40-F

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C.   20549

FORM 40-F

(Check One)

oRegistration statement pursuant to Section 12 of the Securities Exchange Act of 1934

or

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

For fiscal year ended	December 31, 2006
Commission File Number	No. 1-12384

SUNCOR ENERGY INC.

(Exact name of registrant as specified in its charter)

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

x           Annual Information Form                   x           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, 2006 there were 459,943,827 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                           x

Indicate by check mark whether the registrant:  (1) has filed all reports required to be filed by Section 13 or 15(d) of the Exchange Act during the proceeding 12 months (or for such shorter period that the registrant was required to file such reports);  and (2) has been subject to such filing requirements in the past 90 days.

Yes         x                           No                           o

SUNCOR ENERGY INC. ANNUAL INFORMATION FORM

February 28, 2007

ANNUAL INFORMATION FORM

TABLE OF CONTENTS

TABLE OF CONTENTS	ii
GLOSSARY OF TERMS	iv
CONVERSION TABLE	viii
CURRENCY	viii
FORWARD-LOOKING STATEMENTS	viii
NON GAAP FINANCIAL MEASURES	ix
CORPORATE STRUCTURE	1
Name and Incorporation	1
Intercorporate Relationships	1
GENERAL DEVELOPMENT OF THE BUSINESS	2
Overview	2
Three-Year History	3
OIL SANDS (OS)	8
Operations	8
Principal Products	9
Principal Markets	9
Transportation	9
Competitive Conditions	10
Seasonal Impacts	10
Sales of Synthetic Crude Oil and Diesel	10
Environmental Compliance	11
NATURAL GAS (NG)	11
Marketing, Pipeline and Other Operations	11
Principal Products	12
Competitive Conditions	12
Seasonal Impacts	12
Environmental Compliance	12
ENERGY MARKETING & REFINING–CANADA (EM&R)	13
Procurement of Feedstocks	13
Refining Operations	13
Principal Products	14
Principal Markets	15
Transportation and Distribution	16
Competitive Conditions	16
Environmental Compliance	16
REFINING & MARKETING–U.S.A. (R & M)	16
Procurement of Feedstocks	17
Refining Operations	17
Principal Products	18
Principal Markets	18
Transportation and Distribution	19
Competitive Conditions	19
Environmental Compliance	19
MATERIAL CONTRACTS	19
RESERVES ESTIMATES	20
REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE	22
Proved and Probable Oil Sands Mining Reserves	22
Oil Sands Mining Operating Statistics	24
Proved Conventional Oil and Gas Reserves	24
Standardized Measure of Discounted Future Net Cash Flows from Estimated Production of Proved Oil and Gas Reserves after Income Taxes	27
Future Commitments to Sell or Deliver Crude Oil and Natural Gas	30

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VOLUNTARY OIL SANDS RESERVES DISCLOSURE	31
Oil Sands Mining and Firebag In-Situ Reserves Reconciliation	31
SUNCOR EMPLOYEES	33
RISK FACTORS	33
SELECTED CONSOLIDATED FINANCIAL INFORMATION	41
Selected Consolidated Financial Information	41
Dividend Policy and Record	41
MANAGEMENT’S DISCUSSION AND ANALYSIS	42
DESCRIPTION OF CAPITAL STRUCTURE	42
General Description of Capital Structure	42
Ratings	42
MARKET FOR OUR SECURITIES	43
Price Range and Trading Volume of Common Shares	43
DIRECTORS AND EXECUTIVE OFFICERS	44
Directors	44
Executive Officers	44
Additional Disclosure for Directors and Executive Officers	45
INTEREST OF MANAGEMENT AND OTHERS IN MATERIAL TRANSACTIONS	46
TRANSFER AGENT AND REGISTRAR	46
INTERESTS OF EXPERTS	46
FEES PAID TO AUDITORS	47
Fees Paid to Auditors	47
Audit Committee Pre-Approval Policies for Non Audit Services	47
Additional Audit Committee Information	47
RELIANCE ON EXEMPTIVE RELIEF	47
LEGAL PROCEEDINGS	48
ADDITIONAL INFORMATION	48

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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.

Bitumen/Heavy Crude Oil

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

Capacity

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

Coal Bed Methane

Natural gas produced from wells drilled into a coal formation.

Conventional Crude Oil

Crude oil produced through wells by standard industry recovery methods.

Conventional Natural Gas

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

Crude Oil

Unrefined liquid hydrocarbons, excluding natural gas liquids.

Developed Reserves

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

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Development Costs

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

Downstream

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

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.

MD&A

Suncor’s Management’s Discussion and Analysis dated February 28, 2007, 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, 2006, which is incorporated by reference herein.

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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 Reserves⁽¹⁾

Probable reserves are those additional reserves that are less certain to be recovered than proved reserves.  It is equally likely⁽²⁾ that the actual remaining quantities recovered will be greater or less than the sum of the estimated proved plus probable reserves.

Proved oil and gas reserves

Proved oil and gas reserves are the estimated quantities of crude oil, natural gas, and natural gas liquids which geological and engineering data demonstrate with reasonable certainty⁽²⁾ to be recoverable in future years from known reservoirs under assumed economic and operating conditions.

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

(1)We are subject to Canadian disclosure rules in connection with the reporting of reserves.  However, we have received exemptive relief from Canadian securities administrators permitting us to report our reserves in accordance with U.S. disclosure practices.  Although U.S. companies do not disclose probable reserves for non-mining properties, we voluntarily disclose probable reserves for our Firebag in-situ leases as we believe this information is useful to investors.  See “RESERVES ESTIMATES” on page 20 for a description of how our voluntary reserves disclosure differs from our U.S. required disclosure.

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

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portions not yet drilled, but which can be reasonably judged as economically productive on the basis of available geological and engineering data.  In the absence of information on fluid contacts, the lowest known structural occurrence of hydrocarbons controls the lower proved limit of the reservoir.

Reserves which can 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 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.

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.

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 or not such acreage contains proved reserves.

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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.

CURRENCY

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

FORWARD-LOOKING STATEMENTS

This Annual Information Form contains certain forward-looking statements that are based on our current expectations, estimates, projections and assumptions that we’ve made in light of our experience.

All statements that address expectations or projections about the future, including statements about our strategy for growth, expected future expenditures, commodity prices, costs, schedules, production

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volumes, operating and financial results and expected impact of future commitments, are forward-looking statements.  Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “estimate”, “plans,” “believes,” “indicates,” “could,” “goal,” “target,” “objective,” “will continue,” “schedule,” “foreseeable,” “proposed,” “potential,” “may,” and similar expressions.  These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to our experience.  Our actual results may differ materially from those expressed or implied by our forward-looking statements and you are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in the general economic, market and business conditions; fluctuations in supply and demand for our products; commodity prices and currency exchange rates; our ability to respond to changing markets, and to receive timely regulatory approvals;  the successful and timely implementation of capital projects including growth projects (for example the continued investment in our Firebag in-situ development project) and regulatory projects (for example, the clean fuels refinery modifications projects in our downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement of conception of the detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of our capital assets; the cumulative impact of other resource development; future environmental laws;  the accuracy of our reserve, resource and future production estimates and our success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies and from companies that provide alternative sources of energy; labour and material shortages; and other facilities uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties; changes in environmental and other regulations (for example, the Government of Alberta’s current review of the 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.  All such references are inactive textual references only.

References herein to our 2006 Consolidated Financial Statements mean Suncor’s audited consolidated financial statements prepared in accordance with Canadian generally accepted accounting principles (“GAAP”), notes thereto and auditor’s report thereon, as at and for the three years in the period ended December 31, 2006.

NON GAAP FINANCIAL MEASURES

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

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CORPORATE STRUCTURE

Name and Incorporation

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

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

Intercorporate Relationships

We have 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. (SEMI), 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 businesses.  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 (“SPC”), 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 or partly owned pipelines in Wyoming and Colorado.

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

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GENERAL DEVELOPMENT OF THE BUSINESS

Overview

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

We have four principal operating businesses:

Our Oil Sands business, based near Fort McMurray, Alberta, recovers bitumen, primarily through oil sands mining and in-situ development, and upgrades it into refinery feedstock, 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 consumption at our Oil Sands facility and our refineries in Sarnia, Ontario and near Denver, Colorado.  In addition, our indirectly wholly-owned U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., acquires land and explores for coal bed methane in the United States.

Our third business, Energy Marketing and Refining – Canada, headquartered in Toronto, Ontario, refines crude oil at Suncor’s refinery in Sarnia, Ontario, into a broad range of petroleum, petrochemical and biofuel products.  These products are then marketed to industrial, wholesale and commercial customers principally in Ontario and Quebec, and to retail customers in Ontario through Sunoco-branded and joint venture operated retail networks.  We also engage in third party energy marketing and trading activities through this business.

Our fourth business, Refining and Marketing – U.S.A., headquartered in Denver, Colorado, refines crude oil at our refinery in Commerce City, Colorado, near Denver, into a broad range of petroleum products, and markets our refined products to industrial, wholesale and commercial customers principally in Colorado and to retail customers in Colorado through Phillips 66 ® - branded sites.  We also transport crude oil on our wholly or partly owned pipelines in Wyoming and Colorado.

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 activities to pursue the development of low-emission and no-emission energy sources that have a reduced environmental impact outside our hydrocarbon-based businesses.

In 2006, we produced approximately 294,800 boe per day, comprised of 263,000 barrels per day (bpd) of crude oil and natural gas liquids and 191 million cubic feet per day (mmcf/d) of natural gas.  In 2005, the most recent period with published results, we were the fourth largest crude oil and natural gas liquids producer in Canada (approximately 7%⁽³⁾ of Canada’s crude oil production in 2005) and the 18th largest natural gas producer in Canada.⁽⁴⁾

In 2006, our Energy Marketing and Refining business sold approximately 95,000 bpd (2005 – 96,000 bpd) or 15,100 m³ per day (2005 – 15,200 m³ per day) of refined products, mainly in Ontario but also in the United States and Europe.  Our refined product sales in Ontario represented approximately 18% (2005 –

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

(4)  Oilweek – July 2006, Top 100 Oil and Gas Producers

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19%) of Ontario’s total refined product sales in 2006⁽⁵⁾.  In 2006, our Refining & Marketing business sold approximately 90,600 bpd or 14,400 m³ of refined products in Colorado, including approximately 76,100 bpd or 12,100 m³ per day of light oils (gasoline and distillates) (2005 – 86,200 bpd or 13,700 m³ per day, including approximately 69,200 bpd or 11,000 m³ per day of light oils).

