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:
Commission File Number: December 31, 2007
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, 2007 there were 462,782,806 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 preceding 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 3, 2008

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

TABLE OF CONTENTS	ii
GLOSSARY OF TERMS	iii
CONVERSION TABLE	vii
CURRENCY	viii
FORWARD-LOOKING STATEMENTS	viii
NON GAAP FINANCIAL MEASURES	ix
CORPORATE STRUCTURE	1
GENERAL DEVELOPMENT OF THE BUSINESS	2
NARRATIVE DESCRIPTION OF THE BUSINESS	7
NATURAL GAS (NG)	10
REFINING AND MARKETING (R&M)	12
MATERIAL CONTRACTS	18
RESERVES ESTIMATES	18
REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE	20
VOLUNTARY OIL SANDS RESERVES AND RESOURCES DISCLOSURE	29
SUNCOR EMPLOYEES	31
RISK FACTORS	32
SELECTED CONSOLIDATED FINANCIAL INFORMATION	40
MANAGEMENT’S DISCUSSION AND ANALYSIS	41
DESCRIPTION OF CAPITAL STRUCTURE	41
MARKET FOR OUR SECURITIES	42
DIRECTORS AND EXECUTIVE OFFICERS	43
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	47
TRANSFER AGENT AND REGISTRAR	47
INTERESTS OF EXPERTS	48
FEES PAID TO AUDITORS	48
RELIANCE ON EXEMPTIVE RELIEF	50
LEGAL PROCEEDINGS	51
ADDITIONAL INFORMATION	51
	ii

GLOSSARY OF TERMS

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

Barrel of Oil Equivalent (BOE)

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

Best Estimate Resources

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

Bitumen/Heavy Crude Oil

A naturally occurring viscous tar-like mixture, mainly containing hydrocarbons heavier than pentane, which is not recoverable at a commercial rate in its naturally occurring viscous state through a well without using enhanced recovery methods.  When extracted, bitumen/heavy crude oil may be upgraded into crude oil and other petroleum products.

Capacity

Maximum annual average output that may be achieved from a facility in ideal operating conditions in accordance with current design specifications.

Coal Bed Methane

Natural gas produced from wells drilled into a coal formation.

Contingent Resources

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

Conventional Crude Oil

Crude oil produced through wells by standard industry recovery methods.

Conventional Natural Gas

Natural gas produced from all geological strata, excluding coal bed methane.

Crude Oil

Unrefined liquid hydrocarbons, excluding natural gas liquids.

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Developed Reserves

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

Development Costs

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

Downstream

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

Dry Hole/Well

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

Feedstock

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

Finding Costs

Includes the cost of and investment in undeveloped land, geological and geophysical activities, exploratory drilling and direct administrative costs necessary to discover crude oil and natural gas reserves.

Gross Production/Reserves

Suncor’s working interest in production/reserves, as the case may be, before deducting Crown royalties, freehold and overriding royalty interests.

Gross Wells/Land Holdings

Total number of wells or acres, as the case may be, in which Suncor has an interest.

Heavy Fuel Oil

Residue from refining of conventional crude oil that remains after lighter products such as gasoline, petrochemicals and heating oils have been extracted. This product traditionally sells at less than the cost of crude oil.

In-situ Oil

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

Lifting Costs

Includes all expenses related to the operation and maintenance of producing or producible wells and related facilities, natural gas plants and gathering systems.

iv

MD&A

Suncor’s Management’s Discussion and Analysis dated February 27, 2008, accompanying its audited consolidated financial statements, notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2007, which is incorporated by reference herein.

Natural Gas

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

Natural Gas Liquids

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

Net Production/Reserves

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

Net Wells/Land Holdings

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

Overburden

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

Oil Sands

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

Probable Reserves¹

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

1

We are subject to Canadian disclosure rules in connection with the reporting of reserves. However, we have received exemptive relief from Canadian securities administrators permitting us to report our reserves in accordance with U.S. disclosure practices. Although U.S. companies do not disclose probable reserves for non-mining properties, we voluntarily disclose probable reserves for our Firebag in-situ leases as we believe this information is useful to investors. In addition, U.S. companies do not disclose resources but we believe this information is also useful to investors and accordingly disclose “contingent resources” in accordance with National Instrument 51-101. See “RESERVES ESTIMATES” on page 18 for a description of how our voluntary reserves disclosure differs from our U.S. required disclosure.

2

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

v

Proved oil and gas reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty² to be recoverable in future years from known reservoirs under assumed economic and operating conditions.

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

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

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

For a discussion of pricing assumptions see the tables under the headings “Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves” and under “Voluntary Oil Sands Reserves and Resources Disclosure - Oil Sands Mining and In-Situ Firebag Reserves Reconciliation”.

Proved Producing Reserves

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

Remaining Recoverable Resources

The sum of reserves and contingent resources.

Reservoir

Body of porous rock containing an accumulation of water, crude oil or natural gas.

Sour Synthetic Crude Oil

Crude oil produced from oil sands that requires only partial upgrading and contains a higher sulphur content than sweet synthetic crude oil.

Sweet Synthetic Crude Oil

Crude oil produced from oil sands consisting of a blend of hydrocarbons resulting from thermal cracking and purification of bitumen.

vi

Synthetic Crude Oil

Upgraded or partially upgraded crude oil recovered from oil sands including surface mineable oil sands leases and in-situ oil sands/heavy oil leases.

Undeveloped Oil and Natural Gas Lands

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

Upstream

These business segments include acquisition, exploration, development, production and marketing of crude oil, natural gas and natural gas liquids; and for greater clarity include the production of synthetic crude oil, bitumen and other oil products from oil sands as well as production using conventional methods.

Utilization

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

Wells

Development Well

A crude oil or natural gas well drilled in, or adjacent to, a reservoir known to be productive and expected to produce in the future.

Drilled Well

A well that has been drilled and has a defined status (e.g. gas well, shut-in well, producing oil well, producing gas well, suspended well or dry and abandoned well).

Exploratory Well

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

CONVERSION TABLE

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 Annual Information Form may produce small differences from reported amounts.

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

vii

CURRENCY

All references in this Annual Information Form to dollar amounts are in Canadian dollars unless otherwise indicated.

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains certain forward-looking statements that are based on our current expectations, estimates, projections and assumptions that were made by the company in light of its experience, and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about our strategy for growth, expected future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future commitments, are forward-looking statements.  Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “estimates,” “plans,” “scheduled,” “intends,” “may,” “believes,” “projects,” “indicates,” “could,” “focus,” “vision,” “goal,” “proposed,” “target,” “objective,” “continue” and similar expressions.  These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to our experience.  Our actual results may differ materially from those expressed or implied by our forward-looking statements and you are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors, many of which are beyond our control, that could influence actual results include but are not limited to: changes in the general economic, market and business conditions; fluctuations in supply and demand for our products; commodity prices, interest rates and currency exchange rates; our ability to respond to changing markets, and to receive timely regulatory approvals;  the successful and timely implementation of capital projects including growth projects (for example, the Voyageur project, including our Firebag in-situ development) and regulatory projects (for example, the emissions reduction modifications at our Firebag in-situ development); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement of conception of the detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of our capital assets; the cumulative impact of other resource development; the cost of compliance with existing and future environmental laws;  the accuracy of Suncor’s reserve, resource and future production estimates and our success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies and from companies that provide alternative sources of energy; labour and material shortages;  uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties; changes in environmental and other regulations (for example, the Government of Alberta’s current review of the unintended consequences of the proposed Crown Royalty regime, and the Government of Canada’s current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us.  These important factors are not exhaustive.

Many of these risk factors and other specific risks and uncertainties are discussed in further detail throughout this Annual Information Form and in our MD&A, incorporated by reference herein.  Readers are also referred to the risk factors described in other documents we file from time to time with securities regulatory authorities.  Copies of these documents are available without charge from Suncor at 112 – 4^th Avenue S.W., Calgary, Alberta, T2P 2V5, by calling 1-800-558-9071, or by email request to info@suncor.com or by referring to SEDAR at www.sedar.com or by referring to EDGAR at www.sec.gov.  Information contained in or otherwise accessible through our website does not form a part of this AIF, and is not incorporated into the AIF by reference.

viii

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

NON GAAP FINANCIAL MEASURES

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

ix

CORPORATE STRUCTURE

Name and Incorporation

Suncor Energy Inc. (formerly Suncor Inc.) was originally formed by the amalgamation under the Canada Business Corporations Act on August 22, 1979, of Sun Oil Company Limited, incorporated in 1923 and Great Canadian Oil Sands Limited, incorporated in 1953.  On January 1, 1989, we amalgamated with a wholly-owned subsidiary under the Canada Business Corporations Act.  We amended our articles in 1995 to move our registered office from Toronto, Ontario, to Calgary, Alberta, and again in April 1997, to adopt our current name, “Suncor Energy Inc.”.  In April 1997, May 2000, and May 2002, we amended our articles to divide our issued and outstanding shares on a two-for-one basis.

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

Intercorporate Relationships

We have four principal subsidiaries and partnerships.

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

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

Suncor Energy Marketing Inc., wholly-owned by Suncor Energy Products Inc., is incorporated under the laws of Alberta.  This company markets, mainly to customers in Canada and the United States, the crude oil, diesel fuel, bitumen and byproducts such as petroleum coke, sulphur and gypsum, produced by our Oil Sands business.  Through this subsidiary we also administer Suncor’s energy trading activities, market certain third party products, and procure crude oil feedstocks and natural gas for our downstream business.  This subsidiary markets certain natural gas volumes produced by, and purchased from, our Natural Gas business unit.  Suncor Energy Marketing Inc. also has a petrochemical marketing division that holds a 50% interest in Sun Petrochemicals Company, a petrochemical products joint venture.

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

We also have a number of other subsidiary companies.  However, the total assets of such subsidiaries and partnerships combined, and their total sales and operating revenues, do not constitute more than 20 per cent of the consolidated assets, or consolidated sales and operating revenues, respectively, of Suncor.

1

GENERAL DEVELOPMENT OF THE BUSINESS

Overview

Suncor is an integrated energy company, with corporate headquarters in Calgary, Alberta, Canada.  We are strategically focused on developing one of the world’s largest petroleum resource basins – Canada’s Athabasca oil sands.  In addition, we explore for, acquire, develop, produce and market crude oil and natural gas, transport and refine crude oil and market petroleum and petrochemical products.  Periodically, we also market third party petroleum products.  We also carry on energy trading activities focused principally on buying and selling futures contracts and other derivative instruments based on the commodities we produce.

We have three principal operating businesses:

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

Our Natural Gas business, based in Calgary, Alberta, explores for, acquires, develops and produces natural gas and natural gas liquids from reserves in Western Alberta and Northeastern British Columbia. The sale of natural gas production provides a natural price hedge for natural gas purchased for internal consumption.  In addition, our indirectly wholly-owned U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., acquires land and explores for coal bed methane in the United States.

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

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

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

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

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

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

2

Three-Year History

Oil Sands (OS)

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

· Oil Sands Fire – A fire on January 4, 2005 caused significant damage to one of our two upgraders, reducing upgraded crude oil production capacity from 225,000 bpd to about 122,000 bpd for the first nine months of 2005. Repair and maintenance work to restore the facility was completed in September 2005. Our property loss and business interruption insurance policies substantially mitigated the financial impact of the fire, and were fully settled in 2006.

· New Vacuum Unit and Debottleneck – During the fourth quarter of 2005, we increased our production capacity to 260,000 bpd through the completion of a new vacuum unit. In addition, we also completed a debottleneck of our Steepbank mine operation.

· 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 (the “Crown Agreement”), 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.

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

· 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.

· Regulatory Requirements

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

oIn 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, 2007, the addition of a new set of cokers to our upgrading complex was approximately 95% complete. This expansion is expected to increase production capacity to 350,000 bpd, with construction completion targeted in the second quarter of 2008 and ramp-up to full capacity expected in the fourth quarter. Other work included construction of a naphtha unit (which is intended enhance product mix) which was approximately 20% complete at year-end, and the Steepbank extraction plant which was approximately 25% complete at year-end.  For further discussion of our significant capital projects, see page 19 of our MD&A.

3

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

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

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

·Petro-Canada Agreement – Incremental bitumen to feed the expanded Oil Sands operation is  expected to be partially obtained starting in 2008 under a processing agreement between Suncor and Petro-Canada.  Under the terms of the agreement, we will process a minimum of 27,000 bpd of Petro-Canada bitumen on a fee-for-service basis.  Petro-Canada retains ownership of the bitumen and resulting sour crude oil production of about 22,000 bpd.  In addition, Suncor has agreed to sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada.  Both the processing and sales components of the agreement are for a minimum 10-year term.

Natural Gas (NG)

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

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

·Simonette Gas Plant – In December 2005, we, along with our partner, completed a plant capacity expansion and a new pipeline to connect the Simonette plant with volumes produced from the Cabin Creek and Solomon fields in the Alberta Foothills.  We have a 37.5% ownership interest and continue to operate the Simonette gas plant.

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

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

Refining and Marketing (R&M)

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

4

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

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

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

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

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

Other

Renewable Energy

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

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

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

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Other Transactions

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

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NARRATIVE DESCRIPTION OF THE BUSINESS

OIL SANDS (OS)

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

Operations

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

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

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

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

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

Mining/Extraction - - The first step of the open pit mining operation is to remove the overburden with trucks and shovels to access the oil sands - a mixture of sand, clay and bitumen. Oil sands ore is then excavated and transported to a sizing plant followed by an ore preparation plant. Here, the oil sands ore is mixed into a hot water slurry and pumped through hydrotransport pipelines to extraction plants on the east and west sides of the Athabasca River. In extraction, bitumen is extracted from the oil sands ore using a hot water process.  After the final removal of impurities and minerals, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.

In-situ - - Our in-situ operation uses an extraction technology called Steam Assisted Gravity Drainage (“SAGD”) to extract bitumen from oil sands deposits that are too deep to be mined economically.  The first step of the SAGD process is to drill a pair of horizontal wells with one well located above the other.  Steam produced by on-site steam generation facilities is injected through the top well into the oil sands.  Heated bitumen and condensed steam drain into the bottom well and flow up the well to the surface.  The bitumen is pumped to our oil/water separation facilities where the water is removed from the bitumen, treated, and recycled into the steam generation facilities. For current stages of in-situ development, naphtha is added to dilute the bitumen to facilitate transportation to upgrading.  Future stages propose to use a heated pipeline instead of naphtha dilution for transport.

Upgrading - After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and recycled to be used again as diluent. The bitumen from both SAGD and mining is upgraded through a coking and distillation process.  The upgraded product, referred to as sour synthetic crude oil, is either sold directly to customers as sour synthetic crude oil or is further upgraded into sweet synthetic crude oil by removing the sulphur and nitrogen using a hydrogen treating process.  Four separate streams of refined crude oil are produced: diesel, naphtha, kerosene and gas oil.

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

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

While there is virtually no finding cost associated with synthetic crude oil, the delineation of the resource and development and expansion of production entail significant capital outlays.  For the same reason, the costs associated with synthetic crude oil production are largely fixed in the short term, and as a result, operating costs per unit are largely dependent on levels of production.  Natural gas is used or consumed in the production of synthetic crude oil, particularly in SAGD production at our Firebag operations, and accordingly natural gas prices are a key variable component of synthetic crude oil production costs.

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

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 59% of Oil Sands consolidated operating revenues in 2007, compared to 53% in 2006.  The other significant component of our revenues were light sour synthetic crude oil and bitumen sales of 38% (2006 – 43%).  Set forth below is information on daily sales volumes and the corresponding percentage of Oil Sands consolidated operating revenues by product for each of the last two years.

Product:	2007				2006
		(thousands of barrels per  day)		(% of Oil Sands consolidated revenues)		(thousands of barrels per day)			(% of Oil Sands consolidated revenues)
Light sweet crude oil / diesel			126.7	59			138.7	53
Light sour crude oil / bitumen			108.0	38			124.4	43
Total			234.7				263.1

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

Principal Markets

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

Transportation

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

Our Oil Sands business unit entered into a transportation service agreement with a subsidiary of Enbridge Inc. for a term that commenced in 1999 and extends to 2028.  Under the agreement, our current pipeline capacity for the transport of synthetic crude oil and diluted bitumen from Fort McMurray, Alberta to Hardisty, Alberta is 170,000 bpd. In addition, in 2008 we committed to an additional 12,000 bpd that underpins current expansion plans for the pipeline.

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

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

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

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

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

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

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

Competitive Conditions

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

Seasonal Impacts

Severe winter climatic conditions at Oil Sands can cause reduced production and, in some situations, can result in higher costs.

Sales of Synthetic Crude Oil and Diesel

Aside from on site fuel use, all of Oil Sands’ production is sold to, and subsequently marketed by, Suncor Energy Marketing Inc.  Primary markets for our crude oil products include refining operations in Alberta, Ontario, the U.S. Midwest and the U.S. Rocky Mountain region. Diesel products are sold primarily in Western Canada.

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

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initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination on twenty-four months notice by either party. Neither party has provided notice of termination at this time.

Under a long term sales agreement with Consumers Co-operative Refineries Limited (“CCRL”) we supply CCRL with 20,000 bpd of sour crude oil production.  In 2005, we signed another contract with CCRL for an additional 12,000 bpd of sour crude oil.  Prices for sour crude oil under both of these agreements are set at agreed differentials to market benchmarks.  Both CCRL agreements extend through to 2011, with renewal options that could extend out to 2018 and beyond.  Both agreements continue until terminated by either party with twenty-four months notice.  Neither party has provided notice of termination at this time.

In 2001, we announced an agreement with Petro-Canada to supply up to 30,000 bpd of diluent to dilute bitumen produced by Petro-Canada.  Deliveries under the contract are expected to end when the bitumen processing and sour crude oil supply agreement with Petro-Canada, described below, takes effect no later than January 1, 2009. Under the agreement, we will process a minimum of 27,000 bpd of Petro-Canada bitumen on a fee for service basis.  Petro-Canada will retain ownership of the bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, we will sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada.  Both the processing and sales components of the agreement are for a minimum 10-year term.

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

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

Environmental Compliance

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

NATURAL GAS (NG)

Our Natural Gas business, based in Calgary, Alberta, explores for, develops and produces conventional natural gas and natural gas liquids in Western Canada, supplying markets throughout North America.  The sale of NG’s production provides a natural price hedge for natural gas purchased for internal consumption.

In 2007, natural gas and natural gas liquids accounted for approximately 98% of the NG business unit’s production (2006 – 97%).

NG’s exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta.

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Marketing, Pipeline and Other Operations

We operate natural gas processing plants at South Rosevear, Pine Creek, Boundary Lake South, Progress and Simonette with a total design capacity of approximately 315 mmcf/d.  Our capacity interest in these gas processing plants is approximately 135 mmcf/d.  We also have varying undivided percentage interests in natural gas processing plants operated by other companies and processing agreements in facilities where we do not hold an ownership interest.

Approximately 87% of our natural gas production is sold to Suncor Energy Marketing Inc. and then marketed under direct sales arrangements to customers in Alberta, British Columbia, Eastern Canada, and the United States.  Contracts for these direct sales arrangements are of varied terms, with a majority having terms of one year or less, and incorporate pricing which is either fixed over the term of the contract or determined on a monthly basis in relation to a specified market reference price.  Under these contracts, we are responsible for transportation arrangements to the point of sale.

Approximately 13% of our natural gas production is sold under existing contracts to aggregators (“system sales”). Proceeds received by producers under these sales arrangements are determined on a netback basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated transportation charges and a marketing fee.  Most of our system sales volumes are contracted to Cargill Gas Marketing Ltd. (formerly TransCanada Gas Services) and Pan-Alberta Gas.  These companies resell this natural gas primarily to eastern Canadian and Midwest and Eastern United States markets.

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

We do not typically enter long-term supply arrangements for our conventional crude oil production.  Instead, our conventional crude oil production is generally sold under spot contracts or under contracts that can be terminated on relatively short notice.  Our conventional crude oil production is shipped on pipelines operated by independent pipeline companies.  The NG business currently has no pipeline commitments related to the shipment of crude oil.

Principal Products

Sales of natural gas represented 88% (2006 – 90%) of NG’s consolidated operating revenues in 2007, with the remaining 12% (2006 – 10%) comprised of sales of natural gas liquids and crude oil.  Set forth below is information on daily sales volumes and the corresponding percentage of NG’s consolidated operating revenues by product for the last two years.

Product:	2007				2006
		(Millions of cubic feet equivalent per day)		(% of NG consolidated revenues)		(thousands of barrels of oil equivalent per day)			(% of NG consolidated revenues)
Natural gas			196	88			191	90
Crude Oil and Natural gas liquids			19	12			18	10
Total			215				209

Competitive Conditions

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

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Seasonal Impacts

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

Environmental Compliance

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

REFINING AND MARKETING (R&M)

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

Our Canadian-based refining and marketing business operates in Central Canada.  Our refinery in Sarnia, Ontario, has a crude oil capacity of 70,000 bpd and refines petroleum feedstock from Oil Sands and other sources into gasoline, distillates, and petrochemicals with the majority of these refined products being distributed in Ontario.  Our ethanol facility in St. Clair, Ontario, produces ethanol from corn, which is used for blending into our fuels and is also sold to third parties.

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

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

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

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

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

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Procurement of Feedstocks

The Sarnia refinery uses both synthetic and conventional crude oil.  In 2007, the Sarnia refinery procured approximately 50% (2006 – 55%) of its synthetic crude oil feedstock from our Oil Sands production.  In 2007, 43% (2006 – 60%) of the crude oil refined at the Sarnia Refinery was synthetic crude oil.  The balance of the refinery’s synthetic crude oil, as well as its conventional and condensate feedstocks, were purchased from others under month to month contracts.  In the event of a significant disruption in the supply of synthetic crude oil, the refinery has the flexibility to substitute other sources of sweet or sour conventional crude oil.

We procure conventional crude oil feedstock for our Sarnia refinery primarily from Western Canada, supplemented from time to time with crude oil from the United States and other countries.  Foreign crude oil is delivered to Sarnia via pipeline from the United States Gulf Coast or via the Enbridge Pipeline from Montreal.  We have not made any firm capacity commitments on these pipeline systems.  Crude oil is procured from the market on a spot basis or under contracts which can be terminated on short notice.

In 1998, EM&R signed a 10-year feedstock agreement with a Sarnia-based petrochemical refinery, Nova Chemicals (Canada) Ltd.  Under this buy/sell agreement, we obtain feedstock that is more suitable for production of transportation fuels in exchange for feedstock more suitable for petrochemical cracking.  We also enter into reciprocal buy/sell or exchange arrangements with other refining companies from time to time as a means of minimizing transportation costs, balancing product availability and enhancing refinery utilization.  We also purchase refined products in order to meet customer requirements.

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

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

The refinery’s crude oil purchase contracts have terms ranging from month-to-month to multi-year.  In the event of a significant disruption in the supply of crude oil, the refinery has the flexibility to substitute other sources of sweet or sour crude oil on a spot purchase basis.

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

Refining Operations

Canadian

The Sarnia refinery produces transportation fuels (gasoline, diesel, propane and jet fuel), heating fuels, liquefied petroleum gases, residual fuel oil, asphalt feedstock, benzene, toluene, mixed xylenes and orthoxylene, as well as the petrochemicals A-100 and A-150 that are used in the manufacture of paint and chemicals.

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

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

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

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

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

United States

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

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

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

Total Canadian and U.S. Refinery Capacity	2007	2006
Average daily crude input (barrels per day)	157,600	136,700
Average crude utilization rate (%)(1)	98	85

Notes:

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

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

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Principal Products

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

Product:	2007				2006
	(thousands of cubic meters per day)		(% of R &M’s consolidated revenues)		(thousands of cubic meters per day)		(% of R&M’s consolidated revenues)
Transportation Fuels
Gasoline
Retail		5.2		13		5.3		19
Joint Ventures		3.1		5		3.0		6
Other		8.5		24		7.6		23
Jet Fuel		2.3		4		1.7		4
Diesel		8.3		18		6.8		18
Sub-total – Transportation Fuels		27.4		64		24.4		70
Petrochemicals		0.9		2		0.9		3
Asphalt		1.7		2		1.2		1
Other		3.5		5		3.0		5
Total Refined Products		33.5		73		29.5		79
Other Non-Refined Products(1) Energy Marketing & Trading				2 25				2 19
Total %				100				100

Note:

(1)Includes ancillary revenues

Principal Markets

Canadian

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

o272 (2006 – 272) Sunoco-branded retail service stations

o151 (2006 – 151) Pioneer-operated retail service stations

o55 (2006 – 53) UPI-operated retail service stations and a network of 13 bulk distribution facilities for rural and farm fuels

o48 (2006 – 36) Sunoco branded Fleet Fuel Cardlock sites

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

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

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

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

R&M’s share of total refined product sales in its primary Canadian market of Ontario was approximately 20% in 2007 (2006 – 18%).  Transportation fuels accounted for 78% of R&M’s Canadian sales volumes in 2007 (2006 – 82%); and petrochemicals accounted for 5% (2006 – 6%).  The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to industrial users and resellers.

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

United States

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

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

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

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

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

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

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

Transportation and Distribution

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

For our Canadian operations, R&M owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario. The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia refinery to core markets in Ontario is the Sun-

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

We also have pipeline access, subject to availability, to petroleum markets in the Great Lakes region of the United States by way of a pipeline system in Sarnia operated by a U.S. based refiner.  This link to the U.S. allows R&M’s Canadian operations to move products to market or obtain feedstocks/products when market conditions are favourable in the Michigan and Ohio markets.

For our U.S. operations, approximately sixty percent of crude oil processed at the Denver refining operation is transported via pipeline, with the remainder supplied via truck.  R&M owns and operates the Rocky Mountain Crude system, which runs from Guernsey, Wyoming to Denver, Colorado.  This pipeline is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers.  We also operate a crude pipeline, the Centennial pipeline, from Guernsey, Wyoming to Cheyenne, Wyoming.  Until September 27, 2007, we owned approximately 65% of the Centennial pipeline.  Effective September 27, 2007, we purchased the remaining 35% interest from another area refiner, and are now the 100% owner of the Centennial pipeline.

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

R&M’s U.S. operations have both truck and rail loading racks at the Denver area refining facility with product loading capacity in excess of 30,000 bpd, a one mile long 7,000 bpd jet fuel pipeline that connects to a common carrier pipeline system for deliveries to the Denver International Airport, and a four mile long 14,000 bpd diesel pipeline that delivers diesel product directly to the Union Pacific railroad yard in Denver, Colorado.

In both our Canadian and U.S. operations, we believe our own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet our current and foreseeable storage needs.

Competitive Conditions

Competitive conditions affecting our R&M business are described under “Competition” in the “Risk  Factors” section of this Annual Information Form.

Environmental Compliance

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

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

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

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MATERIAL CONTRACTS

During the year ended December 31, 2007, we have not entered into any contracts, nor are there any contracts still in effect, that are material to our business, other than contracts entered into in the ordinary course of business and the Shareholder Rights Plan dated April 28, 2005.

RESERVES ESTIMATES

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”).  However, we have received an exemption from Canadian securities regulatory authorities permitting us to report our reserves in accordance with U.S. disclosure requirements.  Pursuant to U.S. disclosure requirements, we disclose net proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from our Firebag in-situ leases, using constant dollar cost and pricing assumptions.  As there is no recognized posted bitumen price, these assumptions are based on a posted benchmark oil price, adjusted for transportation, gravity and other factors that create the difference (“differential”) in price between the posted benchmark price and Suncor’s bitumen.  Both the posted benchmark price and the differential are generally determined as of a point in time, namely December 31 (“Constant Cost and Pricing”).  Reserves from our Firebag in-situ leases are reported as barrels of bitumen, using these Constant Cost and Pricing assumptions (see “Required U.S. Oil and Gas Disclosure – Proved Conventional Oil and Gas Reserves” for net proved conventional oil and gas reserves).

Pursuant to U.S. disclosure requirements, we also disclose gross and net proved and probable mining reserves.  The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 78.5% for proven reserves, and 80% for proved plus probable reserves.  The lower yield rate applied to proven reserves reflects historical operational levels.  The 80% proved plus probable reserves yield rate reflects anticipated yield levels once operational performance issues have been addressed.

