted the same FIFO valuation approach for U.S. GAAP. As such, there continues to be no impact to net earnings or financial position.

Recently Adopted Accounting Standards

Effective January 1, 2008, the company adopted FAS 157 "Fair Value Measurements" and FAS 159 "The Fair Value Option for Financial Assets and Financial Liabilities". Retrospective application was not permitted. The adoption of these standards had no impact on net earnings or financial position.

Recently Issued Accounting Standards

In December 2007, FASB issued FAS 141(revised), "Business Combinations". The standard, effective January 1, 2009, establishes principles and requirements of the acquisition method for business combinations and the related disclosures. The revisions are to be applied with prospective application, where early adoption is prohibited. No impact to net earnings or financial position is anticipated.

In December 2007, FASB issued FAS 160, "Non-Controlling Interests in Consolidated Financial Statements". The standard is effective January 1, 2009. This interpretation of ARB No. 51 outlines that a non-controlling interest in a subsidiary represents an interest in the consolidated entity, which should be reported as equity in the financial statements. The new standard is to be applied with prospective application, where early adoption is prohibited. No impact to net earnings or financial position is anticipated.

86 SUNCOR ENERGY INC. 2008ANNUAL REPORT

QUARTERLY SUMMARY (unaudited)

FINANCIAL DATA

		For the Quarter Ended								Total Year		For the Quarter Ended								Total Year
($ millions, except per share amounts)		Mar 31 2008		June 30 2008		Sept 30 2008		Dec 31 2008		2008		Mar 31 2007		June 30 2007		Sept 30 2007		Dec 31 2007		2007
Revenues		5 988		7 959		8 946		7 196		30 089		4 053		4 525		4 802		5 185		18 565
Net earnings (loss)
Oil Sands		695		751		854		575		2 875		468		476		494		1 036		2 474
Natural Gas		19		52		18		—		89		4		(4	)	—		25		25
Refining and Marketing		95		91		46		(181	)	51		106		238		69		31		444
Corporate and eliminations		(101	)	(65	)	(103	)	(609	)	(878	)	(2	)	28		64		(50	)	40
		708		829		815		(215	)	2 137		576		738		627		1 042		2 983
Per common share
Net earnings (loss) attributable to common shareholders
	– basic	0.77		0.89		0.87		(0.24	)	2.29		0.63		0.80		0.68		1.12		3.23
	– diluted	0.75		0.87		0.86		(0.24	)	2.26		0.61		0.78		0.66		1.10		3.17
Cash dividends		0.05		0.05		0.05		0.05		0.20		0.04		0.05		0.05		0.05		0.19
Cash flow from (used in) operations
Oil Sands		910		1 174		1 109		645		3 838		600		657		829		1 057		3 143
Natural Gas		82		119		103		64		368		64		70		47		67		248
Refining and Marketing		190		210		85		(207	)	278		180		342		126		68		716
Corporate and eliminations		(21	)	(98	)	49		49		(21	)	(19	)	(42	)	(45	)	8		(98	)
		1 161		1 405		1 346		551		4 463		825		1 027		957		1 200		4 009
OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
	Total production	248.0		174.6		245.6		243.8		228.0		248.2		202.3		239.1		252.5		235.6
	Firebag	34.6		34.7		40.4		39.7		37.4		35.3		36.2		35.8		40.4		36.9
Sales
	Light sweet crude oil	96.2		68.2		48.1		95.7		77.0		105.5		100.0		99.3		102.2		101.7
	Diesel	28.0		21.2		10.9		19.1		19.8		29.5		20.3		23.9		26.0		25.0
	Light sour crude oil	120.8		91.8		157.4		144.2		128.7		112.7		84.2		94.1		118.2		102.3
	Bitumen	0.1		0.3		2.6		3.1		1.5		6.8		3.8		6.6		5.4		5.7
Total sales		245.1		181.5		219.0		262.1		227.0		254.5		208.3		223.9		251.8		234.7

SUNCOR ENERGY INC. 2008ANNUAL REPORT 87

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

		For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008	Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
	Light sweet crude oil	100.93	122.12	121.96	64.58	97.54	68.63	75.64	81.00	87.34	78.03
	Other (diesel, light sour crude oil and bitumen)	93.09	120.52	114.74	59.77	95.15	63.62	66.74	73.76	78.48	70.86
	Total	96.16	121.12	116.32	61.53	95.96	65.70	71.01	76.97	82.07	74.01
	Total (a)	96.22	122.39	117.14	61.20	96.33	65.61	71.01	76.97	82.36	74.07
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		25.10	40.10	27.80	35.35	31.45	21.75	28.40	23.00	24.10	24.15
Natural gas		5.00	8.75	4.30	4.05	5.25	4.50	4.20	2.10	3.60	3.55
Imported bitumen		1.45	2.00	1.90	1.90	1.80	0.05	0.10	—	0.20	0.10
Cash operating costs (3)		31.55	50.85	34.00	41.30	38.50	26.30	32.70	25.10	27.90	27.80
Project start-up costs		0.30	0.90	0.35	0.30	0.40	0.10	1.15	1.10	0.55	0.95
Total cash operating costs (4)		31.85	51.75	34.35	41.60	38.90	26.40	33.85	26.20	28.45	28.75
Depreciation, depletion and amortization		5.75	8.30	6.70	7.50	6.95	4.45	5.85	5.70	5.60	5.40
Total operating costs (5)		37.60	60.05	41.05	49.10	45.85	30.85	39.70	31.90	34.05	34.15
Cash operating costs and total operating costs – In-situ Bitumen Production Only
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		14.60	10.10	10.75	16.55	13.00	11.05	10.60	11.85	9.95	10.85
Natural gas		14.10	14.55	11.30	9.65	12.30	11.05	10.60	9.10	9.15	9.90
Cash operating costs (6)		28.70	24.65	22.05	26.20	25.30	22.10	21.20	20.95	19.10	20.75
Firebag start-up costs		0.35	1.65	0.80	—	0.65	—	—	—	—	—
Total cash operating costs (7)		29.05	26.30	22.85	26.20	25.95	22.10	21.20	20.95	19.10	20.75
Depreciation, depletion and amortization		6.75	6.70	5.40	6.55	6.35	5.35	5.75	6.70	6.80	6.20
Total operating costs (8)		35.80	33.00	28.25	32.75	32.30	27.45	26.95	27.65	25.90	26.95

88 SUNCOR ENERGY INC. 2008ANNUAL REPORT

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

	For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)	Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008	Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007
NATURAL GAS
Gross production (b)
— Natural gas (millions of cubic feet per day)	209	205	197	195	202	191	191	193	210	196
— Natural gas liquids and crude oil (thousands of barrels per day)	3.3	3.4	2.6	3.1	3.1	3.1	3.0	3.1	3.2	3.1
— Total gross production (thousands of barrels of oil equivalent per day)	38.2	37.7	35.4	35.6	36.7	34.9	34.9	35.2	38.2	35.8
— Total gross production (millions of cubic feet equivalent per day)	229	226	213	213	220	209	209	211	229	215
Average sales price (2)
— Natural gas (dollars per thousand cubic feet)	7.30	9.62	9.10	6.90	8.23	7.01	6.85	5.39	6.08	6.32
— Natural gas(a) (dollars per thousand cubic feet)	7.31	9.68	9.14	6.84	8.25	7.14	6.83	5.14	6.02	6.27
— Natural gas liquids and crude oil – conventional (dollars per barrel)	64.14	86.14	96.88	39.31	70.89	56.69	51.21	58.11	60.31	56.64
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)	30.5	33.1	32.0	31.5	31.5	31.6	34.6	35.1	32.8	33.5
Utilization of refining capacity (%)	90	102	99	98	97	97	108	102	87	98

(a)

Excludes the impact of hedging activities.

(b)

Currently Natural Gas production is located in the Western Canada Sedimentary Basin.

Definitions

(1)

Total operations production – Total operations production includes total production from both mining and in-situ operations.

(2)

Average sales price – This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).

(3)

Cash operating costs – Total operations – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non GAAP financial measure see Management's Discussion and Analysis.

(4)

Total cash operating costs – Total operations – Include cash operating costs – Total operations as defined above and cash start-up costs. Per barrel amounts are based on total production volumes.

(5)

Total operating costs – Total operations – Include total cash operating costs – Total operations as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes.

(6)

Cash operating costs – In-situ bitumen production – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes only.

(7)

Total cash operating costs – In-situ bitumen production – Include cash operating costs – In-situ bitumen production as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on in-situ production volumes only.

(8)

Total operating costs – In-situ bitumen production – Include total cash operating costs – In-situ bitumen production as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes only.

Metric conversion

Crude oil, refined products, etc. – 1m³ (cubic metre) = approximately 6.29 barrels
Natural gas – 1m³ (cubic metre) = approximately 35.49 cubic feet

SUNCOR ENERGY INC. 2008ANNUAL REPORT 89

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions, except for ratios)	2008		2007		2006		2005		2004
Revenues
Oil Sands	9 386		6 775		7 407		3 965		3 640
Natural Gas	754		553		578		679		567
Refining and Marketing	21 371		11 805		9 310		7 636		5 317
Corporate and eliminations	(1 422	)	(568	)	(749	)	(499	)	(497	)
	30 089		18 565		16 546		11 781		9 027
Net earnings (loss)
Oil Sands	2 875		2 474		2 775		986		957
Natural Gas	89		25		106		155		114
Refining and Marketing	51		444		244		237		138
Corporate and eliminations	(878	)	40		(156	)	(124	)	(105	)
	2 137		2 983		2 969		1 254		1 104
Cash flow from (used in) operations
Oil Sands	3 838		3 143		3 903		1 961		1 718
Natural Gas	368		248		281		412		314
Refining and Marketing	278		716		451		463		251
Corporate and eliminations	(21	)	(98	)	(111	)	(209	)	(228	)
	4 463		4 009		4 524		2 627		2 055
Capital and exploration expenditures
Oil Sands	7 051		4 431		2 463		1 948		1 119
Natural Gas	339		531		458		363		279
Refining and Marketing	172		376		665		779		418
Corporate	28		77		27		63		31
	7 590		5 415		3 613		3 153		1 847
Total assets	32 528		24 509		18 959		15 335		11 807
Ending capital employed(a)
Short-term and long-term debt, less cash and cash equivalents	7 226		3 248		1 849		2 868		2 109
Shareholders' equity	14 523		11 896		9 084		6 130		4 912
	21 749		15 144		10 933		8 998		7 021
Less capitalized costs related to major projects in progress	(6 583	)	(4 148	)	(2 649	)	(2 938	)	(1 467	)
	15 166		10 996		8 284		6 060		5 554
Total Suncor employees (number at year-end)	6 798		6 465		5 766		5 152		4 605

90 SUNCOR ENERGY INC. 2008ANNUAL REPORT

FIVE-YEAR FINANCIAL SUMMARY (unaudited) (continued)

($ millions, except for ratios)		2008	2007	2006	2005	2004
Dollars per common share
	Net earnings attributable to common shareholders	2.29	3.23	3.23	1.37	1.22
	Cash dividends	0.20	0.19	0.15	0.12	0.115
	Cash flow from operations	4.79	4.35	4.93	2.88	2.27
Ratios
Return on capital employed (%) (a), (b)		22.5	29.3	40.0	21.2	19.4
Return on capital employed (%) (c)		16.3	21.5	30.1	15.4	16.4
Return on shareholders' equity (%) (d)		16.2	28.4	39.0	22.7	25.1
Debt to debt plus shareholders' equity (%) (e)		35.2	24.3	20.7	33.1	30.9
Net debt to cash flow from operations (times) (f)		1.6	0.8	0.4	1.1	1.0
Interest coverage – cash flow basis (times) (g)		14.1	23.2	30.4	17.9	14.9
Interest coverage – net earnings basis (times) (h)		8.9	18.8	25.5	13.5	11.7

(a)

Capital employed – the sum of shareholders' equity plus short-term debt and long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable).

(b)

Net earnings adjusted for after-tax financing expenses (income) for the twelve month period ended; divided by average capital employed. Average capital employed is the sum of shareholders' equity and short-term debt plus long-term debt less cash and cash equivalents, at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non-GAAP financial measure see page 40 of MD&A.

(c)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(d)

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

(e)

Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders' equity.

(f)

Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.

(g)

Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

(h)

Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 91

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2008	2007	2006	2005	2004
OIL SANDS
Production (thousands of barrels per day)	228.0	235.6	260.0	171.3	226.5
Sales(thousands of barrels per day)
Light sweet crude oil	77.0	101.7	110.5	73.3	114.9
Diesel	19.8	25.0	28.2	15.6	27.9
Light sour crude oil	128.7	102.3	118.2	59.8	75.1
Bitumen	1.5	5.7	6.2	16.6	8.4
	227.0	234.7	263.1	165.3	226.3
Average sales price (dollars per barrel)
Light sweet crude oil	97.54	78.03	71.98	49.93	45.60
Other (diesel, light sour crude oil and bitumen)	95.15	70.86	65.17	56.90	39.13
Total	95.96	74.01	68.03	53.81	42.28
Total (a)	96.33	74.07	68.03	62.68	49.78
Cash operating costs – total operations (b)	38.50	27.80	21.70	24.55	15.15
Total cash operating costs – total operations (b)	38.90	28.75	22.10	24.65	15.45
Total operating costs – total operations (b)	45.85	34.15	26.15	29.95	19.05
Cash operating costs – In-situ bitumen production (b), (e)	25.30	20.75	17.30	22.20	22.05
Total cash operating costs – In-situ bitumen production (b), (e)	25.95	20.75	19.00	23.20	28.90
Total operating costs – In-situ bitumen production (b), (e)	32.30	26.95	24.55	28.10	34.90
Ending capital employed excluding major projects in progress	9 352	6 605	5 039	4 468	4 091
Return on capital employed (%) (c)	35.5	43.0	53.1	23.0	22.3
Return on capital employed (%) (d)	21.8	27.9	39.8	16.5	18.3

(a)

Excludes the impact of hedging activities.

(b)

Dollars per barrel rounded to the nearest $0.05. See definitions on page 89.

(c)

See definitions on page 91.

(d)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(e)

In-situ bitumen production commenced commercial operations on April 1, 2004.

92 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

			2008	2007	2006	2005	2004
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
	Gross		202	196	191	190	200
	Net (a)		154	153	141	137	147
Natural gas liquids and crude oil (thousands of barrels per day)
	Gross		3.1	3.1	3.0	3.2	3.5
	Net (a)		2.3	2.4	2.3	2.6	2.6
Total (thousands of boe (b) per day)
	Gross		36.7	35.8	34.8	34.8	36.8
	Net (a)		28.0	27.9	25.8	25.3	27.1
Total (millions of cubic feet equivalent per day)
	Gross		220	215	209	209	221
	Net (a)		168	167	155	152	163
Average sales price
Natural gas (dollars per thousand cubic feet)			8.23	6.32	7.15	8.57	6.70
Natural gas (dollars per thousand cubic feet) (c)			8.25	6.27	6.95	8.59	6.73
Natural gas liquids and crude oil – conventional (dollars per barrel)			70.89	56.64	51.93	54.24	44.99
Ending capital employed			1 152	1 153	857	562	447
Return on capital employed (%) (g)			7.7	2.5	14.9	30.7	26.9
Undeveloped landholdings (d)
Oil and gas (millions of acres)
	Western Canada
		Gross	1.8	1.3	1.2	0.6	0.7
		Net (e)	0.9	0.7	0.7	0.4	0.5
	International
		Gross	0.1	0.1	0.1	0.4	0.7
		Net (e)	—	—	—	0.2	0.4
Net wells drilled (f)
	Exploratory
		Oil	—	—	—	—	—
		Gas	6	7	3	8	5
		Dry	4	6	5	4	5
	Development
		Oil	—	1	1	1	—
		Gas	18	14	13	18	16
		Dry	5	3	4	3	—
			33	31	26	34	26

(a)

Net of royalties

(b)

Barrel of oil equivalent – converts natural gas to oil on the approximate energy equivalent basis that 6,000 cubic feet equals one barrel of oil.