Three-Year History

Cost estimates for major projects involve uncertainties and evolve in stages.  For a discussion of this process, an update on the status of our significant capital projects in progress and an explanation of “on time and on budget”, see page 27 of our MD&A, incorporated by reference herein.

Oil Sands (OS)

OS growth – We continue to advance our multi-phased growth strategy to increase production capacity to 500,000 to 550,000 bpd in 2010 to 2012.  Key components of this strategy include the following milestones:

•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.

•We plan to increase production capacity to 350,000 bpd in 2008.  We anticipate capital spending of approximately $2.1 billion for an additional coker unit to expand Upgrader 2.  The project is currently on schedule and on budget.  We currently estimate an additional $1.5 billion in costs to increase bitumen supply.   (The $2.1 billion estimated cost for the coker unit has a range of uncertainty of +/- 10%.  The $1.5 billion estimated cost for increased bitumen supply in connection with reaching our target of 350,000 bpd, has a range of uncertainty of +/- 10%.)

•For expansion beyond 2008, toward our goal of 500,000 to 550,000 bpd in 2010 to 2012, OS filed a regulatory application in March 2005, and received regulatory approval in November 2006, to construct a third upgrader. The company expects to advance project development plans and cost estimates to a level appropriate to seek Board of Directors’ approval in 2007.  Pending Board approval, we plan to begin construction in 2007.

In support of our plans to increase production capacity, we remain focused on increasing bitumen supply from:

i) the development of our Firebag in-situ oil sands reserves. Firebag Stage 1 began producing bitumen in 2004, and Firebag Stage 2 commenced commercial operations during the first quarter of 2006. A capital project expanding Firebag Stages 1 and 2 in conjunction with the addition of a cogeneration facility is on schedule and on budget for completion in 2007.  Also planned for 2007 is the submission for approval to our Board of Directors for Firebag Stage 3;

ii)  continued development of our mining leases, including our North Steepbank Mine extension, and the regulatory, consultation and engineering work supporting potential development of Lease 23; and

iii)  procurement of bitumen from third parties.

Petro-Canada Agreement - Incremental bitumen to feed the expanded OS operation is also expected to be provided under a processing agreement between Suncor and Petro-Canada, expected to take effect in 2008.  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

(5)  Statistics Canada—Modified Monthly Report For Refined Petrochemical Production Development Sales

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crude oil production to Petro-Canada.  Both the processing and sales components of the agreement will be for a minimum 10-year term.

Kyoto Protocol – On December 17, 2002, the Government of Canada announced its ratification of the Kyoto Protocol.  On October 19, 2006, the Government of Canada announced their plan to address clean air that focuses on the regulation of indoor and outdoor air quality and greenhouse gases (GHG). The announced Clean Air Act, followed by the Notice of Intent to Regulate Criteria Air Contaminants (CACs) and GHGs has been referred to a special committee for review and revision. Consultation with key sectors is underway however, the ultimate regulatory outcome is unknown. We plan to continue to actively manage our air emissions and greenhouse gas emissions to improve performance.  We also plan to advance opportunities such as carbon capture, geological sequestration and renewable and alternate forms of energy, such as wind power and biofuels.

Oil Sands Fire – A fire on January 4, 2005, caused significant damage to one of our two upgraders, reducing upgraded crude oil production capacity of 225,000 bpd from base operations to about 122,000 bpd for the first nine months of 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. For additional information on our insurance policies and recoveries refer to note 10(b) to our 2006 consolidated financial statements, and page 26 of our MD&A.

Bitumen Royalty Option Agreement – In September 2005, an agreement was reached with the Alberta Government on the terms and conditions of Suncor’s option to transition to the generic bitumen-based royalty regime in 2009.  During the fourth quarter of 2006, we elected to exercise our option to move our base operations to the bitumen-based royalty effective January 1, 2009.  Under this regime we will pay a royalty based on 25% of bitumen revenues, minus allowable costs. During 2006, the government of Alberta began deliberations to establish a prescribed method of determining the fair market value of heavy oil/bitumen for the purposes of determining bitumen-based royalty. Royalty payments under this new bitumen pricing methodology may change significantly. The methodology is not likely to be finalized until 2008, and as a result, the potential future impacts are not currently known, but may be material. Any retroactive adjustment is not anticipated to be material.  For additional information on our Oil Sands Crown Royalties see page 29 of our MD&A.

Natural Gas (NG)

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.

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.  In November 2004, Natural Gas divested 62.5% of its interest in the Simonette gas plant for proceeds of $19 million.  We retain a 37.5% ownership and continue to operate the gas plant.

Land Acquisition – In December 2004, we acquired assets in eastern British Columbia for $33 million.  These assets consist of developed and undeveloped land.

Settlement – Also in December 2004, we paid $18 million as a final arbitrated settlement relating to the termination of gas marketing contracts related to Enron Corporation’s bankruptcy in December 2001.

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Energy Marketing & Refining - Canada (EM&R)

Desulphurization Projects – In 2002, the Canadian government passed legislation limiting the concentration of sulphur in diesel fuel produced or imported for use in on-road vehicles to a maximum of 15 parts per million (ppm), by June 1, 2006.  The previous maximum was 500 ppm. To meet these requirements, in October 2003, we and Shell Canada Products Inc. (“Shell”) entered into a 20-year agreement under which we built hydrotreating facilities at our Sarnia refinery to process high-sulphur diesel from both Shell’s and our Sarnia refineries, to produce low sulphur diesel in compliance with the new on-road diesel limits.  Under the agreement Shell pays us a processing fee. Construction of the diesel desulphurization facilities was completed in July 2006, enabling the production of ultra low sulphur diesel sufficient to meet the regulatory requirements.

Regulations reducing sulphur in off-road diesel and light fuel oil are also expected to take effect later in the decade.  We believe that if the regulations are finalized as currently proposed, the new diesel desulphurization facilities for reducing sulphur in on-road diesel should also allow us to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

In combination with the diesel desulphurization project, we are in the process of modifying the refinery’s processing capacity, enabling it to process up to 40,000 bpd of Oil Sands sour crude blends. The project is expected to be completed in 2007.  The original cost estimate for the combined project of $800 million has been revised upward to $960 million.

Ethanol Plant – In July 2006, we completed our 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 available for blending 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.

Refining & Marketing – U.S.A. (R & M)

As part of the agreement to acquire assets from ConocoPhillips Company (“ConocoPhillips”) in August 2003, we assumed obligations of ConocoPhillips at the refinery pursuant to a Consent Decree with the United States Environmental Protection Agency, the United States Department of Justice and the State of Colorado.  These capital obligations were met during a planned maintenance shutdown in 2006.  The total cost was approximately $60 million (approximately US$50 million).  These expenditures reduce air emissions at our refinery, and were primarily capital in nature.  There are other continuing non-capital obligations under the Consent Decree that will continue for several more years.

On May 31, 2005 we acquired a second 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.  We continue efforts to fully integrate the two operations, providing combined refining capacity of approximately 90,000 bpd in the U.S.

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

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Desulphurization Projects – In July 2006, R&M 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 us to produce ultra low sulphur diesel to meet requirements for fuels desulphurization legislation, and enable the refinery to process up to 15,000 bpd of Oil Sands sour crude oil, while also increasing the refinery’s ability to process a broader slate of bitumen based crude oil. The clean fuels legislation required production of lower diesel sulphur levels (15 ppm) by June 2006, and requires lower gasoline sulphur levels (30 ppm average, 80 ppm cap) by 2009.

We are currently assessing plans for additional refinery modifications in 2007 and beyond in order to have the potential to integrate additional volumes of Oil Sands crude oil.

Other

Financing Activities

Our available credit facilities at December 31, 2006 totaled approximately $2.3 billion, of which $1.8 billion was undrawn.  Available credit facilities include a $2.0 billion agreement expiring in 2011, and a $300 million agreement expiring in 2008.  Our current long-term debt ratings are A(low) by Dominion Bond Rating Service, A3 by Moody’s Investors Service and A- by Standard & Poor’s.  All debt ratings have a stable outlook.

In 2004, we repurchased an undivided interest in our Oil Sands energy service assets previously held under a lease financing arrangement with a third party for $101 million.

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

Renewable Energy

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 November 2005, we, along with our joint venture partner Acciona Wind Energy Canada Inc., were selected by the Ontario government to build a 76-megawatt wind power project near Ripley, Ontario.  The Ripley Wind Power project is expected to include 38 wind turbines and offset approximately 66,000 tonnes of carbon dioxide annually.  Commissioning is targeted for late 2007.

Other Transactions

In 2004, we repurchased approximately 2.1 million barrels of crude oil originally sold to a Variable Interest Entity (“VIE”) in 1999 for net consideration of $49 million.  As we economically hedged the repurchase of the inventory the net consideration paid was equal to the original proceeds we received in 1999 when the inventory was sold to the VIE.

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

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In September 2004, we, along with our joint venture partners, Enbridge Income Fund and Acciona Wind Energy Canada Inc., officially opened the 30-megawatt Magrath Wind Power Project (“Magrath”) in southern Alberta.  Magrath’s zero-emissions electricity production is expected to offset the equivalent of approximately 82,000 tonnes of carbon dioxide per year.  The project has benefited from the support of the Federal Government’s Wind Power Production Incentive.

For further information on developments and issues referred to above and other highlights of 2006, and a discussion of other trends known to us that could reasonably be expected to have a material effect on the company, refer to the “Outlook” and other sections of Suncor’s MD&A, and to “Risk Factors” in this Annual Information Form.