During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen-based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves.  The estimate of our net mining reserves reflects the value of Alberta Crown, overriding, and freehold royalty burdens under constant December 31 pricing and our exercise of the option electing to transfer to a bitumen based Crown royalty effective at the beginning of 2009 (See “Required U.S. Oil and Gas and Mining Disclosure – Proved and Probable Oil Sands Mining Reserves” for both gross and net, proved and probable mining reserves).  Our Firebag in-situ leases are subject to Crown royalty based on bitumen, rather than synthetic crude oil.  As there is currently no legislated methodology for determining bitumen value for Alberta Crown royalty purposes, bitumen value for determining royalties has been assumed to correspond to Firebag bitumen sales to our upgrader.  However, determination of bitumen value for royalty purposes is currently under review by the Government of Alberta.  In October 2007, the Government of Alberta proposed changes to the royalty regime.  In January 2008, Suncor entered into a Royalty Amending Agreement to transition to the new royalty framework assuming the government enacts their proposed changes.  Neither the governments  proposed changes, nor our Royalty Amending Agreement have been reflected in the following reserve estimates.  For a full discussion of our Crown royalties, see “Oil Sands Crown Royalties” and “Natural Gas Crown Royalties” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

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

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·Gross and net proved and probable mining reserves are consistent with required US mining disclosures, however the voluntary disclosure reflects normalized constant dollar cost and pricing assumptions.  These assumptions use a posted benchmark oil price as at December 31, but apply a differential generally intended to represent a normalized annual average for the year (“Annual Average Differential Pricing”), rather than a point in time differential, in accordance with CSA Staff Notice 51-315 (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves and 80% for proved plus probable reserves);  and

·Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on Annual Average Differential Pricing.  Bitumen reserves estimated on this basis are subsequently converted, for aggregation purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 80% for proved and proved plus probable reserves.

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

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

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

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

(d)are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

Comparisons of reserve estimates under “Required U.S. Oil and Gas Mining Disclosure” and “Voluntary Oil Sands Reserve Disclosure” may show material differences based on the pricing assumptions used, whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, whether probable reserves are included, and whether the reserves are reported on a gross or net basis.  These differences were significant for 2005 and 2007 reporting given the considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing. Refer to “Voluntary Oil Sands Reserves and Resources Disclosure - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations”.

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

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

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

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drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, project implementation commitments, and regulatory constraints.

For Firebag in-situ reserve estimates, GLJ considered similar factors such as our regulatory approval or likely impediments to the receipt of pending regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects and drill density.  Our proved reserves are delineated to within 80 acre spacing with 3D seismic control (or 40 acre spacing without 3D seismic control) while our probable reserves are delineated to within 160 acre spacing without 3D seismic control.  The major facility expenditures to develop our proved undeveloped reserves have been approved by our Board.  Plans to develop our probable undeveloped reserves in subsequent phases are under way but have not yet received final approval from our Board.

In a report dated February 11, 2008 (“GLJ NG Report”), GLJ also evaluated our proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from our mining leases and the Firebag in-situ reserves) as at December 31, 2007.

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

Net reserves represent Suncor’s undivided percentage interest in total reserves after deducting Crown royalties, freehold and overriding royalty interests.  Reserve estimates are based on assumptions about future prices, production levels, operating costs, capital expenditures, and the current Government of Alberta royalty regime.  These assumptions reflect market and regulatory conditions, as required, at December 31, 2007, which could differ significantly from other points in time throughout the year, or future periods.  Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE

Proved and Probable Oil Sands Mining Reserves

	Proved		Probable		Probable & Proved
Millions of barrels of synthetic crude oil (1)	Gross(2)	Net(3)	Gross(2)	Net(3)	Gross(2)	Net(3)
December 31, 2006	1,709	1,507	634	564	2,343	2,071
Revisions of previous estimates	(1)	103	106	149	105	252
Extensions and discoveries	-	-	-	-	-	-
Production	(74)	(66)	-	-	(74)	(66)
December 31, 2007	1,634	1,544	740	713	2,374	2,257

Notes:

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 78.5% for proved reserves, and 80% for proved plus probable reserves.  The lower yield rate applied to proved reserves reflects historical operational levels that have fallen below management expectations. The 80% proved plus probable reserves yield rate reflects a return to management’s target levels once operational performance issues have been addressed.

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

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

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Significant Mining Leases

Interest Held	Description	Gross Acres	Expiry Date (4)	Retention Conditions
Leases:	7279080T19	18,541	n/a	(1)
	7597030T11	2,454	n/a	(1)
	7280100T25	49,365	n/a	(1)
	7387060T04	4,469	n/a	(1)
	7279120092	1,600	n/a	(1)
	7280060T23	36,526	n/a	(1)
	7498050014	240	May 27, 2019	(2)
	7405080347	5,693	Aug. 24, 2020	(2)
	7405030690	633	Mar. 23, 2020	(2)
	7405010854	22,773	Jan. 26, 2020	(2)
	7405010853	22,773	Jan. 26, 2020	(2)
	7400120007	22,773	Dec. 13, 2015	(2)
	7405080346	5,060	Aug. 24, 2020	(2)
	7401100029	10,120	Oct. 17, 2016	(2)
Permits:	7006060389	8,853	May 31, 2011	(3)
	7006060390	1,897	May 31, 2011	(3)
	7006060391	3,162	May 31, 2011	(3)
Fee Lots:	1	1,894	n/a	n/a
	2	1,972	n/a	n/a
	3	1,967	n/a	n/a
	4	1,886	n/a	n/a
	5	1,881	n/a	n/a
	6	1,483	n/a	n/a
Total		228,015

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

2)     Annual lease rentals are required to maintain these leases until the indicated expiry dates for the primary terms of the leases.  Upon application for continuation prior to the indicated expiry dates, leases can be retained beyond the indicated expiry dates if they meet the minimum level of evaluation and if:

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

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

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

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

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Oil Sands Mining Operating Statistics

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

	2007	2006	2005
Total mined volume (1) millions of tonnes	331.3	356.2	313.7
Mined volume to tar sands ratio(1)	40.6%	41.8%	32.0%
Tar sands mined
millions of tonnes	134.4	149.0	100.5
Average bitumen grade (weight %)	12.4%	12.8%	12.2%
Crude bitumen in mined tar sands
millions of tonnes	16.6	19.1	12.3
Average extraction recovery %	92.8%	93.1%	92.6%
Crude bitumen production
millions of cubic meters(2)	15.4	17.6	11.4
Gross synthetic crude oil produced
Thousands of barrels per day(3)	235.0	231.9	152.2

Notes:

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

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

(3)Cubic meters are converted to barrels at the conversion factor of 6.29.  Bitumen production from Firebag is upgraded and included in the base operations production.  Therefore the mining production reported above will no longer agree to the operating statistics.

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Proved Conventional Oil and Gas Reserves

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

NET PROVED RESERVES⁽¹⁾

Crude Oil,  Natural Gas Liquids and Natural Gas

Constant Cost and Pricing as at December 31	Oil Sands business: Firebag – Crude Oil (millions of barrels of bitumen) (2),(3),(4)		Natural Gas business: Crude Oil and Natural Gas Liquids (millions of barrels)	Total (millions of barrels)		Natural Gas business: Natural Gas (billions of cubic feet)
December 31, 2004	-	(3)	8	8		446
Revisions of previous estimates	639		-	639	(5)	14
Purchases of minerals in place	-		-	-		-
Extensions and discoveries	-		-	-		40
Production	(7)		(1)	(8)		(50)
Sales of minerals in place	-		-	-		(1)
December 31, 2005	632		7	639		449
Revisions of previous estimates	(57)		-	(57)	(5)	5
Improved Recovery	340	(6)	-	340		-
Purchases of minerals in place	-		-	-		-
Extensions and discoveries	-		1	1		26
Production	(12)		(1)	(13)		(53)
Sales of minerals in place	-		-	-		(1)
December 31, 2006	903		7	910		426
Revisions of previous estimates	68		-	68	(5)	4
Improved Recovery	99	(6)	-	99		-
Purchases of minerals in place	-		-	-		19
Extensions and discoveries	-		-	-		33
Production	(13)		(1)	(14)		(53)
Sales of minerals in place	-		-	-		(1)
December 31, 2007	1,057		6	1,063		428
Proved Developed
December 31, 2004	-		7	7		385
December 31, 2005	137		7	144		387
December 31, 2006	188		6	194		365
December 31, 2007	186		6	192		379

Notes:

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

(2)Although we are subject to Canadian disclosure rules in connection with the reporting of our reserves, we have received exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S. disclosure practices.  See Reliance on Exemptive Relief on pg 50.

(3)Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31.  In 2004, due to unusually low year-end posted benchmark oil prices, and unusually high year-end diluent prices, our proved reserves were determined to be uneconomic. Since 2005 we have rebooked our proved reserves, and these continued to be economically viable through 2007.

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

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

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

All reserves are located in Canada. There has been no major discovery or other favourable or adverse event that caused a significant change in estimated proved reserves since December 31, 2007. We do not have long-term supply agreements or contracts with governments in which we act as producer nor do we have any interest in oil and gas operations accounted for by the equity method.

Capitalized Costs Relating to Oil and Gas Activities ⁽¹⁾

	As at December 31,
($ millions)	2007	2006
Proved properties	4,896	3,869
Unproved properties	298	224
Other support facilities and equipment	24	22
Total cost	5,218	4,115
Accumulated depreciation and depletion	(1,306)	(1,041)
Net capitalized costs	3,912	3,074

Note:

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

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

	For the years ended December 31,
($ millions)	2007	2006	2005
Property acquisition costs
Proved properties	140	-	1
Unproved properties	32	29	9
Exploration costs	142	247	148
Development costs	1,459	688	552
Asset retirement obligations	30	35	4
Total capital and exploration expenditures	1,803	999	714

Note:

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

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Results of Operations for Oil and Gas Production

	For the years ended December 31,
($ millions)	2007	2006	2005
Revenues
Sales to unaffiliated customers	492	516	670
Transfers to other operations	431	387	52
	923	903	722
Expenses
Production costs	362	291	213
Depreciation, depletion and amortization	264	215	145
Exploration	93	87	66
Gain on disposal of assets	-	(4)	(12)
Other related costs	47	40	39
	766	629	451
Operating profit before income taxes	157	274	271
Related income taxes	(10)	(38)	(98)
Results of operations	147	236	173

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

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

	2007	2006	2005
Year end natural gas price (AECO- $/GJ)	6.26	7.52	10.22
Year end crude oil price (WTI US$/bbl)	95.98	62.09	59.45
Year end light/heavy crude oil differential, WTI at Cushing less LLB at Hardisty (US$/bbl)	41.72	17.99	26.35

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

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

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

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

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

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

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

($ millions)	2007	2006	2005
Future cash flows	31,227	32,882	16,444
Future production costs	(15,963)	(12,264)	(10,181)
Future development costs	(8,002)	(5,648)	(1,705)
Other related future costs	(742)	(612)	(464)
Future income tax expenses	(2,203)	(4,221)	(1,216)
Subtotal	4,317	10,137	2,878
*Discount at 10%	(3,807)	(6,768)	(1,214)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	510	3,369	1,664

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

($ millions)	2007	2006	2005
Balance, beginning of year	3,369	1,664	1,074
Sales and transfers of oil and gas produced, net of production costs	(483)	(559)	(456)
Net changes in prices and production costs	(3,226)	1,907	737
Changes in estimated future development costs	(2,151)	(1,141)	(573)
Extensions, discoveries and improved recovery, less related costs	72	59	162
Development costs incurred during the period	1,459	772	557
Revisions of previous quantity estimates	(4)	1,051	440
Purchases of reserves in place	37	-	-
Sale of reserves in place	(2)	(2)	(4)
Accretion of discount	472	231	125
Net changes in income taxes	934	(714)	(470)
Other related costs	33	101	72
Balance, end of year	510	3,369	1,664

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

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

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

For the year ended December 31,	2007	2006	2005
Crude Oil and Bitumen ($/bbl)	37.67	38.94	45.86
NGL ($/bbl)	53.32	44.96	50.70
Natural Gas ($/mcf)	6.32	7.15	8.57

Notes:

(1)Production is based in Western Canada.

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

Production Costs

For the year ended December 31,	2007	2006	2005
($ per BOE of gross production)
Average production (lifting) cost of conventional crude oil and gas(1)	13.63	11.92	10.86

Note:

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

Producing Oil and Gas Wells

As at December 31, 2007	Crude Oil(3)				Natural Gas				Total
number of wells
		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Alberta	71		56		399		238		470		294
British Columbia	19		8		143		65		162		73
Total	90		64		542		303		632		367

Notes:

(1)Gross wells are the total number of wells in which an interest is owned.

(2)Net wells are the sum of fractional interests owned in gross wells.

(3)Well information includes Firebag.

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Oil and Gas Acreage

As at December 31, 2007
(thousands of acres)	Developed				Undeveloped(1)				Total
		Gross(1)		Net(2)		Gross(1)		Net(2)		Gross(1)		Net(2)
Canada
Natural Gas	690		410		1,250		680		1,940		1,090
Firebag	2		2		287		287		289		289
Total Canada	692		412		1,537		967		2,229		1,379
USA
Natural Gas	-		-		46		24		46		24
Total	692		412		1,583		991		2,275		1,403

Notes:

(1)Undeveloped acreage is considered to be those on which wells have not been drilled or completed to a point that would permit production of commercial quantities of crude oil and natural gas regardless of whether or not such acreage contains proved reserves. Gross acres mean all the acres in which we have either an entire or undivided percentage interest.

(2)Net acres represent the acres remaining after deducting the undivided percentage interest of others from the gross acres.

Drilling Activity

For the year ended December 31, 2007
(number of net wells)	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total
Canada
Natural Gas	7	4	11	14	1	15
Firebag	-	-	-	26	-	26
United States	-	-	-	-	-	-
Total	7	4	11	40	1	41

For the year ended December 31, 2006
(number of net wells)	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total
Canada
Natural Gas	3	6	9	14	4	18
Firebag	-	-	-	8	-	8
United States	-	-	-	-	-	-
Total	3	6	9	22	4	26

For the year ended December 31, 2005
(number of net wells)	Net Exploratory			Net Development
	Productive	Dry Holes	Total	Productive	Dry Holes	Total
Canada
Natural Gas	8	3	11	18	4	22
Firebag	-	-	-	10	-	10
United States	-	1	1	-	-	-
Total	8	4	12	28	4	32

At December 31, 2007, we were participating in the drilling of 28 gross (16 net) exploratory and development wells.

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Future Commitments to Sell or Deliver Crude Oil and Natural Gas

We have entered into a number of natural gas sale commitments aggregating approximately 64 mmcf/day.  These sales commitments consist of both short-and long-term contracts ranging from one year and for one agreement, for the life of a specified production field.  All production comes from our reserves. All pricing under these agreements is based upon both a combination of variable, fixed and index-based terms.

As at March 4, 2008 crude oil hedges totaling 10,000 bpd of production were outstanding for the remainder of 2008.  Prices for these barrels are fixed within a range of US$59.85 to US$101.06 per barrel.  In addition, we have also purchased $60 USD WTI put options for calendar years 2009 and 2010 for volumes of 55,000 bpd.  We intend to consider additional costless collars of up to approximately 30% of our crude oil planned production if strategic opportunities are available. For further particulars of these arrangements, see the information under the heading “Derivative Financial Instruments”, under “Risk  Factors Affecting Performance” in the “Suncor Corporate Overview and Strategic Priorities” section of our MD&A, and Note 7 to our 2007 Consolidated Financial Statements, which note is incorporated by reference herein.

VOLUNTARY OIL SANDS RESERVES AND RESOURCES DISCLOSURE

Oil Sands Mining and Firebag In-Situ Reserves Reconciliation

The following tables set out, on a gross⁷ and net basis, a reconciliation of our proved and probable reserves of synthetic crude oil from our Oil Sands mining leases and bitumen, converted to synthetic crude oil for comparison purposes only, from our in-situ Firebag leases, from December 31, 2006, to December 31, 2007, based on the GLJ Oil Sands Reports.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases(1)(2)			Firebag In-situ Leases(1)(3)			Total Mining and In-situ(3)
(millions of barrels of synthetic crude oil)(1)	Proved	Probable	Proved & Probable	Proved(3)	Probable(3)	Proved & Probable	Proved & Probable
December 31, 2006	1,709	634	2,343	803	1,907	2,710	5,053
Revisions of previous estimates	(1)	106	105	(17)	(5)	(22)	83
Improved recovery	-	-	-	80	(66)	14	14
Extensions and discoveries	-	-	-	-	-	-	-
Production	(74)	-	(74)	(11)	-	(11)	(85)
December 31, 2007	1,634	740	2,374	855	1,836	2,691	5,065

⁷               Suncor’s working interest in reserves, before deducting Crown royalties, freehold and overriding royalty interests.

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Estimated Net Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases(1)(2)			Firebag In-situ Leases(1)(3)			Total Mining and In-situ(3)
(millions of barrels of synthetic crude oil)(1)	Proved	Probable	Proved & Probable	Proved(3)	Probable(3)	Proved & Probable	Proved & Probable
December 31, 2006	1,507	564	2,071	722	1,639	2,361	4,432
Revisions of previous estimates	11	108	119	(15)	(7)	(22)	97
Improved recovery	-	-	-	72	(60)	12	12
Extensions and discoveries	-	-	-	-	-	-	-
Production	(66)	-	(66)	(11)	-	(11)	(77)
December 31, 2007	1,452	672	2,124	768	1,572	2,340	4,464

Notes:

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 78.5% for proven reserves, and 80% for proved plus probable reserves under Oil Sands mining leases and 80% for both proved reserves and proved plus probable reserves for Firebag in-situ leases.  Virtually all of our bitumen from the Oil Sands mining leases is upgraded into synthetic crude oil.  However, we have the option of selling the bitumen produced from our Firebag in-situ leases directly to the market where strategic opportunities exist.  Accordingly, these bitumen reserves are converted to synthetic crude oil for aggregation purposes.

(2)Our gross mining reserves are evaluated in part, based on the current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing assumptions.  Net mining reserves reflect the relative value of Crown, freehold and overriding royalty burdens based on 2007 Annual Average Differential Pricing assumptions in accordance with CSA Staff Notice 51-315 and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.  Neither the current proposed Alberta royalty regime changes, nor our Royalty Amending Agreement have been incorporated.

(3)Under “Required U.S. Oil and Gas and Mining Disclosure”, we reported proved reserves from our Firebag in-situ leases.  The disclosure in the table above reports proved reserves from these leases and differs in the following four ways.  Reserves from our Firebag in-situ leases under our voluntary disclosure:

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

(b)are converted from barrels of bitumen to barrels of synthetic crude oil in this table for aggregation purposes;

(c)include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements.  U.S. companies do not disclose probable reserves for non-mining properties.  We voluntarily disclose our probable reserves for Firebag in-situ leases as we believe this information is useful to investors, and allows us to aggregate our mining and our in-situ reserves into a consolidated total for our Oil Sands business.  As a result, our Firebag in-situ estimates in the above tables are not comparable to those made by U.S. companies.

(d)are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

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, 2007, our best estimate of remaining recoverable synthetic crude oil resources, and the components included in the summation, are as follows (billions of barrels):

	Mining	In-Situ	Total
Proved plus probable reserves	2.4	2.6	5.0
Best estimate contingent resources	4.2	6.3	10.5
Best estimate remaining recoverable resources	6.6	8.9	15.5

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

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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, locate 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 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,
	2007	2006
Oil Sands	3,612	3,182
Natural Gas	159	170
Refining & Marketing	1,151	1,068
Corporate(2)	1,543	1,346
Total (1)	6,465	5,766

Notes:

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

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

The Communications, Energy and Paperworkers Union Local 707 represent approximately 2,100 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 220 of R&M - Canada’s Sarnia refinery, London terminal and Sun-Canadian Pipe Line Company employees.  During 2005, a three year agreement was signed with the Sarnia employee association that will be renegotiated in 2008.  During 2006, a three year agreement was signed with the CAW at the London terminal that will continue year after year unless either party provides written notice at least 30 days prior to the expiry date of the agreement of their intent to terminate or negotiate revisions.  Management believes the agreement will be renegotiated on its anniversary.  The agreement with the employee association of Sun-Canadian Pipe Line Company was signed in 1993, and it 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 under such agreement has been received or given to date.  Management believes the agreement will be automatically renewed on its anniversary.

The United Steel Workers (USW) union represents approximately 218 employees at R&M’s Denver refining facilities.  In February 2006, the union voted to merge all workers into a single collective bargaining agreement.   The merged contract became effective in March 2006 and will expire in January 2009.

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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.  Risks appear in no particular order below:

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

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

Operating Hazards and Other Uncertainties.  Each of our three principal operating businesses, Oil Sands, NG, and R&M require high levels of investment and have particular 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 normally incident to 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 sands and producing bitumen through in-situ methods, extracting bitumen from the oil sands, and upgrading bitumen into synthetic crude oil and other products involves 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 is 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 NG’s operations, including all of the risks normally incident to 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 accidents.

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

Major Projects.  There are certain risks associated with the execution of our major projects, including without limitation, the new coker unit and the Voyageur growth strategy.  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

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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; 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 with the 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.

Cost estimates for major projects involve uncertainties and evolve in stages.  For a discussion of our significant capital projects in progress, see page 18 of our MD&A, incorporated by reference herein.

Insurance.  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 impact on the company.  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.  We continue to evaluate options to replace this coverage.  Refer to note 11 to our 2007 Consolidated Financial Statements, which is incorporated by reference herein, for further description of our insurance coverage.

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.

2)Financial Risks – Risks that affect the compilation, reporting and accuracy of financial results.

Uncertainty of Reserve Estimates.   The reserves estimates for our Oil Sands and NG 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 are 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, future royalties and 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, and 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.

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

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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 we expect continued volatility and uncertainty in crude oil and natural gas prices.  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 an adverse impact on our financial condition and liquidity and results of operations. A key component of our business strategy is to produce sufficient natural gas to meet or exceed internal demands for natural gas purchased for consumption in our operations, creating a 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.

Under our strategic crude oil hedging program, management has approval to fix a price or range of prices for approximately 30% of our total crude oil planned production for specified periods of time.  As at March 4, 2008, we had crude oil hedges totaling 10,000 bpd of crude oil for production in 2008.  Prices for these barrels are fixed within a range from an average of US$59.85/bbl up to an average of US$101.06/bbl.  In addition, we have also purchased $60 USD WTI put options for calendar years 2009 and 2010 for volumes of 55,000 bpd.  We intend to consider additional strategic hedging opportunities as they become available.

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, the carrying value of our assets could be subject to downward revisions, and our earnings could be adversely affected.

Volatility of Downstream Margins.  Our downstream business is sensitive to wholesale and retail margins for its refined products, including gasoline, and asphalt. Margin volatility is influenced by overall marketplace competitiveness, weather, the cost of crude oil (see “Volatility of Crude Oil and Natural Gas Prices”) 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 R&M can be expected to fluctuate and may be adversely affected.

In the Western Canadian diesel fuel market, demand and supply can fluctuate.  Margins for diesel fuel are typically higher than the margins for synthetic and conventional crude oil.  The below noted expansion plans of our competitors could result in an increase in the supply of diesel fuel and weaken margins.

Energy Trading Activities.  The nature of trading activities creates exposure to financial risks.  These include risks that movements in prices or values will result in a financial loss to the company; a lack of counterparties will leave us unable to liquidate or offset a position, or unable to do so at or near the previous market price; we will not receive funds or instruments from our counterparty at the expected time; the counterparty will fail to perform an obligation owed to us;  we will suffer a loss as a result of human error or deficiency in our systems or controls;  or we will 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.

Exchange Rate Fluctuations.  Our 2007 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.  Crude oil and natural gas prices are generally based in U.S. dollars,

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while a portion of our sales of refined products are in Canadian 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 favorable or unfavorable, creating another element of uncertainty.

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 minimize our exposure to interest rate fluctuations, 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.  For more details, see the “Liquidity and Capital Resources” section of our MD&A.

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.

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

*	the possible cumulative impacts of oil sands development in the Athabasca region and the province;
*	storage, treatment, and disposal of hazardous or industrial waste;
*	the need to reduce or stabilize various emissions to air and withdrawals of and discharges to water;
*	issues relating to global climate change, land reclamation and restoration;
*	issues relating to the manufacture or use of certain substances;
*	reformulated gasoline to support lower vehicle emissions.

Changes in environmental regulation could have an adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production and 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 permits.

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Suncor is making progress to address challenges at its in-situ operation, where high emissions have resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has been capped at approximately 42,000 barrels of bitumen per day. As a result, commissioning of units to increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35% will be delayed. Suncor’s revised outlook reflects this constraint.  However, unexpected problems in connection with installation of emission abatement equipment, or unanticipated changes to permits or changes to regulatory requirements may adversely affect our plans for increasing bitumen production capacity of Firebag.  Furthermore, we may be subject to further regulatory enforcement action, which may in turn, have an adverse effect on our business.

To mitigate the impact to production, we are examining ways to increase bitumen supply from our mining operations. We are also accelerating the construction of emission abatement equipment, which will result in additional maintenance and capital costs being incurred.

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.  However, unexpected problems in connection with upgrading our emission control equipment or introducing process changes, or unanticipated changes to permits or changes to regulatory requirements may adversely affect our plans for decreasing emissions at base plant.  Any such unexpected problems may lead to further regulatory enforcement action, which may in turn, have an adverse effect on our business.

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 of December 31, 2006 ($14 million as at December 31, 2006) as security for the estimated cost of our reclamation activity.  Since there was no production from Leases 86/17 in 2006 or 2007, the amount of security remains unchanged.

For the Millennium, Steepbank, and North Steepbank mines, we have posted irrevocable letters of credit equal to approximately $227 million with Alberta Environment, representing security for the maximum reclamation liability in the period April 1, 2007 through March 31, 2008.  For more information about our reclamation and environmental remediation obligations, refer to “Tailings Management” under “Risk Factors Affecting Performance” and  “Asset Retirement Obligations” under “Critical Accounting Estimates” in our MD&A.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta.  The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement 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 R&M operations, see the information under the R&M section of “Narrative Description of the Business”, in 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 ability to market its products, or subject the Company to fines and penalties potentially having a material impact on revenues and earnings.

The R&M U.S. operations is 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 R&M section of “Three Year History” 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 the Company’s ability to market its products, potentially having a material impact on revenues and earnings.

In addition, our business could be affected by the potential for lawsuits against greenhouse gas emitters, based on links drawn between greenhouse gas emissions and climate change.

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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 negatively affect future earnings 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 financial condition.

Land Claims.  First Nations peoples have claimed aboriginal title and rights to a substantial portion of Western Canada. In addition, First Nations peoples have filed claims against industry participants generally, relating in part to land claims which may affect our Natural Gas business. We are unable to assess the effect, if any, these or other claims, may have on our Oil Sands or other operations.

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:

·Pursuant to the new royalty framework, the government intends to establish a permanent generic “bitumen valuation methodology” (BVM) for determining the “R” related to bitumen.  The Crown is consulting with stakeholders and independent advisors with a decision on the methodology anticipated by June 30, 2008 and final determination of such methodology may have an impact on royalties payable to the Crown.

·The government also announced its intention to assess and recommend improvements in the system, structures and resources supporting the collection, verification and reporting of provincial royalties.  This assessment is expected to be completed by March 31, 2008 and steps taken by the government thereafter may affect the calculation of royalties; 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 Generic Regime by the Government of Alberta; changes in other legislation; and the occurrence of unexpected events.

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

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

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flexibility to conduct periodic plant maintenance on one operation while continuing production and cash flow generation from the other.

Dependence on Oil Sands Business.  The Company’s significant capital commitment to further our growth projects at Oil Sands, including Voyageur, 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 2007, the Oil Sands business accounted for approximately 87% (88% in 2006) of our upstream production, 87% (89% in 2006) of our net earnings and 79% (84% in 2006) of our cash flow from operations. These percentages have been determined excluding the corporate and eliminations segment information.

Need to Replace Conventional Natural Gas Reserves.  Future natural gas reserves and production of the Company’s NG business unit are highly dependent on our success in discovering or acquiring additional reserves and exploiting our current reserve base.  This impacts 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 acquisition activities, our conventional natural gas reserves and production will decline over time as reserves are depleted.  For example, in 2007, our average natural gas reservoir decline rate was approximately 24% (2006 – 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 operations⁸ 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 NG 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 competition for our crude oil production is other North American conventional and synthetic sweet and sour crude oil producers.  With current expansion plans, there are risks associated with the delivery of our products to market.