(c)

Excludes the impact of hedging activities.

(d)

Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres

(e)

Our interest in the undeveloped landholdings

(f)

Excludes interests in 4 net exploratory wells and 6 net development wells in progress at the end of 2008.

(g)

See definitions on page 91.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 93

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2008	2007	2006	2005	2004
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
	Retail (a)	4.6	5.2	5.3	5.2	5.3
	Other	11.3	11.6	10.6	10.1	7.9
Distillate		10.8	10.6	8.5	8.3	6.7
Total transportation fuel sales		26.7	27.4	24.4	23.6	19.9
Petrochemicals		0.8	0.9	0.9	0.7	0.8
Asphalt		1.8	1.7	1.2	1.6	1.5
Other		2.2	3.5	3.0	3.0	2.5
Total refined product sales		31.5	33.5	29.5	28.9	24.7
Crude oil supply and refining
	Processed at refineries (thousands of cubic metres per day)	24.7	25.1	21.7	22.7	19.9
Utilization of refining capacity (%)		97	98	85	97	96
Ending capital employed excluding major projects in progress		3 220	2 489	1 938	907	784
Return on capital employed (%) (b)		1.7	20.0	19.3	27.5	16.2
Return on capital employed (%) (b), (c)		1.7	17.4	12.2	17.6	14.9
Retail outlets (d) (number at year-end)		427	419	417	417	421

(a)

Excludes sales through joint venture interests.

(b)

See definitions on page 91.

(c)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(d)

Sunoco-branded and Phillips 66-branded service stations, other private brands managed by refining and marketing, and refining and marketing's interest in service stations managed through joint ventures.

94 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SHARE TRADING INFORMATION (unaudited)

Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU.

		For the Quarter Ended					For the Quarter Ended
		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008		Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007
Share ownership
Average number outstanding, weighted monthly (thousands) (a)		926 216	928 572	930 393	931 524		920 148	920 844	921 578	922 374
Share price (dollars)
Toronto Stock Exchange
	High	56.14	73.10	62.37	43.78		46.43	49.85	50.78	54.74
	Low	40.92	47.78	39.61	18.80		39.83	43.79	44.36	45.63
	Close	49.61	59.20	44.00	23.72		43.93	47.98	47.23	53.96
New York Stock Exchange – US$
	High	56.73	74.28	61.99	41.12		38.90	46.76	50.06	58.99
	Low	39.67	46.31	38.00	14.52		33.89	37.86	41.19	45.70
	Close	52.61	68.56	51.64	19.50		38.18	44.96	47.41	54.37
Shares traded (thousands)
	Toronto Stock Exchange	219 093	226 392	266 381	396 680		218 970	175 568	199 402	200 466
	New York Stock Exchange	342 938	371 303	458 534	720 851		355 471	290 564	321 810	300 176
Per common share information (dollars)
Net earnings attributable to common shareholders		0.77	0.89	0.87	(0.24	)	0.63	0.80	0.68	1.12
Cash dividends		0.05	0.05	0.05	0.05		0.04	0.05	0.05	0.05

(a)

The company had approximately 2,971 holders of record of common shares as at January 31, 2008.

On May 14, 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares.

Information for Security Holders Outside Canada

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to Canadian non-resident withholding tax of 15%. The withholding tax rate is reduced to 5% on dividends paid to a corporation if it is a resident of the United States that owns at least 10% of the voting shares of the company.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 95

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EXHIBIT 99-1

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SUNCOR ENERGY INC. FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008, INCLUDING RECONCILIATION TO U.S. GAAP (NOTE 20)

EX-99.2

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EXHIBIT 99-2

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE FISCAL YEAR
ENDED DECEMBER 31, 2008, DATED FEBRUARY 25, 2009

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 25, 2009

This Management's Discussion and Analysis (MD&A) contains forward-looking information based on Suncor's current expectations, estimates, projections and assumptions. This information is subject to a number of risks and uncertainties, many of which are beyond the company's control. Users of this information are cautioned that actual results may differ materially. For information on material risk factors and assumptions underlying our forward-looking information, see page 42.

This MD&A should be read in conjunction with Suncor's audited Consolidated Financial Statements and the accompanying notes. All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP), unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in Non-GAAP Financial Measures on page 40.

Certain prior year amounts have been reclassified to enable comparison with the current year's presentation.

Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for projects that, in some cases, are still in the early stages of development. These costs are preliminary estimates only. The actual amounts are expected to differ and these differences may be material. For a further discussion of our significant capital projects, see the Significant Capital Project Update on page 14.

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.

The tables and charts in this document form an integral part of this MD&A.

Additional information about Suncor filed with Canadian securities regulatory authorities and the United States Securities and Exchange Commission (SEC), including quarterly and annual reports and the Annual Information Form (AIF), filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A and is not incorporated by reference into this MD&A.

6 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SUNCOR OVERVIEW AND STRATEGIC PRIORITIES

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate three businesses:

•

Oil sands, 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 byproducts.

•

Natural gas, located primarily in western Canada, is a conventional exploration and development operation, focused primarily on the production of natural gas. Its natural gas production offsets Suncor's purchases for internal consumption at our oil sands operations.

•

Refining and marketing, Suncor's downstream operations located in Ontario and Colorado, produce and market the company's refined products to industrial, commercial and retail customers. 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 oil sands and natural gas segments.

In addition to Suncor's integrated oil sands-focused business activities, the company also invests in renewable energy opportunities. Suncor is a partner in four wind power projects and operates Canada's largest ethanol plant.

Suncor's strategic priorities are:

Operational:

•

Focusing on plant and process reliability, efficiency and cost management as part of operational excellence initiatives.

•

Developing our oil sands resource base through mining and in-situ technology and supplementing our bitumen production with third-party supply.

•

Expanding oil sands mining, in-situ and upgrading facilities to increase crude oil production and improving reliability by providing flexible bitumen feed and upgrading options.

•

Integrating oil sands production into the North American energy market through Suncor's refineries and third-party refineries to reduce vulnerability to supply and demand imbalances.

•

Advancing environmental and social performance by closely managing impact to air, water and land while also earning continued stakeholder support for our ongoing operations and growth plans.

•

Maintaining a strong focus on worker, contractor and community health and safety.

Financial:

•

Controlling costs by achieving economies of scale with a strong focus on safe, reliable, cost-effective and environmentally responsible management of our operations.

•

Reducing risk associated with commodity price volatility by entering into hedging arrangements to fix prices for crude oil production and by producing natural gas volumes that offset purchases for internal consumption at oil sands operations.

•

Ensuring appropriate levels of debt and capital spending are in place to support growth in a fiscally responsible manner.

2008 Overview

•

Combined oil sands and natural gas production in 2008 was 264,700 barrels of oil equivalent (boe) per day, compared to 271,400 boe per day in 2007.

•

Oil sands cash operating costs averaged $38.50 per barrel during 2008, compared to $27.80 per barrel in 2007.

•

Strong commodity prices in the first three quarters of the year led to an average WTI benchmark price almost 40% higher than 2007. However, prices weakened significantly through the last quarter of 2008 and into 2009.

•

Commissioning of Suncor's $2.3 billion expansion to one of two oil sands upgraders was completed in the third quarter of 2008. With the completion of this expansion, Suncor has upgrading design capacity of 350,000 bpd.

•

Capital spending in 2008 totalled $7.6 billion. Net debt at year-end 2008 was $7.2 billion, compared to $3.2 billion at the end of 2007.

•

Suncor achieved a 22.5% return on capital employed (ROCE) excluding capitalized costs related to major projects in progress in 2008, compared to 29.3% in 2007.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 7

SELECTED FINANCIAL INFORMATION

Annual Financial Data

Year ended December 31 ($ millions except per share)	2008	2007	2006
Revenues	30 089	18 565	16 546
Net earnings	2 137	2 983	2 969
Total assets	32 528	24 509	18 959
Long-term debt	7 875	3 811	2 363
Dividends on common shares	180	162	127
Net earnings attributable to common shareholders per share – basic	2.29	3.23	3.23
Net earnings attributable to common shareholders per share – diluted	2.26	3.17	3.16
Cash dividends per share	0.20	0.19	0.15

Outstanding Share Data ⁽¹⁾

At December 31, 2008 (thousands)
Number of common shares	935 524
Number of common share options	46 402
Number of common share options – exercisable	24 933

Net Earnings  ⁽²⁾
Year ended December 31
($ millions)

	08	07	06
•  Oil sands	2 875	2 474	2 775
•  Natural gas	89	25	106
•  Refining and marketing	51	444	244

Cash Flow
from Operations  ^{(2), (3)}
Year ended December 31
($ millions)

	08	07	06
•  Oil sands	3 838	3 143	3 903
•  Natural gas	368	248	281
•  Refining and marketing	278	716	451

Ending Capital Employed  ^{(2), (3), (4)}
At December 31
($ millions)

	08	07	06
•  Oil sands	9 352	6 605	5 039
•  Natural gas	1 152	1 153	857
•  Refining and marketing	3 220	2 489	1 938

(1)	On May 14, 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares.
(2)	Excludes Corporate and Eliminations segment.
(3)	Non-GAAP measures. See page 40.
(4)	Excludes major projects in progress.

8 SUNCOR ENERGY INC. 2008ANNUAL REPORT

CONSOLIDATED FINANCIAL ANALYSIS

This analysis provides an overview of our consolidated financial results for 2008 compared to 2007. For a detailed analysis, see the various business segment discussions.

Net Earnings

Our net earnings were $2.137 billion in 2008, compared with $2.983 billion in 2007 (2006 – $2.969 billion). Excluding unrealized foreign exchange impacts on the company's U.S. dollar denominated long-term debt, income tax rate reductions on opening future income tax liabilities, net insurance proceeds received in 2006 (relating to a January 2005 fire), and project start-up costs, earnings were $3.013 billion in 2008, compared to $2.390 billion in 2007 (2006 – $2.348 billion). The increase in earnings is due primarily

to higher annual average price realizations for oil sands and natural gas products. This was partially offset by unscheduled maintenance – which led to higher operating expenses, lower production and increased product purchases – and decreased earnings from our downstream operations due to declining commodity prices in the latter part of the year that reduced the value of inventories.

Although annual average price realizations were stronger in 2008, this was mainly the result of high benchmark commodity prices through the first three quarters of the year. In the fourth quarter of 2008, decreased benchmark commodity prices resulted in price realizations on our oil sands products that were down more than 50% from the second quarter of 2008, and prices have remained low in the first part of 2009.

Net Earnings Components⁽¹⁾

Year ended December 31 ($ millions, after-tax)		2008		2007		2006
Earnings before the following items:		3 013		2 390		2 348
	Impact of income tax rate reductions on opening future income tax liabilities	—		427		419
	Oil sands fire accrued insurance proceeds (2)	—		—		232
	Unrealized foreign exchange gains (loss) on U.S. dollar denominated long-term debt	(852	)	215		—
	Project start-up costs	(24	)	(49	)	(30	)
Net earnings as reported		2 137		2 983		2 969

(1)

This table highlights some of the factors impacting Suncor's after-tax net earnings. For comparability purposes, readers should rely on the reported net earnings that are prepared and presented in the Consolidated Financial Statements and notes in accordance with Canadian GAAP.

(2)

Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown royalties.

Industry Indicators

(Average for the year)	2008	2007	2006
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	99.65	72.30	66.20
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	103.05	76.65	73.05
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty	20.10	22.25	21.45
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	8.95	6.90	7.25
Natural gas (Alberta spot) Cdn$/mcf at AECO	8.15	6.60	7.00
New York Harbour 3-2-1 crack US$/barrel (1)	9.10	13.70	9.80
Exchange rate: US$/Cdn$	0.94	0.93	0.88

(1)

New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking two times the New York Harbour gasoline margin plus the New York Harbour distillate margin and dividing by three.

Revenues were $30.089 billion in 2008, compared with $18.565 billion in 2007 (2006 – $16.546 billion). The increase was primarily due to the following factors:

•

Energy marketing and trading revenues increased to $11.725 billion in 2008, compared to $3.515 billion in 2007. The significant increase was due primarily to the implementation and further development of crude and natural gas trading strategies designed to maximize value from proprietary production and refinery optimization while gaining market expertise and establishing market presence. In addition, higher energy marketing and trading revenues also reflect the stronger average commodity prices in 2008. The results of energy marketing and trading are evaluated net of

SUNCOR ENERGY INC. 2008ANNUAL REPORT 9

energy marketing and trading expenses. Pretax earnings from energy marketing and trading activities in 2008 were $102 million (2007 – $49 million). For a discussion of these net results, see page 38.

•

Operating revenues benefited from a 38% increase in average U.S. dollar WTI benchmark prices, which increased the selling price of oil sands crude oil production. In addition, stronger price realizations for sales of our oil sands sweet blend and diesel product relative to WTI also increased revenue. High commodity prices also increased revenues from our downstream and natural gas segments. As previously discussed, benchmark prices dropped significantly in the fourth quarter of 2008, negatively impacting operating revenues.

Partially offsetting these increases were the following:

•

Oil sands production and sales volumes were lower during 2008, mainly as a result of upgrader reliability and bitumen production issues. In addition, an unplanned shutdown of facilities that supply hydrogen reduced production of higher-value sweet synthetic crude oil and diesel during the third quarter of 2008.

•

Our refining and marketing segment experienced lower refined product demand driven by the high prices of finished products, particularly gasoline.

The cost to purchase crude oil and crude oil products was $7.184 billion in 2008, compared to $5.817 billion in 2007 (2006 – $4.670 billion). The increase was primarily due to the following:

•

Higher benchmark crude oil prices. This had the largest impact on product purchases for our refining and marketing business, as average WTI prices were more than US$27.00/bbl higher than in 2007.

•

Increased purchases of third-party product in our oil sands segment, primarily bitumen purchases to fill additional upgrading capacity, and also product purchases related to increasing the efficiency of cargo shipments made during 2008.

Operating, selling and general expenses were $4.044 billion in 2008 compared with $3.340 billion in 2007 (2006 – $3.066 billion). The primary reasons for the increase were:

•

Higher planned and unplanned maintenance expenditures at our oil sands operations. The planned maintenance work was aimed at improving reliability, while the unplanned maintenance related to work on our upgrading and extraction assets.

•

Increased energy input costs in our oil sands segment, resulting mainly from strong natural gas prices that saw the average benchmark AECO price in 2008 up almost 25% compared to 2007.