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NARRATIVE DESCRIPTION OF THE BUSINESS

OIL SANDS (OS)

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 2006, represent a significant portion of our 2006 capital employed (65%)⁽⁶⁾, cash flow from operations (83%)⁽⁶⁾ and net earnings (89%).  These percentages have been determined excluding the corporate and eliminations segment information.

Operations

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

1)  Bitumen is supplied from a combination of a mining operation using trucks and shovels, an in-situ operation and third party bitumen supply.  Commencing in 2004, the Firebag in-situ operation began producing bitumen which was initially sold into the market as diluted bitumen.  Since late 2005, bitumen from Firebag is being upgraded, with only a small portion of production being strategically sold directly into the market.

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

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

4) Currently, our energy service needs are primarily met through facilities operated by TransAlta that provide steam and electricity to the operations.  In an effort to reduce our future external steam and electricity needs, we are constructing our own cogeneration facility to assist in meeting growth project steam and electricity needs.  It is currently on schedule to be completed in 2007.

The first step of the open pit mining operation is to remove the overburden with trucks and shovels to access the oil sands - a mixture of sand, clay and bitumen.  Oil sands ore is then excavated, and transported to one of five sizing plants by a fleet of trucks.  The ore is dumped into sizers where it is crushed and sent to the ore preparation plants where it is mixed into a hot water slurry and pumped through hydrotransport pipelines to extraction plants on the east and west sides of the Athabasca River.  The bitumen begins to separate from the sand as the slurry is pumped through the lines.  Bitumen is extracted from the oil sands ore with a hot water process.  After the final removal of impurities and minerals, naphtha is added to the bitumen as diluent to facilitate transportation to the upgrading plant.

We continue to explore and develop improved and alternative technologies to facilitate increased efficiency and processing within our mining operation.  Based on the results of testing performed during 2006, we plan to utilize certain mobile mining and extraction equipment and processes in our future mine development plans.

Our in-situ operation uses an extraction technology called Steam Assisted Gravity Drainage (“SAGD”) to extract bitumen from oil sands deposits that are too deep to be mined economically.  The first step of the SAGD process is to drill a pair of horizontal wells with one well located above the other.  Steam produced by our steam generation facilities is injected through the top well into the oil 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.  Naphtha is added to the bitumen to facilitate transportation and the blended bitumen is transported by pipeline to our upgrading facilities.

After the diluted bitumen is transferred to the upgrading plant, the naphtha is removed and recycled to be used again as diluent.  The bitumen is upgraded through a coking and distillation process.  The upgraded product, referred to as sour synthetic crude oil, is either sold directly to customers as sour synthetic crude

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

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oil or is further upgraded into sweet synthetic crude oil by removing the sulphur and nitrogen using a hydrogen treating process.  Three separate streams of refined crude oil are produced: naphtha, kerosene and gas oil.

While there is virtually no finding cost associated with synthetic crude oil, the delineation of the resource and development and expansion of production can entail significant capital outlays.  For the same reason, the costs associated with synthetic crude oil production are largely fixed, 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.  The next major scheduled shutdown is a planned 50 day shutdown in 2007 to enable key tie-ins for capital expansion projects expected to come online in 2008.

Principal Products

Sales of light sweet synthetic crude oil and diesel represented 58% of Oil Sands consolidated operating revenues in 2006, compared to 54% in 2005.  The balance of our revenues were comprised of light sour synthetic crude oil and bitumen sales of 42% (2005 – 46%).  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.

	2006		2005
Product:	(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	138.7	58	88.9	54
Light sour crude oil/bitumen	124.4	42	76.4	46
Total	263.1	100	165.3	100

In 2005, sales volumes and sales mix were adversely impacted by the fire at our Oil Sands operation that occurred January 2005.  We anticipate that approximately 52% of Oil Sands sales in 2007 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. This pipeline, together with our proprietary pipeline, is expected to meet our anticipated crude oil shipping requirements for expected future production levels until 2008.

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

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the transportation of crude oil, on a proposed new pipeline running from Cheecham, Alberta to Edmonton, Alberta.  The expected in-service date of the line is targeted for July 1, 2008, with a 25 year term.  Initial line capacity is expected to be 350,000 bpd with potential expansion of capacity to 600,000 bpd with the construction of additional pumping facilities.  Our initial line commitment is 30,000 bpd.  It is expected that the pipeline will provide an enhanced ability to access new markets on the West coast and offshore.  We, along with other industry shippers, are assessing additional Athabasca-region pipeline options beyond 2008.

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 2009, 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 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.

In 1997, we entered into a long-term agreement with Koch Industries Inc. (“Koch”) to supply Koch with up to 30,000 bpd (approximately 11% of our average 2006 total production (2005 – 18%)) of sour crude from the Oil Sands operation.  We began shipping the crude to Koch at Hardisty, Alberta (from which Koch ships the product to its refinery in Minnesota) under this long-term agreement effective January 1, 1999.  The initial term of the agreement extends to January 1, 2009, with month to month evergreen terms thereafter, subject to termination on twenty-four months notice by either party. Neither party has provided notice of termination at this time.

Under a long term sales agreement with Consumers Co-operative Refineries Limited (“CCRL”) we supply 20,000 bpd of sour crude oil production.  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.

In 2001, we announced an agreement with Petro-Canada to supply up to 30,000 bpd of diluent to dilute

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bitumen produced by Petro-Canada.  Deliveries under the contract are expected to end when the bitumen processing and sour crude oil supply agreement with Petro-Canada, described below, takes effect in 2008. Under the agreement, we will process a minimum of 27,000 bpd of Petro-Canada bitumen on a fee for service basis.  Petro-Canada will retain ownership to the bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, we will sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada.  Both the processing and sales components of the agreement will be for a minimum 10-year term.

There were no customers that represented 10% or more of our consolidated revenues in 2006, 2005, or 2004.

A portion of our Oil Sands production is used in connection with our Sarnia and Commerce city refining operations.  During 2006, the Sarnia refinery processed approximately 8% (2005 - 4%) of Oil Sands crude oil production and the Commerce City refinery processed approximately 3% (2005 – 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 it to markets throughout North America.  The sale of NG’s production provides a natural price hedge for natural gas purchased for consumption at our Oil Sands facility and our refineries in Sarnia, Ontario and near Denver, Colorado.

In addition, our U.S. subsidiary, Suncor Energy (Natural Gas) America Inc., continues to acquire land and explore for coal bed methane in the United States.

In 2006, natural gas and natural gas liquids accounted for approximately 97% of the NG business unit’s production (2005 – 98%).

NG’s exploration program is focused on multiple geological zones in three core asset areas: Northern (northeast British Columbia and northwest Alberta), Foothills (western Alberta and portions of northeast British Columbia) and Central Alberta.  We drill primarily medium to high-risk wells focusing on prospects that are in proximity to existing infrastructure.  Production in 2006 was below expectations due to shut-in production as a result of pipeline and processing facility constraints, as well as delayed production.

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 83% of our natural gas production is sold to SEMI 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

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for transportation arrangements to the point of sale.

Approximately 17% of our natural gas production is sold under existing contracts to aggregators (“system sales”). Proceeds received by producers under these sales arrangements are determined on a netback basis, whereby each producer receives revenue equal to its proportionate share of sales less regulated transportation charges and a marketing fee.  Most of our system sales volumes are contracted to Cargill Gas Marketing Ltd. (formerly TransCanada Gas Services) and Pan-Alberta Gas.  These companies resell this natural gas primarily to eastern Canadian and Midwest and Eastern United States markets.

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

We do not typically enter long-term supply arrangements for our conventional crude oil production.  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 90% (2005 – 91%) of NG’s consolidated operating revenues in 2006, with the remaining 10% (2005 – 9%) comprised of sales of natural gas liquids and crude oil.  Set forth below is information on daily sales volumes and the corresponding percentage of Natural Gas’ consolidated operating revenues by product for the last two years.

	2006		2005
Product:	(thousands of barrels of oil equivalent per day)	(% of NG consolidated revenues)	(thousands of barrels of oil equivalent per day)	(% of NG consolidated revenues)
Natural gas	31.8	90	31.6	91
Natural gas liquids	2.3	7	2.4	7
Crude oil	0.7	3	0.8	2
Total	34.8	100	34.8	100

Competitive Conditions

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

Seasonal Impacts

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

Environmental Compliance

For a 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.

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ENERGY MARKETING & REFINING – CANADA (EM&R)

Our EM&R business unit operates a refining and marketing business in Central Canada, and an energy marketing and trading business.  Our refinery in Sarnia, Ontario, refines petroleum feedstock from Oil Sands and other sources into gasoline, distillates, biofuels 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 sold to third parties.  For information about EM&R’s energy marketing and trading business, refer to “Energy Marketing and Refining – Canada (EM&R)” under the “Three-Year Highlights”, “Energy Marketing & Trading” heading.

As a marketing channel for our refined products, EM&R’s Ontario retail network generated approximately 58% of EM&R’s total 2006 sales volume of 95,000 bpd.  The retail networks are comprised of Sunoco-branded retail service stations, Sunoco-branded Fleet Fuel Cardlock sites, and two 50% retail joint venture⁽⁷⁾ businesses that operate Pioneer-branded retail service stations, UPI-branded retail service stations and UPI bulk distribution facilities for rural and farm fuels.  Approximately 36% of EM&R’s refined product sales in 2006 were wholesale and industrial sales. Sun Petrochemicals Company (SPC), a 50% joint venture between a Suncor subsidiary and a Toledo, Ohio-based refinery, generated the remaining 6% of sales.

Procurement of Feedstocks

The Sarnia refinery uses both synthetic and conventional crude oil.  In 2006, the Sarnia refinery procured approximately 55% (2005 – 16%) of its synthetic crude oil feedstock from our Oil Sands production.  In 2006, 60% (2005 – 62%) 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 Interprovincial 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 produce ethanol for use in our blended gasoline products, and for sales to third parties.