A number of other companies have entered or have indicated they are planning to enter the oil sands business and begin production of bitumen and synthetic crude oil or expand their existing operations.  It is difficult to assess the number, level of production and ultimate timing of all of the potential new projects or where existing production levels may increase.  Based on management’s knowledge of other projects derived from publicly available information, Canada’s production of bitumen and upgraded synthetic crude oil could increase from approximately one million bpd in 2004 to approximately two million bpd by 2010⁹. Increasing industry consolidation, a global focus on oil sands and additional competitors with financial capacity has: i) materially increased the supply of bitumen and synthetic crude oil and other competing crude oil products in the marketplace; ii) exponentially increased land values and availability of new leases; and iii) placed stress on the availability and cost of all resources required to run the Oil Sands operation.  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

⁸ Refer to “Non GAAP Financial Measures” on page ix of this AIF.

⁹ Alberta Government – Talk About Oil Sands

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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.  With the expansion of the industry and the impact of new entrants to the business, risks in the form of availability of/competition for skilled labour and materials supply continue to build.  Although these risks are not exclusive to our Oil Sands operation, the increased demands on the Fort McMurray, Alberta infrastructure (for example, housing, roads, medical facilities, and schools) and a commuting workforce have heightened concerns.  Our ability to operate safely and effectively and complete major projects on time and on budget is significantly impacted by these risks.  Risks associated with completion of significant capital projects are discussed in “Major Projects” above.

Pipeline Capacity Constraints.  With our current expansion plans, combined with several other major capital initiatives scheduled by others in the industry, there are increasing risks associated with pipeline capacity and infrastructure which may negatively affect our sales mix and production levels.  This is already evident in the timing and method of delivery of our crude oil products to market, as well as our ability to produce at capacity levels in our NG business.

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.  The success of projects incorporating new technologies, such as in-situ technology, cannot be assured.

In-situ Extraction. 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.  Commercial application of this technology is not yet commonplace and accordingly, in the absence of operating history, there can be no assurances with respect to the sustainability of SAGD operations.

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 mine extension, planned for operation in 2010, is subject to certain conditions related to the performance of CT technology.

Labour Relations.  Hourly employees at our Oil Sands facility near Fort McMurray, Alberta, our London, Ontario terminal operation, our Sarnia, Ontario refinery, our Denver, Colorado refinery and at Sun-Canadian Pipeline Company 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 materially and adversely affect our business and financial position.

U.S. Policies re: Clean Oil.  Recently, certain U.S. governmental agencies have indicated their intention to purchase oil and related refined products from conventional sources, rather than from the oil sands, which in their view, is a less environmentally friendly source of oil.  Although we continue to focus on mitigating our business impact to air, water and land, widespread implementation of such policies could adversely affect markets for our products.

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SELECTED CONSOLIDATED FINANCIAL INFORMATION

Selected Consolidated Financial Information

The following selected consolidated financial information for each of the years in the three-year period ended December 31, 2007, is derived from our 2007 Consolidated Financial Statements.  Our consolidated financial statements for each of the years in the three-year period ended December 31, 2007 have been audited by PricewaterhouseCoopers LLP, Chartered Accountants.  The information set forth below should be read in conjunction with our MD&A and our 2007 Consolidated Financial Statements.

	Year ended December 31,
($ millions except per share amounts)	2007	2006	2005
Revenues	17,933	15,829	11,129
Net earnings	2,832	2,971	1,158
Per common share (undiluted)	6.14	6.47	2.54
Per common share (diluted)	6.02	6.32	2.48
Cash flow from operations	3,805	4,533	2,476
Capital and exploration expenditures	5,415	3,613	3,153

	As at December 31,
($ millions)	2007	2006	2005
Total assets	24,167	18,759	15,126
Long-term debt	3,811	2,363	2,984
Accrued liabilities and other(1)	1,434	1,214	1,005
Shareholders’ equity	11,613	8,952	5,996

Note:

(1)           See Note 8 to our 2007 Consolidated Financial Statements, which is incorporated by reference herein.

The following table sets forth, for each of the two most recently completed financial years, the revenues for each category of our principal products or services that accounted for 15 per cent or more of our total consolidated revenues.

Revenues from: ($ millions)	2007		%	2006		%
Transportation fuel sales	8,056		45	7,016		44
Crude oil sales	5,124		29	5,199		33
Energy marketing and trading	2,883		16	1,582		10
Other (2)	1,840		10	2,019		13
Total	17,903	(1)	100	15,816	(1)	100

Notes:

(1)           Excludes interest income.

(2)           Includes net insurance proceeds of $436 million in 2006 (2007 - nil)

Dividend Policy and Record

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 $0.10 per share from $0.08 per share in the second quarter of 2007, and an increase to $0.08 per share from $0.06 per share during the second quarter of 2006.

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

	Year Ended December 31,
	2007	2006	2005
Common Shares
cash dividends	$0.38	$0.30	$0.24
Dividends paid in common shares	-	-	-

MANAGEMENT’S DISCUSSION AND ANALYSIS

Our MD&A, dated February 27, 2008, is incorporated by reference herein and forms an integral part of this AIF, and should be read in conjunction with our 2007 Consolidated Financial Statements and the notes thereto.

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, 2007, a total of 462,782,806 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) Under Review — Developing by Dominion Bond Rating Service Limited; A3 with a stable trend by Moody’s Investors Service, Inc; and A-, with a stable trend by Standard & Poor’s Rating Services, a division of the McGraw-Hill Companies, Inc.

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 A3 by Moody’s is the third

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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 A- by S&P is the third 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.

MARKET FOR OUR SECURITIES

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

Price Range and Trading Volume of Common Shares

Toronto Stock Exchange

2007	Price Range ($ Cdn)		Trading Volume
	High	Low	(000’s)
January	92.85	81.50	43,938
February	88.65	82.29	30,930
March	90.00	79.66	34,616
April	94.20	87.58	27,825
May	96.81	88.39	29,160
June	99.70	91.10	30,799
July	100.67	93.23	31,184
August	97.74	88.72	31,945
September	101.55	92.14	36,572
October	104.15	91.25	42,114
November	108.00	94.59	33,919
December	109.47	94.89	24,200

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New York Stock Exchange

2007	Price Range ($US)		Trading Volume
	High	Low	(000’s)
January	77.35	69.39	43,617
February	75.37	70.25	25,738
March	77.79	67.78	26,717
April	82.89	75.71	22,857
May	89.43	79.81	25,577
June	93.52	85.59	21,554
July	96.41	87.45	22,516
August	92.44	82.37	21,372
September	100.11	88.83	20,197
October	109.49	91.40	24,598
November	117.98	94.56	20,548
December	111.31	94.70	13,011

DIRECTORS AND EXECUTIVE OFFICERS

Directors

The following individuals are directors of Suncor.

Name and Municipality         of Residence	Period Served and Independence	Principle Occupations During Past Five Years
Mel E. Benson (3)(4) Calgary, Alberta	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 partner in Kanetax Energy Inc., Tenax Energy Inc. and a director of Winalta Homes Inc. He is active with several charitable organizations including Hull Family Services and the Canadian Aboriginal Professional Association. He is also a member of the Board of Governors for the Northern Alberta Institute of Technology and the National Aboriginal Economic Development Board.
Brian A. Canfield (1)(2) Point Roberts, Washington	Director since 1995 Independent	Brian Canfield is the chairman of TELUS Corporation, a telecommunications company. Mr. Canfield is also a director and chairman of the governance committee of the Canadian Public Accountability Board. 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) Toronto, Ontario	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. Prior to that, 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.

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Name and Municipality         of Residence	Period Served and Independence	Principle Occupations During Past Five Years
Brian A. Felesky (1)(4) Calgary, Alberta	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. Mr. Felesky is actively involved in not-for-profit and charitable organizations. He is the 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 and board member of the Calgary Stampede Foundation. Mr. Felesky is a Queen’s Counsel and member of the Order of Canada.
John T. Ferguson(2)(3) Edmonton, Alberta	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, 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) Bonita Springs, Florida	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 the company 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 Calgary, Alberta	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 U.S. offshore and onshore drilling company Transocean. In 2006, he was selected to serve as a member of the North American Competitiveness Council. In 2007, he became a member of the Calgary Committee to End Homelessness and is currently chair of 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) Houston, Texas	Director since 1998 Independent	John Huff is chairman of Oceaneering International Inc., an oil field services company. He is also a director of BJ Services Company, KBR and Rowan Companies Inc. Mr. Huff is a member of the National Petroleum Council, the Houston Museum of Natural Science and St. Luke’s Episcopal Hospital System in Houston.
M. Ann McCaig (3)(4) Calgary, Alberta	Director since 1995 Independent	Ann McCaig is actively involved with charitable and community activities. She is past co-chair of the Alberta Children’s Hospital Foundation which raised $52 million for the new state-of-the-art pediatric facility in Calgary. She is currently chair of the Alberta Adolescent Recovery Centre, a trustee of the Killam Estate, chair of the Calgary Health Trust, a director of the Calgary Stampede Foundation and honourary chair of the Alberta Bone and Joint Institute. She is also chancellor emeritus of the University of Calgary and a member of the Order of Canada.

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Name and Municipality         of Residence	Period Served and Independence	Principle Occupations During Past Five Years
Michael W. O’Brien(1)(2) Canmore, Alberta	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) West Vancouver, British Columbia	Director since 2006 Independent	Eira Thomas has been chief executive officer of Stornoway Diamond Corporation, a mineral exploration company, 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)Board Policy, Strategy Review & Governance Committee

(3)Human Resources and Compensation Committee

(4)Environment, Health & Safety Committee

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Executive Officers

The following individuals are the executive officers of Suncor.

Name and Municipality of Residence	Office(1)(2)
J. KENNETH ALLEY Calgary, Alberta	Senior Vice President and Chief Financial Officer
MIKE M. ASHAR Calgary, Alberta	Executive Vice President, Strategic Growth and Energy Trading
KIRK BAILEY Fort McMurray, Alberta	Executive Vice President, Oil Sands
DAVID W. BYLER Cochrane, Alberta	Executive Vice President, Natural Gas and Renewable Energy
RICHARD L. GEORGE Calgary, Alberta	President and Chief Executive Officer
TERRENCE J. HOPWOOD Calgary, Alberta	Senior Vice President and General Counsel
SUE LEE Calgary, Alberta	Senior Vice President, Human Resources and Communications
KEVIN D. NABHOLZ Calgary, Alberta	Executive Vice President, Major Projects
THOMAS L. RYLEY Toronto, Ontario	Executive Vice President, Refining and Marketing
JAY THORNTONCalgary, Alberta	Senior Vice President, Business Integration
STEVEN W. WILLIAMS Calgary, Alberta	Chief Operating Officer

Note:

(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. Ashar is president of Suncor Energy Marketing Inc. and Mr. Ryley is president of Suncor Energy Products Inc., each of which are Suncor’s Canada-based downstream subsidiaries; and Mr. Nabholz, Ms. Lee, and Mr. Thornton are officers of Suncor Energy Services Inc., which provides major projects management, human resources and communication, business integration and other shared services to the Suncor group of companies.

(2)

This information reflects the positions of officers as at December 31, 2007.

All of the foregoing executive officers of the Company have, for the past five years, been actively engaged as executives or employees of Suncor or its affiliates.

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%.

Additional Disclosure for Directors and Executive Officers

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

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(i)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:

(a)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;

(b)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

(c)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 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.

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

(a)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

(b)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;

(iii)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; and

(iv)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.

INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS

No director, executive officer, or principal holder of Suncor 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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INTERESTS OF EXPERTS

As at the date hereof the designated professionals of GLJ Petroleum Consultants Ltd., as a group, beneficially owned, directly or indirectly, less than 1% of our outstanding securities, including the securities of our associates and affiliates.

FEES PAID TO AUDITORS

Fees Paid to Auditors

Fees payable to PricewaterhouseCoopers LLP in 2006 and 2007 are detailed below.

($)	2007	2006(1)
Audit fees	1 440 000	1 719 000
Audit-related fees	448 000	295 000
Tax fees	2 000	-
All other fees	-	3 000
Total	1 890 000	2 017 000

(1)Certain prior period comparative figures have been reclassified to conform to current period presentation.

The nature of each category of fees is described below.

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, attest services not required by statute or regulation, and membership fees levied by the Canadian Public Accountability Board.

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.

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.

Audit Committee Charter

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

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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;

·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:

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·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;

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.

RELIANCE ON EXEMPTIVE RELIEF

We are reporting our reserves data in accordance with, and are relying on, the terms of the following MRRS Decision Document: In the Matter of the Securities Legislation of Alberta, British Columbia, Saskatchewan, Manitoba, Ontario, Quebec, Nova Scotia, Newfoundland and Labrador, Yukon, Northwest Territories and Nunavut AND In the Matter of The Mutual Reliance Review System for Exemptive Relief Applications AND In the Matter of Suncor Energy Inc., December 22, 2003 (the “Decision Document”).

Our reserves data consists of the following:

·net proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2007, using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2007, and the related standardized measure;

·gross and net proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2007;  and

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·gross and net proved and probable working interest oil and gas reserve quantities relating to Firebag in-situ leases, estimated as at December 31, 2007, using constant dollar cost and pricing assumptions, generally intended to represent a normalized annual average for the year in accordance with CSA Staff Notice 51-315.

Our estimates of reserves and related standardized measure of discounted future net cash flows (the “standardized measure”) were evaluated or reviewed in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to the extent necessary to reflect the terminology and standards of US disclosure requirements, including:

·the information required by the United States Financial Accounting Standards Board, including Financial Accounting Standard No. 69;

·the information required by SEC Industry Guide 2 Disclosure of Oil and Gas Operations, as amended from time to time;  and

·certain other information required in accordance with US disclosure practices.

If we had been reporting our reserves data in accordance with NI 51-101 and had not been relying on the terms of the Decision Document, we would have been required to report the following:

·proved and probable working interest oil and gas reserve quantities relating to oil and gas operations, gross and net, using forecast prices and costs for each of proved developed producing reserves, proved developed non-producing reserves, proved undeveloped reserves, proved reserves (in total), probable reserves (in total) and proved plus probable reserves (in total);  and

·future net revenue attributable to the reserves categories referred to above, estimated using forecast prices and costs, before and after deducting future income tax expenses, calculated without discount and using discount rates of 5%, 10%, 15% and 20%.

LEGAL PROCEEDINGS

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 ten percent of our current assets.

ADDITIONAL INFORMATION

Additional information, including directors’ and officers’ remuneration and indebtedness, principal holders of our securities, options to purchase securities 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 2007 Consolidated Financial Statements.

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

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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 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

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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

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.

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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.
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.

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.)

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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.

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Appendix B

Pre-approval Request Form

NATURE OF WORK	ESTIMATED FEES (Cdn $)
Total

Date Signature

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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; 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.

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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.

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

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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 (“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

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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 January 26, 2006

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FORM 51-101F3

REPORT OF MANAGEMENT AND DIRECTORS

ON RESERVES DATA AND OTHER INFORMATION

This is the form referred to in item 3 of section 2.1 of National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”), as amended pursuant to the MRRS Decision Document dated December 22, 2003, In the Matter of Suncor Energy Inc. (the “Decision Document”).

Terms to which a meaning is ascribed in the Decision Document have the same meaning in this form.

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 and surface mineable oil sands activities in accordance with securities regulatory requirements.  This information includes reserves data, which consist of the following:

(a)proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2007, and the related standardized measure;

(b)proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2007;  and

(c)proved and probable working interest oil and gas reserve quantities relating to Firebag in-situ leases, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions, generally intended to represent a normalized annual average for the year in accordance with CSA Staff Notice 51-315.

GLJ Petroleum Consultants Ltd., independent qualified reserves evaluators, have evaluated the Company’s reserves data.  The report of the independent qualified reserves evaluators will be filed with securities regulatory authorities concurrently with this report.

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 evaluators;

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

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

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 and surface mineable oil sands 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 the reserves data and other oil and gas and surface mineable oil sands information;

(b)the filing of the report of the independent qualified reserves evaluators on the reserves data; and

(c)the content and filing of this report.

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Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

“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 3, 2008

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REPORT ON RESERVES DATA

BY INDEPENDENT QUALIFIED RESERVES

EVALUATOR

Suncor Energy Inc.

P.O. Box 38

112 – 4th Avenue S.W.

Calgary, AB T2P 2V5

To:The Board of Directors of Suncor Energy Inc.

Re:Form 51-101F2, as modified in accordance with exemptions from
National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities (“NI 51-101”)
contained in the MRRS Decision Document dated December 22, 2003,
In the Matter of Suncor Energy Inc. (the “Decision Document”)

We are providing this report in accordance with the terms of the Decision Document and any capitalized terms, not otherwise defined in this report, shall have the same meaning as set out in the Decision Document.

We have evaluated the Company’s reserves data as at December 31, 2007. The reserves data consist of the following:

Proved working interest oil and gas reserve quantities relating to oil and gas operations, other than mining, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2007, and the related standardized measure; proved and probable working interest oil reserve quantities relating to surface mineable oil sands operations estimated as at December 31, 2007; and proved and probable working interest oil reserves quantities relating to Firebag in-situ leases, estimated as at December 31, 2007 using constant dollar cost and pricing assumptions.

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 evaluated or reviewed the Company’s estimates of reserves and related future net revenue (or, where applicable, related standardized measure of discounted future net cash flows (the standardized measure)) in accordance with the standards set out in the Canadian Oil and Gas Evaluation Handbook (the “COGE Handbook”) modified to the extent necessary to reflect the terminology and standards of the US Disclosure Requirements.

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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, as modified to the extent necessary to reflect the terminology and standards of the US Disclosure Requirements.

The following table sets forth the estimated standardized measure of future cash flows (before deducting income taxes) attributed to proved oil and gas reserve quantities not related to mining operations, estimated using constant prices and costs and calculated using a discount rate of 10 percent, included in the reserves data of the Company evaluated for the year ended, December 31, 2007:

		Standardized Measure of Future Cash Flows for Proved Oil and Gas Reserve Quantities (before income taxes, 10% discount rate)
Preparation Date of Report	Location of Reserves	Evaluated	Reviewed	Total
February 11, 2008	Canada	$1,108 million (94%)	$75 million (6%)	$1,183 million (100%)

In addition, all proved plus probable company gross and net reserves have been evaluated for Suncor’s oil sands mining properties located in Canada and all reserves and resources have been evaluated or reviewed for all of Suncor’s oil and gas plus mining operations.

In our opinion, the reserves data evaluated by us have, in all material respects, been determined and are in accordance with the COGE Handbook, as modified or amended as set out above. We express no opinion on the reserves data that we reviewed but did not audit or evaluate.

We have no responsibility to update our reports evaluating reserves data of the Company by us for the year ended December 31, 2007 for events and circumstances occurring after the preparation dates of our reports.

Reserves are estimates only, and not exact quantities. Because the reserves data are based on judgments regarding future events, actual results will vary and the variations may be material.

	Executed as to our report referred to above:
	GLJ PETROLEUM CONSULTANTS LTD.
	ORIGINALLY SIGNED BY
	Dana B. Laustsen, P. Eng.
	Executive Vice-President
Calgary, Alberta, Canada
March 3, 2008

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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 page 31 of Exhibit 99-2.

AUDIT COMMITTEE FINANCIAL EXPERT

        See pages 49 and 50 of Annual Information Form.

CODE OF ETHICS

        See page 51 of Annual Information Form.

FEES PAID TO PRINCIPAL ACCOUNTANT

        See page 48 of Annual Information Form.

AUDIT COMMITTEE PRE-APPROVAL POLICIES

        See Schedule "A" of Annual Information Form.

APPROVAL OF NON-AUDIT SERVICES

        See page 48 of Annual Information Form.

OFF-BALANCE SHEET ARRANGEMENTS

        See page 19 of Exhibit 99-2.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

        See page 17 of Exhibit 99-2.

IDENTIFICATION OF THE AUDIT COMMITTEE

        See page 49 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 4, 2008
	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, 2007, including reconciliation to U.S. GAAP (Note 20)
99-2	Management's Discussion and Analysis for the fiscal year ended December 31, 2007, dated February 27, 2008
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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SUNCOR ENERGY INC. (Exact name of registrant as specified in its charter)
112 - 4^th Avenue S.W. Box 38 Calgary, Alberta, Canada T2P 2V5 (403) 269-8100
CT Corporation System 111 Eighth Avenue New York, New York, U.S.A. 10011 (212) 894-8940
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, 2007, 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 53 to 90 and all related financial information contained in this Annual Report, including Management's Discussion and Analysis.

We, as Suncor Energy Inc.'s Chief Executive Officer and Chief Financial Officer, have certified Suncor's annual disclosure document filed with the United States Securities and Exchange Commission (Form 40-F) as required by the United States Sarbanes-Oxley Act.

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 53 to 57. 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 all aspects of the company's operations.

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 27, 2008

SUNCOR ENERGY INC. 2007ANNUAL REPORT 49

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, 2007, 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, 2007.

4.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2007 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 27, 2008

50 SUNCOR ENERGY INC. 2007ANNUAL REPORT

INDEPENDENT AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have completed integrated audits of the consolidated financial statements and internal control over financial reporting of Suncor Energy Inc. (the "Company") as of December 31, 2007 and 2006 and an audit of its 2005 consolidated financial statements. Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated balance sheets of Suncor Energy Inc. as at December 31, 2007 and December 31, 2006, and the related consolidated statements of earnings and comprehensive income, cash flows and shareholders' equity for each of the years in the three year period ended December 31, 2007. 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, 2007 and December 31, 2006 and for each of the years then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Company's financial statements for the year ended December 31, 2005 in accordance with Canadian generally accepted auditing standards. 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, 2007 and December 31, 2006 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2007 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 of December 31, 2007, 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 effectiveness of 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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 51

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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 27, 2008

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 financial statements, such as the changes described in note 1 to the consolidated financial statements. Our report to the shareholders dated February 27, 2008 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors' Report when the change is properly accounted for and adequately disclosed in the financial statements.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada

February 27, 2008

52 SUNCOR ENERGY INC. 2007ANNUAL 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 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. Cash equivalents and short-term investments are stated at cost, which approximates market value.

(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 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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 53

(d) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

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.

54 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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.

Impairment

Property, plant and equipment, including capitalized asset retirement costs, 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.

(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 LIFO 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 Section (m) Recently Issued Canadian Accounting Standards.

(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 long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Each financial asset and financial liability instrument is initially measured at fair value, adjusted for any associated transaction costs.

The company periodically enters into derivative commodity contracts such as forwards, futures, swaps and options to hedge against the potential adverse impact of changing market prices due to changes in the underlying commodity indices. The company also periodically enters into derivative contracts such as interest rate swaps and foreign currency forwards as part of its risk management strategy to manage exposure to interest and foreign exchange rate fluctuations.

Derivative contracts, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge each period, changes in the fair value of the

SUNCOR ENERGY INC. 2007ANNUAL REPORT 55

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 each period, 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.

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 below. 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.

See also Section (m) Recently Issued Canadian Accounting Standards.

(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.

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. Consideration paid to the company on exercise of options is credited to share capital.

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 the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with

56 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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

Inventories

In June 2007, the Canadian Institute of Chartered Accountants (CICA) approved Handbook section 3031 "Inventories". Effective January 1, 2008 this standard eliminates the use of a LIFO (last-in-first-out) based valuation approach for inventory. 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. This standard can be applied prospectively with an initial adjustment to retained earnings or applied retrospectively with restatement of comparative balances.

The company currently uses a LIFO methodology for crude oil and refined product inventory and will be transitioning to a FIFO (first-in-first-out) methodology beginning January 1, 2008. Retrospective application with restatement will increase the following financial statement balances upon transition:

Inventory	$404 million
Future Income Tax Liability	$121 million
Retained Earnings	$283 million

Going Concern

In June 2007, the CICA approved amendments to Handbook section 1400 "General Standards of Financial Statement Presentation". The revisions, effective January 1, 2008, are to include specific requirements for assessing and disclosing an entity's ability to continue as a going concern. The revised standard will not impact net earnings or financial position.

Capital Disclosures

In December 2006, the CICA approved Handbook section 1535 "Capital Disclosures". Effective January 1, 2008 this standard outlines required disclosure of specific information about an entity's objectives, policies and processes for managing capital. The new standard will not impact net earnings or financial position.

Financial Instruments

In December 2006, the CICA approved Handbook section 3862 "Financial Instruments Disclosure" and section 3863 "Financial Instruments Presentation". Effective January 1, 2008, these standards provide a complete set of disclosure and presentation requirements for financial instruments. The standards have increased emphasis on making disclosures more transparent, while enhancing risk identification and discussion of how these risks are managed in relation to both recognized and unrecognized financial instruments. The new standard will not impact net earnings or financial position.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 57

CONSOLIDATED STATEMENTS OF EARNINGS
AND COMPREHENSIVE INCOME

For the years ended December 31 ($ millions)		2007		2006 (restated) (note 1)		2005 (restated) (note 1)
Revenues
	Operating revenues (notes 7, 17 and 19)	15 020		13 798		9 728
	Energy marketing and trading activities (note 7c)	2 883		1 582		827
	Net insurance proceeds	—		436		572
	Interest	30		13		2
		17 933		15 829		11 129
Expenses
	Purchases of crude oil and products	5 935		4 678		4 164
	Operating, selling and general	3 375		3 043		2 437
	Energy marketing and trading activities (note 7c)	2 870		1 541		789
	Transportation and other costs	198		212		152
	Depreciation, depletion and amortization	864		695		568
	Accretion of asset retirement obligations	48		34		30
	Exploration (note 19)	95		104		56
	Royalties (note 5)	691		1 038		555
	Taxes other than income taxes (note 19)	648		595		529
	Loss (gain) on disposal of assets	7		(1	)	(13	)
	Project start-up costs	68		45		25
	Financing expenses (income) (note 15)	(211	)	39		(15	)
		14 588		12 023		9 277
Earnings Before Income Taxes		3 345		3 806		1 852
Provision for income taxes (note 10)
	Current	382		20		39
	Future	131		815		655
		513		835		694
Net Earnings		2 832		2 971		1 158
Other comprehensive income (loss) (notes 1, 7 and 18)		(190	)	10		(26	)
Comprehensive Income		2 642		2 981		1 132
Net Earnings Per Common Share (dollars) (note 13)
Net earnings attributable to common shareholders
	Basic	6.14		6.47		2.54
	Diluted	6.02		6.32		2.48
Cash dividends		0.38		0.30		0.24

See accompanying Summary of Significant Accounting Policies and Notes.

58 SUNCOR ENERGY INC. 2007ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)			2007		2006 (restated) (note 1)
Assets
	Current assets
		Cash and cash equivalents	569		521
		Accounts receivable (notes 1, 7, 11 and 19)	1 416		1 050
		Inventories (note 16)	608		589
		Income taxes receivable	95		33
		Future income taxes (note 10)	130		109
	Total current assets		2 818		2 302
	Property, plant and equipment, net (note 3)		20 945		16 160
	Deferred charges and other (note 4)		404		297
	Total assets		24 167		18 759
Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	6		7
		Accounts payable and accrued liabilities (notes 1, 7, 8 and 9)	2 775		2 111
		Taxes other than income taxes	72		40
		Income taxes payable	244		—
	Total current liabilities		3 097		2 158
	Long-term debt (note 6)		3 811		2 363
	Accrued liabilities and other (notes 8 and 9)		1 434		1 214
	Future income taxes (note 10)		4 212		4 072
	Total liabilities		12 554		9 807
	Commitments and contingencies (note 11)
	Shareholders' equity
		Share capital (note 12)	881		794
		Contributed surplus (note 12)	194		100
		Accumulated other comprehensive income (loss) (notes 1, 7 and 18)	(253	)	(71	)
		Retained earnings (note 1)	10 791		8 129
	Total shareholders' equity		11 613		8 952
	Total liabilities and shareholders' equity		24 167		18 759

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 27, 2008

SUNCOR ENERGY INC. 2007ANNUAL REPORT 59

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions)		2007		2006		2005
Operating Activities
Cash flow from operations (a)		3 805		4 533		2 476
Decrease (increase) in operating working capital
	Accounts receivable	(365	)	53		(477	)
	Inventories	(19	)	(66	)	(63	)
	Accounts payable and accrued liabilities	226		87		435
	Taxes payable/receivable	246		(43	)	(23	)
Cash flow from operating activities		3 893		4 564		2 348
Cash Used in Investing Activities (a)		(5 362	)	(3 489	)	(3 113	)
Net Cash Surplus (Deficiency) Before Financing Activities		(1 469	)	1 075		(765	)
Financing Activities
Increase (decrease) in short-term debt		(4	)	(42	)	19
Net proceeds from issuance of long-term debt		1 835		—		—
Net increase (decrease) in long-term debt		(171	)	(622	)	808
Issuance of common shares under stock option plans		62		45		69
Dividends paid on common shares		(162	)	(127	)	(102	)
Deferred revenue		4		27		50
Cash flow provided by (used in) financing activities		1 564		(719	)	844
Increase in Cash and Cash Equivalents		95		356		79
Effect of Foreign Exchange on Cash and Cash Equivalents		(47	)	—		(2	)
Cash and Cash Equivalents at Beginning of Year		521		165		88
Cash and Cash Equivalents at End of Year		569		521		165

(a)

See Schedules of Segmented Data on pages 63 and 64.