Transportation and other expenses were $275 million in 2008, compared to $182 million in 2007 (2006 – $203 million). The increase in transportation costs was primarily due to a larger number of cargo shipments resulting from increased production of sour crude oil caused by the hydrogen facilities outage in the third quarter of 2008.

Depreciation, depletion and amortization (DD&A) was $1.049 billion in 2008, compared to $864 million in 2007 (2006 – $695 million). The increase primarily reflects the construction and commissioning of the expansion to one of our two oil sands upgraders, in addition to higher DD&A in our natural gas segment resulting from increased production from areas with larger capital bases.

Royalty expenses were $890 million in 2008, compared with $691 million in 2007 (2006 – $1.038 billion). The higher royalties in 2008 were primarily due to increased revenues in our oil sands segment, resulting from high crude prices. This was partially offset by an increase in eligible operating and capital expenditures. In addition, natural gas royalties were higher than the prior year, primarily as a result of the strong natural gas benchmark pricing in 2008. For a discussion of Crown royalties, see page 15.

Taxes other than income taxes were $679 million in 2008, compared to $648 million in 2007 (2006 – $595 million). The increase was primarily due to higher property taxes in our oil sands segment as a result of increased rates and an increased asset base.

Financing expense was $917 million in 2008, compared with income of $211 million in 2007 (2006 – expense of $39 million). The increase in financing expense was primarily due to foreign exchange losses on our U.S. dollar denominated long-term debt. Although interest on our long-term debt increased from the prior year due to additional debt issuance during 2008, we continue to capitalize all of this interest expense. Capitalized interest was $352 million in 2008, compared to $189 million in 2007.

Income tax expense was $995 million in 2008 (32% effective tax rate), compared to $566 million in 2007 (16% effective tax rate) and $828 million in 2006 (22% effective tax rate). The significantly lower effective tax rates in 2007 and 2006 resulted from reductions in tax rates that reduced opening future tax rate liabilities. In addition, there was an increase in the effective tax rate in 2008 as a result of Suncor being unable to realize the full benefit of the capital loss that resulted from the unrealized

10 SUNCOR ENERGY INC. 2008ANNUAL REPORT

foreign exchange loss on our U.S. denominated long-term debt.

Corporate Earnings (Expense)

After-tax net corporate expense was $878 million in 2008, compared to earnings of $40 million in 2007 (2006 – $156 million expense). Excluding the impact of group elimination entries, actual after-tax net corporate expense was $869 million in 2008 (2007 – earnings of $43 million; 2006 – $150 million expense).

Breakdown of Net Corporate Earnings (Expense)

Year ended December 31 ($ millions)	2008		2007		2006
Corporate earnings (expense)	(869	)	43		(150	)
Group eliminations	(9	)	(3	)	(6	)
Total	(878	)	40		(156	)

The net expense in the corporate segment in 2008, compared to net earnings in 2007, was primarily due to unrealized foreign exchange losses on our U.S. denominated long-term debt as a result of the weaker Canadian dollar. As a result of debt issuances during 2008, our U.S. long-term debt balance increased to US$4.15 billion at December 31, 2008 (2007 – US$2.15 billion). After-tax unrealized foreign exchange losses on this U.S. debt were $852 million in 2008, compared to gains of $215 million in 2007 (2006 – nil). Partially offsetting the impact of these foreign exchange losses was a recovery of previously recognized stock-based compensation expense as a result of a decline in our share price.

The corporate net cash deficiency of $659 million was unchanged from 2007 (2006 – $403 million). A $146 million decrease in cash resulting from an increase in working capital was offset by less cash being used in operations and investing activities. The decrease in cash used in operations primarily relates to an operational foreign exchange gain in 2008 compared to a loss in 2007, and the decrease in cash used in investing activities is a result of higher capital spending on the Ripley Wind Power Project in 2007.

Consolidated Cash Flow from Operations

Cash flow from operations was $4.463 billion in 2008, compared to $4.009 billion in 2007 (2006 – $4.524 billion). The increase in cash flow from operations was primarily due to the same factors that impacted earnings.

Dividends

Total dividends paid during 2008 were $0.20 per share, compared with $0.19 per share in 2007 (2006 – $0.15 per share). Suncor's Board of Directors periodically reviews the dividend policy, taking into consideration the company's capital spending profile, financial position, financing requirements, cash flow and other relevant factors.

Quarterly Financial Data

		2008 Three months ended					2007 Three months ended
($ millions except per share)		Dec 31		Sept 30	June 30	Mar 31	Dec 31	Sept 30	June 30	Mar 31
Revenues		7 196		8 946	7 959	5 988	5 185	4 802	4 525	4 053
Net earnings (loss)		(215	)	815	829	708	1 042	627	738	576
Net earnings (loss) attributable to common shareholders per share
	Basic	(0.24	)	0.87	0.89	0.77	1.12	0.68	0.80	0.63
	Diluted	(0.24	)	0.86	0.87	0.75	1.10	0.66	0.78	0.61

Variations in quarterly net earnings during 2008 and 2007 were due to a number of factors:

•

Oil sands production and sales volumes decreased during periods of planned and unplanned maintenance and restricted bitumen supply.

•

Changes in benchmark commodity prices throughout 2007 and 2008. WTI averaged US$99.65 per barrel (bbl) in 2008, compared to US$72.30/bbl in 2007.

•

Cash operating costs varied due to changes in oil sands production levels, the timing and amount of maintenance activities, and the price and volume of natural gas used for energy in oil sands operations.

•

Exchange rate fluctuations impacted the realized commodity prices on our products sold in U.S. dollars, affecting the Canadian dollar revenues earned. Changes in the exchange rate also led to unrealized gains/losses on our U.S. dollar denominated long-term debt.

•

Reductions in federal corporate tax rates during the second and fourth quarters of 2007 increased net earnings in those quarters by $67 million and $360 million, respectively.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 11

•

Oil sands Crown royalties varied as a result of changes in crude oil commodity prices and the extent and timing of eligible capital and operating expenditures.

•

Refined product prices fluctuated as a result of global and regional supply and demand, as well as seasonal demand variations.

For further analysis of quarterly results, refer to Suncor's quarterly reports to shareholders available on our website.

LIQUIDITY AND CAPITAL RESOURCES

The current economic environment has impacted Suncor through both reduced price realizations and higher interest rates on future borrowings. As a result of the current market uncertainty, on January 20, 2009, we announced a reduction to our 2009 planned capital spending.

Our capital resources consist primarily of cash flow from operations and available lines of credit. We believe we will have the capital resources to fund our 2009 capital spending program of $3 billion and to meet current working capital requirements through cash flow from operations and our credit facilities, assuming production of 300,000 bpd and a WTI price of US$40/bbl. Our cash flow from operations depends on a number of factors, including commodity prices, production/sales levels, downstream margins, operating expenses, taxes, royalties, and US$/Cdn$ exchange rates.

To provide an additional element of security to our cash flow from operations, we have entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds of approximately $250 million before tax.

In addition, we are closely managing our operational spending, including a freeze on discretionary salary increases as well as implementing a variety of cost-cutting measures throughout the company.

If additional capital is required, we believe adequate additional financing will be available at commercial terms and rates (which are currently higher than in 2008). Our spending is subject to change due to factors such as internal and regulatory approvals and capital availability. Refer to the discussion under Risk Factors Affecting Performance on page 19 for additional factors that may have an impact on our ability to fund our capital requirements.

In May 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares. Information related to common shares, stock-based compensation, and earnings per share has been restated to reflect the impact of the stock split.

The preceding paragraphs contain forward-looking information regarding our liquidity and capital resources and users of this information are cautioned that our actual liquidity and capital resources may vary from our expectations.

Financing Activities

Management of debt levels continues to be a priority given our growth plans. We believe a phased and flexible approach to existing and future growth projects should assist us in maintaining our ability to manage project costs and debt levels.

At December 31, 2008, our net debt (short and long-term debt less cash and cash equivalents) was $7.226 billion, compared to $3.248 billion at December 31, 2007. The increase in debt levels was primarily a result of increased capital spending to fund our growth strategies.

During 2008, the company's $2 billion committed syndicated credit facility was increased to $3.75 billion and its term was extended to 2013, while the company's $330 million committed bilateral credit facility was increased to $480 million and its term extended to 2009. Undrawn lines of credit at December 31, 2008 were approximately $3.0 billion.

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on May 22, 2018. The net proceeds were added to our general funds to repay outstanding commercial paper, which originally funded our working capital needs, sustaining capital expenditures and growth capital expenditures.

In June 2008, the company issued 6.10% Notes with a principal amount of US$1.25 billion and 6.85% Notes with a principal amount of US$750 million under an amended US$3.65 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 1, 2018, and June 1, 2039, respectively.

12 SUNCOR ENERGY INC. 2008ANNUAL REPORT

The net proceeds were added to our general funds, which are used for our working capital needs, sustaining and growth capital expenditures and to repay outstanding commercial paper borrowings.

Interest expense on debt continues to be influenced by the composition of our debt portfolio, and we are currently benefiting from short-term floating interest rates which remain at low levels compared to historical short-term rates. To manage fixed versus floating rate exposure, we have entered into interest rate swaps with investment grade counterparties. At December 31, 2008, we had $200 million of fixed-rate to variable-rate interest swaps (December 31, 2007 – $200 million).

We are subject to financial and operating covenants related to our public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations.

We are currently in compliance with our financial covenant that requires consolidated debt to not be more than 65% of our total capitalization. At December 31, 2008, our consolidated debt to total capitalization was 35% (where consolidated debt is short-term debt plus long-term debt, and total capitalization is consolidated debt plus shareholders' equity). We are also currently in compliance with all operating covenants.

In addition, a very limited number of our commodity purchase agreements, off-balance sheet arrangements (for a discussion of these arrangements see page 15) and derivative financial instrument agreements contain provisions linked to debt ratings that may result in settlement of the outstanding transactions should our debt ratings fall below investment grade status.

All of our debt ratings are currently investment grade. Suncor's current long-term senior debt ratings are BBB+, with a Negative Outlook by Standard & Poor's; A(low), with a Negative Trend by Dominion Bond Rating Service; and Baa1, with a Stable Outlook by Moody's Investors Service.

Aggregate Contractual Obligations

In the normal course of business, the company is obligated to make future payments. These obligations represent contracts and other commitments that are known and non-cancellable.

	Payments Due by Period
($ millions)	Total	2009	2010-2011 (aggregate)	2012-2013 (aggregate)	Later Years
Fixed-term debt and commercial paper (1)	7 815	934	500	—	6 381
Interest payments on fixed-term debt	8 837	435	858	803	6 741
Capital leases	312	9	19	19	265
Employee future benefits (2)	643	48	105	121	369
Asset retirement obligations (3)	3 471	156	476	302	2 537
Non-cancellable capital spending commitments (4)	470	470	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	8 108	383	850	873	6 002
Total	29 656	2 435	2 808	2 118	22 295

In addition to the enforceable and legally binding obligations quantified in the above table, we have other obligations for goods and services and raw materials entered into in the normal course of business, which may terminate on short notice. Commodity purchase obligations for which an active, highly liquid market exists, and which are expected to be re-sold shortly after purchase, are one example of excluded items.

(1)

Includes $4.150 billion of U.S. and $1.800 billion of Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2011 to 2039. Interest rates vary from 5.39% to 7.15%. We entered into interest rate swap transactions maturing in 2011 that resulted in an average effective interest rate in 2008 of 4.8% on $200 million of our Medium Term Notes. Approximately $934 million of commercial paper with an effective interest rate of 2.2% was issued and outstanding at December 31, 2008.

(2)

Represents the undiscounted expected funding by the company to its pension plans as well as benefit payments to retirees for other post-retirement benefits.

(3)

Represents the undiscounted amount of legal obligations associated with site restoration on the retirement of assets with determinable lives.

(4)

Non-cancellable capital commitments related to capital projects totalled approximately $470 million at the end of 2008. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2009, we anticipate spending approximately $2 billion towards sustaining capital.

(5)

Includes transportation service agreements for pipeline capacity, including tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta, as well as energy services agreements to obtain a portion of the power and steam generated by a cogeneration facility owned by a major energy company. Non-cancellable operating leases are for service stations, office space and other property and equipment.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 13

Significant Capital Project Update

In response to current market uncertainty, we announced an update to our Voyageur program schedule on January 20, 2009. A revised capital budget has deferred the company's growth projects. With the new plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.

Suncor spent $7.6 billion on capital and exploration expenditures in 2008, compared to $5.4 billion in 2007 (2006 – $3.6 billion). A summary of the progress on our significant projects under construction to support both our growth and sustaining needs is provided below. All projects listed below have received Board of Director approval. The estimates and target completion dates do not include project commissioning and start-up.

			Cost				Estimated		Target
			Estimate	Estimate	Spent to		% Complete		Completion
Project		Plan	$ millions(1)	% Accuracy(1)	Date		Engineering	Construction	Date
Coker unit		Expected to increase production capacity by 90,000 bpd	2 100	+13/-7	2 300		100	100	Complete
Firebag sulphur plant		Supports emission abatement plan at Firebag; capacity to support Stages 1-6	340	+10/-10	270		90	55	Q2 2009
Steepbank extraction plant		Location and new technologies aimed at improving operational performance	850	+10/-10	690		100	70	Q3 2009
Naphtha unit (2)		Increases sweet product mix	650	+10/-10	650		100	60	TBD
North Steepbank expansion of mine (2)		Expected to generate about 180,000 bpd of bitumen	400	+10/-10	125		55	45	TBD
Voyageur program:
	Firebag (2)	Expansion of Firebag 3-6 is expected to increase bitumen supply	9 000	+18/-13	3 405	(3)			TBD
		– Stage 3					97	50
		– Stage 4 (4), (5)					70	2
		– Stage 5 (4), (5)					15	—
		– Stage 6 (4), (5)					4	—
Voyageur program:
	Upgrader 3 (2)	Expected to increase production capacity by 200,000 bpd	11 600	+12/-8	3 545	(3)	80	15	TBD

(1)

Cost estimates and estimate accuracy reflect budgets approved by Suncor's Board of Directors.

(2)

At this time, construction restart and completion targets for these projects is to be determined (TBD). Cost estimates for TBD projects including those currently on hold and in "safe mode" will be subject to revision upon resumption of projects.

(3)

Spending to date includes procurement of major project components. For Firebag Stage 3, procurement at year-end 2008 was 95% complete; for Stage 4, 80% complete; for Stage 5, 15% complete; and for Stage 6, 50% complete. For Upgrader 3, procurement was 75% complete.

(4)

Pending regulatory approval.

(5)

Construction of shared and common services is included in Stage 3 construction.

The preceding paragraphs and table contain forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results, including target completion dates, for each of these projects may vary from the plans disclosed in the table. For a list of the material risk factors that could cause actual timing, amount of the final capital expenditures and expected

14 SUNCOR ENERGY INC. 2008ANNUAL REPORT

results to differ materially from those contained in the previous table, please see page 19. For additional information on risks, uncertainties and other factors that could cause actual results to differ, please see page 42.

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 project; updates from third parties on delivery of services and goods associated with the project; and estimates from major projects teams on completion of future phases of the project. We have assumed that commitments from third parties will be honoured and that material delays and increased costs related to the risk factors referred to above will not be encountered.