Refining Operations

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

The refinery has the capacity to refine 70,000 bpd of crude oil.  Upgrading units include a 23,300 bpd hydrocracker, and a 5,400 bpd alkylation unit.  The petrochemical facilities have a capacity of 13,100 bpd,

(7)  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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the aromatic solvents unit has a capacity of approximately 1,000 bpd, and our gasoline desulphurization unit has a capacity to process 10,250 bpd.  The distillate hydrotreater that became operational in July 2006 has a processing capacity of 43,600 bpd

The refinery has a cracking capacity of 40,200 bpd from a Houdry catalytic cracker (“catcracker”) and a hydrocracker.  Approximately 40% of the cracking capacity is attributable to the catcracker, which uses older cracking technology. In 2004, a sustainability study to assess the catcracker concluded that, with planned improvements and upgrades, it can continue to be operated economically and safely for up to 10 years.  A range of replacement options for the catcracker was identified during a review in 2005.  Continued analysis of these and other options will occur through 2007, as we work to identify the preferred option for the catcracker.

Overall, crude utilization averaged 78% for the year, compared to 95% in 2005.  The following chart sets out daily crude input, average refinery utilization rates, and cracking capacity utilization of the Sarnia Refinery over the last two years.  The comparatively low utilization rates in 2006 were a result of a major maintenance shutdown during 2006.

Sarnia Refinery Capacity	2006	2005
Average daily crude input (barrels per day)	57,400	66,700
Average crude utilization rate (%)(1)	78	95
Average cracking capacity utilization (%)(2)	82	95

Notes:

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

(2)           Based on cracking capacity and input to the hydrocracker and catcracker.

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

In the normal course of our operations we regularly complete planned maintenance shutdowns of our EM&R refinery facilities.  These shutdowns are scheduled, and provide both preventative maintenance and capital replacement which is expected to improve our operational efficiency.  During 2006, a significant maintenance shutdown was successfully completed.

Principal Products

Sales of gasoline and other transportation fuels represented 58% of EM&R’s consolidated operating revenues in 2006, compared to 68% in 2005.  Set forth below is information on daily sales volumes and percentage of EM&R’s consolidated operating revenues contributed by product group for the last two years.

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	2006		2005
Product:	(thousands of cubic meters per day)	(% of EM&R’s consolidated revenues)	(thousands of cubic meters per day)	(% of EM&R’s consolidated revenues)
Transportation Fuels
Gasoline
Retail	4.6	24	4.5	27
Joint Ventures	3.0	10	2.8	15
Other	0.9	9	1.1	7
Jet Fuel	0.7	2	0.9	4
Diesel	3.3	13	3.3	15
Sub-total – Transportation Fuels	12.5	58	12.6	68
Petrochemicals	0.9	5	0.7	4
Heating Fuels	0.5	2	0.4	3
Heavy Fuel Oils	0.8	1	1.0	2
Other	0.6	2	0.5	2
Total Refined Products	15.3	68	15.2	79
Other Non-Refined Products(1)		3		3
Energy Marketing & Trading		29		18
Total %		100		100

Note:

(1)Includes ancillary revenues

Principal Markets

Approximately 58% (2005 – 57%) of EM&R’s total sales volumes are marketed through retail networks, including the Sunoco-branded retail network, joint venture operated retail stations and cardlock operations.  In 2006, this network was comprised of:

272 (2005 – 275) Sunoco-branded retail service stations

151 (2005 – 149) Pioneer-operated retail service stations

53 (2005 – 50) UPI-operated retail service stations and a network of 14 bulk distribution facilities for rural and farm fuels

36 (2005 – 28) Sunoco branded Fleet Fuel Cardlock sites

UPI Inc. is a joint venture company owned 50% by each of EM&R and GROWMARK Inc., a U.S. Midwest agricultural supply and grain marketing cooperative.  Pioneer is a 50% joint venture partnership between EM&R and The Pioneer Group Inc.

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

Approximately 36% (2005 – 39%) of EM&R’s total sales volumes are sold to industrial, commercial, wholesale and refining customers, primarily in Ontario.  EM&R also supplies industrial and commercial customers in Quebec through long-term arrangements with other regional refiners.

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

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EM&R’s share of total refined product sales in its primary market of Ontario was approximately 18% in 2006 (2005 – 19%).  Transportation fuels accounted for 82% of EM&R’s total sales volumes in 2006 (2005 – 82%); and petrochemicals accounted for 6% (2005 – 4%).  The remaining volumes included other refined products such as heating fuels, heavy oils and liquefied petroleum gases, and were sold to industrial users and resellers.

EM&R supplies refined petroleum products to the Pioneer and UPI joint ventures.  We have a separate supply agreement with each of UPI and Pioneer.  These supply agreements are evergreen, subject to termination only in accordance with the terms of the various agreements between the parties.

Transportation and Distribution

EM&R uses a variety of transportation modes to deliver products to market, including pipeline, water, rail and road.  EM&R owns and operates petroleum transportation, terminal and dock facilities, including storage facilities and bulk distribution plants in Ontario.  The major mode of transporting gasoline, diesel, jet fuel and heating fuels from the Sarnia refinery to core markets in Ontario is the Sun-Canadian Pipe Line, which is 55% owned by us and 45% owned by another refiner.  The pipeline operates as a private facility for its owners, serving terminal facilities in Toronto, Hamilton and London, with a capacity of 130,800 bpd (20,800 cubic metres).  EM&R utilized 50% of this capacity in 2006 (2005 – 54%).  Total utilization of the pipeline was 77% in 2006 (2005 - 84%).

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

We believe our own storage facilities, and those under long-term contractual arrangements with other parties, are sufficient to meet our current and foreseeable storage needs.

Competitive Conditions

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

Environmental Compliance

For a discussion of environmental risks at our EM&R 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 & MARKETING – U.S.A. (R & M)

Our R&M business unit operates a refining and marketing, and pipeline transportation business primarily in Colorado and Wyoming.  The Denver area refining facility, located in Commerce City, Colorado, has a combined crude distillation capacity of 90,000 bpd.  The majority of the refined products from the Denver refinery are distributed in Colorado.

Approximately 18% of R&M’s petroleum products sales in 2006 (2005 – 18%) were sold through a distribution network in Colorado that sells gasoline and diesel fuel to retail customers.  In 2006, approximately 74% (2005 – 70%) of R&M’s petroleum product sales volumes were to industrial, commercial, wholesale and refining customers in Colorado, representing primarily jet fuels, diesel and gasoline.  Asphalt sales comprised the remaining 8% of R&M’s refined product sales volumes for 2006 (2005 – 12%).

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Procurement of Feedstocks

The Denver 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 in the Rocky Mountain region. With the completion of our diesel desulphurization and oil sands integration project in July 2006, the refinery facility commenced processing up to 15,000 bpd of Oil Sands sour crude oil.

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

Refining Operations

Upgrading units at the refining operation include 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 Denver refinery supply R&M’s marketing operations in Colorado.  Refining sales in 2006 averaged approximately 90,600 bpd (14,400 m³ per day) compared to 86,200 bpd (13,700 m³) in 2005.

The Denver area refining operation is a high conversion operation that produces a full range of products, including gasoline, jet fuels, diesel and asphalt.  The refinery’s upgrading units enable it to process a crude slate containing approximately one-third heavy, high sulphur crude.  Overall, crude utilization averaged 92% in 2006 (2005 – 98%).  The following chart sets out daily crude input, average refinery utilization rates and cracking capacity utilization for 2006 and 2005.

Denver Refining Capacity	2006	2005
Average daily crude input (barrels per day)(1)	82,600	76,300
Average crude utilization rate (%)(2)	92	98
Average fluidized catalytic cracker capacity utilization rate (%)(3)	76	89

Notes:

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

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

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

In the normal course of our operations we regularly complete planned maintenance shutdowns of our R&M refinery facilities.  These shutdowns are scheduled, and provide both preventative maintenance and capital replacement which is expected to improve our operational efficiency.  During 2006, a significant maintenance and capital tie-in shutdown was successfully completed.

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Principal Products

Sales of gasoline and other transportation fuels represented 93% of R&M’s consolidated operating revenues in 2006 (2005 – 90%).  Set forth below is information on daily sales volumes and percentage of R&M’s consolidated operating revenues contributed by product group for 2006 and 2005.

	2006		2005
Product:	(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	0.7	11	0.7	11
Other	6.8	48	6.2	46
Jet Fuel	1.0	7	0.8	6
Diesel	3.6	27	3.3	27
Total Transportation Fuels	12.1	93	11.0	90
Asphalt	1.2	4	1.6	4
Other	1.1	2	1.1	4
Total Refined Product Sales	14.4	99	13.7	98
Other Non-Refined Product(1)		1		2
		100		100

Note:

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

Principal Markets

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

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

•Supply agreements with 167 Phillips 66 ® branded marketer outlets throughout the state of Colorado, which account for approximately 13% of R&M’s sales volumes. These agreements are typically for three year terms with provision for automatic three year renewal periods on an evergreen basis.

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

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 total 2006 sales volumes (2005 – 12%).

Approximately 74% of R&M’s total sales volumes are sold to industrial, commercial, wholesale, and refining customers, primarily in Colorado, of which approximately 13% was sold under a long-term supply

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agreement with ConocoPhillips (expiring in 2013) and 24% under a supply agreement with Valero (expiring in 2008).

R&M estimates its sales of total light fuels refined product in 2006 represented a market share, in its primary market of Colorado, of approximately 40% (2005 – 35%).  Within this market, R&M’s Phillips 66 ® - branded sites represent a 15% market share (2005 – 18%).