See accompanying Summary of Significant Accounting Policies and Notes.

60 SUNCOR ENERGY INC. 2007ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CHANGES
IN SHAREHOLDERS' EQUITY

For the years ended December 31 ($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings		Accumulated Other Comprehensive Income (AOCI)
At December 31, 2004, as previously reported	651	32		(55	)	4 246		—
Retroactive adjustment for change in accounting policy, net of tax (note 1)	—	—		55		—		(55	)
At December 31, 2004, as restated	651	32		—		4 246		(55	)
Net earnings	—	—		—		1 158		—
Dividends paid on common shares	—	—		—		(102	)	—
Issued for cash under stock option plans	74	(5	)	—		—		—
Issued under dividend reinvestment plan	7	—		—		(7	)	—
Stock-based compensation expense	—	23		—		—		—
Change in AOCI related to foreign currency translation	—	—		—		—		(26	)
At December 31, 2005, as restated	732	50		—		5 295		(81	)
Net earnings	—	—		—		2 971		—
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		—		8 129		(71	)
Net earnings	—	—		—		2 832		—
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	881	194		—		10 791		(253	)

See accompanying Summary of Significant Accounting Policies and Notes.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 61

SCHEDULES OF SEGMENTED DATA ^(a)

	Oil Sands						Natural Gas						Refining and Marketing (note 2)
For the years ended December 31 ($ millions)	2007		2006		2005		2007		2006		2005		2007		2006		2005
EARNINGS
Revenues (b)
Operating revenues	6 195		6 259		2 938		541		554		632		8 278		6 981		6 155
Energy marketing and trading activities	—		—		—		—		—		—		2 890		1 607		827
Net insurance proceeds	—		436		572		—		—		—		—		—		—
Intersegment revenues (c)	580		712		455		12		23		47		—		—		—
Interest	—		—		—		—		1		—		5		5		2
	6 775		7 407		3 965		553		578		679		11 173		8 593		6 984
Expenses
Purchases of crude oil and products	157		89		32		—		—		—		6 351		5 308		4 613
Operating, selling and general (note 2)	2 435		2 198		1 455		135		110		93		693		669		682
Energy marketing and trading activities	—		—		—		—		—		—		2 876		1 572		810
Transportation and other costs	138		162		104		31		25		22		29		25		26
Depreciation, depletion and amortization	462		385		330		189		152		130		171		132		96
Accretion of asset retirement obligations	40		28		24		7		5		5		1		1		1
Exploration	13		22		10		82		82		46		—		—		—
Royalties (note 5)	565		911		406		126		127		149		—		—		—
Taxes other than income taxes	90		75		51		4		3		3		553		516		475
Loss (gain) on disposal of assets	1		—		—		(1	)	(4	)	(12	)	7		3		(1	)
Project start-up costs	60		38		25		—		—		—		8		7		—
Financing expenses (income)	—		—		—		—		—		—		—		—		—
	3 961		3 908		2 437		573		500		436		10 689		8 233		6 702
Earnings (loss) before income taxes	2 814		3 499		1 528		(20	)	78		243		484		360		282
Income taxes	(380	)	(716	)	(571	)	45		28		(88	)	(139	)	(125	)	(108	)
Net earnings (loss)	2 434		2 783		957		25		106		155		345		235		174
As at December 31
TOTAL ASSETS	18 108		13 692		11 648		1 811		1 503		1 307		4 519		4 037		3 172

(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 2007, 2006 or 2005 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.

62 SUNCOR ENERGY INC. 2007ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

	Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2007		2006		2005		2007		2006		2005
EARNINGS
Revenues (b)
Operating revenues	6		4		3		15 020		13 798		9 728
Energy marketing and trading activities	(7	)	(25	)	—		2 883		1 582		827
Net insurance proceeds	—		—		—		—		436		572
Intersegment revenues (c)	(592	)	(735	)	(502	)	—		—		—
Interest	25		7		—		30		13		2
	(568	)	(749	)	(499	)	17 933		15 829		11 129
Expenses
Purchases of crude oil and products	(573	)	(719	)	(481	)	5 935		4 678		4 164
Operating, selling and general (note 2)	112		66		207		3 375		3 043		2 437
Energy marketing and trading activities	(6	)	(31	)	(21	)	2 870		1 541		789
Transportation and other costs	—		—		—		198		212		152
Depreciation, depletion and amortization	42		26		12		864		695		568
Accretion of asset retirement obligations	—		—		—		48		34		30
Exploration	—		—		—		95		104		56
Royalties (note 5)	—		—		—		691		1 038		555
Taxes other than income taxes	1		1		—		648		595		529
Loss (gain) on disposal of assets	—		—		—		7		(1	)	(13	)
Project start-up costs	—		—		—		68		45		25
Financing expenses (income)	(211	)	39		(15	)	(211	)	39		(15	)
	(635	)	(618	)	(298	)	14 588		12 023		9 277
Earnings (loss) before income taxes	67		(131	)	(201	)	3 345		3 806		1 852
Income taxes	(39	)	(22	)	73		(513	)	(835	)	(694	)
Net earnings (loss)	28		(153	)	(128	)	2 832		2 971		1 158
As at December 31
TOTAL ASSETS	(271	)	(473	)	(1 001	)	24 167		18 759		15 126

SUNCOR ENERGY INC. 2007ANNUAL REPORT 63

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Oil Sands						Natural Gas						Refining and Marketing (note 2)
For the years ended December 31 ($ millions)			2007		2006		2005		2007		2006		2005		2007		2006		2005
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		2 434		2 783		957		25		106		155		345		235		174
	Exploration expenses		—		—		—		67		52		46		—		—		—
	Non-cash items included in earnings
		Depreciation, depletion and amortization	462		385		330		189		152		130		171		132		96
		Future income taxes	97		731		609		(43	)	(28	)	88		40		70		72
		Loss (gain) on disposal of assets	1		—		—		(1	)	(4	)	(12	)	7		3		(1	)
		Stock-based compensation expense	49		25		11		5		2		—		25		13		6
		Other	1		14		23		7		1		5		(5	)	(7	)	16
	Increase (decrease) in deferred credits and other		48		(21	)	(14	)	(1	)	—		—		(3	)	(3	)	—
Total cash flow from (used in) operations			3 092		3 917		1 916		248		281		412		580		443		363
Decrease (increase) in operating working capital			637		426		(270	)	22		(27	)	(5	)	(118	)	(102	)	(30	)
Total cash from (used in) operating activities			3 729		4 343		1 646		270		254		407		462		341		333
Cash from (used in) investing activities:
Capital and exploration expenditures			(4 431	)	(2 463	)	(1 948	)	(531	)	(458	)	(363	)	(376	)	(665	)	(779	)
Acquisition of Denver refineries and related assets			—		—		—		—		—		—		—		—		(62	)
Deferred maintenance shutdown expenditures			(135	)	—		(65	)	(6	)	—		(2	)	(73	)	(80	)	(10	)
Deferred outlays and other investments			(18	)	(2	)	(1	)	—		—		—		—		7		4
Proceeds from disposals			3		2		41		5		15		21		1		4		3
Proceeds from property loss			—		36		44		—		—		—		—		—		—
Decrease (increase) in investing working capital			333		197		47		—		—		—		(43	)	(53	)	26
Total cash (used in) investing activities			(4 248	)	(2 230	)	(1 882	)	(532	)	(443	)	(344	)	(491	)	(787	)	(818	)
Net cash surplus (deficiency) before financing activities			(519	)	2 113		(236	)	(262	)	(189	)	63		(29	)	(446	)	(485	)

(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.

64 SUNCOR ENERGY INC. 2007ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Corporate and Eliminations						Total
For the years ended December 31 ($ millions)			2007		2006		2005		2007		2006		2005
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		28		(153	)	(128	)	2 832		2 971		1 158
	Exploration expenses		—		—		—		67		52		46
	Non-cash items included in earnings
		Depreciation, depletion and amortization	42		26		12		864		695		568
		Future income taxes	37		42		(114	)	131		815		655
		Loss (gain) on disposal of assets	—		—		—		7		(1	)	(13	)
		Stock-based compensation expense	24		13		6		103		53		23
		Other	(236	)	(22	)	(77	)	(233	)	(14	)	(33	)
	Increase (decrease) in deferred credits and other		(10	)	(14	)	86		34		(38	)	72
Total cash flow from (used in) operations			(115	)	(108	)	(215	)	3 805		4 533		2 476
Decrease (increase) in operating working capital			(453	)	(266	)	177		88		31		(128	)
Total cash from (used in) operating activities			(568	)	(374	)	(38	)	3 893		4 564		2 348
Cash from (used in) investing activities:
Capital and exploration expenditures			(77	)	(27	)	(63	)	(5 415	)	(3 613	)	(3 153	)
Acquisition of Denver refineries and related assets			—		—		—		—		—		(62	)
Deferred maintenance shutdown expenditures			—		—		—		(214	)	(80	)	(77	)
Deferred outlays and other investments			(14	)	(2	)	(6	)	(32	)	3		(3	)
Proceeds from disposals			—		—		—		9		21		65
Proceeds from property loss			—		—		—		—		36		44
Decrease (increase) in investing working capital			—		—		—		290		144		73
Total cash (used in) investing activities			(91	)	(29	)	(69	)	(5 362	)	(3 489	)	(3 113	)
Net cash surplus (deficiency) before financing activities			(659	)	(403	)	(107	)	(1 469	)	1 075		(765	)

SUNCOR ENERGY INC. 2007ANNUAL REPORT 65

SUNCOR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGES IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007 the company adopted CICA Handbook Section 3855 "Financial Instruments, Recognition and Measurement", Section 3865 "Hedging", Section 1530 "Comprehensive Income" and Section 3251 "Equity".

Sections 3855 and 3865 establish accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. Section 1530 establishes standards for reporting and display of comprehensive income, where comprehensive income refers to all changes in equity (net assets) during a reporting period except those resulting from investments by owners and distributions to owners, and Section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period.

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 long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and/or appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Upon initial recognition, each financial asset and financial liability instrument is recorded at fair value, adjusted for any transaction costs.

Derivative contracts, excluding those considered as normal purchases and normal sales, 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 each period. 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'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. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized.

The company's equity section now contains a new caption "Accumulated Other Comprehensive Income". In addition to containing the effective portions of the gains/losses on our cash flow hedges, accumulated other comprehensive income will also contain the cumulative foreign currency translation adjustment of our self-sustaining foreign operations.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following increases (decreases), net of income taxes, were recorded to the Consolidated Balance Sheet:

($ millions)
Financial Assets (1)	42
Financial Liabilities (1)	29
Retained Earnings (2)	5
Cumulative Foreign Currency Translation (3)	71
Accumulated Other Comprehensive Loss (4)	(63	)

(1)

Recognition of fair value of derivative financial instruments designated as cash flow hedges and fair value hedges, and the related income tax impacts

(2)

Impact on adoption of the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges

(3)

Restatement of foreign currency translation adjustment to accumulated other comprehensive loss

(4)

Recognition of accumulated other comprehensive loss arising from the restatement of foreign currency translation adjustment, offset by accumulated other comprehensive income arising from the effective component on derivative financial instruments designated as cash flow hedges

The comparative consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

See Note 7 for a summary of financial instrument disclosures at December 31, 2007.

66 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 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

		2007		2006
($ millions)		Cost	Accumulated Provision	Cost	Accumulated Provision
Oil sands
	Plant	11 049	1 962	8 160	1 706
	Mine and mobile equipment	1 423	388	1 191	320
	In-situ properties	2 566	222	1 963	148
	Pipeline	149	35	149	29
	Capital leases	102	6	38	4
	Major projects in progress	3 830	—	2 887	—
		19 119	2 613	14 388	2 207
Natural gas
	Proved properties	2 405	1 042	1 975	874
	Unproved properties	238	32	186	21
	Other support facilities and equipment	92	30	90	23
		2 735	1 104	2 251	918
Refining and marketing
	Refinery	2 699	628	2 179	555
	Marketing	783	304	741	291
	Pipeline	53	4	35	3
	Major projects in progress	—	—	386	—
		3 535	936	3 341	849
Corporate		305	96	208	54
		25 694	4 749	20 188	4 028
Net property, plant and equipment			20 945		16 160

4. DEFERRED CHARGES AND OTHER

($ millions)	2007	2006
Deferred maintenance shutdown costs	296	172
Deferred government tax credits	36	74
Other	72	51
Total deferred charges and other	404	297

SUNCOR ENERGY INC. 2007ANNUAL REPORT 67

5. ROYALTIES

Our current estimation of Alberta Crown royalties is based on regulations currently in effect. Alberta Crown royalties currently in effect for each oil sands project require payments to the Government of Alberta based on annual gross revenues less related 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, 2007, was $565 million (2006 – $911 million, 2005 – $406 million). The balance of the consolidated royalty expense is in respect of natural gas royalties of $126 million (2006 – $127 million, 2005 – $149 million).

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

In January 2008, Suncor entered into a Royalty Amending Agreement with the government of Alberta to transition to the new royalty framework rates in the Generic Regime commencing January 1, 2010 to January 1, 2016. The new royalty framework rates will apply to the bitumen royalty for current production levels of our base oil sands mining operations, subject to a cap of 30% of R-C, and a minimum royalty of 1.2% of R (assuming the government enacts their proposed framework). In addition, the Suncor Royalty Amending agreement provides Suncor with certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes.

In 2016 and subsequent years, the royalty rates for all of our oil sands operations (our base operation and Firebag in-situ project) will be the rates prescribed under the generic regime.

6. LONG-TERM DEBT

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

($ millions)	2007		2006
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150) (i)	1 137		—
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	494		583
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	494		583
5.39% Series 4 Medium Term Notes, due in 2037 (ii)	600		—
6.70% Series 2 Medium Term Notes, due in 2011 (iii)	500		500
6.80% Medium Term Notes, repaid in 2007 (iii) (iv)	—		250
6.10% Medium Term Notes, repaid in 2007 (iii) (iv)	—		150
	3 225		2 066
Revolving-term debt, with interest at variable rates (see B. Credit Facilities)
Commercial Paper (interest at December 31, 2007 – 4.8%, 2006 – 4.3%) (v)	522		280
Total unsecured long-term debt	3 747		2 346
Secured long-term debt	1		1
Capital leases (vi), (vii)	102		38
Fair values of interest swaps	6		—
Deferred financing costs	(45	)	(22	)
Total long-term debt	3 811		2 363

(i)

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.

(ii)

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.

(iii)

The company has entered into various 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	2007	2006
Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.7%	5.2%
Swap of 6.80% Medium Term Notes to floating rates (iv)	250	2007	6.0%	6.0%
Swap of 6.10% Medium Term Notes to floating rates (iv)	150	2007	4.7%	5.3%

68 SUNCOR ENERGY INC. 2007ANNUAL REPORT

(iv)

During the third quarter of 2007, the company repaid maturing 6.10% $150 million Medium Term Notes using commercial paper, and the associated swap transaction expired.

During the first quarter of 2007, the company repaid maturing 6.80% $250 million Medium Term Notes using commercial paper, and the associated swap transaction expired.

(v)

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).

(vi)

Equipment leases with interest rates between 6.5% and 15.7% and maturity dates ranging from 2008 to 2037.

(vii)

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

($ millions)	Capital Leases	Other Long-term Debt
2008	9	529  (a)
2009	9	—
2010	9	—
2011	10	500
2012	10	—
Later years	277	2 680
Total minimum payments	324	3 709
Less amount representing imputed interest	222
Present value of obligation under capital leases	102

(a)

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

Long-term Debt (per cent)

	2007	2006
Variable rate	19	37
Fixed rate	81	63

B. Credit facilities

During 2007, our $300 million bilateral credit facility was amended and extended by one year to 2008 and the credit limit was increased by $30 million to $330 million total funds available. Our $2 billion syndicated credit facility was renegotiated and extended by one year to have a five year term expiring in June 2012 and the company's commercial paper program limit was increased by $300 million from $1.2 billion to $1.5 billion. Additionally, a $15 million revolving demand credit facility was renegotiated and increased by $15 million to $30 million. At December 31, 2007, the company had available credit facilities of $2,375 million, of which $1,579 was undrawn as follows:

($ millions)	2007
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2008	330
Facility that is fully revolving for a period of five years and expires in 2012	2 000
Facilities that can be terminated at any time at the option of the lenders	45
Total available credit facilities	2 375
Credit facilities supporting outstanding commercial paper	522
Credit facilities supporting standby letters of credit	274
Total undrawn credit facilities	1 579

7. FINANCIAL INSTRUMENTS

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 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 manage the exposure to losses that could result if commodity prices or foreign currency exchange 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 can 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).

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, or vice versa; a domestic currency debt may be converted to a foreign currency debt.

See below for more technical details and amounts.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 69

(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 long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

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 below. 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, other than the foreign exchange effect, of this debt until the gains or losses are realized.

The following table summarizes estimated fair value information about the company's financial instruments recognized in the Consolidated Balance Sheets at December 31:

	2007		2006
($ millions)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Cash and cash equivalents	569	569	521	521
Accounts receivable	1 416	1 416	1 050	1 050
Current liabilities	2 507	2 507	1 947	1 947
Long-term debt	3 811	3 926	2 363	2 505

(b)   Hedges

Fair Value Hedges

Suncor 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 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, 2007, the company had interest rate derivatives classified as fair value hedges outstanding for up to four 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, 2007. The notional amounts of interest rate swap contracts outstanding at December 31, 2007 are 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 the accounts 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, 2007, was a gain of $4 million, net of income taxes of $2 million.

Cash Flow Hedges

Suncor 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 oil 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 swap transactions and foreign exchange forward contracts.

At December 31, 2007, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity risk for 2008.

The 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, 2007 was a 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

70 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.

As at December 31, 2007, assets increased by $27 million and liabilities increased by $31 million as a result of recording derivative instruments at fair value in accordance with the new standards.

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, 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
As at December 31, 2005
Costless collars	7 000	50.00 – 92.57	149 – 276	2006
Costless collars	7 000	50.00 – 92.57	149 – 276	2007

Natural Gas	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2007
Swaps	–	–	–	–
As at December 31, 2006
Swaps	4 000	6.11	9	2007
As at December 31, 2005
Swaps	4 000	6.58	10	2006
Costless collars	25 000	10.76 – 16.13	24 – 36	2006	(d)
Costless collars	10 000	8.75 – 13.38	19 – 29	2006	(e)
Swaps	4 000	6.11	9	2007

Margin Hedges	Quantity (bpd)	Average Margin (US$/bbl)	Margin Hedged (Cdn$ millions) (b)	Hedge Period (c)
Refined product sale and crude purchase swaps
As at December 31, 2007	–	–	–	–
As at December 31, 2006	–	–	–	–
As at December 31, 2005	5 100	11.69	10	2006	(f)

Foreign Currency Hedges	Notional (Euro Millions)	Average Forward Rate	Dollars Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2007
Euro/Cdn forward	–	–	–	–
As at December 31, 2006
Euro/Cdn forward	20.6	1.41	29.0	2007	(g)
As at December 31, 2005
Euro/Cdn forward	9.9	1.39	13.8	2006	(h)
Euro/Cdn forward	20.6	1.41	29.0	2007	(g)

(a)

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

(b)

The revenue and margin hedged is translated to Cdn$ at the respective year-end exchange rate and is subject to change as the US$/Cdn$ exchange rate fluctuates during the hedge period.

(c)

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

(d)

For the period January to March 2006, inclusive.

(e)

For the period April to October 2006, inclusive.

(f)

For the period January to May 2006, inclusive.

(g)

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

(h)

Settlement for applicable forward was March 2006.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 71

Fair Value of Hedging Derivative Financial Instruments

The fair value of hedging derivative financial instruments as recorded, is the estimated amount, based on broker quotes and/or internal valuation models 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 at December 31:

($ millions)	2007		2006
Revenue hedge swaps and collars	(11	)	22
Fixed to floating interest rate swaps	8		16
Specific hedges of individual transactions	12		(4	)
Fair value of outstanding hedging derivative financial instruments	9		34

Accumulated Other Comprehensive Income (AOCI)

A reconciliation of changes in AOCI attributable to derivative hedging activities for the twelve-month period ending December 31, 2007, is as follows:

($ millions)	2007
AOCI attributable to derivatives and hedging activities, recorded upon initial adoption on January 1, 2007, net of income taxes of $5	8
Current year net changes arising from cash flow hedges, net of income taxes of $1	8
Net unrealized hedging gains at the beginning of the year reclassified to earnings during the period, net of income taxes of $2	(3	)
AOCI attributable to derivatives and hedging activities, at December 31, 2007, net of income taxes of $4	13

(c)    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. The financial energy trading activities 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. 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 trading and marketing expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss)

($ millions)	2007		2006		2005
Physical energy contracts trading activity	21		41		15
Financial energy contracts trading activity	(3	)	(3	)	5
General and administrative costs	(4	)	(3	)	(3	)
Total	14		35		17

The fair value of unsettled (unrealized) energy trading assets and liabilities at December 31 were as follows:

($ millions)	2007		2006
Energy trading assets	18		16
Energy trading liabilities	21		13
Net energy trading assets (liabilities)	(3	)	3

72 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Change in fair value of net assets

($ millions)	2007
Fair value of contracts at December 31, 2006	3
Fair value of contracts realized during the period	29
Fair value of contracts entered into during the period	(56	)
Changes in values attributable to market price and other market changes during the period	21
Fair Value of Contracts outstanding at December 31, 2007	(3	)

The source of the valuations of the above contracts was based on actively quoted prices and/or internal valuation models.

(d)   Counterparty Credit Risk

The company may be exposed to certain losses in the event that counterparties to the 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. The company minimizes this risk by ensuring that substantially all agreements are with counterparties of investment grade. Risk is also minimized through regular management review of credit ratings and potential exposure to such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2007	2006
Derivative contracts not accounted for as hedges	18	16
Derivative contracts accounted for as hedges	20	35
Total	38	51

8. ACCRUED LIABILITIES AND OTHER

($ millions)	2007	2006
Asset retirement obligations (a)	882	704
Employee future benefits liability (see note 9)	175	170
Employee and director incentive plans (b)	173	143
Deferred revenue	164	143
Environmental remediation costs (c)	11	26
Other	29	28
Total	1 434	1 214

(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)	2007		2006
Asset retirement obligations, beginning of year	808		543
Liabilities incurred	275		286
Liabilities settled	(59	)	(54	)
Accretion of asset retirement obligations	48		33
Asset retirement obligations, end of year	1 072		808

The portion of the ARO expected to be paid within one year is shown within current liabilities and amounts to an additional $190 million (2006 – $104 million).

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2007, was approximately $2.2 billion (2006 – $1.7 billion). The liability recognized in 2007 was discounted using the company's credit-adjusted risk-free rate of 6.0% (2006 – 5.5%). 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

SUNCOR ENERGY INC. 2007ANNUAL REPORT 73

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 $50 million (2006 – $32 million).

(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 $19 million (2006 – $17 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

9. 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, 2007, was $1,063 million (2006 – $1,024 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 2007, Plan Assets to meet the Benefit Obligation were $684 million (2006 – $616 million).

The excess of the Benefit Obligation over Plan Assets of $379 million (2006 – $408 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.

74 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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)		2007		2006		2007		2006
Change in benefit obligation
	Benefit obligation at beginning of year	866		745		158		144
	Service costs	51		44		4		5
	Interest costs	45		40		8		8
	Plan participants' contributions	5		4		—		—
	Foreign exchange	(5	)	(2	)	(2	)	—
	Actuarial (gain) loss	(28	)	67		(3	)	5
	Benefits paid	(33	)	(32	)	(3	)	(4	)
Benefit obligation at end of year (a) (d)		901		866		162		158
Change in plan assets (b)
	Fair value of plan assets at beginning of year	616		479		—		—
	Actual return on plan assets	7		60		—		—
	Employer contributions	88		103		—		—
	Foreign exchange	(2	)	—		—		—
	Plan participants' contributions	5		4		—		—
	Benefits paid	(30	)	(30	)	—		—
Fair value of plan assets at end of year (d)		684		616		—		—
Net unfunded obligation		(217	)	(250	)	(162	)	(158	)
Items not yet recognized in earnings:
	Unamortized net actuarial loss (c)	158		177		43		52
	Unamortized past service costs	—		—		(20	)	(23	)
Accrued benefit liability		(59	)	(73	)	(139	)	(129	)
	Current liability	(41	)	(46	)	(3	)	(3	)
	Long-term liability	(40	)	(44	)	(136	)	(126	)
	Long-term asset	22		17		—		—
Total accrued benefit liability		(59	)	(73	)	(139	)	(129	)

(a)

Obligations are based on the following assumptions:

	Pension Benefit Obligations		Other Post-Retirement Benefits Obligations
(percent)	2007	2006	2007	2006
Discount rate	5.25	5.00	5.25	5.00
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	(21	)	25	10	(9	)
Increase (decrease) to benefit obligation	—		—	(140	)	165	35	(32	)

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 2007 (2006 – 9.5%; 2005 – 10%). It is assumed that this rate will remain constant in 2008 and 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	15	(12	)

SUNCOR ENERGY INC. 2007ANNUAL REPORT 75

(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 (2006 – 11 years; 2005 – 11 years), and over the expected average future service life to full eligibility age of 12 years for other post-retirement benefits (2006 – 10 years; 2005 – 9 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)	2007	2006	2007	2006
Partially funded plans	901	866	—	—
Unfunded plans	—	—	162	158
Benefit obligation at end of year	901	866	162	158

Components of Net Periodic Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other Post-Retirement Benefits
($ millions)	2007		2006		2005		2007	2006	2005
Current service costs	51		44		32		4	5	5
Interest costs	45		40		38		8	8	6
Expected return on plan assets (ii)	(42	)	(32	)	(28	)	—	—	—
Amortization of net actuarial loss	25		28		21		3	1	1
Net periodic benefit cost recognized (iii)	79		80		63		15	14	12

Components of Net Incurred Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other Post-Retirement Benefits
($ millions)	2007		2006		2005		2007		2006	2005
Current service costs	51		44		32		4		5	5
Interest costs	45		40		38		8		8	6
Actual return on plan assets (ii)	(7	)	(60	)	(41	)	—		—	—
Actuarial (gain) loss	(28	)	67		75		(4	)	5	8
Net incurred benefit cost	61		91		104		8		18	19

(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)	2007	2006	2005	2007	2006	2005
Discount rate	5.00	5.00	5.75	5.00	5.00	5.75
Expected return on plan assets	6.50	6.50	6.75	N/A	N/A	N/A
Rate of compensation increase	5.00	4.50	4.50	4.75	4.25	4.25

76 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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, 2007 and 2006, and the target allocation for 2008, are as follows:

	Target Allocation %	Plan Assets %
Asset Category	2008	2007	2006
Equities	60	58	61
Fixed income	40	42	39
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 2008 will be $72 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
2008	38	5
2009	42	6
2010	45	6
2011	47	7
2012	51	8
2013 - 2017	310	47
Total	533	79

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 $13 million in 2007 (2006 – $11 million; 2005 – $10 million).