Guarantees, Variable Interest Entities and Off-Balance Sheet Arrangements

At December 31, 2008, the company had various indemnification agreements with third parties as described below.

The company had a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2007 – $170 million) having a maturity of 45 days or less, to a third party. The third party was a multiple party securitization vehicle that provided funding for numerous asset pools. At December 31, 2008, no outstanding accounts receivable had been sold under the program (2007 – nil) and the program has expired. Although the company does not believe it had any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $57 million in 2008 and no contingent liability or earnings impact was recorded for this indemnification as the company believes it had no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2008, were $170 million and approximately $510 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2008 (2007 – $4 million; 2006 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a Variable Interest Entity (VIE) for proceeds of $30 million. The VIE's sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term covered a period of seven years and had been accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2008 and 2007, the VIE did not have any assets or liabilities.

ROYALTIES

Oil Sands Crown Royalties

Under the Province of Alberta's generic oil sands royalty regime in effect to December 31, 2008 (1997 Generic Regime), Alberta Crown royalties for oil sands projects were payable at the rate of 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 at 1% of R. The Alberta government has classified Suncor's current oil sands operations as two distinct "projects" for royalty purposes.

Royalties on our current Firebag in-situ project were under the 1997 Generic Regime until the end of 2008, and assessed based on bitumen value. In December 2008, the government of Alberta enacted the New Royalty Framework which increased royalty rates from the 1997 Generic Regime to a sliding scale royalty of 25% to 40% of R-C, subject to minimum royalty of 1% to 9% of R, depending on oil price. In both cases, the sliding scale royalty moves with increases in WTI prices from Cdn$55/bbl to the maximum rate at a WTI price of Cdn$120/bbl.

Royalties on our base oil sands mining and associated upgrading operations (the "base operations") are modified by Crown Agreements and are assessed on the R-C royalty subject to a minimum royalty as follows:

•

Based on upgraded product values until December 31, 2008 with the rates at 25% of R-C, subject to the 1% minimum royalty of R.

•

Commencing January 1, 2009, a bitumen-based royalty applies pursuant to Suncor's exercise of its option to transition to the bitumen-based 1997 Generic Regime. The royalty rates will remain at 25% of R-C, subject to the 1% minimum royalty of R, but will apply to a revised R-C, where R will be based on bitumen value and C would exclude substantially all upgrading costs.

•

From January 1, 2010 through December 31, 2015, pursuant to our January 2008 Royalty Amending Agreement with the government of Alberta, the New Royalty Framework rates described above will apply to the bitumen royalty for current production levels, subject to a cap of 30% of R-C, and a minimum royalty of 1% to 1.2% of R. In addition, the Suncor Royalty Amending Agreement provides Suncor with a level of certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 15

In 2016 and subsequent years, the royalty rates for all of our oil sands operations (our base operation 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.

Oil Sands Mining and In-Situ Royalties

The following table sets forth our estimates of royalties in the years 2009 through 2013, and certain assumptions on which we have based our estimates.

WTI Price/bbl US$	40	50	60
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.50	7.00	7.50
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	8.00	9.00	11.00
Differential of Maya at the US Gulf Coast less Western Canadian Select at Hardisty, Alberta US$	7.00	7.00	7.00
US$/Cdn$ exchange rate	0.75	0.80	0.85
Crown Royalty Expense (based on percentage of total oil sands revenue) %
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates(1))	1	1	1
2010 to 2013 – Bitumen (new rates – with limits for mining only(1))	1	1	1-5

(1)

Oil Sands royalty rates – see page 15.

The previous table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the ranges disclosed in the table. The royalty ranges disclosed in the table were developed using the following assumptions: current agreements with the government of Alberta, royalty rates and other changes enacted effective January 1, 2009 by the government of Alberta, current forecasts of production, capital and operating costs, and the forward estimates of commodity prices and exchange rates described in the table.

The following material risk factors could cause actual royalty rates to differ materially from the rates contained in the foregoing table:

(i)

The government has enacted new Bitumen Valuation Methodology regulations as part of the implementation of the New Royalty Framework effective January 1, 2009. While the interim bitumen valuation methodology in 2009 has been enacted, the permanent valuation methodology for 2010 has yet to be finalized. For our mining operations, the bitumen valuation methodology is based on our interpretation of the terms of our January 2008 Royalty Amending Agreement. That agreement places certain limitations on the bitumen valuation methodology as recently enacted. If our interpretations of these limitations changes, this could impact the royalties payable to the Crown.

(ii)

The government enacted new Allowed Cost regulations as part of the implementation of the New Royalty Framework effective January 1, 2009. Further clarification of some Allowed Cost business rules is still expected. We believe that we are sheltered through 2015 from the impact of many of these changes for our mining operations due to our January 2008 Royalty Amending Agreement and from the cost-related changes for our in-situ operations which are forecast to remain in pre-payout royalty for the near term. However, potential changes and the interpretation of the Allowed Cost regulations could, over time, have a significant impact on our calculation of royalties.

(iii)

Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project; further changes to applicable royalty regimes by the government of Alberta; changes in other legislation and the occurrence of unexpected events all have the potential to have an impact on royalties payable to the Crown.

Alberta Natural Gas Crown Royalties

In 2008, royalty rates on natural gas production in Alberta were capped at 30% for gas discovered in 1974 or later and 35% for gas discovered prior to 1974. These rates were subject to reduction if (i) gas prices dropped below $3.70/gigajoule ($3.89/mcf), (ii) a gas well qualified for a deep gas royalty holiday incentive, or (iii) a gas well qualified as a low productivity well. The New Royalty Framework, effective from January 1, 2009, is a sliding scale that is dependent on the production rate, depth of the well, and the market price for natural gas, up to a maximum royalty rate of 50%. The framework provides some royalty relief, under the Natural Gas Deep Drilling Program, for wells drilled beyond 2,500 metres true vertical depth, based on the total depth and whether the well is exploratory or developmental. On November 19,

16 SUNCOR ENERGY INC. 2008ANNUAL REPORT

2008, the government of Alberta announced the Transitional Royalty Program available for wells from 1,000 metres to 3,500 metres in measured depth. Companies can elect to be subject to the Transitional Royalty Program for qualifying wells which would cap the maximum royalty at 30%, however, these wells cannot also receive royalty relief from the Natural Gas Deep Drilling Program. The Transitional Royalty Program is available from 2009 to 2013 inclusive. After January 1, 2014, all wells are subject to the New Royalty Framework.

CASH INCOME TAXES

We estimate we will have cash income taxes of 100% to 300% of our provision for income taxes during 2009. We anticipate this increase in 2009 because a portion of Suncor's calendar 2008 income will be included in the calculation of 2009 cash taxes as a result of a different year-end of a Suncor affiliate, and because we anticipate a decrease in the 2009 provision for income taxes. Thereafter, we anticipate our cash income tax position may fluctuate to a maximum of approximately 100% of our provision for income taxes by 2015. Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of deductibility of capital expenditures for income tax purposes, among other things. This estimate is based on the following assumptions: current forecasts of production, capital and operating costs and the commodity prices and exchange rates described in the table "Oil Sands Mining and In-Situ Royalties" on page 16, assuming there are no changes to the current income tax regime. Our outlook on cash income tax is a forward looking statement and users of this information are cautioned that actual cash income taxes may vary materially from our outlook.

DERIVATIVE FINANCIAL INSTRUMENTS

On January 1, 2008, Suncor adopted the Canadian Institute of Chartered Accountants (CICA) Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. These new disclosures have been incorporated in the following discussion and in the notes to our financial statements.

We periodically enter into derivative contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices.

We have estimated fair values of derivative financial instruments by assessing available market information and appropriate valuation methodologies based on industry-accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

Derivative contracts are required to be recorded on the balance sheet at fair value. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the hedged item is recognized. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both cash flow and fair value hedges.

Suncor also periodically enters into derivative financial instruments that either do not qualify for hedge accounting treatment or that Suncor has not elected to document as part of a qualifying hedge relationship. These financial instruments are accounted for using the mark-to-market method, with any changes in fair value immediately recognized in earnings.

Commodity and Treasury Hedging Activities

The company has hedged a portion of its forecasted U.S. dollar denominated sales subject to U.S. dollar West Texas Intermediate (WTI) price risk. In February 2009, we entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds to Suncor of approximately $250 million before tax.

These contracts have not been designated for hedge accounting, and as such, any fair value changes on these contracts are recognized in earnings each period.

In addition to our strategic crude oil hedging program, Suncor uses derivative contracts to hedge risks related to

SUNCOR ENERGY INC. 2008ANNUAL REPORT 17

purchases and sales of natural gas and refined products, and to hedge risks specific to individual transactions.

Settlement of our commodity hedging contracts results in cash receipts or payments for the difference between the derivative contract and market rates for the applicable volumes hedged during the contract term. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings and Comprehensive Income.

We periodically enter into interest rate swap contracts as part of our strategy to manage exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between ourselves and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized as an adjustment to interest expense.

The company also manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate swaps and foreign exchange forward contracts.

Significant commodity contracts outstanding at February 10, 2009 were as follows:

Crude Oil	Quantity (bpd)	Price (US$/bbl)(1)	Revenue Hedged (Cdn$ millions)(2)		Hedge Period
Purchased puts	55 000	60.00	1 319		2009  (3)
Fixed price	126 575	50.73	2 566		2009  (4)
Purchased puts	55 000	60.00	1 485		2010  (3)
Sold puts	54 753	60.00	(1 479	)	2010  (3)
Collars-floor	49 384	50.00	1 111		2010  (3)
Collars-cap	49 986	68.10	1 532		2010  (3)

Natural Gas	Quantity (MMBtu/day)	Price (US$/MMBtu)	Consumption Hedged (Cdn$ millions) (2)	Hedge Period
Fixed price	25 000	6.92	10	2009  (5)

(1)

Price for crude oil contracts is US$ WTI per barrel at Cushing, Oklahoma.

(2)

The revenue hedged is translated to Cdn$ at the January 31, 2009 month-end rate and is subject to change as the US$/Cdn$ exchange rate flucturates during the hedge period.

(3)

Original hedge term is for full year.

(4)

For the period February to December inclusive.

(5)

For the period February to March inclusive.

Significant treasury contracts outstanding at February 10, 2009 were as follows:

Description of Swap Transaction	Principal Swapped ($ millions)	Swap Maturity	2008 Effective Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	4.8%

The earnings impact associated with our commodity and treasury hedging activities in 2008 was a pretax gain of $465 million (2007 – pretax loss of $4 million).

A reconciliation of changes in accumulated other comprehensive income (AOCI) attributable to derivative hedging activities for the twelve month periods ending December 31 is as follows:

($ millions)	2008		2007
AOCI attributable to derivative hedging activities, beginning of the period, net of income taxes of $4 (2007 – $5)	13		8
Current year net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1)	(7	)	8
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $3 (2007 – $2)	7		(3	)
AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2007 – $4)	13		13

18 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Energy Marketing and Trading Activities

In addition to derivative contracts used for hedging activities, Suncor uses physical and financial energy derivatives to earn trading and marketing revenues. These energy contracts are comprised of crude oil, natural gas and refined products derivative contracts. The results of these trading activities are reported as energy marketing and trading revenues and expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pretax gains associated with our energy marketing and trading activities in 2008 were $102 million (2007 – $49 million).

Fair Value of Derivative Financial Instruments

The fair value of derivative financial instruments is the estimated amount we would receive (pay) to terminate the contracts. Such amounts, which also represent the unrealized gain (loss) on the contracts, were as follows at December 31:

($ millions)		2008		2007
Derivative financial instruments accounted for as hedges
	Assets	24		20
	Liabilities	(13	)	(11	)
Derivative financial instruments not accounted for as hedges
	Assets	635		18
	Liabilities	(14	)	(21	)
Net derivative financial instruments		632		6

Risks Associated with Derivative Financial Instruments

Our strategic crude oil hedging program is subject to periodic management reviews to determine appropriate hedge requirements in light of our tolerance for exposure to market volatility as well as the need for stable cash flow to finance future growth.

We may be exposed to certain losses in the event that the counterparties to derivative financial instruments are unable to meet the terms of the contracts. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date. We minimize this risk by entering into agreements with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties.

Energy marketing and trading activities, by their nature, can result in volatile and large positive or negative fluctuations in earnings. A separate risk management function reviews and monitors practices and policies and provides independent verification and valuation of these activities.

For further details on our derivative financial instruments, including additional discussion of exposure to risks and our mitigation activities, see note 7 to the Consolidated Financial Statements on page 63.

RISK FACTORS AFFECTING PERFORMANCE

Our financial and operational performance is potentially affected by a number of factors including, but not limited to, commodity prices and exchange rates, environmental regulations, changes to royalty and income tax legislation, credit market conditions, stakeholder support for activities and growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors Affecting Performance for each of our business segments. A more detailed discussion of our risk factors is presented in our most recent Annual Information Form (AIF)/Form 40-F, filed with securities regulatory authorities. We are continually working to mitigate the impact of potential risks to our stakeholders. This process includes an entity-wide risk review. This internal review is completed annually to ensure all significant risks are identified and appropriately managed. Certain key risk factors are discussed below:

Commodity Prices and Exchange Rates

Our future financial performance remains closely linked to hydrocarbon commodity prices, which may be influenced by many factors including global and regional supply and demand, seasonality, worldwide political events and weather. These factors can cause a high degree of price volatility. For example, from 2006 to 2008, the monthly average price for benchmark WTI crude oil ranged from a low of US$42.04/bbl to a high of US$134.02/bbl. During the same three-year period, the natural gas AECO benchmark monthly average price ranged from a low of $4.45/mcf to a high of $12.11/mcf.

Crude oil prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the US$/Cdn$ currency exchange rate, thereby creating an element of uncertainty. Should the Canadian dollar strengthen compared to the U.S. dollar, the resulting negative effect on net earnings would be partially offset by foreign exchange gains on our U.S. dollar denominated debt. The opposite would occur should the Canadian dollar weaken compared to the U.S. dollar. Cash flow from operations is not impacted by the effects of currency fluctuations on our U.S. dollar denominated debt.

We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 17).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 19

SENSITIVITY ANALYSIS ⁽¹⁾

						Approximate Change in
			2008 Average		Change	Cash Flow from Operations ($ millions)	After-Tax Earnings ($ millions)
Oil Sands
	Realized crude oil price ($/barrel)(2)		95.96	US$	1.00	66	48
	Sales (bpd)		227 000		1 000	16	11
Natural Gas
	Realized natural gas price ($/mcf)(2)		8.23		0.10	5	4
	Sales (mmcf/d)		202		10	18	8
Consolidated
	Exchange rate: US$/Cdn$		0.94		0.01
		Effect on oil sands operations				63	45
		Effect on U.S. denominated long-term debt					(55	)
	Total exchange rate impact					63	(10	)

(1)

The sensitivity analysis shows the main factors affecting Suncor's annual cash flow from operations and earnings based on actual 2008 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2008 results. A change in any one factor could compound or offset other factors.

(2)

Includes the impact of hedging activities. See page 17.

Environmental Regulation and Risk

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require us to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new projects or undertaking significant changes to existing operations. In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air emissions (Criteria Air Contaminants (CACs) and Greenhouse Gases (GHGs)), will impose further requirements on companies operating in the energy industry.