Transportation and Distribution

Approximately three-quarters of crude oil processed at the Denver refining operation is transported via pipeline, with the remainder supplied via truck.  R&M owns and operates the Rocky Mountain Crude system which runs from Guernsey, Wyoming to Denver, Colorado.  This pipeline is a common carrier pipeline that transports crude for the Denver refinery as well as for other shippers.  We also operate a joint venture crude pipeline, the Centennial pipeline, from Guernsey, Wyoming to Cheyenne, Wyoming.  We own approximately 65% of the Centennial pipeline.  The other 35% is owned by another area refiner.  The Rocky Mountain crude system had a capacity of 38,000 bpd in 2006 for the Guernsey to Cheyenne leg of the pipeline and 73,500 bpd for the Cheyenne to Denver leg of the pipeline.  In 2006, the Rocky Mountain Crude system utilized approximately 81% (2005 – 115%) of its capacity with average throughput of 28,200 bpd (2005 – 35,400 bpd) in the Guernsey to Cheyenne leg of the pipeline, and 62,400 bpd (2005 - 70,150 bpd) in the higher capacity Cheyenne to Denver leg.   During the same period, the Centennial pipeline utilized approximately 85% (2005 – 102%) of capacity, with an average throughput of approximately 54,400 bpd (2005 – 62,500 bpd).

R&M has 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.

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 the heading “Competition” in the “Risk Factors” section of this Annual Information Form.

Environmental Compliance

Due to increasingly stringent regulations regarding water discharges, we need to improve water treatment capability at our Denver refining operation which will require additional water treating equipment for the discharge of process waste water.  It is estimated that this will cost approximately $19 to $23 million (US$16 to $20 million) and be completed in the 2007 to 2010 timeframe.

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.

MATERIAL CONTRACTS

During the year ended December 31, 2006, 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.

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RESERVES ESTIMATES

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

Pursuant to U.S. disclosure requirements, we also disclose gross and net proved and probable mining reserves.  The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80%.  During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves.  The estimate of our net mining reserves reflects the value of Alberta Crown and freehold royalty burdens under constant December 31st bitumen 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 equal the bitumen value used to determine reserve quantities.  However, determination of bitumen value for royalty purposes is currently under review by the Government of Alberta.  For a full discussion of our oil sands Crown royalties, see “Oil Sands Crown Royalties and Cash Income Taxes” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

In addition to required disclosure, our exemption issued by Canadian securities administrators permits us to provide further disclosure voluntarily.  We provide this additional voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and reserves from our Firebag in-situ leases.  In our voluntary disclosure we report our aggregate reserves on the following basis:

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

•Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on constant dollar cost and pricing assumptions.  Bitumen reserves estimated on this basis are subsequently converted, for aggregation purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 80%.

Accordingly, our voluntary disclosures of reserves from our Firebag in-situ leases will differ from our required U.S. disclosure in three 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;

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

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

Under the U.S. disclosure requirements described above, our Firebag in-situ reserves were determined to be entirely uneconomic at December 31, 2004.  In 2005, Constant Cost and Pricing assumptions were again applied to assess economic viability of our in-situ reserves.  This assessment resulted in the rebooking of proved reserves at December 31, 2005.  At December 31, 2006, pricing assumptions were again considered economically viable and our proved reserves disclosures reflect this. (See “REQUIRED U.S. OIL AND GAS AND MINING DISCLOSURE - Proved Conventional Oil and Gas Reserves”).

Under our voluntary disclosure, the year end 2006 bitumen price determined pursuant to SEC pricing methodology was not materially different than the price determined pursuant to CSA Staff Notice 51-315.  Consequently for 2006 only one constant price scenario was used for year end disclosures. Refer to “VOLUNTARY OIL SANDS RESERVES DISCLOSURE - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations”.

Comparisons of reserve estimates under “Required U.S. Oil and Gas Mining Disclosure” and “Voluntary Oil Sands Reserve Disclosure” 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 more significant during 2004 and 2005 with considerably lower constant price assumptions.  At December 31, 2006, there was no difference arising from pricing.

All of our reserves have been evaluated as at December 31, 2006, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (“GLJ”).  In reports dated February 9, 2007 (“GLJ Oil Sands Reports”), GLJ evaluated our proved and probable reserves on our oil sands mining and Firebag in-situ leases pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions.

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 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 9, 2007 (“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, 2006.

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

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Alberta royalty regime.  These assumptions reflect market and regulatory conditions, as required, at December 31, 2006, 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, 2005	1,528		1,440		896		862		2,424		2,302
Revisions of previous estimates	266		140		(262	)	(298	)	4		(158	)
Extensions and discoveries	—		—		—		—		—		—
Production	(85	)	(73	)	—		—		(85	)	(73	)
December 31, 2006	1,709		1,507		634		564		2,343		2,071

Notes:

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80%

(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 31st pricing and incorporates our exercised option to elect to transfer to a bitumen based Crown royalty effective at the beginning of 2009.  Refer to the “Alberta Crown Bitumen-Based Royalty Regime” 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(3)	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	(2)
	7006060390	1,897	May 31, 2011	(2)
	7006060391	3,162	May 31, 2011	(2)
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 term of the lease. Leases can be retained after these dates if:

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

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

(3)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.  Statistics for the Oil Sands Firebag in-situ operations are not included but are addressed under the heading “Proved Conventional Oil and Gas Reserves” and “Sales, Production, Well Data, Land Holdings and Drilling - Conventional”.

	2006		2005		2004
Total mined volume (1)
millions of tonnes	356.2		313.7		371.2
Mined volume to tar sands ratio(1)	41.8	%	32.0	%	41.6	%
Tar sands mined
millions of tonnes	149.0		100.5		154.3
Average bitumen grade (weight %)	12.8	%	12.2	%	11.2	%
Crude bitumen in mined tar sands
millions of tonnes	19.1		12.3		17.3
Average extraction recovery %	93.1	%	92.6	%	91.9	%
Crude bitumen production
millions of cubic meters(2)	17.6		11.4		15.7
Gross synthetic crude oil produced
Thousands of barrels per day(3)	231.9		152.2		215.6

Notes:

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

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

(3)Cubic meters are converted to barrels at the conversion factor of 6.29.  Note, in 2004 production equaled our “base operations” production statistics as included in the operating summaries filed with our annual financial statements.  In 2005 and subsequent years, bitumen production from Firebag is upgraded and included in the base operations production.  Therefore the mining production reported above will no longer agree to the operating statistics.

Proved Conventional Oil and Gas Reserves

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

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NET PROVED RESERVES(1)

Crude Oil,  Natural Gas Liquids and Natural Gas

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, 2003	424		8		432		456
Revisions of previous estimates	(420	)	1		(419	)(5)	—
Purchases of minerals in place	—		—		—		14
Extensions and discoveries	—		—		—		30
Production	(4	)	(1	)	(5	)	(54	)
Sales of minerals in place	—		—		—		—
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
Proved Developed
December 31, 2003	92		6		98		403
December 31, 2004	—		7		7		385
December 31, 2005	137		7		144		387
December 31, 2006	188		6		194		365

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 46.

(3)Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31.  In 2004, due to unusually low year-end posted benchmark oil prices, and unusually high year-end diluent prices, our proved reserves were determined to be uneconomic.  Under 2005 Constant Cost and Pricing we have rebooked our proved reserves, and these continued to be economically viable in 2006.

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

(5)Natural gas infill drilling included in total revisions for 2006 was 11 billion cubic feet (bcf), (2005 – 23 bcf; 2004 – 20 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, 2006. We do not have

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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)

	For the years ended December 31,
($ millions)	2006		2005
Proved properties	3,869		3,268
Unproved properties	224		159
Other support facilities and equipment	22		15
Total cost	4,115		3,442
Accumulated depreciation and depletion	(1,041	)	(852	)
Net capitalized costs	3,074		2,590

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)	2006	2005	2004
Property acquisition costs
Proved properties	—	1	32
Unproved properties	29	9	10
Exploration costs	247	148	78
Development costs	688	552	545
Asset retirement obligations	35	4	27
Total capital and exploration expenditures	999	714	692

Note:

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

Results of Operations for Oil and Gas Production

	For the years ended December 31,
($ millions)	2006		2005		2004
Revenues
Sales to unaffiliated customers	516		670		469
Transfers to other operations	387		52		64
	903		722		533
Expenses
Production costs	291		213		122
Depreciation, depletion and amortization	215		145		130
Exploration	87		66		57
Gain on disposal of assets	(4	)	(12	)	(19	)
Other related costs	40		39		73
	629		451		363
Operating profit before income taxes	274		271		170
Related income taxes	(38	)	(98	)	(48	)
Results of operations	236		173		122

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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:

	2006	2005	2004
Year end natural gas price (AECO- $/GJ)	7.52	10.22	7.17
Year end crude oil price (WTI US$/bbl)	62.09	59.45	43.26
Year end light/heavy crude oil differential, WTI at Cushing less LLB at Hardisty (US$/bbl)	17.99	26.35	22.71

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; and

•Our exercised election to move to the generic bitumen based Crown royalty effective 2009.

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 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”.

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($ millions)	2006		2005		2004
Future cash flows	32,882		16,444		3,355
Future production costs	(12,264	)	(10,181	)	(640	)
Future development costs	(5,648	)	(1,705	)	(64	)
Other related future costs	(612	)	(464	)	(367	)
Future income tax expenses	(4,221	)	(1,216	)	(460	)
Subtotal	10,137		2,878		1,824
*Discount at 10%	(6,768	)	(1,214	)	(750	)
Standardized measure of discounted future net cash flows from estimated production of proved oil and gas reserves after income taxes	3,369		1,664		1,074

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)	2006		2005		2004
Balance, beginning of year	1,664		1,074		1,851
Sales and transfers of oil and gas produced, net of production costs	(559	)	(456	)	(359	)
Net changes in prices and production costs	1,907		737		(1,786	)
Changes in estimated future development costs	(1,141	)	(573	)	14
Extensions, discoveries and improved recovery, less related costs	59		162		131
Development costs incurred during the period	772		557		524
Revisions of previous quantity estimates	1,051		440		(47	)
Purchases of reserves in place	—		—		32
Sale of reserves in place	(2	)	(4	)	—
Accretion of discount	231		125		245
Net changes in income taxes	(714	)	(470	)	426
Other related costs	101		72		43
Balance, end of year	3,369		1,664		1,074

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 Operations”.

Sales Prices(1), (2)

For the year ended December 31,	2006	2005	2004
Crude Oil and Bitumen ($/bbl)	38.94	45.86	37.71
NGL ($/bbl)	44.96	50.70	42.82
Natural Gas ($/mcf)	7.15	8.57	6.70

Notes:

(1)Production is based in Western Canada.