SUNCOR ENERGY INC. 2007ANNUAL REPORT 77

10. 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 two rates and the dollar effect is as follows:

		2007				2006				2005
($ millions)		Amount		%		Amount		%		Amount		%
Federal tax rate		1 053		32		1 256		33		648		35
Provincial abatement		(294	)	(9	)	(381	)	(10	)	(186	)	(10	)
Federal surtax		33		1		43		1		21		1
Provincial tax rates		307		9		395		10		213		12
Statutory tax and rate		1 099		33		1 313		34		696		38
Adjustment of statutory rate for future rate reductions		(133	)	(4	)	(146	)	(4	)	(84	)	(5	)
		966		29		1 167		30		612		33
Add (deduct) the tax effect of:
	Crown royalties	—		—		125		3		119		6
	Resource allowance (a)	—		—		(42	)	(1	)	(48	)	(2	)
	Large corporations tax	—		—		2		—		23		1
	Tax rate changes on opening future income taxes (b)	(427	)	(13	)	(419	)	(11	)	—		—
	Attributed Canadian royalty income	—		—		(23	)	(1	)	(24	)	(1	)
	Stock-based compensation	33		1		18		1		8		—
	Assessments and adjustments	(1	)	—		(9	)	—		7		—
	Capital gains	(40	)	(1	)	—		—		(6	)	—
	Other	(18	)	(1	)	16		—		3		—
Income taxes and effective rate		513		15		835		21		694		37

(a)

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.

(b)

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.

In 2007 net income tax payments totalled $152 million (2006 – $36 million; 2005 – $77 million).

78 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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

		2007				2006
($ millions)		Current		Non-Current		Current	Non-Current
Future income tax assets:
	Employee future benefits	16		—		12	—
	Asset retirement obligations	49		—		32	—
	Inventories	84		—		59	—
	Other	(19	)	—		6	—
		130		—		109	—
Future income tax liabilities:
	Excess of book values of assets over tax values	—		4 378		—	4 413
	Deferred maintenance shutdown costs	—		89		—	43
	Employee future benefits	—		(102	)	—	(88	)
	Asset retirement obligations	—		(220	)	—	(203	)
	Attributed Canadian royalty income	—		—		—	(93	)
	Other	—		67		—	—
		—		4 212		—	4 072

11. COMMITMENTS, CONTINGENCIES, VARIABLE INTEREST ENTITIES, AND GUARANTEES

(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, 2007, future minimum amounts payable under these leases and agreements are as follows:

($ millions)	Pipeline Capacity and Energy Services (1)	Operating Leases
2008	284	46
2009	313	38
2010	388	31
2011	379	26
2012	364	23
Later years	5 284	134
	7 012	298

(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, including the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreements commenced in 1999 and extend up to 2033. As the initial shipper on one of the pipelines, Suncor's tolls payable are subject to annual adjustments.

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.

(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$1.7 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$1.3 billion can be used for either property damage or business interruption coverage for oil sands operations. Excess business interruption coverage begins the greater of 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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 79

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, 2007, the company had various indemnification agreements with third parties as described below.

The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2006 – $170 million) having a maturity of 45 days or less, to a third party. The third party is a multiple party securitization vehicle that provides funding for numerous asset pools. As at December 31, 2007, no outstanding accounts receivable had been sold under the program (2006 – $170 million). Although the company does not believe it has 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 $42 million in 2007 and no contingent liability or earnings impact have been recorded for this indemnification as the company believes it has 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, 2007, were $170 million and approximately $1,530 million, respectively. The company recorded an after-tax loss of approximately $4 million on the securitization program in 2007 (2006 – $2 million; 2005 – $4 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 covers a period of seven years and is accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2007, the VIE did not have any assets or liabilities.

The company has agreed to indemnify holders of the 6.50% notes, the 7.15% notes, 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 the receivables securitization program, and 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.

12. SHARE CAPITAL

(a)   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.

80 SUNCOR ENERGY INC. 2007ANNUAL REPORT

(b)   Issued

	Common Shares
	Number (thousands)	Amount ($ millions)
Balance as at December 31, 2004	454 241	651
Issued for cash under stock option plans	3 302	74
Issued under dividend reinvestment plan	122	7
Balance as at December 31, 2005	457 665	732
Issued for cash under stock option plans	2 147	52
Issued under dividend reinvestment plan	132	10
Balance as at December 31, 2006	459 944	794
Issued for cash under stock options plan	2 694	74
Issued under dividend reinvestment plan	145	13
Balance as at December 31, 2007	462 783	881

Common Share Options

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 directors that hold options must earn the right to exercise them. This is done by the employee or director 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.

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

(a)   Stock Option Plans

(i)    Executive Stock Plan

Under this plan, the company granted 479,000 common share options in 2007 (2006 – 538,000; 2005 – 518,000) 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.

(ii)   SunShare 2012 Performance Stock Option Plan

During 2007, the company granted 7,843,000 options 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") which was approved at the Annual and Special Meeting of shareholders on April 26, 2007. Under this plan, meeting specified performance targets may accelerate the vesting of some options, such that 25% of outstanding options may vest on January 1, 2010, and the remaining 75% of outstanding options may vest on January 1, 2013. All unvested options at January 1, 2013, which have not previously been cancelled, will automatically expire.

(iii)  SunShare Performance Stock Option Plan

During 2007, the company granted 1,045,000 options (2006 – 1,637,000; 2005 – 1,253,000) to eligible permanent full-time and part-time employees, both executive and non-executive, under its employee stock option incentive plan ("SunShare"). Under SunShare, meeting specified performance targets accelerates the vesting of some or all options.

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, approximately 25% of the then outstanding options vested under the SunShare plan. On June 30, 2005, an additional predetermined performance criterion under the SunShare plan was met, resulting in the vesting of 50% of the outstanding, unvested SunShare options on April 30, 2008. During 2007, the final predetermined performance criterion was met, and as a result, the remaining 50% of the outstanding, unvested SunShare options will vest on April 30, 2008.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 81

(iv)  Key Contributor Stock Option Plan

Under this plan, the company granted 1,185,000 common share options in 2007 (2006 – 1,050,000; 2005 – 901,000) to non-insider senior managers and key employees. Options granted have a 10-year life and vest annually over a three-year period.

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, 2004		20 687		5.22 – 42.02	24.49
	Granted	2 672		36.93 – 71.13	48.27
	Exercised	(3 302	)	5.22 – 41.38	20.71
	Cancelled	(854	)	26.14 – 70.53	30.82
Outstanding, December 31, 2005		19 203		5.22 –   71.13	28.12
	Granted	3 224		73.36 – 101.79	89.95
	Exercised	(2 147	)	5.22 –   61.92	20.99
	Cancelled	(471	)	25.00 –   96.10	46.66
Outstanding, December 31, 2006		19 809		7.77 – 101.79	38.48
	Granted	10 552		70.56 – 107.02	93.36
	Exercised	(2 694	)	7.77 –   92.11	22.75
	Cancelled	(667	)	25.31 – 101.73	65.68
Outstanding, December 31, 2007		27 000		10.13 – 107.02	60.61
Exercisable, December 31, 2007		7 276		10.13 – 100.04	30.87

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)	2007	2006	2005
	7 285	7 970	10 724

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2007:

	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 ($)
10.13 – 17.45	1 598	2	15.40	1 598	15.40
21.35 – 28.93	8 538	4	27.00	3 588	26.26
31.59 – 42.65	2 656	6	37.83	1 527	37.32
45.51 – 72.42	965	5	56.81	71	52.83
73.36 – 92.68	4 993	7	88.29	475	91.32
93.36 – 107.02	8 250	7	95.16	17	98.07
Total	27 000	6	60.61	7 276	30.87

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.

82 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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:

	2007	2006	2005
Annual dividend per share	$0.38	$0.30	$0.24
Risk-free interest rate	4.22%	4.08%	3.69%
Expected life	6 years	5 years	6 years
Expected volatility	30%	29%	28%
Weighted-average fair value per option	$29.77	$29.17	$15.42

Stock-based compensation expense recognized for the year ended December 31, 2007 related to stock option plans was $103 million (2006 – $53 million; 2005 – $23 million).

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)		2007	2006	2005
Net earnings attributable to common shareholders – as reported		2 832	2 971	1 158
Less: compensation cost under the fair value method for pre-2003 options		8	15	13
Pro forma net earnings attributable to common shareholders for pre-2003 options		2 824	2 956	1 145
Basic earnings per share
	As reported	6.14	6.47	2.54
	Pro forma	6.12	6.44	2.51
Diluted earnings per share
	As reported	6.02	6.32	2.48
	Pro forma	6.00	6.29	2.46

(b)   Deferred Share Units (DSUs)

The company had 1,168,000 DSUs outstanding at December 31, 2007 (1,170,000 at December 31, 2006). 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 2007, 20,000 DSUs were redeemed for cash consideration of $2 million (2006 – 59,000 redeemed for cash consideration of $5 million; 2005 – 81,000 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, 2007, the total liability related to the DSUs was $126 million (2006 – $107 million), of which $5 million (2006 – $2 million) was classified as current.

During 2007, total pretax compensation expense related to DSUs was $21 million (2006 – $25 million; 2005 – $39 million).

(c)    Performance Share Units (PSUs)

During 2007, the company issued 415,000 PSUs (2006 – 397,000; 2005 – 453,000) 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 expense recognized for PSUs during 2007 was $60 million (2006 – $42 million; 2005 – $21 million).

SUNCOR ENERGY INC. 2007ANNUAL REPORT 83

13. EARNINGS PER COMMON SHARE

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

($ millions)		2007	2006	2005
Net earnings attributable to common shareholders		2 832	2 971	1 158
(millions of common shares)
Weighted-average number of common shares		461	459	456
Dilutive securities:
	Shares issued under stock-based compensation plans	10	11	10
Weighted-average number of diluted common shares		471	470	466
(dollars per common share)
Basic earnings per share (a)		6.14	6.47	2.54
Diluted earnings per share (b)		6.02	6.32	2.48

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.

14. ACQUISITION OF REFINERY AND RELATED ASSETS

On May 31, 2005, the company acquired all of the issued shares of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero Energy Corp. for cash consideration of $37 million. Additional payments for working capital and associated inventory brought the total purchase price to $62 million. The acquired company's principal assets are a Commerce City refinery and a products terminal located in Grand Junction, Colorado. The allocation of fair value to the assets acquired and liabilities assumed was $79 million for property, plant and equipment, $30 million for inventory and $41 million for environmental liabilities assumed. The fair value assigned to other liabilities was $6 million. The acquisition was accounted for by the purchase method of accounting.

The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition. The new operations have been reported as part of the refining and marketing segment in the Schedules of Segmented Data.

15. FINANCING EXPENSES (INCOME)

($ millions)		2007		2006		2005
Interest on debt		189		150		151
Capitalized interest		(189	)	(129	)	(119	)
	Net interest expense	—		21		32
	Foreign exchange gain on long-term debt	(252	)	—		(37	)
	Other foreign exchange loss (gain)	41		18		(10	)
Total financing (income) expenses		(211	)	39		(15	)

Cash interest payments in 2007 totaled $183 million (2006 – $146 million; 2005 – $149 million).

84 SUNCOR ENERGY INC. 2007ANNUAL REPORT

16. INVENTORIES

($ millions)	2007	2006
Crude oil	332	249
Refined products	126	200
Materials, supplies and merchandise	150	140
Total	608	589

The replacement cost of crude oil and refined product inventories exceeded their LIFO carrying value by $415 million (2006 – $243 million) as at December 31, 2007.

During 2007, the company recorded a pretax gain of $57 million related to a permanent reduction in LIFO inventory layers, as the LIFO layers were lower than current cost (2006 – $6 million pretax gain).

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)			2007	2006	2005
Operating revenues
	Sales to refining and marketing segment joint ventures:
		Refined products	329	294	327
		Petrochemicals	163	136	279

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.

At December 31, 2007, amounts due from refining and marketing segment joint ventures were $17 million (2006 – $20 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 loss, net of income taxes, are as follows:

As at December 31 ($ millions)	2007		2006
Unrealized foreign currency translation adjustment	(266	)	(71	)
Unrealized gains and losses on derivative hedging activities	13		—
Total	(253	)	(71	)

SUNCOR ENERGY INC. 2007ANNUAL REPORT 85

19. SUPPLEMENTAL INFORMATION

($ millions)			2007	2006	2005
Geographic areas
	Revenues
		Canada	13 733	12 213	8 037
		U.S.	4 091	3 532	3 090
		Other	109	84	2
			17 933	15 829	11 129
	Total assets
		Canada	21 389	16 087	12 945
		U.S.	2 440	2 379	2 003
		Other	338	293	178
			24 167	18 759	15 126
Export sales (a)			876	810	648
Exploration expenses
	Geological and geophysical		26	51	22
	Other		—	1	1
	Cash costs		26	52	23
	Dry hole costs		69	52	33
	Cash and dry hole costs (b)		95	104	56
	Leasehold impairment (c)		—	2	13
			95	106	69
Taxes other than income taxes
	Excise taxes (d)		568	538	482
	Production, property and other taxes		80	57	47
			648	595	529
Allowance for doubtful accounts			3	4	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.

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	2007		2006		2005
Net earnings as reported, Canadian GAAP			2 832		2 971		1 158
Adjustments
	Derivatives and hedging activities	(a)	—		11		83
	Stock-based compensation expense	(b)	15		(19	)	(26	)
	Research and development costs	(g)	(34	)	—		—
	Income tax expense		4		(3	)	(28	)
Net earnings from continuing operations, U.S. GAAP			2 817		2 960		1 187
	Cumulative effect of change in accounting principles, net of income taxes of $nil (2006 – $2; 2005 – $nil)	(b)	—		(4	)	—
Net earnings, U.S. GAAP			2 817		2 956		1 187
Derivatives and hedging activities, net of income taxes of $nil (2006 – $3; 2005 – $70)		(a)	5		6		140
Minimum pension liability, net of income taxes of $nil (2006 – $20; 2005 – $8)		(c)	—		39		(15	)
Pension and Post-retirement obligation, net of income taxes of $8		(c)	17		—		—
Foreign currency translation adjustment		(d)	(195	)	10		(26	)
Comprehensive income, U.S. GAAP			2 644		3 011		1 286

86 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Per common share (dollars)		2007	2006	2005
Net earnings per share from continuing operations, U.S. GAAP
	Basic	6.11	6.45	2.60
	Diluted	5.98	6.29	2.55
Net earnings per share, U.S. GAAP
	Basic	6.11	6.44	2.60
	Diluted	5.98	6.29	2.55

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

			December 31, 2007				December 31, 2006
		Notes	As Reported		U.S. GAAP		As Reported		U.S. GAAP
Current assets			2 818		2 818		2 302		2 302
Property, plant and equipment, net		(g)	20 945		20 911		16 160		16 160
Deferred charges and other		(a,c)	404		404		297		323
	Total assets		24 167		24 133		18 759		18 785
Current liabilities			3 097		3 097		2 158		2 158
Long-term borrowings		(a)	3 811		3 811		2 363		2 376
Accrued liabilities and other		(b,c)	1 434		1 602		1 214		1 430
Future income taxes		(a,c,g)	4 212		4 147		4 072		4 002
Share capital		(b)	881		944		794		842
Contributed surplus		(b)	194		240		100		153
Retained earnings		(a,b,g)	10 791		10 667		8 129		8 026
Accumulated other comprehensive income		(a,c,d)	(253	)	(375	)	(71	)	(202	)
	Total liabilities and shareholders' equity		24 167		24 133		18 759		18 785

(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 at December 31, 2007. For prior year comparative balances 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. (2005 – $2 million ineffectiveness relating to 2006 and 2007 forecasted cash flows). 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 accumulated OCI attributable to derivative hedging activities for the years ended December 31 is as follows:

($ millions)	2007		2006
AOCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $4 (2006 – $1)	8		2
Current period net changes arising from cash flow hedges, net of income taxes of $1 (2006 – $4)	8		9
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $2 (2006 – $1)	(3	)	(3	)
AOCI attributable to derivatives and hedging activities, end of period, net of income taxes of $4 (2006 – $4)	13		8

For the year ended December 31, 2006, U.S. GAAP net earnings increased by $7 million, net of income taxes of $4 million (2005 – increased net earnings of $55 million, net of income taxes of $28 million) to reflect the impact of ineffectiveness on derivative contracts classified as cash flow hedges.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 87

(b)   Stock-Based Compensation

On January 1, 2006, the company adopted the U.S. Financial Accounting Standards Board (FASB) Statement 123(R), "Share-Based Payment", using the modified-prospective approach. FAS 123(R) allows the company to expense 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. After adoption of FAS 123(R), our PSUs for U.S. GAAP have been measured using a Monte Carlo Simulation approach to determine fair value. The impact on net earnings for the year ended December 31, 2007 is a recovery of previously recognized stock-based compensation expense of $17 million, 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 $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 (other than a multi-employer plan) as an asset or liability on the balance sheet. The changes to funded status in the year are recorded through comprehensive income, net of income taxes. The standard was applied prospectively effective December 31, 2006, as retrospective application was not permitted.

For the comparative period, prior to the adoption of FAS 158 on December 31, 2006, 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 purpose of determining the additional minimum pension liability, the accumulated benefit obligation does not incorporate projections of future compensation increases in the determination of the obligation. No such adjustment was required under Canadian GAAP. As required under FAS 158, the minimum pension liability adjustment recorded in 2006 was reversed in that year.

At December 31, 2006, the company would have recognized a minimum pension liability of $35 million, an intangible asset of $16 million and an accumulated other comprehensive loss of $12 million, net of income taxes of $7 million. Other comprehensive income for the year ended December 31, 2006 would have increased by $39 million, net of income taxes of $20 million (2005 – a decrease of $15 million, net of taxes of $8 million).

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

($ millions)	2007		2006
AOCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $67 million (2006 – $27 million)	(139	)	(51	)
Minimum pension liability (2006 – net of income taxes of $20 million)	—		39
Reversal of minimum pension liability upon adoption of FAS 158, (2006 – net of income taxes of $7 million)	—		12
Amortization of net actuarial loss, net of income taxes of $10 million	21		—
Amortization of past service costs, net of income taxes of $1 million	(2	)	—
Additions to unamortized net actuarial loss, net of income taxes of $2 million (2006 – $74 million)	(2	)	(155	)
Additions to unamortized past service costs (2006 – net of income taxes of $7 million)	—		16
AOCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $59 million (2006 – $67 million)	(122	)	(139	)

88 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Total amount included in AOCI expected to be recognized as components of net periodic benefit cost during 2008 are as follows:

Amortization of net actuarial loss	$31 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

Effective January 1, 2005, Suncor adopted Financial Accounting Standards Board Staff Position 19-1 (FSP 19-1), "Accounting for Suspended Well Costs". FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), "Financial Accounting and Reporting by Oil and Gas Producing Companies", to permit the continued 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. There were no capitalized exploratory well costs charged to expense upon the adoption of FSP 19-1.

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)		2007		2006		2005
Balance, beginning of year		23		15		5
	Additions pending determination of proved reserves	14		21		14
	Charged to dry hole expense	(6	)	—		(2	)
	Reclassifications to proved properties	(10	)	(13	)	(2	)
Balance, end of year		21		23		15
Capitalized for a period greater than one year ($ millions)		7		2		1
Number of projects that have exploratory well costs capitalized for a period greater than 12 months		3		3		2

(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.

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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 89

The purchase/sale of contract amounts included in revenue for 2007, 2006 and 2005 are shown below.

($ millions)	2007	2006	2005
Consolidated revenues	17 933	15 829	11 129
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	—	5	16

(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, $24 million, net of income taxes of $10 million, would have been charged to income during 2007 (2006 – nil; 2005 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.

Recently Issued Accounting Standards

In February 2007, FASB issued FAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities". The standard, effective January 1, 2008, affords entities the option to irrevocably choose to measure many financial instruments and certain other items at fair value, at specified election dates. Retrospective application is not permitted. No impact to net earnings or financial position is anticipated.

In September 2006, FASB issued FAS 157 "Fair Value Measurements". The standard, effective January 1, 2008, establishes a recognized framework for measuring fair value, and expands disclosure relating to fair value inputs. No new fair value measurements are required. This Statement is generally to be applied prospectively and does not have an impact on earnings or financial position.

90 SUNCOR ENERGY INC. 2007ANNUAL 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 2007		June 30 2007		Sept 30 2007		Dec 31 2007		2007		Mar 31 2006		June 30 2006		Sept 30 2006		Dec 31 2006		2006
Revenues		3 951		4 358		4 666		4 958		17 933		3 858		4 070		4 114		3 787		15 829
Net earnings (loss)
Oil Sands		453		419		556		1 006		2 434		707		1 100		582		394		2 783
Natural Gas		4		(4	)	—		25		25		40		60		12		(6	)	106
Refining and Marketing		99		206		40		—		345		11		116		85		23		235
Corporate and eliminations		(5	)	20		81		(68	)	28		(45	)	(58	)	3		(53	)	(153	)
		551		641		677		963		2 832		713		1 218		682		358		2 971
Per common share
Net earnings attributable to common shareholders
	– basic	1.20		1.39		1.47		2.08		6.14		1.56		2.65		1.48		0.78		6.47
	– diluted	1.17		1.36		1.43		2.04		6.02		1.52		2.59		1.45		0.76		6.32
Cash dividends		0.08		0.10		0.10		0.10		0.38		0.06		0.08		0.08		0.08		0.30
Cash flow from (used in) operations
Oil Sands		578		576		918		1 020		3 092		1 205		1 116		924		672		3 917
Natural Gas		64		70		47		67		248		99		66		68		48		281
Refining and Marketing		171		292		83		34		580		53		184		162		44		443
Corporate and eliminations		(23	)	(54	)	(21	)	(17	)	(115	)	(43	)	(46	)	(1	)	(18	)	(108	)
		790		884		1 027		1 104		3 805		1 314		1 320		1 153		746		4 533
OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
	Total production	248.2		202.3		239.1		252.5		235.6		264.4		267.3		242.8		266.4		260.0
	Firebag	35.3		36.2		35.8		40.4		36.9		27.4		35.0		37.2		35.1		33.7
Sales
	Light sweet crude oil	105.5		100.0		99.3		102.2		101.7		119.2		124.7		84.9		113.7		110.5
	Diesel	29.5		20.3		23.9		26.0		25.0		35.1		32.9		20.7		24.0		28.2
	Light sour crude oil	112.7		84.2		94.1		118.2		102.3		121.0		99.2		125.8		126.8		118.2
	Bitumen	6.8		3.8		6.6		5.4		5.7		—		8.5		6.6		9.7		6.2
Total sales		254.5		208.3		223.9		251.8		234.7		275.3		265.3		238.0		274.2		263.1

SUNCOR ENERGY INC. 2007ANNUAL REPORT 91

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 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007	Mar 31 2006	June 30 2006	Sept 30 2006	Dec 31 2006	2006
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
	Light sweet crude oil	68.63	75.64	81.00	87.34	78.03	69.00	78.27	78.11	64.51	71.98
	Other (diesel, light sour crude oil and bitumen)	63.62	66.74	73.76	78.48	70.86	63.28	72.75	68.60	57.91	65.17
	Total	65.70	71.01	76.97	82.07	74.01	65.75	75.34	71.99	60.65	68.03
	Total(a)	65.61	71.01	76.97	82.36	74.07	65.75	75.34	71.99	60.65	68.03
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		21.75	28.40	23.00	24.10	24.15	15.55	15.65	21.00	22.65	18.70
Natural gas		4.50	4.20	2.10	3.60	3.55	3.45	2.55	2.60	3.00	2.90
Imported bitumen		0.05	0.10	—	0.20	0.10	0.05	0.10	0.10	—	0.10
Cash operating costs (3)		26.30	32.70	25.10	27.90	27.80	19.05	18.30	23.70	25.65	21.70
Project start-up costs		0.10	1.15	1.10	0.55	0.95	0.90	0.10	0.35	0.25	0.40
Total cash operating costs (4)		26.40	33.85	26.20	28.45	28.75	19.95	18.40	24.05	25.90	22.10
Depreciation, depletion and amortization		4.45	5.85	5.70	5.60	5.40	3.90	3.80	4.30	4.25	4.05
Total operating costs (5)		30.85	39.70	31.90	34.05	34.15	23.85	22.20	28.35	30.15	26.15
Cash operating costs and total operating costs – In-Situ Bitumen Production Only
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		11.05	10.60	11.85	9.95	10.85	5.70	8.50	5.55	8.05	8.95
Natural gas		11.05	10.60	9.10	9.15	9.90	7.70	8.15	7.60	9.90	8.35
Cash operating costs (6)		22.10	21.20	20.95	19.10	20.75	13.40	16.65	13.15	17.95	17.30
Firebag start-up costs		—	—	—	—	—	8.50	—	—	—	1.70
Total cash operating costs (7)		22.10	21.20	20.95	19.10	20.75	21.90	16.65	13.15	17.95	19.00
Depreciation, depletion and amortization		5.35	5.75	6.70	6.80	6.20	6.90	3.75	5.55	6.20	5.55
Total operating costs (8)		27.45	26.95	27.65	25.90	26.95	28.80	20.40	18.70	24.15	24.55

92 SUNCOR ENERGY INC. 2007ANNUAL 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 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007	Mar 31 2006	June 30 2006	Sept 30 2006	Dec 31 2006	2006
NATURAL GAS
Gross production(b)
	Natural gas (millions of cubic feet per day)	191	191	193	210	196	196	189	191	192	191
	Natural gas liquids and crude oil (thousands of barrels per day)	3.1	3.0	3.1	3.2	3.1	3.2	3.5	2.8	2.6	3.0
	Total gross production (thousands of barrels of oil equivalent per day)	34.9	34.9	35.2	38.2	35.8	35.9	35.1	34.6	34.7	34.8
	Total gross production (millions of cubic feet equivalent per day)	209	209	211	229	215	215	211	208	208	209
Average sales price (2)
	Natural gas (dollars per thousand cubic feet)	7.01	6.85	5.39	6.08	6.32	9.03	6.38	6.33	6.55	7.15
	Natural gas(a) (dollars per thousand cubic feet)	7.14	6.83	5.14	6.02	6.27	8.75	6.22	6.13	6.40	6.95
	Natural gas liquids and crude oil – conventional (dollars per barrel)	56.69	51.21	58.11	60.31	56.64	53.89	63.75	61.07	45.55	51.93
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)		31.6	34.6	35.1	32.8	33.5	26.6	31.6	31.4	29.1	29.5
Utilization of refining capacity (%)		97	108	102	87	98	74	96	95	76	85

(a)

Excludes the impact of hedging activities.

(b)

Currently natural gas production is located in the Western Canada Sedimentary Basin.