Some of the issues that are, or may in future be, subject to environmental regulation include:

•

the possible cumulative regional impacts of oil sands development;

•

manufacture, import, storage, treatment and disposal of hazardous or industrial waste and substances;

•

the need to reduce or stabilize various emissions to air;

•

withdrawals, use of, and discharges to, water;

•

issues relating to land reclamation, restoration and wildlife habitat protection;

•

reformulated gasoline to support lower vehicle emissions;

•

U.S. implementation of regulation or policy to limit its purchases of oil to oil produced from conventional sources, or U.S. state or federal calculation and regulation of fuel lifecycle carbon content.

Changes in environmental regulation could have a potentially adverse effect on our financial results from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for clean-up costs and damages, and the loss of important permits and licenses.

In 2007, the Alberta government introduced the Climate Change and Emissions Management Amendment Act, which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year. Suncor's oil sands operations are subject to this legislation. The act calls for intensity reductions of 12% commencing July 1, 2007.

In compliance with this new legislation, Suncor filed applications in December 2007 to establish baseline

20 SUNCOR ENERGY INC. 2008ANNUAL REPORT

intensities for our oil sands facility. In March 2009, Suncor must file compliance reports that show what actions the company took during the year to offset intensities. Compliance options available to Suncor include internal emission reductions, utilizing offset projects or contributing to a government climate change emission management fund.

For the compliance period of January 1 to December 31, 2008, the compliance costs to Suncor are estimated at between $7 million and $8 million. Final costs will be determined with the company's March 2009 compliance report filing to the province of Alberta.

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

In 2007, the Canadian federal government introduced the Clean Air Act regulatory framework, which is expected to regulate both greenhouse gas emissions and air pollutants from industrial emitters. Suncor has been engaging in the ongoing consultations on this framework. The financial impact of this proposed legislation will be dependent on the details of Clean Air Act regulations, which were expected to be released by the end of 2008. Now that the Canadian federal government has committed to implement a North American cap and trade system with the United States, it is not certain that the Clean Air Act framework, in its current form, will be implemented.

There remains uncertainty around the outcome and impacts of climate change and other environmental regulations. We continue to actively work to mitigate our environmental impact, including taking action to reduce greenhouse gas emissions, investing in renewable forms of energy such as wind power and biofuels, accelerating land reclamation, installing new emission abatement equipment and pursuing other opportunities such as carbon capture and sequestration.

Regulatory Requirements at Oil Sands Suncor continues work to decrease emissions at our oil sands operations. At our in-situ operation, high emissions in 2007 resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board (now known as the Energy Resources Conservation Board or ERCB). The production cap, which limited production to 42,000 bpd, was lifted in the third quarter of 2008. Suncor's planned $340 million Firebag sulphur plant is expected to play a role in managing sulphur emissions for existing and planned in-situ developments.

Any regulatory requirements placed on us could have a material effect on our business and results of operations.

Tailings Management Another area of risk for Suncor is the reclamation of tailings ponds, which contain water, clay and residual bitumen produced through the extraction process. To reclaim tailings ponds, we are using a process referred to as consolidated tailings (CT) technology. At this time, no ponds have been fully reclaimed using this technology. The success of CT technology and time to reclaim the tailings ponds could increase or decrease our current asset retirement cost estimates. We continue to monitor and assess other possible technologies and/or modifications to the CT process now being used. Regulatory approval of our North Steepbank extension of mine is subject to certain conditions related to the performance of CT technology.

For the Millennium, Steepbank, and North Steepbank expansion of our mine we have posted irrevocable letters of credit equal to approximately $271 million with Alberta Environment, representing security for the maximum reclamation liability in the period January 1 through December 31, 2009. For Suncor's oil sands mining leases 86 and 17, we are required to and have posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced as security for the estimated cost of our reclamation activity. This letter of credit equalled $14 million at December 31, 2008. For more information about our reclamation and environmental remediation obligations, refer to Asset Retirement Obligations in the Critical Accounting Estimates section on page 22.

In February 2009, the ERCB released a directive, Tailings Performance Criteria and Requirements for Oil Sands Mining Schemes. The directive establishes performance criteria for CT operations, a requirement for specific approval and monitoring of CT ponds, a requirement for reporting tailings plans, and changes to the ERCB annual mine plan requirements and approval process to regulate tailings operations. We are currently assessing the impact of the directive.

A new reclamation liability management program is under review by the Province of Alberta. The new program would involve increased reporting of progressive reclamation, an asset/liability-based risk assessment, consideration of reserve life, and posting of security.

Regulatory Approvals Before proceeding with most major projects, we must obtain regulatory approvals. The regulatory approval process involves stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 21

CRITICAL ACCOUNTING ESTIMATES

Critical accounting estimates are defined as estimates that are important to the portrayal of our financial position and operations, and require management to make judgments based on underlying assumptions about future events and their effects. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as our operating environment changes. Critical accounting estimates are reviewed annually by the Audit Committee of the Board of Directors. The following are the critical accounting estimates used in the preparation of our Consolidated Financial Statements.

Asset Retirement Obligations (ARO)

We are required to recognize a liability for the future retirement obligations associated with our property, plant and equipment. An ARO liability is only recognized to the extent there is a legal obligation associated with the retirement of a tangible long-lived asset that we are required to settle as a result of an existing or enacted law, statute, ordinance, written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying our total ARO amount. These individual assumptions can be subject to change based on experience.

The ARO is re-measured every year-end, and incremental increases are discounted to present value using a credit-adjusted risk-free discount rate. The ARO accretes over time until we settle the obligation, the effect of which is included in a separate line in the Consolidated Statements of Earnings and Comprehensive Income entitled accretion of asset retirement obligations. The discount rate is adjusted as appropriate, to reflect long-term changes in market rates and outlook.

An ARO is not recognized for assets with an indeterminate useful life because the amount cannot be reasonably estimated. An ARO for these assets will be recorded in the first period in which the lives of the assets are determinable.

In connection with company and third-party reviews of ARO during 2008, we increased our estimated undiscounted total obligation to $3.498 billion from the previous estimate of $2.231 billion. The increase was mainly due to a change in the oil sands estimate to $3.163 billion from $1.941 billion, primarily reflecting the inclusion of costs related to conversion of plant equipment to process consolidated tailings (CT), additional extraction operating costs related to production of CT, and increased inflationary estimates. The majority of the costs in oil sands are projected to occur over a time horizon extending to approximately 2060.

The current economic conditions resulted in our credit-adjusted risk-free discount rate increasing to 9.0% at December 31, 2008, from 6.0% at December 31, 2007. The discounted amount of our ARO liability was $1.600 billion at December 31, 2008, compared to $1.072 billion at December 31, 2007. If our credit-adjusted risk-free discount rate had remained unchanged at 6.0%, our ARO liability at December 31, 2008 would have been approximately $160 million larger. The ARO liability is reported as part of accrued liabilities and other in the Consolidated Balance Sheets.

In 2009, the increase in the ARO estimate will result in additional after-tax expenses of approximately $60 million.

Employee Future Benefits

We provide a range of benefits to our employees and retired employees, including pensions and other post-retirement benefits. The determination of obligations under our benefit plans and related expenses requires the use of actuarial valuation methods and assumptions. Assumptions typically used in determining these amounts include, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, return on plan assets, mortality rates and future medical costs. The fair value of plan assets is determined using market values. Actuarial valuations are subject to management judgment. Management continually reviews these assumptions in light of actual experience and expectations for the future. Changes in assumptions are accounted for on a prospective basis. Employee future benefit costs are reported as part of operating, selling and general expenses in our Consolidated Statements of Earnings and Comprehensive Income. The accrued benefit liability is reported as part of accrued liabilities and other in the Consolidated Balance Sheets.

The assumed rate of return on plan assets considers the current level of expected returns on the fixed income portion of the plan assets portfolio, the historical level of risk premium associated with other asset classes in the portfolio and the expected future returns on each asset class. The discount rate assumption is based on the year-end interest rate on high-quality bonds with maturity terms equivalent to the benefit obligations. The rate of compensation increases is based on management's judgment. The accrued benefit obligation and net periodic benefit cost for both pensions and other post-retirement

22 SUNCOR ENERGY INC. 2008ANNUAL REPORT

benefits may differ significantly if different assumptions are used. The impact of a 1% change in the assumptions at which pension benefits and other post-retirement benefit liabilities could be effectively settled is disclosed in note 10 to the Consolidated Financial Statements on page 71.

The current economic conditions resulted in an increase to the discount rate used to calculate the year-end benefit obligation to 6.50% at December 31, 2008, from 5.25% at December 31, 2007. This resulted in a $195 million decrease to the benefit obligation. This was partially offset by a $107 million decrease in the value of the plan assets that resulted from lower returns for the plan investments.

Property, Plant and Equipment

We account for our in-situ and natural gas exploration and production activities using the successful efforts method. This policy was selected over the alternative of the full-cost method because we believe it provides timelier accounting of the success or failure of exploration and production activities.

The application of the successful efforts method of accounting requires management to determine the proper classification of activities designated as developmental or exploratory, which then determines the appropriate accounting treatment of the costs incurred. The results from a drilling program can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Where it is determined that exploratory drilling will not result in commercial production, the drilling costs of the exploratory dry hole are written off and reported as part of exploration expenses in the Consolidated Statements of Earnings and Comprehensive Income. Dry hole expense can fluctuate from year to year due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in the exploratory drilling and the degree of risk in drilling in particular areas.

Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance. Such changes may require a test for the potential impairment of capitalized properties based on estimates of future cash flow from the properties. An impairment test may also be required as a result of other economic events. Estimates of future cash flows are subject to significant management judgment concerning oil and gas prices, production quantities and operating costs. Where properties are assessed by management to be fully or partially impaired, the book value of the properties is reduced to fair value and either completely removed (written off) or partially removed (written down) in our records and reported as part of depreciation, depletion and amortization expenses, in the Consolidated Statements of Earnings and Comprehensive Income. Negative revisions in natural gas and in-situ reserves estimates will result in an increase in depletion expenses.

Oil and Gas Reserves

Our oil and gas reserves are evaluated by independent qualified reserves evaluators. The estimation of reserves is an inherently complex process and involves the exercise of professional judgment.

Estimates are based on projected future rates of production, estimated commodity prices, engineering data and the timing of future expenditures, all of which are subject to uncertainty. Changes in reserve estimates can have an impact on reported net earnings through revisions to depreciation, depletion and amortization expense, in addition to determining possible writedowns of property, plant and equipment.

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). Prior to 2008, we presented our disclosures in accordance with U.S. disclosure requirements under an exemption from Canadian securities regulatory authorities which was not renewed following our annual disclosures at December 31, 2007.

As a result, reserves information presented for comparative years has been restated to comply fully with NI 51-101, consistent with the presentation format for December 31, 2008 reserve disclosures.

Our reserves and resources have been evaluated, at December 31, 2008, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (GLJ), in a report dated February 6, 2009 (GLJ Report). The crude oil, natural gas liquids and natural gas reserves estimates presented in the GLJ Report are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

Net reserves represent Suncor's undivided gross (working 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 government of Alberta's enacted New Royalty Framework and our specific oil sands royalty agreements. For a full discussion of our Crown royalties, see page 15.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 23

Assumptions reflect market and regulatory conditions, as required, at December 31, 2008, 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.

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

All of the reserves disclosures presented below reflect forecast pricing. No supplemental constant pricing disclosures have been made.

Reserves Data (Forecast Prices and Costs)

Summary of Oil and Gas Reserves

		Oil(1)		Natural Gas		Natural Gas Liquids
As at December 31, 2008		Working Interest MMbbl	Net MMbbl	Working Interest Bcf	Net Bcf	Working Interest MMbbl	Net MMbbl
Proved Producing
	Conventional	2	2	459	352	5	4
	SCO – Mining	1,571	1,335	—	—	—	—
	SCO – In-Situ	94	91	—	—	—	—
	Total Proved Producing	1,667	1,428	459	352	5	4
Proved Developed Non-Producing
	Conventional	—	—	50	38	—	—
	SCO – In-Situ	45	43	—	—	—	—
	Total Proved Developed Non-Producing	45	43	50	38	—	—
Proved Undeveloped
	Conventional	—	—	30	24	—	—
	SCO – In-Situ	766	658	—	—	—	—
	Total Proved Undeveloped	766	658	30	24	—	—
Total Proved
	Conventional	2	2	539	414	5	4
	SCO – Mining	1,571	1,335	—	—	—	—
	SCO – In-Situ	905	792	—	—	—	—
	Total Proved	2,478	2,129	539	414	5	4
Total Probable
	Conventional	1	—	216	153	2	1
	SCO – Mining	745	626	—	—	—	—
	SCO – In-Situ	1,808	1,506	—	—	—	—
	Total Probable	2,554	2,132	216	153	2	1
Total Proved Plus Probable
	Conventional	3	2	755	567	7	5
	SCO – Mining	2,316	1,961	—	—	—	—
	SCO – In-Situ	2,713	2,298	—	—	—	—
	Total Proved Plus Probable	5,032	4,261	755	567	7	5

(1)

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

24 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Pricing Assumptions

The following table outlines the benchmark reference prices, as at December 31, 2008, reflected by GLJ in their independent reserves report.

Forecast Prices Used in Preparing Reserves Estimates

Year	Inflation %	Bank of Canada Average Noon Exchange Rate $US/$Cdn	NYMEX WTI Crude Oil at Cushing Oklahoma $US/bbl	Light, Sweet Crude Oil at Edmonton (40 API, 0.3%S) $Cdn/bbl	NYMEX Natural Gas at Henry Hub $US/mmbtu	Natural Gas at AECO $Cdn/mmbtu
2009	2.0	0.825	57.50	68.61	7.00	7.58
2010	2.0	0.850	68.00	78.94	7.50	7.94
2011	2.0	0.875	74.00	83.54	8.00	8.34
2012	2.0	0.925	85.00	90.92	8.75	8.70
2013	2.0	0.950	92.01	95.91	9.20	8.95
2014	2.0	0.950	93.85	97.84	9.38	9.14
2015	2.0	0.950	95.73	99.82	9.57	9.34
2016	2.0	0.950	97.64	101.83	9.76	9.54
2017	2.0	0.950	99.59	103.89	9.96	9.75
2018	2.0	0.950	101.59	105.99	10.16	9.95
2019+	2.0	0.950	+2%/yr	+2%/yr	+2%/yr	+2%/yr

The company's weighted average historical prices realized for the year ended December 31, 2008 were $95.96/bbl for synthetic crude oil, $8.23/mcf for natural gas, and $70.89/bbl for natural gas liquids.

Remaining Recoverable Resources

Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca region of Alberta. Based upon independent evaluations conducted by GLJ effective December 31, 2008, our best estimate of remaining recoverable synthetic crude oil resources are as follows:

As at December 31, 2008 (millions of barrels of SCO)	Mining	In-Situ	Total
Total Proved (1)	1,600	900	2,500
Total Probable (1)	700	1,800	2,500
Total Proved Plus Probable Reserves	2,300	2,700	5,000
Contingent Resources – Best Estimate (2), (3)	3,500	6,500	10,000
Remaining Recoverable Resources (4)	5,800	9,200	15,000

(1)

Total proved and total probable reserves as per Summary of Oil and Gas Reserves table.