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

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Production Costs

For the year ended December 31,	2006	2005	2004
($ per BOE of gross production)
Average production (lifting) cost of conventional crude oil and gas(1)	11.92	10.86	7.08

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

	Crude Oil(3)		Natural Gas		Total
As at December 31, 2006	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
number of wells
Alberta	70	54	364	220	434	274
British Columbia	24	11	136	59	160	70
Total	94	65	500	279	594	344

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.

Oil and Gas Acreage

	Developed		Undeveloped(1)		Total
As at December 31, 2006	Gross(1)	Net(2)	Gross(1)	Net(2)	Gross(1)	Net(2)
(thousands of acres)
Canada
Natural Gas	714	412	1,207	664	1,921	1,076
Firebag	2	2	287	287	289	289
Total Canada	716	414	1,494	951	2,210	1,365
USA
Natural Gas	—	—	63	28	63	28
Total	716	414	1,557	979	2,273	1,393

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.

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Drilling Activity

	Net Exploratory			Net Development
For the year ended December 31, 2006	Productive	Dry Holes	Total	Productive	Dry Holes	Total
(number of net wells)
Canada
Natural Gas	3	6	9	14	4	18
Firebag	—	—	—	8	—	8
United States	—	—	—	31	—	31
Total	3	6	9	53	4	57

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

	Net Exploratory			Net Development
For the year ended December 31, 2004	Productive	Dry Holes	Total	Productive	Dry Holes	Total
(number of net wells)
Canada
Natural Gas	5	5	10	15	—	15
Firebag	—	—	—	11	—	11
Total	5	5	10	26	—	26

At December 31, 2006, we were participating in the drilling of 42 gross (25 net) exploratory and development wells.

Future Commitments to Sell or Deliver Crude Oil and Natural Gas

We have entered into a number of natural gas sale commitments aggregating approximately 92 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 1, 2007 crude oil hedges totaling 60,000 bpd of production were outstanding for the remainder of 2007 and 10,000 bpd in 2008.  Prices for these barrels are fixed within a range of US$51.64 to US$93.26 per barrel in 2007 and US$59.85 to US$101.06 per barrel in 2008.  We intend to consider additional costless collars of up to approximately 30% of our crude oil production if strategic opportunities are available. For further particulars of these hedging 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 6 to our 2006 Consolidated Financial Statements, which note is incorporated by reference herein.

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VOLUNTARY OIL SANDS RESERVES DISCLOSURE

Oil Sands Mining and Firebag In-Situ Reserves Reconciliation

The following tables set out, on a gross⁽⁸⁾ 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, 2005, to December 31, 2006, based on the GLJ Oil Sands Reports.

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

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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, 2005	1,528		896		2,424		561		2,137		2,698		5,122
Revisions of previous estimates	266		(262	)	4		—		22		22		26
Improved recovery	—		—		—		252		(252	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(85	)	—		(85	)	(10	)	—		(10	)	(95	)
December 31, 2006	1,709		634		2,343		803		1,907		2,710		5,053

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, 2005	1,440		862		2,302		556		2,029		2,585		4,887
Revisions of previous estimates	140		(298	)	(158	)	(50	)	(164	)	(214	)	(372	)
Improved recovery	—		—		—		226		(226	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(73	)	—		(73	)	(10	)	—		(10	)	(83	)
December 31, 2006	1,507		564		2,071		722		1,639		2,361		4,432

Notes:

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80% for reserves under Oil Sands mining and Firebag in-situ leases.  Although virtually all of our bitumen from the Oil Sands mining leases is upgraded into synthetic crude oil, 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 under constant December 31st pricing and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.

(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 three 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.

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SUNCOR EMPLOYEES

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

	as at
	December 31,
	2006	2005
Oil Sands	3,182	2,787
Natural Gas	170	214
Energy Marketing & Refining – Canada	605	638
Marketing & Refining – U.S.A	463	662
Corporate(2)	1,346	851
Total (1)	5,766	5,152

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 four of our business units.

The Communications, Energy and Paperworkers Union Local 707 represent approximately 1,500 Oil Sands employees.  A collective agreement with the union was entered effective May 1, 2004. The terms of the agreement include a 9.5% wage increase over a three-year term.

Employee associations represent approximately 170 of EM&R’s Sarnia refinery 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.  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 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.

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 stakeholders.  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.  Identified risks are outlined 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 four principal operating businesses, Oil Sands, NG, EM&R, 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,

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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. For information on the 2005 Oil Sands fire, refer to page 4 of this AIF.  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 cost associated with oil sands resources, delineation of the resources, the costs associated with production, including mine development and drilling of 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 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 units, EM&R and R&M, are subject to all of the risks normally inherent with 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, each of the Firebag stages, the Voyageur growth strategy, and the oil sands integration capital project in EM&R.  These risks include: our ability to obtain the necessary environmental and other regulatory approvals; risks relating to schedule, resources and costs, including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; the impact of weather conditions; our ability to finance growth if commodity prices were to decline and stay at low levels for an extended period; 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.  Our 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 this process, an update on the status of our significant capital projects in progress and an explanation of “on time and on budget”, see page 27 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, a self-insurance entity was formed to provide additional business interruption coverage for potential

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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 10(b) to our 2006 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 have filed a statement of claim to recover settlement costs.  Due to the terms of 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 Natural Gas (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, 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.  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 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 Petroleum Exporting Countries and weather, among other things, can affect world oil supply and demand.  Natural gas prices realized by us 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 production for specified periods of time.  As at March 1, 2007, crude oil hedges totaling 60,000 bpd of crude oil production in 2007, and 10,000 bpd of production in

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2008.  Prices for these barrels are fixed within a range from an average of US$51.64/bbl up to an average of US$101.06/bbl.  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.  EM&R and R&M operations are sensitive to wholesale and retail margins for their refined products, including gasoline, and in the case of R&M, 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 EM&R and 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 2006 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, 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

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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;

•storage, treatment, and disposal of hazardous or industrial waste;

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

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

•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 and 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 will result in the imposition of fines and penalties, liability for clean up costs and damages and the loss of important permits.

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, 2005 ($14 million as at December 31, 2005) as security for the estimated cost of our reclamation activity.  Since there has been no production from Leases 86/17 in 2006, the amount of security remains unchanged.

For the Millennium and Steepbank mines, we have posted irrevocable letters of credit equal to approximately $163 million, representing security for the maximum reclamation liability in the period March 31, 2006 through March 31, 2007.  For more information about our reclamation and environmental remediation obligations, refer to “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta, and is currently planned for implementation on June 30, 2007. The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement of reserve life. As currently proposed, initial security deposits for oil sands mining would be reduced. 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 EM&R and R&M operations, see the information under the EM&R and R&M sections 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.

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The R&M business 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 “Narrative Description of the Business” in this AIF.  The Company is subject to the risk that failure to meet its 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.

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 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.  Certain First Nations peoples have filed a claim against the Government of Canada, certain governmental entities and the Regional Municipality of Wood Buffalo (which includes the city of Fort McMurray, Alberta), claiming, among other things, a declaration that the plaintiffs have aboriginal title to large areas of lands surrounding Fort McMurray, including the lands on which Oil Sands and most of the other oil sands operations in Alberta are situated. 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 claims would have on our Oil Sands or other operations. Other than these claims, to our knowledge the First Nations peoples have asserted no other land claims against us.

Alberta Crown Bitumen-Based Royalty Regime.  During the fourth quarter of 2006, we elected to exercise our option to move our base operations to the bitumen based royalty effective January 1, 2009.  Also in 2006, the government of Alberta began deliberations to establish a prescribed method of determining the fair market value of heavy oil/bitumen for the purposes of determining bitumen-based royalty. This new bitumen pricing methodology may significantly change the nature, extent and timing of our royalty obligations, and as a result impact cash flows, earnings and net reserve estimates. The methodology is not likely to be finalized until 2008, and as a result, the potential future impacts are not currently known but may be material.

In early 2007, the Alberta Government also announced a review of its Crown royalty regime.  The outcome of this review is uncertain and future royalties payable, as well as the determination of net reserves may be affected.

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 Firebag and 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 2006, the Oil Sands business accounted for approximately 88% (83% in 2005) of our upstream production, 89% (76% in 2005) of our net earnings and 83% (70% in 2005) 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 2006, our average natural gas reservoir decline rate was approximately 24% (2005 – 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 operations⁽⁹⁾ is insufficient 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 producers 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 2010⁽¹⁰⁾. 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 availability 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

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

(10)    Alberta Government – Talk About Oil Sands

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will continue.  In addition, to the extent that our downstream business units, EM&R and R&M, participate in new product markets, they 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/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 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 Natural Gas 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.

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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, 2006, is derived from our 2006 Consolidated Financial Statements.  Our consolidated financial statements for each of the years in the three-year period ended December 31, 2006, have been audited by PricewaterhouseCoopers LLP, Chartered Accountants.  The information set forth below should be read in conjunction with our MD&A and our 2006 Consolidated Financial Statements.

	Year ended December 31,
($ millions except per share amounts)	2006	2005	2004
Revenues	15,829	11,129	8,705
Net earnings	2,971	1,158	1,076
Per common share (undiluted)	6.47	2.54	2.38
Per common share (diluted)	6.32	2.48	2.33
Cash flow from operations	4,533	2,476	2,013
Capital and exploration expenditures	3,613	3,153	1,847

	Year ended December 31,
($ millions)	2006	2005	2004
Total assets	18,781	15,149	11,774
Long-term debt	2,385	3,007	2,217
Accrued liabilities and other(1)	1,214	1,005	749
Shareholders’ equity	8,952	5,996	4,874

Note:

(1)See Note 7 to our 2006 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)	2006		%	2005		%
Transportation fuel sales	7,016		44	5,502		49
Crude oil sales	6,781		43	3,203		29
Other (2)	2,019		13	2,422		22
Total	15,816	(1)	100	11,127	(1)	100

Note:

(1)Excludes interest income.