Definitions

(1)

Total production – Total 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. 2007ANNUAL REPORT 93

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions, except for ratios)	2007		2006		2005		2004		2003
Revenues
Oil Sands	6 775		7 407		3 965		3 640		3 101
Natural Gas	553		578		679		567		512
Refining and Marketing	11 173		8 593		6 984		4 995		3 451
Corporate and eliminations	(568	)	(749	)	(499	)	(497	)	(453	)
	17 933		15 829		11 129		8 705		6 611
Net earnings (loss)
Oil Sands	2 434		2 783		957		956		892
Natural Gas	25		106		155		114		120
Refining and Marketing	345		235		174		107		70
Corporate and eliminations	28		(153	)	(128	)	(101	)	18
	2 832		2 971		1 158		1 076		1 100
Cash flow from (used in) operations
Oil Sands	3 092		3 917		1 916		1 717		1 780
Natural Gas	248		281		412		314		296
Refining and Marketing	580		443		363		204		158
Corporate and eliminations	(115	)	(108	)	(215	)	(222	)	(194	)
	3 805		4 533		2 476		2 013		2 040
Capital and exploration expenditures
Oil Sands	4 431		2 463		1 948		1 119		953
Natural Gas	531		458		363		279		184
Refining and Marketing	376		665		779		418		153
Corporate	77		27		63		31		32
	5 415		3 613		3 153		1 847		1 322
Total assets	24 167		18 759		15 126		11 749		10 463
Ending capital employed(a)
Short-term and long-term debt, less cash and cash equivalents	3 248		1 849		2 868		2 134		2 551
Shareholders' equity	11 613		8 952		5 996		4 874		3 858
	14 861		10 801		8 864		7 008		6 409
Less capitalized costs related to major projects in progress	(4 148	)	(2 649	)	(2 938	)	(1 467	)	(1 122	)
	10 713		8 152		5 926		5 541		5 287
Total Suncor employees (number at year-end)	6 465		5 766		5 152		4 605		4 231

94 SUNCOR ENERGY INC. 2007ANNUAL REPORT

FIVE-YEAR FINANCIAL SUMMARY (unaudited) (continued)

($ millions, except for ratios)		2007	2006	2005	2004	2003
Dollars per common share
	Net earnings attributable to common shareholders	6.14	6.47	2.54	2.38	2.45
	Cash dividends	0.38	0.30	0.24	0.23	0.1925
	Cash flow from operations	8.25	9.87	5.43	4.44	4.54
Ratios
Return on capital employed (%) (a), (b)		28.3	40.7	19.8	19.0	18.8
Return on capital employed (%) (c)		20.7	30.5	14.4	16.1	16.3
Return on shareholders' equity (%) (d)		27.5	39.7	21.3	24.6	32.9
Debt to debt plus shareholders' equity (%) (e)		24.7	20.9	33.6	31.3	43.2
Net debt to cash flow from operations (times) (f)		0.9	0.4	1.2	1.1	1.3
Interest coverage – cash flow basis (times) (g)		22.2	30.5	16.9	13.7	11.9
Interest coverage – net earnings basis (times) (h)		17.7	25.5	12.5	10.8	10.5

(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 46 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. 2007ANNUAL REPORT 95

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 2007	June 30 2007	Sept 30 2007	Dec 31 2007	Mar 31 2006	June 30 2006	Sept 30 2006	Dec 31 2006
Share ownership
Average number outstanding, weighted monthly (thousands) (a)		460 074	460 422	460 789	461 187	458 230	458 596	458 859	459 069
Share price (dollars)
Toronto Stock Exchange
	High	92.85	99.70	101.55	109.47	93.85	102.18	97.12	95.00
	Low	79.66	87.58	88.72	91.25	75.58	75.00	71.18	72.26
	Close	87.85	95.96	94.46	107.91	89.63	90.34	80.19	91.79
New York Stock Exchange – US$
	High	77.79	93.52	100.11	117.98	82.15	89.86	86.78	82.08
	Low	67.78	75.71	82.37	91.40	64.00	67.36	63.77	64.06
	Close	76.35	89.92	94.81	108.73	77.02	81.01	72.05	78.91
Shares traded (thousands)
	Toronto Stock Exchange	109 485	87 784	99 701	100 233	107 797	101 626	106 348	99 704
	New York Stock Exchange	97 383	71 365	65 133	58 157	114 031	116 492	100 714	94 676
Per common share information (dollars)
Net earnings attributable to common shareholders		1.20	1.39	1.47	2.08	1.56	2.65	1.48	0.78
Cash dividends		0.08	0.10	0.10	0.10	0.06	0.08	0.08	0.08

(a)

The company had approximately 2,387 holders of record of common shares as at January 31, 2008.

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.

96 SUNCOR ENERGY INC. 2007ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2007	2006	2005	2004	2003
OIL SANDS
Production (thousands of barrels per day)	235.6	260.0	171.3	226.5	216.6
Sales(thousands of barrels per day)
Light sweet crude oil	101.7	110.5	73.3	114.9	112.3
Diesel	25.0	28.2	15.6	27.9	26.3
Light sour crude oil	102.3	118.2	59.8	75.1	73.3
Bitumen	5.7	6.2	16.6	8.4	6.4
	234.7	263.1	165.3	226.3	218.3
Average sales price (dollars per barrel)
Light sweet crude oil	78.03	71.98	49.93	45.60	40.26
Other (diesel, light sour crude oil and bitumen)	70.86	65.17	56.90	39.13	33.93
Total	74.01	68.03	53.81	42.28	37.19
Total (a)	74.07	68.03	62.68	49.78	40.22
Cash operating costs – total operations (b)	27.80	21.70	24.55	15.15	13.80
Total cash operating costs – total operations (b)	28.75	22.10	24.65	15.45	13.80
Total operating costs – total operations (b)	34.15	26.15	29.95	19.05	17.15
Cash operating costs – in-situ bitumen production (b), (e)	20.75	17.30	22.20	22.05	—
Total cash operating costs – in-situ bitumen production (b), (e)	20.75	19.00	23.20	28.90	—
Total operating costs – in-situ bitumen production (b), (e)	26.95	24.55	28.10	34.90	—
Ending capital employed excluding major projects in progress	6 541	5 015	4 436	4 088	4 007
Return on capital employed (%) (c)	42.6	53.5	22.4	22.3	21.1
Return on capital employed (%) (d)	27.6	40.1	16.0	18.2	17.7

(a)

Excludes the impact of hedging activities.

(b)

Dollars per barrel rounded to the nearest $0.05. See definitions on page 93.

(c)

See definitions on page 95.

(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 commerical operations on April 1, 2004.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 97

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

			2007	2006	2005	2004	2003
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
	Gross		196	191	190	200	187
	Net (a)		153	141	137	147	142
Natural gas liquids and crude oil (thousands of barrels per day)
	Gross		3.1	3.0	3.2	3.5	3.7
	Net (a)		2.4	2.3	2.6	2.6	2.8
Total (thousands of boe (b) per day)
	Gross		35.8	34.8	34.8	36.8	34.9
	Net (a)		27.9	25.8	25.3	27.1	26.4
Total (millions of cubic feet equivalent per day)
	Gross		215	209	209	221	209
	Net (a)		167	155	152	163	158
Average sales price
Natural gas (dollars per thousand cubic feet)			6.32	7.15	8.57	6.70	6.42
Natural gas (dollars per thousand cubic feet) (c)			6.27	6.95	8.59	6.73	6.42
Natural gas liquids and crude oil – conventional (dollars per barrel)			56.64	51.93	54.24	44.99	37.67
Ending capital employed			1 153	857	562	447	400
Return on capital employed (%) (g)			2.5	14.9	30.7	26.9	29.2
Undeveloped landholdings (d)
Oil and gas (millions of acres)
	Western Canada
		Gross	1.3	1.2	0.6	0.7	0.5
		Net (e)	0.7	0.7	0.4	0.5	0.4
	International
		Gross	0.1	0.1	0.4	0.7	0.9
		Net (e)	—	—	0.2	0.4	0.2
Net wells drilled (f)
	Exploratory
		Oil	—	—	—	—	—
		Gas	7	3	8	5	2
		Dry	6	5	4	5	31
	Development
		Oil	1	1	1	—	1
		Gas	14	13	18	16	16
		Dry	3	4	3	—	4
			31	26	34	26	54

(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 eight net exploratory wells and eight net development wells in progress at the end of 2007.

(g)

See definitions on page 95.

98 SUNCOR ENERGY INC. 2007ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2007	2006	2005	2004	2003
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
	Retail (a)	5.2	5.3	5.2	5.3	5.1
	Other	11.6	10.6	10.1	7.9	7.7
Distillate		10.6	8.5	8.3	6.7	6.5
Total transportation fuel sales		27.4	24.4	23.6	19.9	19.3
Petrochemicals		0.9	0.9	0.7	0.8	0.8
Asphalt		1.7	1.2	1.6	1.5	1.7
Other		3.5	3.0	3.0	2.5	2.3
Total refined product sales		33.5	29.5	28.9	24.7	24.1
Crude oil supply and refining
	Processed at refineries (thousands of cubic metres per day)	25.1	21.7	22.7	19.9	19.9
Utilization of refining capacity (%)		98	85	97	96	96
Ending capital employed excluding major projects in progress		2 270	1 818	796	736	820
Return on capital employed (%) (b)		16.8	20.4	22.2	13.0	10.7
Return on capital employed (%) (b), (c), (e)		14.5	12.5	13.8	12.0	10.7
Retail outlets (d) (number at year-end)		419	417	417	421	422

(a)

Excludes sales through joint venture interests.

(b)

See definitions on page 95.

(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.

(e)

For 2003, return on capital employed calculated for Canadian operations only (U.S. operations acquired during 2003).

SUNCOR ENERGY INC. 2007ANNUAL REPORT 99

QuickLinks

EXHIBIT 99-1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2007, 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,
2007, dated February 27, 2008

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 27, 2008

This Management's Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 48 for additional information.

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 46.

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.

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 periodic 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 our website 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.

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 18.

10 SUNCOR ENERGY INC. 2007ANNUAL 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 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.

In addition to Suncor's integrated oil sands-focused business activities, the company is also investing 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:

•

Developing our oil sands resource base through mining and in-situ technology and supplementing Suncor 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.

•

Managing environmental and social performance by mitigating 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 through a strong focus on operational excellence, economies of scale and continued management of engineering, procurement and construction of major projects.

•

Reducing risk associated with natural gas price volatility by producing natural gas volumes that offset purchases for internal consumption.

•

Ensuring appropriate levels of debt and capital spending are in place to support growth in a fiscally responsible manner.

2007 Overview

•

Combined oil sands and natural gas production in 2007 was 271,400 barrels of oil equivalent (boe) per day, compared to 294,800 boe per day in 2006. Oil sands production averaged 235,600 barrels per day (bpd) in 2007, compared to 260,000 bpd in 2006. Oil sands cash operating costs averaged $27.80 per barrel during 2007, compared to $21.70 per barrel in 2006. Natural gas production averaged 215 million cubic feet equivalent (mmcfe) per day, compared to an average 209 mmcfe per day in 2006.

•

Suncor continued to make progress on plans to expand Upgrader 2 and increase production capacity to 350,000 bpd, with construction completion targeted in the second quarter of 2008 and ramp-up to full capacity expected in the fourth quarter. As of December 31, 2007, the project was 95% complete.

•

In July, Suncor filed a regulatory application for the Voyageur South mine extension. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility.

•

In Suncor's downstream operations, investments were made to integrate up to 40,000 bpd of oil sands sour crude into the company's Sarnia, Ontario refinery.

•

In September, Suncor commissioned its fourth wind farm. The 76-megawatt facility located near Ripley, Ontario is the company's largest wind power project.

•

Capital spending in 2007 totalled $5.4 billion. Net debt at year-end 2007 was $3.2 billion, compared to $1.8 billion at the end of 2006.

•

Suncor achieved a company-wide return on capital employed of 28.3% in 2007, compared to 40.7% in 2006 (excluding capitalized costs for major projects in progress).

SUNCOR ENERGY INC. 2007ANNUAL REPORT 11

SELECTED FINANCIAL INFORMATION

Annual Financial Data

Year ended December 31 ($ millions except per share)	2007	2006	2005
Revenues	17 933	15 829	11 129
Net earnings	2 832	2 971	1 158
Total assets	24 167	18 759	15 126
Long-term debt	3 811	2 363	2 984
Dividends on common shares	162	127	102
Net earnings attributable to common shareholders per share – basic	6.14	6.47	2.54
Net earnings attributable to common shareholders per share – diluted	6.02	6.32	2.48
Cash dividends per share	0.38	0.30	0.24

Outstanding Share Data

At December 31, 2007 (thousands)
Number of common shares	462 783
Number of common share options	27 000
Number of common share options – exercisable	7 276

Net Earnings  ⁽¹⁾
Year ended December 31
($ millions)

	07	06	05
•  Oil sands	2 434	2 783	957
•  Natural gas	25	106	155
•  Refining and marketing	345	235	174

Cash Flow
from Operations  ^(1),(2)
Year ended December 31
($ millions)

	07	06	05
•  Oil sands	3 092	3 917	1 916
•  Natural gas	248	281	412
•  Refining and marketing	580	443	363

Capital Employed  ^(1),(2),(3)
At December 31
($ millions)

	07	06	05
•  Oil sands	6 541	5 015	4 436
•  Natural gas	1 153	857	562
•  Refining and marketing	2 270	1 818	796

(1)	Excludes Corporate and Eliminations segment.
(2)	Non-GAAP measures.
(3)	Excludes major projects in progress.

12 SUNCOR ENERGY INC. 2007ANNUAL REPORT

CONSOLIDATED FINANCIAL ANALYSIS

This analysis provides an overview of our consolidated financial results for 2007 compared to 2006. For a detailed analysis, see the various business segment discussions.

Net Earnings

Our net earnings were $2.832 billion in 2007, compared with $2.971 billion in 2006 (2005 – $1.158 billion). Excluding the impacts of the reduction of federal and Alberta income tax rates, net insurance proceeds (relating to a January 2005 fire), unrealized foreign exchange gains on the company's U.S. dollar denominated long-term debt, and project start-up costs, earnings were $2.239 billion in 2007, compared to $2.350 billion in 2006 (2005 – $850 million). The decrease in net earnings primarily reflects the impact of scheduled and unscheduled maintenance that reduced crude oil production and increased operating expenses. The largest impacts on financial results were a scheduled 50-day maintenance shutdown to portions of Suncor's oil sands operation to tie in new facilities related to a planned expansion and a scheduled 120-day shutdown to portions of the Sarnia refinery to tie in new sour crude processing facilities. These impacts were partly offset by higher realized crude oil prices.

Net Earnings Components⁽¹⁾

Year ended December 31 ($ millions, after-tax)		2007		2006		2005
Net earnings before the following items:		2 239		2 350		850
	Impact of income tax rate reductions on opening future income tax liabilities	427		419		—
	Oil sands fire accrued insurance proceeds (2)	—		232		293
	Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	215		—		31
	Project start-up costs	(49	)	(30	)	(16	)
Net earnings as reported		2 832		2 971		1 158

(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)	2007	2006	2005
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	72.30	66.20	56.55
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	76.65	73.05	69.00
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty	22.25	21.45	20.20
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	6.90	7.25	8.55
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.60	7.00	8.50
New York Harbour 3-2-1 crack US$/barrel (1)	13.70	9.80	9.50
Exchange rate: US$/Cdn$	0.93	0.88	0.83

(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 $17.933 billion in 2007, compared with $15.829 billion in 2006 (2005 – $11.129 billion). The increase was primarily due to the following factors:

•

Energy marketing and trading revenues increased to $2.883 billion in 2007, compared to $1.582 billion in 2006. The increase is due primarily to a larger volume of crude oil traded and higher average crude oil prices.

•

A reduction in planned refinery maintenance in 2007 compared to 2006 led to increased refinery utilization and sales in our downstream operations. Downstream operations also benefited from stronger refining and retail margins reflecting supply constraints in the Ontario and U.S. Rocky Mountain regions.

•

Average crude oil prices were higher in 2007 than in 2006. A 9% increase in average U.S. dollar WTI benchmark prices increased the selling price of oil sands crude oil production. In addition, strengthening price realizations for our sweet and sour blends relative to WTI also increased our revenue.

Partially offsetting these increases were the following:

•

Oil sands production and sales volumes were lower during 2007, mainly as a result of the planned shutdown of Upgrader 2. The 50-day outage was

SUNCOR ENERGY INC. 2007ANNUAL REPORT 13

required to tie in new facilities related to our planned expansion of oil sands production capacity.

•

A 6% increase in the average US$/Cdn$ exchange rate negatively impacted realizations on our crude oil sales basket. Because crude oil is primarily sold based on U.S. dollar benchmark prices, a strengthening Canadian dollar produced a corresponding reduction in the Canadian dollar value of our products.

•

The absence of net insurance proceeds relating to a January 2005 fire at our oil sands operations (2006 – $436 million).

Overall, reduced production in our oil sands operations decreased revenues by approximately $634 million. Higher price realizations on our crude oil products increased total revenues by approximately $470 million.

The cost to purchase crude oil and crude oil products was $5.935 billion in 2007, compared to $4.678 billion in 2006 (2005 – $4.164 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 WTI increased by more than US$6.00/bbl over the prior year.

•

Increased inputs of crude oil feedstock to meet higher demand from our refineries, and additional purchases of refined products to meet sales commitments during planned maintenance outages in our oil sands and downstream operations.

Operating, selling and general expenses were $3.375 billion in 2007 compared with $3.043 billion in 2006 (2005 – $2.437 billion). The primary reasons for the increase were:

•

An increase in the costs associated with maintenance activities.

•

Higher stock-based compensation expenses resulting from the launch of our new performance stock option plan in September 2007 and continued growth in our share price.

Transportation and other expenses were $198 million in 2007, compared to $212 million in 2006 (2005 – $152 million). The decrease in transportation costs was primarily due to reduced volumes shipped out of the Fort McMurray area.

Depreciation, depletion and amortization (DD&A) was $864 million in 2007, compared to $695 million in 2006 (2005 – $568 million). The increase primarily reflects the construction and commissioning of new operating units at both our oil sands operation and our Sarnia refinery.

Royalty expenses were $691 million in 2007, compared with $1,038 million in 2006 (2005 – $555 million). The decrease in 2007 was primarily due to an increase in capital expenditures incurred in our oil sands operations, lower sales volumes and also the absence of net insurance proceeds (relating to a January 2005 fire). These factors were partially offset by increased crude oil prices. For a discussion of Crown royalties, see pages 19 and 20.

Taxes other than income taxes were $648 million in 2007, compared to $595 million in 2006 (2005 – $529 million). The increase was primarily due to higher sales volumes subject to Canadian fuel excise taxes in our refining and marketing operations.

Financing income was $211 million in 2007, compared with expenses of $39 million in 2006 (2005 – income of $15 million). The increase in financing income was primarily due to the foreign exchange gains on our U.S. dollar denominated long-term debt. Although interest expense related to our long-term debt increased from the prior year due to additional debt issuance during 2007, it was all capitalized, resulting in no total interest expense in 2007, compared to $21 million in 2006. Capitalized interest was $189 million in 2007, compared to $129 million in 2006.

Income tax expense was $513 million in 2007 (15% effective tax rate), compared to $835 million in 2006 (21% effective tax rate) and $694 million in 2005 (37% effective tax rate). The decrease in the effective tax rate was primarily due to a decrease in statutory rates, an increase in the deductibility of Crown royalties, as well as an increase in the revaluation of opening future income tax liabilities due to the enactment of tax rate reductions. Income tax expense in both 2007 and 2006 included the effects of reductions in tax rates that reduced opening future income tax liabilities as follows:

14 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Impact of Tax Rate Changes on Segmented Earnings

	2007					2007	2006	2005
($ millions, increase (decrease) in earnings)	Oil Sands	Natural Gas	Refining and Marketing	Corporate and Eliminations		Total	Total	Total
Federal	413	39	17	(42	)	427	292	—
Alberta	—	—	—	—		—	127	—
	413	39	17	(42	)	427	419	—

Reflects fourth quarter 2007 federal rate reduction of 3.5%, second quarter 2007 federal rate reduction of 0.5%, second quarter 2006 federal rate reduction of 3.1% and second quarter 2006 Alberta rate reduction of 1.5%.

Excluding these adjustments, income tax expense in 2007 was $940 million (28% effective tax rate) and $1,254 million in 2006 (33% effective tax rate).

Corporate Earnings

After-tax net corporate earnings were $28 million in 2007, compared to expense of $153 million in 2006 (2005 – $128 million expense). Excluding the impact of group elimination entries, actual after-tax net corporate earnings were $31 million in 2007 (2006 – $147 million expense; 2005 – $139 million expense). The net earnings in the corporate segment in 2007, compared to net expense in 2006, were primarily due to the unrealized foreign exchange gains on our U.S. denominated long-term debt as a result of the stronger Canadian dollar. After-tax unrealized foreign exchange gains on our U.S. denominated long-term debt were $215 million in 2007, compared to nil in 2006 (2005 – gain of $31 million). In addition, the increase in future tax expense as a result of the revaluation of future income taxes was smaller in 2007 – an expense of $42 million in 2007, compared to an expense of $68 million in 2006. These factors were partially offset by an increase in stock-based compensation expense. Corporate had a net cash deficiency of $659 million in 2007, compared with $403 million in 2006 (2005 – $107 million). The additional deficiency in 2007 was primarily due to increases in working capital of $187 million.

Breakdown of Net Corporate Earnings (Expense)

Year ended December 31 ($ millions)	2007		2006		2005
Corporate earnings (expense)	31		(147	)	(139	)
Group eliminations	(3	)	(6	)	11
Total	28		(153	)	(128	)

Consolidated Cash Flow from Operations

Cash flow from operations was $3.805 billion in 2007, compared to $4.533 billion in 2006 (2005 – $2.476 billion). The decrease in cash flow from operations was primarily due to the same factors that impacted net earnings, as well as an increase in cash income taxes during 2007 compared to 2006.

Dividends

Total dividends paid during 2007 were $0.38 per share, compared with $0.30 per share in 2006 (2005 – $0.24 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. In the second quarter of 2007, the Board approved an increase in the quarterly dividend to $0.10 per share from $0.08 per share.

Quarterly Financial Data

		2007 Quarter ended				2006 Quarter ended
($ millions except per share)		Dec 31	Sept 30	June 30	Mar 31	Dec 31	Sept 30	June 30	Mar 31
Revenues		4 958	4 666	4 358	3 951	3 787	4 114	4 070	3 858
Net earnings		963	677	641	551	358	682	1 218	713
Net earnings attributable to common shareholders per share
	Basic	2.08	1.47	1.39	1.20	0.78	1.48	2.65	1.56
	Diluted	2.04	1.43	1.36	1.17	0.76	1.45	2.59	1.52

SUNCOR ENERGY INC. 2007ANNUAL REPORT 15

Variations in quarterly net earnings during 2007 and 2006 were due to a number of factors:

•

Oil sands production and sales volumes decrease during periods of planned and unplanned maintenance.

•

Changes in benchmark commodity prices throughout 2006 and 2007. WTI averaged US$72.30 per barrel (bbl) in 2007, compared to US$66.20/bbl in 2006.

•

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.

•

Reductions in federal corporate tax rates during the second and fourth quarters of 2007 increased net earnings by $67 million and $360 million, respectively, and reductions in both the federal and Alberta corporate tax rates during the second quarter of 2006 increased 2006 net earnings by $419 million.

•

Insurance proceeds were received in the second and fourth quarters of 2006 of $205 million and $27 million after tax, respectively, related to a January 2005 fire at our oil sands operations.

•

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.

•

The continued strengthening of the Canadian dollar through 2007 unfavourably impacted the realized commodity prices on our products sold in U.S. dollars, reducing the Canadian dollar revenues earned. Changes in the exchange rate also led to unrealized gains on our U.S. dollar denominated long-term debt in 2007.

•

Refined product prices fluctuated as a result of global and regional supply and demand, as well as seasonal demand variations. In our downstream operations, seasonal fluctuations have historically reflected higher demand for vehicle fuels and asphalt in summer and heating fuels in winter. Refining and retail margins strengthened in 2007, compared to 2006 as a result of tighter supply of refined products in both the Ontario and U.S. Rocky Mountain markets.

LIQUIDITY AND CAPITAL RESOURCES

Our capital resources consist primarily of cash flow from operations and available lines of credit. Our level of earnings and cash flow from operations depends on many factors, including commodity prices, production/sales levels, downstream margins, operating expenses, taxes, royalties, and US$/Cdn$ exchange rates.

At December 31, 2007, our net debt (short and long-term debt less cash and cash equivalents) was $3.248 billion, compared to $1.849 billion at December 31, 2006. The increase in debt levels was primarily a result of increased capital spending to fulfill our growth strategies.

During the first quarter of 2007, the company repaid maturing $250 million of 6.80% Medium Term Notes using commercial paper borrowings. Also during the first quarter, 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 received 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 received were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

Also during the second quarter, the company's $300 million bilateral credit facility was amended and extended by one year to 2008 and the credit limit was increased by $30 million to $330 million total funds available. A $2 billion syndicated credit facility was renegotiated and extended by one year to have a five-year term expiring in June 2012 and the company's commercial paper program limit was increased by $300 million to $1.5 billion from $1.2 billion. Additionally, a $15 million revolving demand credit facility was renegotiated and increased by $15 million to $30 million.

16 SUNCOR ENERGY INC. 2007ANNUAL REPORT

During the third quarter of 2007, the company repaid $150 million of maturing 6.10% Medium Term Notes using commercial paper borrowings. Also during the third quarter, the company issued additional 6.50% Notes with a principal amount of US$400 million under our 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 received were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

Undrawn lines of credit at December 31, 2007 were approximately $1.6 billion. Suncor's current long-term senior debt ratings are A-, with a stable trend by Standard & Poor's; A(low), Under Review – Developing by Dominion Bond Rating Service; and A3, with a stable trend by Moody's Investors Service.

Interest expense on debt continues to be influenced by the composition of our debt portfolio, and we are benefiting from short-term floating interest rates remaining at low levels. To manage fixed versus floating rate exposure, we have entered into interest rate swaps with investment grade counterparties. At December 31, 2007, we had $200 million of fixed-rate to variable-rate interest swaps (December 31, 2006 – $600 million).

Management of debt levels continues to be a priority given our growth plans. We believe a phased approach to existing and future growth projects should assist us in maintaining our ability to manage project costs and debt levels.

We believe we will have the capital resources to fund our 2008 capital spending program of $7.5 billion and to meet current working capital requirements. If additional capital is required, we believe adequate additional financing will be available at commercial terms and rates. Suncor expects similar levels of company-wide capital spending over the next several years. (Actual spending is subject to change due to such factors as internal and external approvals and capital availability.)

We anticipate our growth plan will be financed through cash flow from operations, credit facilities and access to debt capital markets. Refer to the discussion under Risk Factors Affecting Performance on page 21 for additional factors that may have an impact on our ability to generate funds to support investing activities.

Aggregate Contractual Obligations

	Payments Due by Period
($ millions)	Total	2008	2009-2010 (aggregate)	2011-2012 (aggregate)	Later Years
Fixed-term debt and commercial paper (1)	3 747	522	—	500	2 725
Interest payments on fixed-term debt and commercial paper (1)	5 022	233	409	397	3 983
Capital leases	324	9	18	20	277
Employee future benefits (2)	612	43	99	113	357
Asset retirement obligations (3)	2 231	190	269	93	1 679
Non-cancellable capital spending commitments (4)	446	446	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	7 310	330	770	792	5 418
Total	19 692	1 773	1 565	1 915	14 439

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 $3,225 million of U.S. and Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2011 to 2038. Interest rates vary from 5.39% to 7.15%. We entered into various interest rate swap transactions maturing in 2011 that resulted in an average effective interest rate in 2007 of 5.7% on $200 million of our Medium Term Notes. Approximately $522 million of commercial paper with an effective interest rate of 4.8% was issued and outstanding at December 31, 2007.

(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 $446 million at the end of 2007. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2008, we anticipate spending approximately $1.5 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. 2007ANNUAL REPORT 17

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.

In addition, a very limited number of our commodity purchase agreements, off-balance sheet arrangements (for a discussion of these arrangements see page 19) 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.

At December 31, 2007, we were in compliance with all covenants and our debt ratings were investment grade.

Significant Capital Project Update

We spent $5.4 billion on capital and exploration expenditures in 2007, compared to $3.6 billion in 2006 (2005 – $3.2 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 Directors approval.

							Estimated % Complete
Project		Plan	Cost Estimate $ millions(1)	Estimate % Accuracy	Spent to Date		Engineering	Construction	Target Completion Date
Coker unit		Expected to increase production capacity by 90,000 bpd	2 100	+13/-7	2 120		100	95	Q2 2008
Steepbank extraction plant		Location and new technologies aimed at improving operational performance	850	+10/-10	320		96	25	2009
Naphtha unit		Increases sweet product mix	650	+10/-10	345		95	20	2009
North Steepbank mine expansion		Expected to generate about 180,000 bpd of bitumen	400	+10/-10	60		50	10	2009
Firebag sulphur plant(2)		Supports emission abatement plan at Firebag; capacity to support Stages 1-6	340	+10/-10	80		65	5	2009
Voyageur program:
	Firebag	Expansion of Firebag 3-6 is expected to increase bitumen supply.	9 000	+18/-13	1 440	(3)
		– Stage 3					75	20	2009
		– Stage 4(2)					25	—	2010
		– Stage 5(2)					10	—	2011
		– Stage 6(2)					—	—	2011
Voyageur program:
	Upgrader 3	Expected to increase production capacity by 200,000 bpd	11 600	+12/-8	1 075	(3)	20	1	2011 (4)

(1)

Excludes commissioning and start-up costs.

(2)

Pending regulatory approval.

(3)

Spending to date includes procurement of major project components. For Firebag Stage 3, procurement at year-end 2007 was 70% complete; for Stage 4, 45% complete; and for Stage 5, 2% complete. For Upgrader 3, procurement was 20% complete.

(4)

Construction completion targeted in 2011 with ramp-up to full capacity during 2012.