(2)

Contingent resources are 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. There is no certainty that it will be commercially viable to produce the contingent resources.

(3)

Contingent Resources – Best Estimate is considered to be the best estimate of the quantity 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.

(4)

Remaining recoverable resources are the unrisked arithmetic sum of proved and probable reserves and best estimate contingent resources.

Remaining recoverable resources were 15,500 millions of barrels of SCO at December 31, 2007. The decrease in 2008 was primarily due to additional data and modeling for the Audet leases.

The contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable timeframe, and in some cases due to higher uncertainty as a result of lower core-hole drilling density. Our Voyageur South development area, for which we submitted a regulatory application in 2007, is part of our mining contingent resources. Significant mining contingent resources are also associated with our Audet leases, located north of our Firebag leases and immediately adjacent to leases proposed for mining development by other operators. All of our in-situ leases are associated with our Firebag leases. While we consider the contingent resources to be potentially recoverable under reasonable economic and operating conditions, there is no certainty that it will be commercially viable to produce any portion of them.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 25

CONTROL ENVIRONMENT

Based on their evaluation as of December 31, 2008, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13a-15(e) and 15d-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed by us in reports that we file or submit to Canadian and U.S. securities authorities is recorded, processed, summarized and reported within the time periods specified in Canadian and U.S. securities laws. In addition, as of December 31, 2008, there were no changes in our internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) – 15d-15(f)) that occurred during 2008 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal control over financial reporting and will make any modifications from time-to-time as deemed necessary.

The company has undertaken a comprehensive review of the effectiveness of its internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). For the year ended December 31, 2008, based on that evaluation, the company's internal controls were found to be operating free of any material weaknesses.

The effectiveness of our internal control over financial reporting as at December 31, 2008 was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report, which is included in our audited Consolidated Financial Statements for the year ended December 31, 2008.

Based on their inherent limitations, disclosure control and procedures and internal controls over financial reporting may not prevent or detect misstatements and even those options determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

CHANGE IN ACCOUNTING POLICIES

Inventories

On January 1, 2008, the company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook section 3031 "Inventories". Under the new standard, the use of a LIFO (last-in, first-out) based valuation approach for inventory has been eliminated. The standard also required any impairment to net realizable value of inventory to be written down at each reporting period, with subsequent reversals when applicable. The company transitioned to a FIFO (first-in, first-out) based valuation approach for inventory effective January 1, 2008. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase)	As at December 31 2008	As at December 31 2007
Inventories	110	404
Total assets	110	404
Future income taxes	30	121
Retained earnings	80	283
Total liabilities and shareholders' equity	110	404

Change in Consolidated Statements of Earnings (Loss) and Comprehensive Income

	Twelve months ended December 31
($ millions, increase/(decrease))	2008		2007		2006
Purchases of crude oil and products	270		(153	)	(5	)
Operating, selling and general	24		(51	)	14
Future income taxes	(91	)	53		(7	)
Net earnings (loss)	(203	)	151		(2	)
Per common share – basic (dollars)	(0.22	)	0.16		—
Per common share – diluted (dollars)	(0.22	)	0.16		—

26 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Segmented Net Earnings Impact

		Twelve months ended December 31
($ millions, increase/(decrease))		2008		2007	2006
Net earnings
	Oil sands	(19	)	40	(8	)
	Refining and marketing	(202	)	99	9
	Corporate and eliminations	18		12	(3	)
Total		(203	)	151	(2	)

Capital Disclosures

On January 1, 2008, the company adopted CICA Handbook section 1535 "Capital Disclosures". This section establishes disclosure requirements for management's policies and processes in defining and managing its capital. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard.

Financial Instruments – Disclosures and Presentation

On January 1, 2008, the company adopted CICA Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard.

International Financial Reporting Standards

In February 2008, the Accounting Standards Board confirmed that International Financial Reporting Standards (IFRS) will replace Canadian GAAP in 2011 for publicly accountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP there are significant differences in accounting policies that must be evaluated. More disclosures will be required under IFRS.

The company's IFRS conversion project began in 2008. A formal project plan, governance structure, and a project team, including an external advisor, have been established. The project philosophy is to align with current accounting practices and policies, where possible, to minimize the impact of any changes to the business. Regular reporting is provided to senior management and the Audit Committee of the Board of Directors.

The IFRS conversion project consists of four phases: Diagnostic; Design & Planning/Solution Development; Implementation; and Post Implementation.

To date, the IFRS conversion project team has completed the Diagnostic phase, which involved a high-level review of the major differences between Canadian GAAP and IFRS. This assessment has provided insight on the high risk and complex areas relating to the conversion. These areas include accounting for property, plant and equipment, exploration and evaluation of mineral resources, the effects of changes in foreign currency exchange rates, and alternatives available under IFRS 1 – First Time Adoption of IFRS.

Please see the associated table for certain elements of the transition plan, and an assessment of progress. Note that the project team is working through a detailed project plan and that certain project activities and milestones could change.

Given the progress of the project and outcomes identified, we could change our intentions between the time of communicating these key milestones below and the changeover date. Further, changes in regulation or economic conditions at the date of the changeover or through the project could result in changes to the project activities communicated in the following chart.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 27

Key Activity	Key Milestones	Status
Financial Statement Preparation:    – Identify differences in Canadian       GAAP/IFRS accounting policies.    – Select Suncor's ongoing IFRS policies.    – Develop financial statement format.    – Quantify effects of change in initial IFRS       disclosure and 2010 financial statements.	Senior management and steering committee sign-off for all key IFRS accounting policy choices to occur during 2009. Develop draft financial statement format to occur during 2009.	Completed the IFRS diagnostic during 2008, which involved a high level review of the major differences between Canadian GAAP and IFRS. In-depth analysis of issues and accounting policy choices is currently underway.
Training:   Define and introduce appropriate level of       IFRS expertise for each of the following:    – Financial reporting group and operating       accounting staff.    – Suncor management.    – Audit Committee.	Financial reporting group and operating accounting staff training to occur during 2009 as needed. Additional training will occur throughout the project as needs are reassessed. Suncor management and Audit Committee training scheduled to occur during 2009.	Project team expert resources have been identified to provide insights and training. Training for project team members is occurring throughout the project.
Infrastructure:   Confirm that business processes and systems       are IFRS compliant, including:    – Program upgrades/changes.    – Gathering data for disclosures.	Confirm that systems can address 2010 parallel processing requirements by 2009 and identify deficiency areas. Confirmation that business processes and systems are IFRS compliant will occur throughout the project.	Diagnostic analysis regarding current IT systems completed. Currently reviewing options to address business process changes and parallel processing during 2010.
Control Environment:    – For all accounting policy changes       identified, assess control design and       effectiveness implications.    – Implement appropriate changes.	All key control and design effectiveness implications are being assessed as part of the key IFRS differences and accounting policy choices through 2009.	Analysis of control issues is underway in conjunction with review of accounting issues and policies.
External Communications:   Assess the effects of key IFRS related       accounting policy and financial statement       changes on external communications.   In particular:    – Confirm 2011 investor communications are       IFRS compliant regarding guidance and       expected earnings.    – Monitor and update MD&A       communications package.    – Confirm investor relations process can       respond to IFRS-related queries.	Analyze and publish the effect of IFRS on the financial statements throughout the project.	IFRS disclosure in the MD&A will be updated throughout the project. Vice President, Investor Relations is part of the IFRS Conversion Steering Committee.

RECENTLY ISSUED CANADIAN ACCOUNTING STANDARDS

Goodwill and Intangible Assets

In February 2008, the CICA approved Handbook section 3064 "Goodwill and Intangible Assets". Effective January 1, 2009, this new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs". The standard focuses on the criteria for asset recognition in the financial statements, including those internally developed. The new standard will not materially impact net earnings or financial position, however will result in the reclassification and presentation of certain balances on the balance sheet. At December 31, 2008, $566 million of turnaround costs would have been reclassified as part of property, plant and equipment (December 31, 2007 – $296 million).

28 SUNCOR ENERGY INC. 2008ANNUAL REPORT

OIL SANDS

Located near Fort McMurray, Alberta, our oil sands business forms the foundation of our operations and represents the most significant portion of our assets. The oil sands business recovers bitumen through mining and in-situ development and upgrades it into refinery feedstock, diesel fuel and byproducts. Our marketing plan also allows for sales of bitumen when market conditions are favourable or when operating conditions warrant.

Oil sands strategy focuses on:

•

Acquiring long-life leases with substantial bitumen resources in place.

•

Sourcing low-cost bitumen supply through mining, in-situ development and third-party supply agreements, and upgrading this bitumen supply into high value crude oil products.

•

Increasing production capacity and improving reliability through staged expansion, continued focus on operational excellence and worksite safety.

•

Reducing costs through the application of technologies, economies of scale, direct management of growth projects, strategic alliances with key suppliers and continuous improvement of operations.

•

Pursuing new technology applications to increase production, mitigate costs and reduce environmental impacts.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2008		2007		2006
Revenue	9 386		6 775		7 407
Production (thousands of bpd)	228.0		235.6		260.0
Average sales price ($/barrel)	95.96		74.01		68.03
Net earnings	2 875		2 474		2 775
Cash flow from operations (1)	3 838		3 143		3 903
Total assets	25 795		18 172		13 727
Cash used in investing activities	6 996		4 248		2 230
Net cash surplus (deficiency) before financing activities	(2 555	)	(519	)	2 113
Sales mix (light/heavy mix)	43/57		54/46		53/47
Cash operating costs ($/barrel) (1)	38.50		27.80		21.70
ROCE (%) (1), (2)	35.5		43.0		53.1
ROCE (%) (1), (3)	21.8		27.9		39.8

(1)

Non-GAAP measure. See page 40.

(2)

Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.

(3)

Includes capitalized costs related to major projects in progress.

2008 Overview

•

Oil sands production averaged 228,000 bpd in 2008, compared to 235,600 bpd in 2007. Production was down year-over-year primarily as the result of upgrader reliability and bitumen production issues. In addition, an unplanned shutdown of facilities that supply hydrogen reduced production of higher-value sweet synthetic crude oil and diesel during the third quarter of 2008.

•

Oil sands cash operating costs averaged $38.50 per barrel during 2008, compared to $27.80 per barrel in 2007. The higher costs in 2008 are primarily due to increases in operating expenses, natural gas input costs and third-party bitumen purchases being spread over lower production.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 29

•

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. With the revised plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.

•

During 2008, progress was made on a variety of capital projects that are expected to benefit operational reliability, production and sales. The addition of a new $2.3 billion set of cokers to our upgrading complex, which increased design capacity to 350,000 bpd, was completed during the year. Other work included construction of a naphtha unit (which is intended to enhance product mix) which was approximately 60% complete at year-end, and the Steepbank extraction plant which was approximately 70% complete at year-end.

•

During 2008, we continued to make progress on our Voyageur growth strategy. At December 31, 2008, we had spent approximately $7.0 billion out of the total Voyageur program budget of $20.6 billion.

•

Production from Suncor's Firebag in-situ operations had been limited by regulators to 42,000 bpd due to sulphur emissions that exceeded regulatory limits in 2007. This production cap was lifted during the third quarter of 2008.

Analysis of Net Earnings

Net earnings were $2.875 billion in 2008, compared to $2.474 billion in 2007 (2006 – $2.775 billion). Excluding the impacts of income tax rate reductions on opening future income tax liabilities, net insurance proceeds received in 2006 (relating to the January 2005 fire) and project start-up costs, earnings were $2.899 billion in 2008, compared to $2.104 billion in 2007 (2006 – $2.140 billion).

(1)

Future income tax.

The increase in earnings primarily reflects strong price realizations due to high average benchmark WTI crude oil prices during the first three quarters of the year. This was partially offset by increased operating expenses, decreased production of higher-value sweet crude oil products, and significantly lower price realizations in the fourth quarter of 2008.

Oil sands average production was 228,000 bpd in 2008, compared to 235,600 bpd in 2007. Sales volumes in 2008 averaged 227,000 bpd, compared with 234,700 bpd in 2007. Lower sales volumes decreased 2008 net earnings by $206 million. Production and sales volumes were lower in 2008 due mainly to upgrader reliability and bitumen supply issues. This was partially offset by a shorter planned maintenance shutdown during 2008 (38 days in 2008, compared to a 50-day shutdown in 2007).

Sales price realizations averaged $95.96 per barrel in 2008 (including the impact of pretax hedging losses of $31 million), compared with $74.01 per barrel in 2007 (with pretax hedging losses of $5 million). The average sales price realization was favourably impacted by stronger WTI benchmark crude oil prices and strengthening differentials on our sweet crude blend and diesel products relative to WTI, partially offset by an increased discount to WTI for our sour crude blends and an increased proportion of lower priced sour products in our sales mix.

The net impact of the above sales mix and pricing factors increased net earnings by $2.084 billion in 2008.

30 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Cash Expenses

Cash expenses, which include purchases of crude oil and products, operating, selling and general expenses, transportation and other costs, exploration expenses, and taxes other than income taxes, were $4.055 billion in 2008, compared to $2.782 billion in 2007 (2006 – $2.560 billion). Expenses increased year-over-year primarily due to higher maintenance expenditures aimed at improving reliability, increased energy input costs as a result of strong natural gas pricing, and a significant increase in purchases of both third-party bitumen and product related to transportation of sour crude shipments.

Overall, increased cash expenses reduced net earnings by $941 million.

Royalties

Alberta oil sands Crown royalties increased to $715 million in 2008, compared to $565 million in 2007 (2006 – $911 million). The increased royalty expense is due primarily to higher revenues resulting from strong WTI crude pricing during the first nine months of the year. This was partially offset by the impact of higher operating expenses, lower volumes, and higher capital expenditures eligible for deduction under Crown royalty formulas. Alberta oil sands Crown royalties are subject to completion of audits for 2008 and prior years. Changes to the estimated amounts previously recorded will be reflected in our financial statements on a prospective basis and may be significant. For a further discussion on Crown royalties, see page 15.

Non-Cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $580 million in 2008 from $462 million in 2007 (2006 – $385 million). The increase primarily resulted from continued growth in the depreciable cost base after the commissioning of new assets throughout the year. Higher non-cash expenses decreased net earnings by $95 million.

Revaluation of Future Income Taxes

Reductions to the federal income tax rate in the second and fourth quarters of 2007 resulted in a total decrease of $413 million in the oil sands opening future income tax (FIT) liability balance, and a corresponding increase in the net earnings of the oil sands segment. There were no adjustments to income tax rates during 2008.

Cash Operating Costs

Cash operating costs increased to $3.212 billion in 2008, compared to $2.391 billion in 2007. On a per barrel basis, these costs increased to $38.50 per barrel from $27.80 per barrel in 2007. The increase in cash operating costs per barrel is a result of increases in operating expenses, natural gas input costs and third-party bitumen purchases being spread over lower production. Refer to page 40 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Net Cash Surplus (Deficiency) Analysis

Cash flow from operations was $3.838 billion in 2008, compared to $3.143 billion in 2007 (2006 – $3.903 billion). The increase was primarily due to the same factors that impacted net earnings.