(2)Includes net insurance proceeds of $436 million (2005 - $572 million)

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 $0.08 per share from $0.06 per share in the second quarter of 2006, and an increase to $0.06 per share from $0.05 per share during the second quarter of 2004.

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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,
	2006		2005		2004
Common Shares cash dividends	$	0.30	$	0.24	$	0.23
Dividends paid in common shares	—		—		—

MANAGEMENT’S DISCUSSION AND ANALYSIS

Our MD&A, dated February 28, 2007, is incorporated by reference herein and forms an integral part of this AIF, and should be read in conjunction with our 2006 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, 2006, a total of 459,943,827 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

At December 31, 2006, our current long-term senior debt ratings are A(low) by Dominion Bond Rating Service,  A3 by Moody’s Investor Service and A- by Standard & Poor’s and our current commercial paper debt rating is R-1(low) by Dominion Bond Rating Service.  All debt ratings have a stable outlook.

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.

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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 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	Price Range ($Cdn)		Trading Volume
2006	High	Low	(000’s)
January	91.70	73.58	39,965
February	93.85	80.06	36,389
March	91.66	80.68	31,443
April	102.18	90.53	26,010
May	99.13	83.40	33,894
June	92.40	75.00	41,722
July	94.85	86.33	26,464
August	97.12	85.55	28,816
September	87.75	71.18	51,069
October	89.75	72.26	47,728
November	92.38	83.25	29,849
December	95.00	88.24	22,127

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New York Stock Exchange	Price Range ($US)		Trading Volume
2006	High	Low	(000’s)
January	80.41	64.00	38,549
February	82.15	69.20	37,791
March	78.83	69.70	33,070
April	89.96	77.75	28,726
May	89.53	72.21	40,808
June	83.83	67.36	46,959
July	85.37	75.89	30,052
August	86.78	77.21	26,670
September	78.89	63.77	43,991
October	79.59	64.06	44,606
November	81.80	73.44	29,420
December	82.08	76.39	20,650

DIRECTORS AND EXECUTIVE OFFICERS

Directors

Reference is made to the information under the heading, “Election of Directors” on pages 5-8 inclusive of Suncor’s Management Proxy Circular dated March 1, 2007 for information regarding our directors, which information is incorporated by reference into this AIF.

Executive Officers

The following individuals are the executive officers of Suncor.  Except where otherwise indicated, these individuals held the offices set out opposite their respective names as at December 31, 2006, and as of the date hereof.

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Name and Municipality of Residence	Office(1)
J. KENNETH ALLEY Calgary, Alberta	Senior Vice President and Chief Financial Officer
MIKE M. ASHA Denver, Colorado	Executive Vice President, Refining and Marketing – U.S.A.
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, Energy, Marketing and Refining – Canada
JAY THORNTONCalgary, Alberta	Senior Vice President, Business Integration
STEVEN W. WILLIAMS Fort McMurray, Alberta	Executive Vice President, Oil Sands

Note:

(1)Offices shown are positions held by the officers in relation to business units of Suncor Energy Inc. and its subsidiaries on a consolidated basis.  On a legal entity basis, Mr. Ashar is President of Suncor Energy (U.S.A.) Inc., Suncor’s U.S. based downstream subsidiary, Mr. Ryley is the President of Suncor’s Canadian based downstream subsidiaries, Suncor Energy Marketing Inc. and Suncor Energy Products Inc., respectively, and Mr. Nabholz, Ms. Lee and Mr. Thornton are Executive Vice-Presidents of Suncor Energy Services Inc., in respect of major projects, human resources and communications, and business services, respectively, which are shared services provided to the Suncor group of companies.

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, except Mr. Williams, who joined the Company in May 2002.  Prior to joining Suncor, Mr. Williams held various executive positions with Octel Corporation, a global chemicals company.  Prior to joining Octel Corporation in 1995, Mr. Williams held executive positions with Esso Petroleum Company Limited, an affiliate of Exxon Mobile Corporation.

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:

(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

45

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.

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.

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FEES PAID TO AUDITORS

Fees Paid to Auditors

Reference is made to the information under the heading, “Appointment of Auditors” on page 9 of Suncor’s Management Proxy Circular dated March 1, 2007, for information regarding fees paid by Suncor to its auditors for the last two completed fiscal years, which information is incorporated by reference into this AIF.

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.

Additional Audit Committee Information

Additional information about the members of the Audit Committee and their financial literacy is contained on pages 32 and 47-48 inclusive of our management proxy circular dated March 1, 2007, and incorporated by reference herein.  The Audit Committee Charter is attached as Schedule “B” to this AIF.

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, 2006, using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2006, 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, 2006;  and

•gross and net proved and probable working interest oil and gas reserve quantities relating to Firebag in-situ leases, estimated as at December 31, 2006, 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.

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

•proved working interest oil and gas reserve quantities relating to oil and gas operations using constant prices and costs and related net present value of future net revenue, discounted at 10%;  and

•proved and probable working interest oil and gas reserve quantities relating to oil and gas operations using forecast prices and costs and related net present value of future net revenue, discounted at 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 2006 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.  All such references are inactive textual references only.

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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

1

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.)

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

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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.

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,

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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 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

2

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 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, 2006 using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2006, 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, 2006;  and

(c)           proved and probable working interest oil and gas reserve quantities relating to Firebag in-situ leases, estimated as at December 31, 2006 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

Director

“JR SHAW”

JR SHAW

Chairman of the Board of Directors

March 8, 2007

2

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, 2006. 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, 2006 using constant dollar cost and pricing assumptions as of a point in time, namely December 31, 2006, 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, 2006; and proved and probable working interest oil reserves quantities relating to Firebag in-situ leases, estimated as at December 31, 2006 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.

1

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, 2006:

		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 9, 2007	Canada	$4,861 million (99%)	$54 million (1%)	$4,915 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, 2006 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

February 9, 2007

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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 41 of Exhibit 99-2.

AUDIT COMMITTEE FINANCIAL EXPERT

                See pages 47 and 48 of Appendix B of Exhibit 99-3.

CODE OF ETHICS

                See page 38 of Exhibit 99-3 and page 48 of our Annual Information Form.

FEES PAID TO PRINCIPAL ACCOUNTANT

                See page 9 of Exhibit 99-3.

AUDIT COMMITTEE PRE-APPROVAL POLICIES

                See Schedule “A” of Annual Information Form.

APPROVAL OF NON-AUDIT SERVICES

See page 9 of Exhibit 99-3.

OFF-BALANCE SHEET ARRANGEMENTS

See page 26 of Exhibit 99-2.

TABULAR DISCLOSURE OF CONTRACTUAL OBLIGATIONS

                See page 26 of Exhibit 99-2.

IDENTIFICATION OF THE AUDIT COMMITTEE

                See page 32 of Exhibit 99-3.

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 8, 2007	PER:	“Richard L. George”
			RICHARD L. GEORGE
			President and Chief Executive
			Officer

EXHIBIT INDEX

Exhibit No.	Description
99-1	Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2006, including reconciliation to U.S. GAAP (Note 18)
99-2	Management’s Discussion and Analysis for the fiscal year ended December 31, 2006, dated February 28, 2007
99-3	Excerpts from pages 9, 32, 38, 47 and 48 inclusive of Suncor Energy Inc.’s Management Proxy Circular dated March 1, 2007
99-4	Consent of PricewaterhouseCoopers LLP
99-5	Consent of GLJ Petroleum Consultants Ltd.
99-6	Certificate of President and Chief Executive Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
99-7	Certificate of Senior Vice President and Chief Financial Officer Pursuant to Exchange Act Rules 13a-14(a) or 15d-14(a)
99-8	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
99-9	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

EX-99.1

Exhibit 99.1

Suncor Energy Inc.	061
2006 Annual Report

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 65 to 103 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 65 to 69. 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.

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 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	Senior Vice President and
Chief Executive Officer	Chief Financial Officer
February 28, 2007

062	Suncor Energy Inc.
	2006 Annual Report

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 the Company’s internal control over financial reporting as of December 31, 2006, 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, 2006.

4.Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report, which appears herein.

Richard L. George	J. Kenneth Alley
President and	Senior Vice President and
Chief Executive Officer	Chief Financial Officer
February 28, 2007

Suncor Energy Inc.	063
2006 Annual 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. as of December 31, 2006 and December 31, 2004 and an audit of its December 31, 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, 2006 and December 31, 2005 and the related consolidated statements of income, cash flows and changes in shareholders’ equity for each of the three years in the period ended December 31, 2006. 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, 2006 and December 31, 2004 and for 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 as at December 31, 2005 and 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.

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, 2006 and December 31, 2005 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in accordance with Canadian generally accepted accounting principles.

Internal Control Over Financial Reporting

We have also audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December31,2006, 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. Our responsibility is to express opinions on management’s assessment and 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

064	Suncor Energy Inc.
	2006 Annual Report

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the COSO. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

February 28, 2007

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 28, 2007 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

February 28, 2007

Suncor Energy Inc.	065
2006 Annual Report

Summary of significant accounting policies

Suncor Energy Inc. is a Canadian integrated energy company comprised of four operating segments: Oil Sands, Natural Gas, Energy Marketing and Refining – Canada, and Refining and Marketing – U.S.A.

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.

Energy Marketing and Refining – Canada includes the manufacture, transportation and marketing of petroleum, petrochemical and biofuel products, primarily in Ontario and Quebec.

Refining and Marketing – U.S.A. includes the manufacture, transportation and marketing of petroleum and petrochemical products, 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 18.

The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company’s proportionate share of the assets, liabilities, 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 (Energy Marketing and Refining – Canada and Refining and Marketing – U.S.A.) 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 a portion of 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.

066	Suncor Energy Inc.
	2006 Annual Report

(d) Property, Plant and Equipment and Intangible Assets

Cost

Property, plant and equipment and intangible assets 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.

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.