18 SUNCOR ENERGY INC. 2007ANNUAL REPORT

The previous table contains forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results for each of these projects may vary from the plans disclosed in the table. The target completion dates and cost estimates are based on information and assumptions from the procurement, design and engineering phases of the projects. The more preliminary the project, the greater the range of uncertainty that is projected in connection with the project.

For a list of the material risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially from those contained in the previous table, please see pages 21 to 26. The forward-looking information in the preceding paragraphs and table should not be taken as an estimate, forecast or prediction of future events or circumstances.

Guarantees, Variable Interest Entities and Off-Balance Sheet Arrangements

At December 31, 2007, we had various indemnification agreements with third parties, as described below.

We have a multiple-party securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million (2006 – $170 million) of accounts receivable having a maturity of 45 days or less. At December 31, 2007, no outstanding accounts receivable had been sold under the program (2006 – $170 million). Under the recourse provisions, we indemnify certain counterparties against credit losses, and in 2007 such indemnification did not exceed $42 million. A contingent liability has not been recorded for this indemnification as we believe we have 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, 2007, were $170 million and approximately $1,530 million, respectively. We recorded an after-tax loss of approximately $4 million on the securitization program in 2007 (2006 – $2 million; 2005 – $4 million).

We have agreed to indemnify holders of our outstanding U.S. dollar denominated debt securities and our credit facility lenders for added costs related to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to the receivables securitization program, and certain facility and equipment leases.

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

In 1999, we entered into an equipment sale and leaseback arrangement with a Variable Interest Entity (VIE) for proceeds of $30 million. The VIE's sole asset was the equipment sold to it and leased back by Suncor. 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. At December 31, 2007, the VIE did not have any assets or liabilities.

Oil Sands Crown Royalties

Under the current Province of Alberta generic oil sands royalty regime (the "Generic Regime"), Alberta Crown royalties for oil sands projects are currently payable at the rate of 25% of the difference between a project's annual gross revenues net of related transportation costs (R), less allowable costs including allowable capital expenditures (the R-C Royalty), subject to a minimum royalty, currently 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 are under the Generic Regime, and assessed based on bitumen value. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will increase royalty rates under the Generic Regime to a sliding scale royalty of 25% – 40% of R-C, subject to minimum royalty of 1% – 9% of R, depending on oil price. In both cases, the sliding scale royalty would move with increases in WTI prices from Cdn$55 to the maximum rate at a WTI price of Cdn$120.

Royalties on our base oil sands mining and associated upgrading operations (the "base operations") are assessed on the R-C calculation as follows:

•

Continues to be 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 will apply from Suncor's 1997 option to transition to the Generic Regime. The royalty rates will remain the same, but will apply to a revised R-C, where R will be based on bitumen value and C would exclude substantially all upgrading costs.

•

Commencing January 1, 2010, pursuant to the Suncor Royalty Amending Agreement we entered into with the government of Alberta in January 2008, the new royalty rates in the Generic Regime described above will apply to the bitumen royalty for current production levels,

SUNCOR ENERGY INC. 2007ANNUAL REPORT 19

subject to a cap of 30% of R-C, and a minimum royalty of up to 1.2% of R (assuming the government enacts their proposed framework). In addition, the Suncor Royalty Amending Agreement provides Suncor with certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes, generally until 2016.

•

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 Generic Regime.

Anticipated Oil Sands Royalty Expense Based on Certain Assumptions

The table below shows the potential royalty payment at various WTI crude prices, for both mining and in-situ operations, as a percentage of gross revenues.

Oil Sands Mining and In-Situ Royalties

WTI Price/bbl US$	70	80	90
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.71	6.98	7.22
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	15.89	18.72	20.86
US$/Cdn$ exchange rate	0.95	1.00	1.05
Crown Royalty Expense (based on percentage of total oil sands revenue) %
2008 – Mining synthetic crude oil, in-situ bitumen (25% and 1% min)	9-10	9-10	10-11
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates)	7-8	8-9	9-10
2010 to 2012 – Bitumen (new rates – cap 30% for mining)	8-10	9-11	9-11

The foregoing table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the percentages or ranges disclosed in the table. The royalty percentages or ranges disclosed in the table were developed using the following assumptions: current agreements with the government of Alberta, royalty rates proposed by the government of Alberta, current forecasts of production, capital and operating costs, and the commodity prices and exchange rates described in the table. If WTI prices rise beyond $90, Suncor anticipates Firebag in-situ royalties may be higher than disclosed 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)

Pursuant to the new royalty framework, the government intends to establish a permanent generic "bitumen valuation methodology" (BVM) for determining the "R" related to bitumen. The Crown is consulting with stakeholders and independent advisors with a decision on the methodology anticipated by June 30, 2008. Final determination of that methodology may have an impact on royalties payable to the Crown;

(ii)

The government also announced its intention to assess and recommend improvements in its systems, structures and resources supporting the collection, verification and reporting of provincial royalties. This assessment is expected to be completed by March 31, 2008. Steps taken by the government thereafter may affect the calculation of royalties; and

(iii)

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 Generic Regime 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.

The forward-looking information in the preceding paragraphs and table should not be taken as an estimate, forecast or prediction of future events or circumstances.

Natural Gas Crown Royalties

Royalty rates on natural gas production are currently capped at 30% for gas discovered in 1974 or later and 35% for gas discovered prior to 1974. These rates are subject to reduction if gas prices drop below $3.70/Gigajoule ($3.89/mcf), a gas well qualifies for a deep gas royalty holiday incentive, or a gas well qualifies as a low productivity well. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will change royalty rates beginning in 2009. The announced framework 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%. If enacted as proposed, the new royalty framework would

20 SUNCOR ENERGY INC. 2007ANNUAL REPORT

negatively impact the economics of deep gas wells in the Alberta Foothills which may cause management to reduce drilling activity in this area.

Cash Income Taxes

The 2007 federal budget proposes to phase out the accelerated capital cost allowance that was originally intended to offset some of the risk associated with the large capital investment required to bring oil sands projects to production. The accelerated capital cost allowance will continue to be available for assets acquired before 2012 on major projects where major construction commenced before March 19, 2007. We believe Suncor's Voyageur expansion, targeted for completion in 2012, will fall under the current accelerated capital cost allowance provisions. If not, the accelerated capital cost allowance will be gradually phased out between 2011 and 2015.

Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for income tax purposes. Based on 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 20, we anticipate our effective income tax rate to be within 2% of the statutory income tax rate for each respective year beyond 2007. Based on the enacted tax rates and assuming that there are no further changes to the current income tax regime, we estimate we will have cash income taxes of 30-50% of our effective tax rate during 2008 to 2010 inclusive. Thereafter, we do not anticipate any significant cash income tax until the middle of the next decade. 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 from our outlook.

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 growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors Affecting Performance for each of our business segments. As a company we identify risks in four principal categories: 1) Operational; 2) Financial; 3) Legal and Regulatory; and 4) Strategic. 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. The internal review is completed annually to ensure all significant risks are identified and appropriately managed.

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, among others, may result in a high degree of price volatility. For example, from 2005 to 2007 the monthly average price for benchmark WTI crude oil ranged from a low of US$46.85/bbl to a high of US$94.63/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 $12.74/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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 21

SENSITIVITY ANALYSIS ⁽¹⁾

						Approximate Change in
			2007 Average		Change	Cash Flow from Operations ($ millions)	After-Tax Earnings ($ millions)
Oil Sands
	Price of crude oil ($/barrel)(2)		74.01	US$	1.00	69	50
	Sweet/sour differential ($/barrel)		10.13	US$	1.00	30	22
	Sales (bpd)		234 700		1 000	13	9
Natural Gas
	Price of natural gas ($/mcf)(2)		6.32		0.10	5	4
	Sales (mmcf/d)		196		10	13	3
Consolidated
	Exchange rate: US$/Cdn$		0.93		0.01
		Effect on oil sands operations				51	36
		Effect on U.S. denominated long-term debt					(15	)
	Total exchange rate impact					51	21

(1)

The sensitivity analysis shows the main factors affecting Suncor's annual cash flow from operations and earnings based on actual 2007 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2007 results. A change in any one factor could compound or offset other factors.

(2)

Includes the impact of hedging activities.

Derivative Financial Instruments

Effective January 1, 2007, new accounting standards were implemented relating to financial instruments. For a more detailed discussion, see Change in Accounting Policies on page 32. Adoption of these changes did not significantly impact earnings.

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 also use physical and financial energy contracts, including swaps, forwards and options, to earn trading and marketing revenues.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Upon initial recognition, each financial asset and financial liability instrument is recorded at fair value, adjusted for any transaction costs.

Derivative contracts, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge each period, 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 each period, 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 related 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.

Commodity Hedging Activities To provide an element of stability to future earnings and cash flow, we have Board of Director approval to fix a price or range of prices for up to approximately 30% of our total planned production of crude oil for specified periods of time. Our 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.

Settlement of our hedging contracts result 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 collars, if market rates are within the range of the hedged contract prices, the option contracts making up the collar will expire with no exchange of cash. Cash received or paid offsets corresponding decreases or increases in our sales revenues or product purchase costs. 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. In 2007, there was a $3 million decrease in net earnings due to the settlement of crude oil hedges, compared to no impact in 2006 (2005 – decrease of $337 million).

22 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Crude oil hedge contracts outstanding at December 31, 2007 were as follows:

	Quantity (bpd)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Costless collars	10 000	59.85 - 101.06	216 - 365	2008

(a)

Average price of crude oil costless collars is WTI per barrel at Cushing, Oklahoma.

(b)

The revenue hedged is translated to Cdn$ at the year-end exchange rate and is subject to change as the US$/Cdn$ exchange rate fluctuates during the hedge period.

(c)

Original hedge term is for the full year.

In addition to our strategic crude oil hedging program, the company also uses derivative contracts to hedge risks related to sales of natural gas and refined products, and to hedge risks specific to individual transactions.

Financial Hedging Activities 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 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. We had the following interest rate swap transactions during 2007.

Description of Swap Transaction	Principal Swapped ($ millions)	Swap Maturity	2007 Effective Interest Rate	2006 Effective Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.7%	5.2%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	6.0%	6.0%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	4.7%	5.3%

In 2007, these interest rate swap transactions reduced pretax financing expense by $4 million, compared to a reduction of $6 million in 2006 (2005 – $14 million reduction).

In addition to our interest rate swap contracts, 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.

The net pretax loss associated with hedge ineffectiveness in 2007 was $1 million.

Fair Value of Hedging Derivative Financial Instruments The fair value of hedging derivative financial instruments is the estimated amount, based on broker quotes and/or internal valuation models, that 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)	2007		2006
Revenue hedge swaps and collars	(11	)	22
Fixed to floating interest rate swaps	8		16
Specific hedges of individual transactions	12		(4	)
Fair value of outstanding hedging derivative financial instruments	9		34

Energy Marketing and Trading Activities In addition to derivative contracts used for hedging activities, the company uses physical and financial energy derivatives to earn trading and marketing revenues. These trading activities are accounted for using the mark-to-market method, with the results reported as revenue and as energy marketing and trading expenses in the Consolidated Statements of Earnings and Comprehensive Income.

The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss) ($ millions)	2007		2006
Physical energy contracts trading activity	21		41
Financial energy contracts trading activity	(3	)	(3	)
General and administrative costs	(4	)	(3	)
Total	14		35

SUNCOR ENERGY INC. 2007ANNUAL REPORT 23

The fair value of unsettled energy marketing and trading instruments is the estimated amount, based on broker quotes and/or internal valuation models, that 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)	2007		2006
Energy trading assets	18		16
Energy trading liabilities	21		13
Net energy trading assets (liabilities)	(3	)	3

The change in fair value of energy marketing and trading net assets during 2007 was as follows:

($ millions)	2007
Fair value of contracts at December 31, 2006	3
Fair value of contracts realized during 2007	29
Fair value of contracts entered into during the year	(56	)
Changes in values attributable to market price and other market changes	21
Fair value of contracts outstanding at December 31, 2007	(3	)

Counterparty Credit Risk 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 positive fair values at the reporting date. We minimize this risk by entering into agreements primarily with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties.

At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2007	2006
Derivative contracts not accounted for as hedges	18	16
Derivative contracts accounted for as hedges	20	35
Total	38	51

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. We were issued a new 10-year operating approval in connection with our oil sands base operations in August 2007. In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air pollution (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 impacts of oil sands development in the province;

•

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

•

the need to reduce or stabilize various emissions to air and withdrawals of, and discharges to, water;

•

issues relating to global climate change, land reclamation and restoration;

•

water use and water disposal;

•

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.

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

24 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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.

On March 8, 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 intensities for our oil sands facility. In March 2008, Suncor must file compliance reports that show what actions the company took during the year to offset intensities. Mitigation 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 July 1, 2007 to December 31, 2007, the compliance costs to Suncor are estimated at between $3 million and $5 million. Final costs will be determined with the company's March 2008 compliance report filing to the province.

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 any of these jurisdictions and any potential impacts are unknown.

In April 2007, the Canadian federal government introduced the Clean Air 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. In support of developing regulation, the federal government has required the submission of production, operations and emissions information for each of Suncor's operations by May 31, 2008. The financial impact of this proposed legislation will be dependent on the details of Clean Air Act regulations.

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 and alternate forms of energy such as wind power and biofuels, accelerating land reclamation, the installation of new emission abatement equipment and pursuing other opportunities such as carbon capture and sequestration.

Regulatory Requirements at Oil Sands Suncor is working to decrease emissions at our oil sands operations. At our in-situ operation, high emissions resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has been capped at approximately 42,000 barrels of bitumen per day. As a result, commissioning of units to increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35% have been delayed. Suncor's production outlook for 2008 reflects this constraint. 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.

At Suncor's base plant we are taking steps to comply with an environmental protection order issued by Alberta Environment. The order relates to emissions at Suncor's oil sands plant that have exceeded air quality standards and which are resulting in increased odours from the operation. To correct the problem, Suncor is upgrading its emission control equipment and reducing discharges to the tailings ponds. The company has also introduced processing changes and is undertaking a more comprehensive air monitoring program.

Any additional regulatory requirements placed on us due to these, or other, matters 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 the 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.

For the Millennium, Steepbank, and North Steepbank Extension mines, we have posted irrevocable letters of credit equal to approximately $227 million with Alberta Environment, representing security for the maximum reclamation liability in the period April 1, 2007 through March 31, 2008. 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

SUNCOR ENERGY INC. 2007ANNUAL REPORT 25

credit equalled $14 million at December 31, 2007 (2006 – $14 million). For more information about our reclamation and environmental remediation obligations, refer to Asset Retirement Obligations in the Critical Accounting Estimates section on page 30.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta. The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement of reserve life. Partial security could be required if reclamation targets are not met and full security may eventually be required.

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.

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.

Reserves Estimates

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). However, we have received an exemption from Canadian securities administrators permitting us to report our reserves in accordance with U.S. disclosure requirements. Pursuant to U.S. disclosure requirements, we disclose net proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from our Firebag in-situ leases, using constant dollar cost and pricing assumptions. As there is no recognized posted bitumen price, these assumptions are based on a posted benchmark oil price, adjusted for transportation, gravity and other factors that create the difference ("differential") in price between the posted benchmark price and Suncor's bitumen. Both the posted benchmark price and the differential are generally determined as of a point in time, namely December 31 ("Constant Cost and Pricing"). Reserves from our Firebag in-situ leases are reported as barrels of bitumen, using these Constant Cost and Pricing assumptions (see Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves for net proved conventional oil and gas reserves).

Pursuant to U.S. disclosure requirements, we also disclose gross and net proved and probable mining reserves. The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proven reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proven reserves reflects historical operational levels. The 80% proved plus probable reserves yield rate reflects anticipated yield levels once operational performance issues have been addressed.

During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen-based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves. The estimate of our net mining reserves reflects the value of Alberta Crown, overriding, and freehold royalty burdens under constant December 31 pricing and our exercise of the option electing to transfer to a bitumen-based Crown royalty effective at the beginning of 2009 (See Required U.S. Oil and Gas and Mining Disclosure – Proved and Probable Oil Sands Mining Reserves for both gross and net, proved and probable mining reserves). Our Firebag in-situ leases are subject to Crown royalty based on bitumen, rather than synthetic, crude oil. As there is currently no legislated methodology for determining bitumen value for Alberta Crown royalty purposes, bitumen value for determining royalties has been assumed to correspond to Firebag bitumen sales to our upgrader. However, determination of bitumen value for royalty purposes is currently under review by the Government of Alberta.

In October 2007, the Government of Alberta proposed changes to the royalty regime. In January 2008, Suncor entered into a Royalty Amending Agreement to transition to the new royalty framework assuming the government enacts their proposed changes. Neither the government's proposed changes nor our Royalty Amending Agreement have been reflected in the following reserve estimates. For a full discussion of our Crown royalties, see Oil Sands Crown Royalties and Natural Gas Crown Royalties on pages 19 and 20.

26 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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

•

Gross and net proved and probable mining reserves are consistent with required US mining disclosures, however the voluntary disclosure reflects normalized constant dollar cost and pricing assumptions. These assumptions use a posted benchmark oil price as at December 31, but apply a differential generally intended to represent a normalized annual average for the year ("Annual Average Differential Pricing"), rather than a point in time differential, in accordance with CSA Staff Notice 51-315 (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves and 80% for proved plus probable reserves); and

•

Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on Annual Average Differential Pricing. Bitumen reserves estimated on this basis are subsequently converted, for aggregation purposes only, to barrels of synthetic crude oil based on a net coker, or synthetic crude oil, yield from bitumen of 80% for proved and proved plus probable reserves.

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

(a)

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

(b)

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

(c)

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

(d)

are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

Comparisons of reserve estimates under Required U.S. Oil and Gas Mining Disclosure and Voluntary Oil Sands Reserve Disclosure may show material differences based on the pricing assumptions used, whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, whether probable reserves are included, and whether the reserves are reported on a gross or net basis. These differences were significant for 2005 and 2007 reporting given the considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing. Refer to Voluntary Oil Sands Reserves and Resources Disclosure – Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations.

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

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

Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory applications have been submitted and no impediment to the receipt of regulatory approval is expected. The mining reserve estimates are based on a detailed geological assessment and also consider industry practice, drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, project implementation commitments and regulatory constraints.

For Firebag in-situ reserve estimates, GLJ considered similar factors such as our regulatory approval or likely impediments to the receipt of pending regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects and drill density. Our proved reserves are delineated to within 80-acre spacing with 3D seismic control (or 40-acre spacing without 3D seismic control) while our probable reserves are delineated to within 160-acre spacing without 3D seismic control. The major facility expenditures to develop our proved undeveloped reserves have been approved by our Board. Plans to develop our probable undeveloped reserves in subsequent phases are under way but have not yet received final approval from our Board.

In a report dated January 10, 2008 ("GLJ NG Report"), GLJ also evaluated our proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from our

SUNCOR ENERGY INC. 2007ANNUAL REPORT 27

mining leases and the Firebag in-situ reserves) as at December 31, 2007.

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

Net reserves represent Suncor's undivided percentage interest in total reserves after deducting Crown royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about future prices, production levels, operating costs, capital expenditures, and the current government of Alberta royalty regime. These assumptions reflect market and regulatory conditions, as required, at December 31, 2007, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Required U.S. Oil and Gas and Mining Disclosure

Proved and Probable Oil Sands Mining Reserves

	Proved				Probable		Proved & Probable
Millions of barrels of synthetic crude oil (1)	Gross (2)		Net (3)		Gross (2)	Net (3)	Gross (2)		Net (3)
December 31, 2006	1 709		1 507		634	564	2 343		2 071
Revisions of previous estimates	(1	)	103		106	149	105		252
Extensions and discoveries	–		–		–	–	–		–
Production	(74	)	(66	)	–	–	(74	)	(66	)
December 31, 2007	1 634		1 544		740	713	2 374		2 257

(1)

Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proved reserves reflects historical operational levels that have fallen below management expectations. The 80% proved plus probable reserves yield rate reflects a return to management's target levels once operational performance issues have been addressed.

(2)

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

(3)

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

Proved Conventional Oil and Gas Reserves

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

Net Proved Reserves ⁽¹⁾

Crude Oil, Natural Gas Liquids and Natural Gas

Constant cost and pricing as at December 31	Oil sands business: Firebag – crude oil (millions of barrels of bitumen) (2) (3)		Natural gas business: crude oil and natural gas liquids (millions of barrels)		Total (millions of barrels)		Natural gas business: natural gas (billions of cubic feet)
December 31, 2006	903		7		910		426
Revisions on previous estimates (4)	68		–		68		4
Improved recovery(5)	99		–		99		–
Purchases of minerals in place	–		–		–		19
Extensions and discoveries	–		–		–		33
Production	(13	)	(1	)	(14	)	(53	)
Sales of minerals in place	–		–		–		(1	)
December 31, 2007	1 057		6		1 063		428

(1)

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

(2)

Although we are subject to Canadian disclosure rules in connection with the reporting of our reserves, we have received exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S. disclosure practices. See Reliance on Exemptive Relief in our AIF.

(3)

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

(4)

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

(5)

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

28 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Voluntary Oil Sands Reserves Disclosure

Oil Sands Mining and Firebag
In-Situ Reserves Reconciliation

The following tables set out, on a gross and net basis, a reconciliation of our proved and probable reserves of synthetic crude oil from our oil sands mining leases and bitumen, converted to synthetic crude oil for comparison purposes only, from our in-situ Firebag leases, from December 31, 2006, to December 31, 2007, based on the GLJ Oil Sands Reports.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases (1), (2)					Firebag In-Situ Leases (1), (3)						Total Mining and In-Situ (3)
Millions of barrels of synthetic crude oil (1)	Proved		Probable	Proved & Probable		Proved		Probable		Proved & Probable		Proved & Probable
December 31, 2006	1 709		634	2 343		803		1 907		2 710		5 053
Revisions of previous estimates	(1	)	106	105		(17	)	(5	)	(22	)	83
Improved recovery	–		–	–		80		(66	)	14		14
Extensions and discoveries	–		–	–		–		–		–		–
Production	(74	)	–	(74	)	(11	)	–		(11	)	(85	)
December 31, 2007	1 634		740	2 374		855		1 836		2 691		5 065

Estimated Net Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases (1), (2)					Firebag In-Situ Leases (1), (3)						Total Mining and In-Situ (3)
Millions of barrels of synthetic crude oil (1)	Proved		Probable	Proved & Probable		Proved		Probable		Proved & Probable		Proved & Probable
December 31, 2006	1 507		564	2 071		722		1 639		2 361		4 432
Revisions of previous estimates	11		108	119		(15	)	(7	)	(22	)	97
Improved recovery	–		–	–		72		(60	)	12		12
Extensions and discoveries	–		–	–		–		–		–		–
Production	(66	)	–	(66	)	(11	)	–		(11	)	(77	)
December 31, 2007	1 452		672	2 124		768		1 572		2 340		4 464

(1)

Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proven reserves, and 80% for proved plus probable reserves under oil sands mining leases and 80% for both proved reserves and proved plus probable reserves for Firebag in-situ leases. Virtually all of our bitumen from the oil sands mining leases is upgraded into synthetic crude oil. However, we have the option of selling the bitumen produced from our Firebag in-situ leases directly to the market where strategic opportunities exist. Accordingly, these bitumen reserves are converted to synthetic crude oil for aggregation purposes.

(2)

Our gross mining reserves are evaluated in part, based on the current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing assumptions. Net mining reserves reflect the relative value of Crown, freehold and overriding royalty burdens based on 2007 Annual Average Differential Pricing assumptions in accordance with CSA Staff Notice 51-315 and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009. Neither the current proposed Alberta royalty regime changes, nor our Royalty Amending Agreement have been incorporated.

(3)

Under Required U.S. Oil and Gas and Mining Disclosure, we reported proved reserves from our Firebag in-situ leases. The disclosure in the table above reports proved reserves from these leases and differs in the following four ways. Reserves from our Firebag in-situ leases under our voluntary disclosure:

(a)

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

(b)

are converted from barrels of bitumen to barrels of synthetic crude oil in this table for aggregation purposes only;

(c)

include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements. U.S. companies do not disclose probable reserves for non-mining properties. We voluntarily disclose our probable reserves for Firebag in-situ leases as we believe this information is useful to investors, and allows us to aggregate our mining and our in-situ reserves into a consolidated total for our oil sands business. As a result, our Firebag in-situ estimates in the above tables are not comparable to those made by U.S. companies.

(d)

are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 29

Remaining Recoverable Resources ^(1)(2)(3)(4)

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, 2007, our best estimate of remaining recoverable synthetic crude oil resources are as follows:

(1)

As U.S. companies are prohibited from disclosing estimates of probable reserves for non-mining properties and resources for oil and gas or mining properties, Suncor's resource estimates will not be comparable to those made by U.S. companies.

(2)

Remaining Recoverable Resources are the sum of reserves and contingent resources.

(3)

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.

(4)

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

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.

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 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 measured at fair value every year-end, and incremental increases are discounted to present value using a credit-adjusted risk-free discount rate (2007 – 6.0%; 2006 – 5.5%). 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". Payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 30 years. 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 2007, we increased our estimated undiscounted total obligation to $2.231 billion from the previous estimate of $1.657 billion. The increase was primarily due to a change in the oil sands estimate to $1.941 billion from $1.473 billion, primarily reflecting increased estimated costs related to pond reclamation. The majority of the costs in oil sands are projected to occur over a time horizon extending to approximately 2060. In 2008, these changes in the ARO estimate are anticipated to result in additional after-tax expenses of approximately $24 million. The discounted amount of our ARO liability was $1.072 billion at December 31, 2007, compared to $808 million at December 31, 2006.

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

30 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 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 9 to the consolidated financial statements on page 75.

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 more timely 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 exploratory dry hole costs 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. 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.

Control Environment

Based on their evaluation as of December 31, 2007, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-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 under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the Securities and Exchange Commission rules and forms. In addition, as of December 31, 2007, there were no changes in our internal control over financial reporting that occurred during 2007 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 as part of the reporting, certification and attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of 2002. For the year ended December 31, 2007, the company's internal controls were found to be operating free of any material weaknesses.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 31

CHANGE IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007, the company adopted The Canadian Institute of Chartered Accountants (CICA) Handbook section 3855 "Financial Instruments, Recognition and Measurement", section 3865 "Hedging", section 1530 "Comprehensive Income" and section 3251 "Equity".

Sections 3855 and 3865 establish accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. Section 1530 establishes standards for reporting and disclosure of comprehensive income, where comprehensive income refers to all changes in equity (net assets) during a reporting period except those resulting from investments by owners and distributions to owners, and section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period.

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 long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and/or appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Upon initial recognition, each financial asset and financial liability instrument is recorded at fair value, adjusted for any transaction costs.

Derivative contracts, excluding those considered as normal purchases and normal sales, 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 each period. 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'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. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized.

The company's equity section will now contain a new caption "Accumulated Other Comprehensive Income". In addition to containing the effective portions of the gains/losses on our cash flow hedges, accumulated other comprehensive income will also contain the cumulative foreign currency translation adjustment of our foreign operations.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following increases (decreases), net of income taxes, were recorded to the Consolidated Balance Sheet:

($ millions)
Financial Assets (1)	42
Financial Liabilities (1)	29
Retained Earnings (2)	5
Cumulative Foreign Currency Translation (3)	71
Accumulated Other Comprehensive Loss (4)	(63	)

(1)

Recognition of fair value of derivative financial instruments designated as cash flow hedges and fair value hedges, and the related income tax impacts.

(2)

Impact on adoption of the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges.

(3)

Restatement of foreign currency translation adjustment to accumulated other comprehensive loss.

(4)

Recognition of accumulated other comprehensive loss arising from the restatement of foreign currency translation adjustment, offset by accumulated other comprehensive income arising from the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges.

The comparative consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

32 SUNCOR ENERGY INC. 2007ANNUAL REPORT

RECENTLY ISSUED CANADIAN ACCOUNTING STANDARDS

Inventories

In June 2007, the CICA approved Handbook section 3031 "Inventories". Effective January 1, 2008, this standard eliminates the use of a LIFO (last-in-first-out) based valuation approach for inventory. 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. This standard can be applied prospectively with an initial adjustment to retained earnings or applied retrospectively with restatement of comparative balances.