Cash flow used in investing activities increased to $6.996 billion in 2008 from $4.248 billion in 2007 (2006 – $2.230 billion). During 2008, capital spending related primarily to our Voyageur program, Steepbank extraction plant and naphtha unit projects.

Combined, the above factors resulted in a net cash deficiency of $2.555 billion in 2008, compared with a deficiency of $519 million in 2007 (2006 – net cash surplus of $2.113 billion).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 31

Future Expansion

In 2001, Suncor announced plans to pursue a multi-phased growth strategy to increase production capacity at its oil sands plant from 225,000 barrels per day (bpd) to 550,000 bpd in 2012.

The first step in that plan was completed in 2005 when Suncor increased production capacity by 35,000 bpd (bringing total production capacity to 260,000 bpd). During 2008, we completed a $2.3 billion expansion to one of our two upgraders, increasing production design capacity to 350,000 bpd.

Suncor's Board of Directors approved the final phase of this multi-staged growth strategy in January 2008. Our total estimated investment of $20.6 billion for the Voyageur program was comprised of $11.6 billion targeted for construction of a third upgrader and $9 billion for expanding bitumen supply at our Firebag in-situ operation.

In response to current market uncertainty, we announced an update to our Voyageur program schedule on January 20, 2009. A revised capital budget has deferred the company's growth projects. With the new plan, construction on the Voyageur upgrader and Firebag Stage 3 will be wound down and the projects placed in a "safe mode" pending resumption of expansion work. At this time, construction restart and completion targets for these projects, and start up and completion targets for other expansion projects, have not been determined. Capital growth plans will be reviewed on a quarterly basis in light of market conditions and updates provided as details are known.

For further details, see the Significant Capital Projects table on page 14.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•

Our ability to finance oil sands growth and sustaining capital expenditures in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 12.

•

Production reliability risk. Our ability to reliably operate our oil sands facilities in order to meet production targets. We implemented planned maintenance shutdowns in 2008 that are expected to improve reliability.

•

Ability to manage production operating costs. Operating costs could be impacted by inflationary pressures on labour, volatile pricing for natural gas used as an energy source in oil sands processes, and planned and unplanned maintenance. We continue to address these risks through such strategies as application of technologies that help manage operational workforce demand, offsetting natural gas purchases through internal production, investigation of technologies that mitigate reliance on natural gas as an energy source, and an increased focus on preventative maintenance.

•

Our ability to complete projects both on time and on budget. This could be impacted by competition from other projects (including other oil sands projects) for goods and services and demands on the Fort McMurray infrastructure (including housing, roads and schools). We continue to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing oil sands expansion to reduce unit costs, seeking strategic alliances with service providers and maintaining a strong focus on engineering, procurement and project management.

•

Potential changes in the demand for refinery feedstock and diesel fuel. Our strategy is to reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding our customer base and offering a variety of blends of refinery feedstock to meet customer specifications.

•

Volatility in crude oil and natural gas prices, foreign exchange rates and the light/heavy and sweet/sour crude oil differentials. Current prices are well below the average price realized in 2008. We mitigate some of the risk associated with changes in commodity prices through the use of derivative financial instruments (see page 17).

•

Logistical constraints and variability in market demand, which can impact crude movements. These factors can be difficult to predict and control.

•

Changes to royalty and tax legislation and agreements that could impact our business. While fiscal regimes in Alberta and Canada are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company's planned investments, and rates of return on existing investments.

•

Our relationship with our trade unions. Work disruptions have the potential to adversely affect oil sands operations and growth projects. The Communications, Energy and Paperworkers Union Local 707 represents approximately 2,300 oil sands employees. The current collective agreement with the union expires on April 30, 2010.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

32 SUNCOR ENERGY INC. 2008ANNUAL REPORT

NATURAL GAS

Suncor's natural gas business, operating primarily in western Canada, acts as a natural price hedge against the company's purchases for internal consumption at our oil sands operations.

Natural gas strategy focuses on:

•

Building competitive operating areas.

•

Improving base business efficiency, with a focus on operational excellence and work site safety.

•

Pursuing new, low-capital business opportunities.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2008	2007		2006
Revenue	754	553		578
Natural gas production (mmcf/d)	202	196		191
Average natural gas sales price ($/mcf)	8.23	6.32		7.15
Net earnings	89	25		106
Cash flow from operations (1)	368	248		281
Total assets	1 862	1 811		1 503
Cash used in investing activities	316	532		443
Net cash surplus (deficiency) before financing activities	94	(262	)	(189	)
ROCE (%) (1) (2)	7.7	2.5		14.9

(1)

Non-GAAP Measure. See page 40.

(2)

ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.

2008 Overview

•

Total production averaged 220 million cubic feet equivalent per day (mmcfe/d) in 2008, compared to 215 mmcfe/d in 2007. Production during 2008 comprised 92% natural gas and 8% natural gas liquids and crude oil.

•

Purchases of natural gas for internal consumption at our oil sands operations were approximately 143 million cubic feet per day (mmcf/d) during 2008, compared to natural gas production of 202 mmcf/d in 2008.

•

During the second quarter of 2008, Suncor disposed of Arctic properties for proceeds of $24 million.

•

In September, 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.

(1)

Purchases for internal consumption at our oil sands operations.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 33

Analysis of Net Earnings

Natural gas net earnings were $89 million in 2008, compared to $25 million in 2007 (2006 – $106 million). Excluding the impact of income tax rate reductions on opening future income tax liabilities, earnings for 2008 were $89 million, compared to a loss of $14 million in 2007 (2006 – net earnings of $53 million). The increase in earnings was primarily due to higher revenues driven by stronger price realizations including higher sulphur prices and increased production, in addition to a gain on sale of non-core assets and lower dry hole costs. These factors were partially offset by higher royalties and increased depreciation, depletion and amortization expense resulting from increased production from areas with larger capital bases relative to assigned reserves.

The average realized price for natural gas was $8.23 per thousand cubic feet (mcf) in 2008, compared to an average of $6.32 per mcf in 2007, reflecting higher benchmark natural gas prices in the first three quarters of 2008. There was also an increase in price realizations for crude oil and natural gas liquids resulting from higher benchmark prices for those products in the first three quarters of 2008. The net impact of the price variance was an increase in net earnings of $94 million. Strong pricing was also experienced on our sulphur products, resulting in a $36 million positive impact to net earnings.

Natural gas total production was 220 mmcfe/d in 2008, compared to 215 mmcfe/d in the prior year. The increase in 2008 production was primarily due to increased volumes from positive drilling results, offset by natural declines. Increased production volumes positively impacted 2008 net earnings by $11 million.

Cash Expenses

Operating costs, including general and administrative expenses, were $155 million in 2008, a slight increase from $151 million in 2007 (2006 – $119 million). An increase in lifting costs resulting from increased volumes from areas with higher processing costs and reduced third-party processing credits, was partially offset by a reduction in administration costs.

Exploration expenses were $73 million in 2008, compared to $82 million in 2007 (2006 – $82 million). The decrease was mainly due to lower dry hole costs in 2008.

Non-Cash expenses

DD&A expense was $225 million in 2008, compared to $189 million in 2007 (2006 – $152 million). The increase was due to production increases in areas with a higher cost structure.

Royalties

Royalties on production of natural gas, liquids and sulphur were $175 million ($2.17 per thousand cubic feet equivalent (mcfe)) in 2008, an increase from $126 million ($1.61 per mcfe) in 2007 (2006 – $127 million; $1.67 per mcfe). The current year saw both higher production and higher sales price realizations. In 2008 the government of Alberta announced the New Royalty Framework which changed the royalty rates beginning January 1, 2009. Natural gas generated about 76% of its production from Alberta in 2008. For a further discussion on Crown royalties, see page 15.

34 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Net Cash Surplus/Deficiency Analysis

Natural gas net cash surplus was $94 million in 2008, compared with a $262 million deficiency in 2007 (2006 – $189 million deficiency). Cash flow from operations increased to $368 million compared with $248 million in the prior year (2006 – $281 million), mainly due to increased revenues.

Cash used in investing activities decreased to $316 million, compared with $532 million in 2007 (2006 – $443 million) primarily due to a large purchase of developed and undeveloped land made in 2007, as well as reduced drilling activity in 2008.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•

Consistently and competitively finding and developing reserves that can be brought on stream economically.

•

Our ability to finance capital investment to replace reserves or increase processing capacity in a volatile commodity pricing and credit environment. Also refer to Liquidity and Capital Resources on page 12.

•

Volatility in natural gas and liquids prices is not predictable and can significantly impact revenues. Current prices are well below the average price realized in 2008.

•

The impact of market demand for land. Market demand also influences the cost and available opportunities for acquisitions.

•

The impact of market demand for labour and equipment, which in a heated exploration and development market, could increase costs and/or cause delays to projects for natural gas and its competitors.

•

Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in our operating areas. These risks could increase costs and/or cause delays to or cancellation of projects.

•

Risks and uncertainties associated with weather conditions, which can shorten the winter drilling season and impact the spring and summer drilling program, which may result in increased costs and/or delays in bringing on new production.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 35

REFINING AND MARKETING

Refining and marketing operates an 85,000 barrel per day (bpd) capacity refinery in Sarnia, Ontario and a 93,000 bpd capacity refining complex in Commerce City, Colorado, and markets refined products to industrial, wholesale and commercial customers primarily in Ontario and Colorado. Through a combination of joint venture-operated, company-owned and branded-reseller retail stations, we market products to retail customers in Ontario and the Denver area. Assets also include a 200-million litre per year ethanol plant in St. Clair, Ontario, the 480-kilometre Rocky Mountain pipeline system, the 140-kilometre Centennial pipeline system, two product terminals in Ontario, and two product terminals in Colorado. This business also supports Suncor's sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

The refining and marketing business also 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 from the oil sands and natural gas segments.

Refining and marketing's strategy is focused on:

•

Enhancing the profitability of refining operations by improving reliability and product yields and enhancing operational flexibility to process a variety of feedstock, including crude oil streams from oil sands operations.

•

Creating downstream market opportunities to capture greater long-term value from oil sands production.

•

Reducing costs through the application of technologies, economies of scale, an increased focus on reliability through carefully managed maintenance scheduling, strategic alliances with key suppliers and customers and continuous improvement of operations.

•

Increasing the profitability and efficiency of our retail networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)		2008		2007		2006
Revenue		21 371		11 805		9 310
Refined product sales (millions of litres)
	Gasoline	5 819		6 132		5 804
	Total	11 529		12 228		10 803
Net earnings breakdown:
	Downstream earnings	58		403		239
	Energy marketing and trading activities	71		35		22
	Inventory valuation and marketing expense	(78	)	6		(17	)
	Total net earnings	51		444		244
Cash flow from operations (1)		278		716		451
Total assets		4 666		4 825		4 219
Cash used in investing activities		(256	)	(491	)	(787	)
Net cash deficiency before financing activities		(8	)	(29	)	(446	)
ROCE (%) (1) (2)		1.7		20.0		19.3
ROCE (%) (1) (3)		1.7		17.4		12.2

(1)

Non-GAAP measure. See page 40.

(2)

Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures.

(3)

Includes capitalized costs related to major projects in progress.

36 SUNCOR ENERGY INC. 2008ANNUAL REPORT

2008 Overview

•

Lower gasoline margins and demand, weak asphalt and residual pricing, and a decline in crude oil prices at the end of 2008 that reduced the value of our inventories negatively impacted earnings in 2008. This was partially offset by stronger distillate fuel margins.

•

Significantly increased energy marketing and trading activities as a result of the implementation and further development of crude and natural gas trading strategies to maximize value from proprietary production and for refinery optimization and gain market expertise and market presence. Increased earnings from these activities were largely the result of gains on crude oil financial contracts.

•

During the second quarter, additional capital equipment improvements were identified that will be required before the Sarnia refinery can achieve full benefit from modifications made in 2007 to increase sour synthetic crude capacity at the facility. We are currently evaluating our options relating to these capital expenditures.

•

Refinery utilization levels were slightly lower due to softening demand for petroleum products as well as additional scheduled and unscheduled maintenance.

•

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.

Analysis of Net Earnings

Refining and marketing results include the impact of our third-party energy marketing and trading activities that are discussed separately on page 38.

Refining and marketing's net earnings decreased to $51 million in 2008 from $444 million in 2007 (2006 – $244 million). This decrease was primarily due to reduced margins on gasoline, asphalt and other heavy products, as well as softening demand for petroleum products due initially to historically high prices and later to general economic conditions. This was partially offset by increased margins on distillate fuels.

Volumes

Total sales volumes averaged 31.5 10 ³m ³/d (thousands of cubic metres per day), compared to 33.5 10 ³m ³/d in 2007. The decrease in sales was the result of softening demand for petroleum products. Total gasoline sales volumes through our Sunoco and Phillips 66® branded retail network were 1,700 million litres in 2008, down from 1,900 million litres in 2007.

Fuel Margins

Gasoline margins were significantly lower in 2008 as a result of reduced demand for gasoline. We also encountered reduced margins on asphalt mainly due to the high crude price environment. Asphalt margins did recover in the fourth quarter as the price of crude lowered. These factors were partially offset by increased margins on distillate fuels resulting from strong market demand for diesel and jet fuel throughout the year. Crude and product purchases were $8.074 billion in 2008, compared to $6.250 billion in 2007 (2006 – $5.297 billion). The increase was primarily the result of higher crude oil prices during the first three quarters of 2008.

Refinery Utilization

Overall crude refinery utilization averaged 97% in 2008, compared with 98% in 2007. The decrease in refinery utilization was primarily the result of softening demand for petroleum products and additional scheduled and unscheduled maintenance.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 37

Cash and Non-Cash Expenses

Overall, cash and non-cash operating expenses increased by $38 million after-tax in 2008. Cash expenses increased by $18 million after-tax in 2008, primarily due to higher energy and employee related costs. Non-cash expenses increased by $20 million after-tax in 2008, due to increased depreciation, depletion and amortization expense mainly resulting from a full year's depreciation being taken on both the Sarnia refinery oil sands integration project that was completed in 2007 and a comprehensive maintenance turnaround at Sarnia that was completed in the fall of 2007.

Related Party Transactions

The Pioneer and UPI retail facilities joint ventures and the Sun Petrochemicals Company (SPC) joint venture are considered to be related parties to Suncor under Canadian GAAP. Refining and marketing supplies refined petroleum products to the Pioneer and UPI joint ventures, and petrochemical products to SPC. Suncor has a separate supply agreement with each of Pioneer, UPI and SPC.

The following table summarizes our related party transactions with Pioneer, UPI and SPC, after eliminations, for the year. These transactions are in the normal course of operations and have been conducted on the same terms as would apply with third parties.

($ millions)			2008	2007	2006
Operating revenues
	Sales to refining and marketing joint ventures:
		Refined products	368	329	294
		Petrochemicals	188	163	136

At December 31, 2008, amounts due from refining and marketing joint ventures were $13 million, compared to $17 million at December 31, 2007.

Energy Marketing and Trading Activities

These activities involve marketing and trading of crude oil, natural gas, refined products and by-products, and the use of financial derivatives. These activities resulted in net earnings after-tax of $71 million in 2008 compared to $35 million in 2007 (2006 – $22 million). The higher earnings in 2008 compared to 2007 were the result of gains on crude oil financial contracts. For further details on our energy marketing and trading activities, see page 17.