The company currently uses a LIFO methodology for crude oil and refined product inventory and will be transitioning to a FIFO (first-in-first-out) methodology beginning January 1, 2008. Retrospective application with restatement will increase the following financial statement balances upon transition:

($ millions)
Inventory	404
Future Income Tax Liability	121
Retained Earnings	283

Capital Disclosures

In December 2006, the CICA approved Handbook section 1535 "Capital Disclosures". Effective January 1, 2008 this standard outlines required disclosure of specific information about an entity's objectives, policies and processes for managing capital. The new standard will not impact net earnings or financial position.

Financial Instruments

In December 2006, the CICA approved Handbook section 3862 "Financial Instruments Disclosure" and section 3863 "Financial Instruments Presentation". Effective January 1, 2008, these standards provide a complete set of disclosure and presentation requirements for financial instruments. The standards have increased emphasis on simplifying disclosures, while enhancing risk identification and discussion of how these risks are managed in relation to both recognized and unrecognized financial instruments. The new standard will not impact net earnings or financial position.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 33

OIL SANDS

Located near Fort McMurray, Alberta, our oil sands business forms the foundation of our growth strategy 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)	2007		2006	2005
Revenue	6 775		7 407	3 965
Production (thousands of bpd)	235.6		260.0	171.3
Average sales price ($/barrel)	74.01		68.03	53.81
Net earnings	2 434		2 783	957
Cash flow from operations (1)	3 092		3 917	1 916
Total assets	18 108		13 692	11 648
Cash used in investing activities	4 248		2 230	1 882
Net cash surplus (deficiency)	(519	)	2 113	(236	)
Sales mix (light/heavy mix)	54/46		53/47	54/46
Cash operating costs ($/barrel) (1)	27.80		21.70	24.55
ROCE (%) (2)	42.6		53.5	22.4
ROCE (%) (3)	27.6		40.1	16.0

(1)

Non-GAAP measure. See page 46.

(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. See Page 46.

(3)

Includes capitalized costs related to major projects in progress. See page 46.

2007 Overview

•

Oil sands production averaged 235,600 bpd in 2007, compared to 260,000 bpd in 2006. Production was down year-over-year primarily as the result of planned and unplanned maintenance including a planned 50-day outage of Upgrader 2.

•

Oil sands cash operating costs averaged $27.80 per barrel during 2007, compared to $21.70 per barrel in 2006. The increase in 2007 was primarily due to fixed costs being spread over lower production, as well as higher maintenance costs related to planned and unplanned maintenance.

34 SUNCOR ENERGY INC. 2007ANNUAL REPORT

•

The oil sands business made considerable progress on a variety of projects that are expected to benefit operational reliability, production and sales. At December 31, 2007, the addition of a new set of cokers to our upgrading complex was approximately 95% complete. This expansion is expected to increase production capacity to 350,000 bpd, with construction completion targeted in the second quarter of 2008 and ramp-up to full capacity expected in the fourth quarter. Other work included construction of a naphtha unit (which is intended to enhance product mix) which was approximately 20% complete at year-end, and the Steepbank extraction plant which was approximately 25% complete at year-end.

•

Significant progress was also made on components of the Voyageur program to increase production capacity to 550,000 bpd in 2012. Engineering, procurement and field construction on these projects was advanced to a point sufficient for Suncor's Board of Directors to provide final project approval in early 2008.

•

In July, Suncor filed a regulatory application for the Voyageur South mine extension. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility.

•

In August, Alberta Environment issued a new 10-year operating approval for Suncor's base oil sands operations.

•

At our in-situ operation, high emissions resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. See page 25 for further discussion.

Analysis of Net Earnings

Net earnings were $2,434 million in 2007, compared to $2,783 million in 2006 (2005 – $957 million). Excluding the impacts of income tax rate revaluations, net insurance proceeds (relating to the January 2005 fire) and project start-up costs, earnings were $2,063 million in 2007, compared to $2,148 million in 2006 (2005 – $680 million).

The decrease in earnings primarily reflects the impact of scheduled and unscheduled maintenance that reduced crude oil production and increased operating expenses.

Oil sands average production was 235,600 bpd in 2007, compared to 260,000 bpd in 2006. Sales volumes in 2007 averaged 234,700 bpd, compared with 263,100 bpd in 2006. Lower sales volumes decreased 2007 net earnings by $427 million. Production and sales volumes were significantly lower in 2007 due mainly to the planned shutdown of Upgrader 2 during the summer. The 50-day outage was required to tie-in new facilities related to our planned expansion of oil sands production capacity. Unplanned outages throughout the year have also had a negative impact on our 2007 production volumes.

Sales price realizations averaged $74.01 per barrel in 2007 (including the impact of pretax hedging losses of $5 million), compared with $68.03 per barrel in 2006 (with no pretax hedging gains). The average sales price realization was favourably impacted by stronger WTI benchmark crude oil prices and strengthening differentials on our sweet and sour crude blends relative to WTI, partially offset by a higher average US$/Cdn$ exchange rate. As crude oil is sold based on U.S. dollar benchmark prices, the increased average US$/Cdn$ exchange rate decreased the Canadian dollar value of crude oil products.

The net impact of the above sales mix and pricing factors increased net earnings by $297 million in 2007.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 35

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 $2,833 million in 2007, compared to $2,546 million in 2006 (2005 – $1,652 million). Expenses increased year-over-year primarily due to higher maintenance expenditures, in addition to diesel fuel purchases made in order to satisfy customer commitments during the Upgrader 2 shutdown.

Overall, increased cash expenses, which include Firebag operating expenses, reduced net earnings by $194 million.

Royalties

Alberta oil sands Crown royalties decreased to $565 million in 2007, compared to $911 million in 2006 (2005 – $406 million). The lower royalty expense is due primarily to increased capital expenditures incurred, lower sales volumes and the absence of net insurance proceeds (relating to a January 2005 fire). These factors were partially offset by higher crude oil prices. Alberta oil sands Crown royalties are subject to completion of audits for 2007 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 19.

Non-Cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $462 million from $385 million in 2006 (2005 – $330 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 $61 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. In the second quarter of 2006, reductions to both the federal and the Alberta provincial income tax rates resulted in a $429 million revaluation of the oil sands future income tax liability balance, with a corresponding increase in net earnings (2005 – nil).

Cash Operating Costs

Cash operating costs increased to $2,391 million in 2007, compared to $2,057 million in 2006. On a per barrel basis, these costs increased to $27.80 per barrel from $21.70 per barrel in 2006. The increase in cash operating costs per barrel is a result of increased operating expenses and lower production. Refer to page 46 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 $3,092 million in 2007, compared to $3,917 million in 2006 (2005 – $1,916 million). The decrease was primarily due to the same factors that impacted net earnings, excluding the impact of depreciation, depletion and amortization. In addition, cash flows were reduced by cash income taxes that were not present in 2006.

Cash flow used in investing activities increased to $4,248 million in 2007 from $2,230 million in 2006 (2005 – $1,882 million). During 2007, capital spending related primarily to continued progress on the current coker unit expansion, future Voyageur strategy expansion, Steepbank extraction plant and naphtha unit projects.

Combined, the above factors resulted in a net cash deficiency of $519 million in 2007, compared with a surplus of $2,113 million in 2006 (2005 – $236 million deficiency).

36 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 by 35,000 bpd (bringing the total production capacity to 260,000 bpd). In the second half of 2008, Suncor expects to complete an expansion to increase production capacity by 90,000 bpd (bringing the total production capacity to 350,000 bpd).

Suncor's Board of Directors approved the final phase of this multi-staged growth strategy in January 2008. An investment estimated at $20.6 billion for our Voyageur program is expected to increase production capacity by 200,000 bpd, enabling production capacity of 550,000 bpd in 2012. Of the $20.6 billion, $9 billion is planned for expansion of bitumen supply at our in-situ operation, while $11.6 billion is targeted for construction of a third upgrader. For further details, see the Significant Capital Projects table on page 18.

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 in a volatile commodity pricing environment. Also refer to Liquidity and Capital Resources on page 16.

•

Our ability to complete future projects both on time and on budget. This could be impacted by competition from other projects (including other oil sands projects) for skilled people, increased demands on the Fort McMurray infrastructure (including housing, roads and schools), or higher prices for the products and services required to operate and maintain the operations. 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.

•

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.

•

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. These factors are difficult to predict and impossible to control.

•

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 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 2,100 oil sands employees. The current collective agreement with the union expires on April 30, 2010.

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Also refer to Risk Factors Affecting Performance on page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 37

NATURAL GAS

Suncor's natural gas business, operating primarily in western Canada, acts as a price hedge against the company's purchases for internal consumption at our oil sands operations. This business also supports Suncor's sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

Natural gas strategy focuses on:

•

Building competitive operating areas.

•

Improving base business efficiency, with a focus on operational excellence and work site safety.

•

Developing new, low-capital business opportunities.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2007		2006		2005
Revenue	553		578		679
Natural gas production (mmcf/d)	196		191		190
Average natural gas sales price ($/mcf)	6.32		7.15		8.57
Net earnings	25		106		155
Cash flow from operations (1)	248		281		412
Total assets	1 811		1 503		1 307
Cash used in investing activities	532		443		344
Net cash surplus (deficit)	(262	)	(189	)	63
ROCE (%) (2)	2.5		14.9		30.7

(1)

Non-GAAP Measure. See Page 46.

(2)

ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 46.

2007 Overview

•

Total production averaged 215 million cubic feet equivalent per day (mmcfe/d) in 2007, compared to 209 mmcfe/d in 2006. Production during 2007 was comprised of 91% natural gas and 9% natural gas liquids and crude oil.

•

Company-wide purchases of natural gas for internal consumption were approximately 184 million cubic feet per day (mmcf/d) during 2007, compared to natural gas production of 196 mmcf/d in 2007.

•

In September, Suncor commissioned its fourth wind power project. The 76-megawatt facility located near Ripley, Ontario is the company's largest wind power project.

•

During the first quarter of 2007, Suncor acquired developed and undeveloped lands in British Columbia for approximately $160 million.

38 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Analysis of Net Earnings

Natural gas net earnings were $25 million in 2007, compared to $106 million in 2006 (2005 – $155 million). Excluding the impact of income tax rate reductions on the opening future income tax liability, the net loss for 2007 was $14 million, compared to net earnings of $53 million in 2006 (2005 – $155 million). The decrease in net earnings was due primarily to lower natural gas price realizations and higher depreciation, depletion and amortization, operating costs, and transportation expenses.

The average realized price for natural gas was $6.32 per thousand cubic feet (mcf) in 2007, compared to an average of $7.15 per mcf in 2006, reflecting lower benchmark natural gas prices. This was partially offset by the increase in price realizations for crude oil and natural gas liquids that resulted from the higher benchmark prices for those products. The net impact of the price variance was a reduction in net earnings of $38 million.

Natural gas total production was 215 mmcfe/d in 2007, compared to 209 mmcfe/d in the prior year. The increase in 2007 production was primarily due to increased volumes from the Grizzly Valley area as a result of new wells added during the period and improved access to processing facilities. Increased production volumes positively impacted 2007 net earnings by $11 million.

Cash Expenses

Operating costs, including general and administrative expenses, were $135 million in 2007, compared to $110 million in 2006 (2005 – $93 million). The increase in operating costs was mainly due to higher lifting costs resulting from third-party processing fees and industry cost pressures, including higher labour costs.

Exploration expenses were $82 million in 2007, unchanged from 2006 (2005 – $46 million). A $15 million increase in dry hole costs recognized during the year was offset by a reduction in seismic expenditures.

Non-Cash expenses

DD&A expense was $189 million in 2007, compared to $152 million in 2006 (2005 – $130 million). The increase was due to higher production and an increase in the capitalized costs, including the impact of developmental dry holes.

Royalties

Royalties on production of natural gas and liquids were $126 million ($1.61 per thousand cubic feet equivalent (mcfe)) in 2007, comparable to the $127 million royalty expense ($1.67 per mcfe) in 2006 (2005 – $149 million; $1.95 per mcfe). Higher production was offset by lower sales price realizations. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will change royalty rates beginning in 2009. For a further discussion on Crown royalties, see page 20.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 39

Net Cash Deficiency Analysis

Natural gas net cash deficiency was $262 million in 2007, compared with a $189 million deficiency in 2006 (2005 – $63 million surplus). Cash flow from operations decreased to $248 million compared with $281 million in the prior year (2005 – $412 million), mainly due to decreased revenues and higher operating costs.

Cash used in investing activities increased to $532 million, compared with $443 million in 2006 (2005 – $344 million) primarily due to the acquisition of developed and undeveloped lands in British Columbia for approximately $160 million.

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.

•

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 reduced production.

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Refer to Risk Factors Affecting Performance on page 21.

40 SUNCOR ENERGY INC. 2007ANNUAL REPORT

REFINING AND MARKETING

Consistent with the company's organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment – refining and marketing. 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. There was no impact to previously reported net earnings as a result of the combination. The results of company-wide energy marketing and trading will continue to be included in this segment. The financial results relating to the sales of oil sands and natural gas production will continue to be reported in their respective business segments.

Refining and marketing operates a 70,000 barrel per day (bpd) capacity refinery in Sarnia, Ontario and a 90,000 bpd capacity refining complex in Commerce City, Colorado, and markets refined products to industrial, wholesale and commercial customers primarily in Ontario, Quebec and Colorado. Through a combination of joint venture-operated and company-owned 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 Grand Junction, Colorado.

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 and natural gas 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)		2007		2006		2005
Revenue		11 173		8 593		6 984
Refined product sales (millions of litres)
	Gasoline	6 132		5 804		5 585
	Total	12 228		10 803		10 574
Net earnings breakdown:
	Total earnings excluding energy, marketing and trading activities	335		213		163
	Energy marketing and trading activities	10		22		11
	Total net earnings	345		235		174
Cash flow from operations (1)		580		443		363
Total assets		4 519		4 037		3 172
Cash used in investing activities		(491	)	(787	)	(818	)
Net cash deficiency		(29	)	(446	)	(485	)
ROCE (%) (2)		16.8		20.4		22.2
ROCE (%) (3)		14.5		12.5		13.8

(1)

Non-GAAP measure. See page 46.

(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. See page 46.

(3)

Includes capitalized costs related to major projects in progress. See page 46.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 41

2007 Overview

•

The final phase of a three-year, $1 billion investment project in the Sarnia refinery is now complete. This investment was made to improve the refinery's environmental performance, enable the production of ultra low sulphur diesel fuel and increase the refinery's sour synthetic processing capacity. The upgrades to enable the production of ultra low sulphur diesel fuel were completed in 2006. The final phase of this multi-phased project was a 120-day shutdown of the refinery hydrocracker unit to complete the tie-in of new facilities to the existing refinery.

•

During commissioning of the new facilities, operational difficulties were encountered resulting in a lengthier than planned start-up period. As a result, full production from the new facilities had not yet been achieved by year end.

•

Refinery utilization levels increased as there were fewer scheduled shutdowns during 2007, compared to the prior year and the Commerce City refinery had improved reliability during the year.

•

Both our Canadian and U.S. downstream operations benefited from high refining and retail margins due to tighter supply of refined products in the Ontario and U.S. Rocky Mountain markets during the first half of the year. Partially offsetting this was increased purchases of refined products to meet customer commitments during planned refinery shutdowns, which reduced overall fuel margins.

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 43.

Refining and marketing's net earnings increased to $345 million in 2007 from $235 million in 2006 (2005 – $174 million). This increase was primarily due to higher sales volumes, offset by increased operating expenses.

Volumes

Total sales volumes averaged 33.5 10³m³/d (thousands of cubic metres per day), compared to 29.5 10³m³/d in 2006. The increase in sales was the result of the higher refinery utilization levels and higher purchases for resale. Total gasoline sales volumes through our Sunoco and Phillips 66® branded retail network were comparable to the prior year, with 1,900 million litres in 2007, slightly down from 1,935 million litres in 2006.

Fuel Margins

Refining and marketing benefited from stronger margins in both Canada and the U.S. Rocky Mountain regions during the first half of the year as tighter supply of refined products resulted in higher light oil product margins. This was mostly offset in the second half of the year by lower margins on heavy fuel oil sales and lower margins from finished products purchased for re-sale. Crude and product purchases were $6,351 million in 2007, compared to $5,308 million in 2006 (2005 – $4,613 million). The increase was a result of higher crude oil prices, higher crude oil purchases due to higher refinery utilization levels and an increase in refined product purchases to meet customer commitments during the planned outage at our Sarnia refinery.

Refinery Utilization

Overall crude refinery utilization averaged 98% in 2007, compared with 85% in 2006. The increase in refinery utilization was primarily the result of a reduction in overall planned maintenance shutdowns occurring during 2007 compared to 2006, in addition to improved reliability at the Commerce City refinery.

Cash and Non-Cash Expenses

Overall, cash and non-cash operating expenses increased by $72 million after-tax in 2007. Cash expenses increased by $44 million after-tax in 2007, primarily due to an increase in Canadian federal excise tax paid as a result of increased sales volumes in 2007. Non-cash expenses increased by $28 million after-tax in 2007, due to increased depreciation, depletion and amortization expense mainly resulting from a full year's depreciation being taken on the Commerce City and Sarnia refinery diesel desulphurization projects and the St. Clair ethanol project that were completed in 2006.

42 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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)			2007	2006	2005
Operating revenues
	Sales to refining and marketing joint ventures:
		Refined products	329	294	327
		Petrochemicals	163	136	279

At December 31, 2007, amounts due from refining and marketing joint ventures were $17 million, compared to $20 million at December 31, 2006.

Energy Marketing and Trading Activities

Energy marketing and trading activities consist of both third party crude oil marketing and financial and physical derivatives trading activities. These activities resulted in net earnings after-tax of $10 million in 2007 compared to net earnings of $22 million in 2006 (2005 – $11 million). The higher earnings in 2006 compared to 2007 were the result of very strong crude trading margins in the prior year. For further details on our energy marketing and trading activities, see page 23.

Energy 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.

Net Cash Deficiency Analysis

Refining and marketing's net cash deficiency was $29 million in 2007 compared to a net cash deficiency of $446 million in 2006 (2005 – $485 million). Cash flow from operations was $580 million in 2007 compared to $443 million in 2006 (2005 – $363 million). The increase was primarily due to the same factors that impacted net earnings.

Cash used in investing activities was $491 million in 2007 compared to $787 million in 2006 (2005 – $818 million). Capital expenditures in 2007 were significantly lower than the previous year, as the majority of the work related to the diesel desulphurization and oil sands integration projects was completed in 2006. Capital spending in 2007 related mainly to completion of this work at Sarnia, including a planned refinery shutdown to allow the tie-in of the new facilities.

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.

•

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

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Refer to Risk Factors Affecting Performance on page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 43

OUTLOOK

During 2008, management will focus on the following priorities:

•

Achieve annual oil sands production of 275,000 to 300,000 bpd at a cash operating cost average of $25 to $27 per barrel. Planned production increases with the commissioning of an expansion to Upgrader 2 and a strong focus on production reliability are key to managing operating costs.

•

Maintain production from our natural gas business (including natural gas liquids and crude oil) at an average 205 to 215 mmcf equivalent per day. We expect to bring several new wells into production and will continue to focus on high-volume deep gas prospects in 2008.

•

Advance plans for increased bitumen supply. Meet regulatory requirements to allow ramp up of expansion to Firebag Stages 1 and 2, commence construction of Stage 3 and seek regulatory approval to proceed with Stages 4 to 6. New third-party bitumen supplies are also expected in 2008.

•

Advance plans for increasing crude oil production. Fully commission expanded units to enable production capacity of 350,000 bpd by year end. With Board of Director's approval given in January 2008, accelerate work on a $20.6 billion expansion of bitumen feed and upgrader capacity to generate 550,000 bpd capacity in 2012.

•

Fulfill regulatory requirements. Construct and commission emission abatement equipment and reduce diluent discharges to the tailings ponds to meet specific regulatory requirements.

•

Continue to focus on safety. Increase focus on identifying and reducing potential process hazards.

•

Focus on efficiency. Safely complete planned modifications to Upgrader 2 aimed at ensuring reliable full capacity production. A planned maintenance shutdown to Upgrader 1, part of $1.5 billion in maintenance capital spending in 2008, is also expected to improve reliability going forward.

•

Maintain a strong balance sheet. While net debt is expected to rise with capital spending of $7.5 billion in 2008, plan to maintain a strong debt to cash flow ratio and protect future cash flow with strategic crude oil hedging of up to 30% of planned production.

•

Continue efforts to reduce environmental impact intensity. Investments planned to reduce sulphur emissions at oil sands facilities and reduce water use intensity.

•

Continue to pursue energy efficiencies, greenhouse gas offsets and new, renewable energy projects. In oil sands operations, advance work on more efficient extraction technology. Advance renewable energy portfolio.

44 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Suncor's outlook provides management's targets for 2008 in certain key areas of the company's business. Users of this information are cautioned that the actual events in 2008 may vary from the priorities disclosed.

		2008 Full-Year Outlook
Oil Sands
Production		275,000 bpd to 300,000 bpd
	Diesel	11%
	Sweet	36%
	Sour	49%
	Bitumen	2%
	Third-party processing	2%
Realization on crude sales basket		WTI @ Cushing less Cdn$4.25 to Cdn$5.25 per barrel
Cash operating costs (1)		$25.00 to $27.00 per barrel
Natural Gas
Production (2) (mmcf equivalent per day)		205 to 215
	Natural gas	93%
	Liquids	7%

(1)

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 $6.70 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 46.

(2)

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.

Factors that could potentially impact Suncor's 2008 financial performance include:

•

Planned maintenance at oil sands. Upgrader 1 is expected to be shut down for approximately 30 days in the second quarter for scheduled maintenance. Although this shutdown is reflected in operational targets for the year, production estimates could be impacted if unplanned work is identified, or the schedule is impacted by labour or material supply issues. During the outage, Upgrader 2 is expected to continue producing approximately 200,000 bpd.

•

Completion and commissioning of an expansion to Upgrader 2 during the second quarter to enable production capacity of 350,000 bpd. Production rates during the ramp-up period are difficult to predict and can be impacted by bitumen supply, as well as planned and unplanned maintenance. However, Suncor expects to move towards the 350,000 bpd capacity in the fourth quarter.

•

Regulatory requirements at the company's oil sands base plant and in-situ operation. Suncor plans to incur maintenance and capital expenditures to construct and commission emission abatement equipment. The timing and scope of this work could impact 2008 results.

•

Bitumen supply. If Suncor encounters unexpected issues in meeting regulatory requirements aimed at controlling emissions at both base plant and the in-situ operation, or if there are unexpected issues related to third-party supplies, there may be bitumen supply restrictions that could impact 2008 production targets.

•

Production volumes at the Sarnia refinery. Suncor is lining-out new facilities at the refinery and this work could impact production in the first few months of 2008.

•

Crude oil hedges. Consistent with the approval received from the Board of Directors, Suncor may fix a price or range of prices for up to approximately 30% of our planned production of crude oil for specified periods of time. At December 31, 2007, Suncor had hedging agreements in place for 10,000 bpd in 2008. These costless collar hedges have an average floor of US$59.85 per barrel with an average ceiling of US$101.06 per barrel in 2008.

For additional information on risk factors that could cause actual results to differ, please see page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 45

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		2007	2006	2005
Cash flow from operations ($ millions)	A	3 805	4 533	2 476
Weighted average number of common shares outstanding – basic (millions of shares)	B	461	459	456
Cash flow from operations – basic ($ per share)	A/B	8.25	9.87	5.43

ROCE

For the year ended December 31 ($ millions, except ROCE)		2007		2006	2005
Adjusted net earnings
Net earnings		2 832		2 971	1 158
Add: after-tax financing expenses (income)		(179	)	26	(16	)
	D	2 653		2 997	1 142
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents		1 849		2 868	2 134
Shareholders' equity		8 952		5 996	4 874
	E	10 801		8 864	7 008
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents		3 248		1 849	2 868
Shareholders' equity		11 613		8 952	5 996
	F	14 861		10 801	8 864
Average capital employed	(E+F)/2=G	12 831		9 832	7 936
Average capitalized costs related to major projects in progress	H	3 454		2 476	2 175
ROCE (%)	D/(G-H)	28.3		40.7	19.8

46 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Oil Sands Operating Costs – Total Operations

			2007			2006			2005
(unaudited)			$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses			2 435			2 198			1 455
	Less: natural gas costs, inventory changes and stock-based compensation		(353	)		(361	)		(281	)
	Less: non-monetary transactions		(102	)		(126	)		—
Accretion of asset retirement obligations			41			28			24
Taxes other than income taxes			55			36			29
Cash costs			2 076		24.15	1 775		18.70	1 227		19.60
Natural gas			307		3.55	276		2.90	307		4.90
Imported bitumen (net of other reported product purchases)			8		0.10	6		0.10	2		0.05
Cash operating costs		A	2 391		27.80	2 057		21.70	1 536		24.55
Project start-up costs		B	60		0.95	38		0.40	25		0.40
Total cash operating costs		A+B	2 451		28.75	2 095		22.10	1 561		24.95
Depreciation, depletion and amortization			462		5.40	385		4.05	330		5.30
Total operating costs			2 913		34.15	2 480		26.15	1 891		30.25
Production (thousands of barrels per day)					235.6			260.0			171.3

Oil Sands Operating Costs – In-Situ Bitumen Production Only

		2007			2006			2005
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		273			209			155
Less: natural gas costs and inventory changes		(134	)		(103	)		(91	)
Taxes other than income taxes		7			4			—
Cash costs		146		10.85	110		8.95	64		9.15
Natural gas		134		9.90	103		8.35	91		13.05
Cash operating costs	A	280		20.75	213		17.30	155		22.20
In-situ (Firebag) start-up costs	B	—		—	21		1.70	7		1.00
Total cash operating costs	A+B	280		20.75	234		19.00	162		23.20
Depreciation, depletion and amortization		83		6.20	68		5.55	34		4.90
Total operating costs		363		26.95	302		24.55	196		28.10
Production (thousands of barrels per day)				36.9			33.7			19.1

SUNCOR ENERGY INC. 2007ANNUAL REPORT 47

Legal Notice – Forward-Looking Information

This management's discussion and analysis contains certain forward-looking statements that are based on Suncor's 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 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," "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.

The risks, uncertainties and other factors that could influence actual results include, but are not limited to, changes in the general economic, market and business conditions; fluctuations in supply and demand for 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 (for example, the Voyageur project, including our Firebag in-situ development) and regulatory projects (for example, the emissions reduction modifications at our Firebag in-situ development); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement 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 current review of the unintended consequences of the proposed Crown royalty regime, and the Government of Canada's current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting 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.

48 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2007, dated February 27, 2008

EX-99.3

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EXHIBIT 99-3

Consent of PricewaterhouseCoopers LLP

Exhibit 99.3

PricewaterhouseCoopers LLP

Chartered Accountants

111 5th Avenue SW, Suite 3100

Calgary, Alberta

Canada T2P 5L3

Telephone +1 (403) 509 7500

Facsimile +1 (403) 781 1825

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) and Form F-9 (File No. 333-140797) of Suncor Energy Inc., of our report dated February 27, 2008 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 4, 2008

PricewaterhouseCoopers refers to the Canadian firm of PricewaterhouseCoopers LLP and the other member firms of PricewaterhouseCoopers International Limited, 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.

Exhibit 99.4

LETTER OF CONSENT

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 reports (collectively the “Reports”), prepared by GLJ Petroleum Consultants Ltd.:

·the Reserves Assessment and Evaluation of Canadian Oil and Gas Properties of Suncor Energy Inc. Natural Gas effective December 31, 2007 and dated February 11, 2008;

·the Assessment and Evaluation of the synthetic crude oil reserves and resources effective December 31, 2007 associated with the Suncor Energy Inc. oil sands operations located near Fort McMurray, Alberta and dated February 19, 2008;  and

·the Assessment and Evaluation of the bitumen reserves and resources effective December 31, 2007 associated with the Suncor Energy Inc. Firebag operation located near Fort McMurray, Alberta and dated February 11, 2008.

We hereby consent to the use of our name, reference to and excerpts from the said reports by Suncor Energy Inc. in its Annual Information Form for the 2007 fiscal year (AIF) and its annual report on Form 40-F (Form 40-F), and the registration statements of Suncor Energy Inc. on Form F-3 (File No. 333-7450), Form F-9 (File No. 333-140797), Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648) and Form S-8 (File No. 333-124415).

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 Reports 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 4, 2008

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 4, 2008 /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 4, 2008 /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, 2007 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 4, 2008

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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, 2007 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 4, 2008

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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