Net Cash Deficiency Analysis

Refining and marketing's net cash deficiency was $8 million in 2008 compared to a net cash deficiency of $29 million in 2007 (2006 – $446 million). Cash flow from operations was $278 million in 2008 compared to $716 million in 2007 (2006 – $451 million). The decrease was primarily due to the same factors that impacted net earnings.

Cash used in investing activities was $256 million in 2008 compared to $491 million in 2007 (2006 – $787 million). Capital expenditures in 2008 were significantly lower than the previous year, as the work related to the Sarnia oil sands integration projects was completed in 2007. Capital spending in 2008 related mainly to planned refinery shutdowns as well as other regulatory related project spending.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•

Management expects that fluctuations in demand and supply for refined products, margin and price volatility, and market competition, including potential new market entrants, will continue to impact the business environment.

•

There are certain risks associated with the execution of capital projects, including the risk of cost overruns. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.

Additional risks impacting Suncor's general operations can be seen at Risk Factors Affecting Performance on page 19. Additional risks, assumptions and uncertainties are discussed on page 42 under Forward-Looking Information.

38 SUNCOR ENERGY INC. 2008ANNUAL REPORT

OUTLOOK

During 2009, management will focus on the following priorities:

•

Operational excellence. Focusing on operational excellence to enhance personal and process safety management, environmental excellence and sustainability, reliability, and people.

•

Achieve annual oil sands production of 300,000 bpd (+5%/-10%) at a cash operating cost average of $33 to $38 per barrel. Increased bitumen supply and reliability improvements in extraction and upgrading are expected to increase production from existing capital assets.

•

Target production from our natural gas business of 210 mmcf equivalent per day (+5%/-5%). Continue to pursue exploration and development of natural gas assets to offset natural gas purchases for internal consumption at our oil sands operations.

•

Continue to focus on safety. Continue efforts to identify and reduce potential process safety hazards and implement enhanced company-wide occupational hygiene and health standards.

•

Maintain a strong balance sheet. Planned capital spending has been reduced to $3 billion for 2009, with major growth capital investment deferred. Strategic hedging of 60% of target 2009 production provides a degree of insurance to the balance sheet.

•

Continue efforts to reduce environmental impact intensity. We expect to complete the sulphur recovery plant at Firebag in mid-2009 with start-up and commissioning taking place throughout the remainder of the year, while work will continue on developing accelerated reclamation technology. Improved oil sands plant reliability is expected to contribute to lower energy and emissions intensity.

Suncor's outlook provides management's targets for 2009 in certain key areas of the company's business. Users of this information are cautioned that the actual results in 2009 may vary materially from the targets disclosed. Readers are cautioned against placing undue reliance on this outlook.

		2009 Full-Year Outlook
Oil Sands
Production (1) (bpd)		300,000 (+5%/-10%)
Sales
	Diesel	11%
	Sweet	39%
	Sour	48%
	Bitumen	2%
Realization on crude sales basket		WTI @ Cushing less Cdn$4.50 to Cdn$5.50 per barrel
Cash operating costs (2)		$33 to $38 per barrel
Natural Gas
Production (3) (mmcf equivalent per day)		210 (+5%/-5%)
	Natural gas	92%
	Liquids	8%

(1)

Includes volumes transferred to Suncor for processing for which the company receives a processing fee. Volumes received under this arrangement are not included as purchases for financial statement presentation.

(2)

Cash operating cost estimates are based on the following assumptions: (i) production volumes and sales mix as described in the table above; and (ii) a natural gas price of $7.10 per gigajoule at AECO. This goal also includes costs incurred for third-party bitumen processing. Cash operating costs per barrel are not prescribed by Canadian generally accepted accounting principles (GAAP). This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Suncor includes this non-GAAP financial measure because investors may use this information to analyze operating performance. This information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See Non-GAAP Financial Measures on page 40.

(3)

Production target includes natural gas liquids (NGL) and crude oil converted into mmcf equivalent at a ratio of one barrel of NGL/crude oil: six thousand cubic feet of natural gas. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This mmcf equivalent may be misleading, particularly if used in isolation.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 39

The 2009 outlook is based on Suncor's current estimates, projections and assumptions for the 2009 fiscal year and is subject to change. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. Assumptions of the 2009 outlook include implementing reliability and operational efficiency initiatives which we expect to minimize unplanned maintenance in 2009.

Factors that could potentially impact Suncor's operations and financial performance in 2009 include:

•

Bitumen supply. Ore grade quality, unplanned mine equipment and extraction plant maintenance, tailings storage and in-situ reservoir performance could impact 2009 production targets. Production could also be impacted by the availability of third-party bitumen.

•

Performance of recently commissioned upgrading facilities. Production rates while new equipment is being lined out are difficult to predict and can be impacted by unplanned maintenance.

•

Unplanned maintenance. Production estimates could be impacted if unplanned work is required at any of our mining, production, upgrading, refining or pipeline assets.

•

Crude oil hedges. Suncor has hedging agreements for approximately 60% of targeted production in 2009 and for 50,000 bpd in 2010.

•

Market instability. Suncor's ability to borrow in the capital debt markets at acceptable rates may be affected by market instability.

For additional information on risk factors that could cause actual results to differ, please see page 19.

NON-GAAP FINANCIAL MEASURES

Certain financial measures referred to in this MD&A are not prescribed by Canadian generally accepted accounting principles (GAAP). 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), return on capital employed (ROCE), and cash and total operating costs per barrel data 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.

Cash Flow from Operations per Common Share

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of our Consolidated Financial Statements.

For the year ended December 31	2008	2007	2006
Cash flow from operations ($ millions)	4 463	4 009	4 524
Weighted average number of common shares outstanding – basic (millions of shares)	932	922	918
Cash flow from operations – basic ($ per share)	4.79	4.35	4.93

40 SUNCOR ENERGY INC. 2008ANNUAL REPORT

ROCE

For the year ended December 31 ($ millions, except ROCE)		2008	2007		2006
Adjusted net earnings
Net earnings		2 137	2 983		2 969
Add: after-tax financing expenses (income)		852	(179	)	26
	A	2 989	2 804		2 995
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents		3 248	1 849		2 868
Shareholders' equity		11 896	9 084		6 130
	B	15 144	10 933		8 998
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents		7 226	3 248		1 849
Shareholders' equity		14 523	11 896		9 084
	C	21 749	15 144		10 933
Average capital employed	(B+C)/2=D	18 447	13 039		9 966
Average capitalized costs related to major projects in progress	E	5 149	3 454		2 476
ROCE (%)	A/(D-E)	22.5	29.3		40.0

Oil Sands Operating Costs – Total Operations

		2008			2007			2006
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		3 124			2 384			2 212
	Less: natural gas costs, inventory changes, stock-based compensation and other	(524	)		(301	)		(375	)
	Less: non-monetary transactions	(111	)		(102	)		(126	)
Accretion of asset retirement obligations		55			40			28
Taxes other than income taxes		80			55			36
Cash costs		2 624		31.45	2 076		24.15	1 775		18.70
Natural gas		438		5.25	307		3.55	276		2.90
Imported bitumen (net of other reported product purchases)		150		1.80	8		0.10	6		0.10
Cash operating costs		3 212		38.50	2 391		27.80	2 057		21.70
Project start-up costs		35		0.40	60		0.95	38		0.40
Total cash operating costs		3 247		38.90	2 451		28.75	2 095		22.10
Depreciation, depletion and amortization		580		6.95	462		5.40	385		4.05
Total operating costs		3 827		45.85	2 913		34.15	2 480		26.15
Production (thousands of barrels per day)				228.0			235.6			260.0

Oil Sands Operating Costs – In-Situ Bitumen Production Only

	2008			2007			2006
(unaudited)	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	334			273			209
Less: natural gas costs and inventory changes	(168	)		(134	)		(103	)
Taxes other than income taxes	12			7			4
Cash costs	178		13.00	146		10.85	110		8.95
Natural gas	168		12.30	134		9.90	103		8.35
Cash operating costs	346		25.30	280		20.75	213		17.30
In-situ (Firebag) start-up costs	9		0.65	—		—	21		1.70
Total cash operating costs	355		25.95	280		20.75	234		19.00
Depreciation, depletion and amortization	87		6.35	83		6.20	68		5.55
Total operating costs	442		32.30	363		26.95	302		24.55
Production (thousands of barrels per day)			37.4			36.9			33.7

SUNCOR ENERGY INC. 2008ANNUAL REPORT 41

Legal Notice – Forward-Looking Information

This Management's Discussion and Analysis contains certain forward-looking statements and other information that are based on Suncor's current expectations, estimates, projections and assumptions made by the company in light of its experience and its perception of historical trends.

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

Suncor's outlook includes a production range of +5%/-10% based on our current expectations, estimates, projections and assumptions. Uncertainties in the estimating process and the impact of future events may cause actual results to differ, in some cases materially, from our estimates. Assumptions are based on management's experience and perception of historical trends, current conditions, anticipated future developments and other factors believed to be relevant. For a description of assumptions and risk factors specifically related to the 2009 outlook, see page 40.

The risks, uncertainties and other factors that could influence actual results include, but are not limited to, market instability affecting Suncor's ability to borrow in the capital debt markets at acceptable rates; availability of third-party bitumen; success of hedging strategies, maintaining a desirable debt to cashflow ratio; changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor's products; commodity prices, interest rates and currency exchange rates; Suncor's 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 or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor's capital assets; the cumulative impact of other resource development; the cost of compliance with current and future environmental laws; the accuracy of Suncor's reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations 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 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 Suncor or other parties whose operations or assets directly or indirectly affect Suncor. These foregoing important factors are not exhaustive.

Many of these risk factors are discussed in further detail throughout this Management's Discussion and Analysis and in the company's Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

42 SUNCOR ENERGY INC. 2008ANNUAL REPORT

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EXHIBIT 99-2

MANAGEMENT'S DISCUSSION AND ANALYSIS FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008, DATED FEBRUARY 25, 2009

EX-99.3

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EXHIBIT 99-3

CONSENT OF PRICEWATERHOUSECOOPERS LLP

CONSENT OF INDEPENDENT ACCOUNTANTS

We hereby consent to inclusion in this Annual Report on Form 40-F and the incorporation by reference in the registration statements on Form F-3 (File No. 333-7450), Form S-8 (File No. 333-87604), Form S-8 (File 333-112234), Form S-8 (File No. 333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form F-9 (File No. 333-14242), Form F-9 (File No. 333-140797) and Form F-9 (File No. 333-151347) of Suncor Energy Inc., of our report dated February 25, 2009 relating to the consolidated financial statements and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders.

Chartered Accountants
Calgary, Alberta
March 2, 2009

"PricewaterhouseCoopers" refers to PricewaterhouseCoopers LLP, an Ontario limited liability partnership, or, as the context requires, the
PricewaterhouseCoopers global network or other member firms of the network, each of which is a separate and independent legal entity.

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EXHIBIT 99-3

CONSENT OF PRICEWATERHOUSECOOPERS LLP

EX-99.4

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EXHIBIT 99-4

CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.

TO: Suncor Energy Inc.
The Securities and Exchange Commission
The Securities Regulatory Authorities of Each of the Provinces of Canada

Dear Sirs

Re:        Suncor Energy Inc.

We refer to the following report (the "Report"), prepared by GLJ Petroleum Consultants Ltd.:

•

the Reserves Assessment and Evaluation of Canadian Oil and Gas Properties of Suncor Energy Inc. effective December 6, 2008 and dated February 6, 2009;

We hereby consent to the use of our name, reference to and excerpts from the said Report by Suncor Energy Inc. in its Annual Report on Form 40-F and the incorporation by reference in the registration statements on Form F-3 (File No. 333-7450), Form S-8 (File No. 333-87604), Form S-8 (File 333-112234), Form S-8 (File No.333-118648), Form S-8 (File No. 333-124415), Form S-8 (File No. 333-149532), Form F-9 (File No. 333-14242), Form F-9 (File No. 333-140797) and Form F-9 (File No. 333-151347) of Suncor Energy Inc., of our Report.

We have read the AIF and the Form 40-F and have no reason to believe that there are any misrepresentations in the information contained therein that is derived from our Report or that are within our knowledge as a result of the services which we performed in connection with the preparation of the Reports.

	Yours very truly,
	GLJ PETROLEUM CONSULTANTS LTD.
	"GLJ PETROLEUM CONSULTANTS LTD."
	Dana B. Laustsen, P. Eng. Executive Vice-President
Dated: March 2, 2009 Calgary, Alberta CANADA

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EXHIBIT 99-4

CONSENT OF GLJ PETROLEUM CONSULTANTS LTD.

EX-99.5

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EXHIBIT 99-5

CERTIFICATION

        I, RICHARD L. GEORGE, certify that:

1.

I have reviewed this annual report on Form 40-F of the Issuer;

2.

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

3.

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

4.

The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.

The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

DATE:
March 2, 2009

/s/ "Richard L. George"
RICHARD L. GEORGE
President and Chief Executive Officer

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EXHIBIT 99-5

CERTIFICATION

EX-99.6

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EXHIBIT 99-6

CERTIFICATION

        I, J. KENNETH ALLEY, certify that:

1.

I have reviewed this annual report on Form 40-F of the issuer;

2.

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

3.

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

4.

The issuer's other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the issuer and have:

(a)

Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this annual report is being prepared;

(b)

Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)

Evaluated the effectiveness of the issuer's disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

(d)

Disclosed in this report any change in the issuer's internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer's internal control over financial reporting; and

5.

The issuer's other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer's auditors and the audit committee of the issuer's board of directors (or persons performing the equivalent functions):

(a)

All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer's ability to record, process, summarize and report financial information; and

(b)

Any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer's internal control over financial reporting.

DATE:
March 2, 2009

/s/ "J. Kenneth Alley"
J. KENNETH ALLEY
Senior Vice President and Chief Financial Officer

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EXHIBIT 99-6

CERTIFICATION

EX-99.7

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EXHIBIT 99-7

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ENACTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the annual report of Suncor Energy Inc. (the "Company") on Form 40-F for the fiscal year ending December 31, 2008 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, RICHARD L. GEORGE, President and Chief Executive Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ "Richard L. George" RICHARD L. GEORGE President and Chief Executive Officer Suncor Energy Inc.
DATE:	March 2, 2009

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EXHIBIT 99-7

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ENACTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

EX-99.8

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EXHIBIT 99-8

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,
AS ENACTED PURSUANT TO
SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

        In connection with the annual report of Suncor Energy Inc. (the "Company") on Form 40-F for the fiscal year ending December 31, 2008 as filed with the Securities and Exchange Commission on the date hereof (the "Report"), I, J. KENNETH ALLEY, Senior Vice President and Chief Financial Officer of the Company, certify, pursuant to 18 U.S.C. section 1350, as adopted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that:

1.

The Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934; and



2.

The information contained in the Report fairly presents, in all material respects, the financial condition and results of operations of the Company.

/s/ "J. Kenneth Alley" J. KENNETH ALLEY Senior Vice President and Chief Financial Officer Suncor Energy Inc.
DATE:	March 2, 2009

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EXHIBIT 99-8

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350, AS ENACTED PURSUANT TO SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002