Suncor Energy Inc.	067
2006 Annual Report

DOWNSTREAM OPERATIONS (INCLUDING ENERGY MARKETING AND REFINING – CANADA AND REFINING AND MARKETING – U.S.A.) 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. Intangible assets with determinable useful lives are amortized over a maximum period of four years. The amortization of intangible assets is included within depreciation expense in the Consolidated Statements of Earnings.

Asset Retirement Obligations

A liability is recognized for future retirement obligations associated with the company’ 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.

A significant portion of the company’s assets have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets is reviewed regularly, and will be recorded in the first period in which the lives of the assets become determinable.

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

Deferred charges and other are primarily comprised of deferred maintenance shutdown costs and deferred financing costs.

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 seven years. Normal maintenance and repair costs are charged to expense as incurred.

Financing costs related to the issuance of long-term debt are amortized over the term of the related debt.

(f) Employee Future Benefits

The company’s employee future benefit programs consist of 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 ratably 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.

068	Suncor Energy Inc.
	2006 Annual Report

(h) Derivative Financial Instruments

The company periodically enters into derivative financial instrument 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 financial instrument 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.

These derivative contracts are initiated within the guidelines of the company’s risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions.

Derivative contracts accounted for as hedges are not recognized in the Consolidated Balance Sheets. Gains or losses on these contracts, including realized gains and losses on hedging derivative contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.

Canadian Accounting Guideline 13 (AcG 13) “Hedging Relationships” is applicable to the company’s hedging relationships. AcG 13 specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, as well as the discontinuance of hedge accounting. The Guideline does not specify hedge accounting methods. The company believes that its hedging documentation and tests of effectiveness are prepared in accordance with the provisions of AcG 13.

The company also uses energy derivatives, including physical and financial swaps, forwards and options to earn trading revenues. These energy marketing and trading activities are accounted for at fair value.

Effective January 1, 2007, accounting for financial instruments will change significantly as outlined in Section (l) “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. 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.

The company’s Refining and Marketing – U.S.A. operations, and 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 cumulative foreign currency translation in the Consolidated Statements of Changes in Shareholders’ Equity.

(j) Stock-based Compensation Plans

Under the company’s common share option programs (see note 11), common share options are granted to executives, employees and non-employee directors.

Compensation expense is recorded in the Consolidated Statements of Earnings 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 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.

Suncor Energy Inc.	069
2006 Annual Report

For common share options granted prior to January 1, 2003 (“pre-2003 options”), compensation expense is not recognized in the Consolidated Statements of Earnings. 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 over the estimated vesting periods of the respective award.

See also Section (l) “Recently Issued Canadian Accounting Standards.”

(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.

(l) Recently Issued Canadian Accounting Standards

Financial Instruments/Other Comprehensive Income/Hedges

In 2005, the Canadian Institute of Chartered Accountants (CICA) approved Handbook section 3855 “Financial Instruments – Recognition and Measurement,” section 1530 “Comprehensive Income” and section 3865 “Hedges.” Effective January 1, 2007, these standards require the presentation of financial instruments at fair value on the balance sheet. These standards must be applied prospectively with an initial recognition adjustment to retained earnings and accumulated other comprehensive income.

For specific transactions identified as hedges, changes in fair value are recognized in net earnings or other comprehensive income based on the type and effectiveness of the individual instruments. Upon adoption the company’s presentation will be more aligned with the current U.S. GAAP reporting as outlined in note 18 to the consolidated financial statements.

Other comprehensive income will represent the foreign currency translation of self-sustaining subsidiaries, the fair value gains/losses of specific financial investments (available for sale) and the effective portion of gains/losses of cash flow hedges. Presentation of other comprehensive income will require a change in the presentation of the Consolidated Statements of Earnings, and result in a new Statement of Comprehensive Income.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments will be recorded to the balance sheet:

•  Financial Assets – $26 million

•  Financial Liabilities – $13 million

•  Retained Earnings – $5 million

•  Cumulative Foreign Currency Translation – $71 million

•  Accumulated Other Comprehensive Loss – $63 million

No restatement of comparative balances is permitted.

The CICA has approved additional financial instrument and capital disclosure requirements. These new requirements will become effective on January 1, 2008.

Accounting Changes

In 2006, the CICA approved revisions to Handbook section 1506 “Accounting Changes.” Effective January 1, 2007, accounting policy changes are permitted only in the event a change is made within a primary source of GAAP, or where a change is warranted to provide more relevant and reliable information. All accounting policy changes are to be applied retrospectively, unless impracticable. Any prior period errors identified also require retrospective application. The revised standards will not impact net earnings or financial position.

Stock-based Compensation

On July 6, 2006, the Emerging Issues Committee (EIC) of the CICA approved an abstract (EIC 162) addressing the recognition of stock-based compensation expenses for employees eligible to retire prior to the vesting date of any award(s) issued. The abstract requires that the compensation expense be recognized over the term until the employee is eligible to retire, when earlier than the award vesting date. If the employee is eligible to retire at the time of grant, the award is to be expensed immediately. The abstract was applied retrospectively, effective December 31, 2006. No material adjustment was required in applying this standard.

070	Suncor Energy Inc.
	2006 Annual Report

Consolidated statements of earnings

For the years ended December 31 ($ millions)	2006		2005		2004
Revenues
Operating revenues (notes 6, 16 and 17)	13 798		9 728		8 270
Energy marketing and trading activities (note 6c)	1 582		827		432
Net insurance proceeds	436		572		—
Interest	13		2		3
	15 829		11 129		8 705
Expenses
Purchases of crude oil and products	4 723		4 184		2 867
Operating, selling and general	2 998		2 417		1 991
Energy marketing and trading activities (note 6c)	1 541		789		413
Transportation and other costs	212		152		132
Depreciation, depletion and amortization (note 1)	695		568		514
Accretion of asset retirement obligations	34		30		26
Exploration (note 17)	104		56		55
Royalties (note 4)	1 038		555		531
Taxes other than income taxes (note 17)	595		529		540
Gain on disposal of assets	(1	)	(13	)	(16	)
Project start-up costs	45		25		26
Financing expenses (income) (note 14)	39		(15	)	24
	12 023		9 277		7 103
Earnings Before Income Taxes	3 806		1 852		1 602
Provision for income taxes (note 9)
Current	20		39		69
Future	815		655		457
	835		694		526
Net Earnings	2 971		1 158		1 076
Per Common Share (dollars) (note 12)
Net earnings attributable to common shareholders
Basic	6.47		2.54		2.38
Diluted	6.32		2.48		2.33
Cash dividends	0.30		0.24		0.23

See accompanying Summary of Significant Accounting Policies and Notes.

Suncor Energy Inc.	071
2006 Annual Report

Consolidated balance sheets

As at December 31 ($ millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	521		165
Accounts receivable (notes 10 and 17)	1 050		1 139
Inventories (note 15)	589		523
Income taxes receivable	33		6
Future income taxes (note 9)	109		83
Total current assets	2 302		1 916
Property, plant and equipment, net (note 2)	16 189		12 966
Deferred charges and other (note 3)	290		267
Total assets	18 781		15 149
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	7		49
Accounts payable and accrued liabilities (notes 7 and 8)	2 111		1 830
Taxes other than income taxes	40		56
Total current liabilities	2 158		1 935
Long-term debt (note 5)	2 385		3 007
Accrued liabilities and other (notes 7 and 8)	1 214		1 005
Future income taxes (note 9)	4 072		3 206
Total liabilities	9 829		9 153
Commitments and contingencies (note 10)
Shareholders’ equity
Share capital (note 11)	794		732
Contributed surplus (note 11)	100		50
Cumulative foreign currency translation	(71	)	(81	)
Retained earnings	8 129		5 295
Total shareholders’ equity	8 952		5 996
Total liabilities and shareholders’ equity	18 781		15 149

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board of Directors:

Richard L. George	John T. Ferguson
Director	Director

February 28, 2007

072	Suncor Energy Inc.
	2006 Annual Report

Consolidated statements of cash flows

For the years ended December 31 ($ millions)	2006		2005		2004
Operating Activities
Cash flow from operations (a)	4 533		2 476		2 013
Decrease (increase) in operating working capital
Accounts receivable	53		(477	)	(121	)
Inventories	(66	)	(63	)	(51	)
Accounts payable and accrued liabilities	87		435		201
Taxes payable	(43	)	(23	)	16
Cash flow from operating activities	4 564		2 348		2 058
Cash Used in Investing Activities (a)	(3 489	)	(3 113	)	(1 689	)
Net Cash Surplus (Deficiency) Before Financing Activities	1 075		(765	)	369
Financing Activities
Increase (decrease) in short-term debt	(42	)	19		(1	)
Net increase (decrease) in other long-term debt	(622	)	808		(635	)
Issuance of common shares under stock option plans	45		69		41
Dividends paid on common shares	(127	)	(102	)	(97	)
Deferred revenue	27		50		26
Cash flow provided by (used in) financing activities	(719	)	844		(666	)
Increase (Decrease) in Cash and Cash Equivalents	356		79		(297	)
Effect of Foreign Exchange on Cash and Cash Equivalents	—		(2	)	(3	)
Cash and Cash Equivalents at Beginning of Year	165		88		388
Cash and Cash Equivalents at End of Year	521		165		88

(a) See Schedules of Segmented Data on pages 76 and 77.

See accompanying Summary of Significant Accounting Policies and Notes.

Suncor Energy Inc.	073
2006 Annual Report

Consolidated statements of changes in shareholders’ equity

				Cumulative
				Foreign
	Share	Contributed		Currency		Retained
For the years ended December 31 ($ millions)	Capital	Surplus		Translation		Earnings
At December 31, 2003, as previously reported	604	7		(26	)	3 308
Retroactive adjustment for change
in accounting policy, net of tax (note 1)	—	—		—		(35	)
At December 31, 2003, as restated	604	7		(26	)	3 273
Net earnings	—	—		—		1 076
Dividends paid on common shares	—	—		—		(97	)
Issued for cash under stock option plans	41	—		—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	25		—		—
Foreign currency translation adjustment	—	—		(29	)	—
At December 31, 2004, as restated	651	32		(55	)	4 246
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		—		—
Foreign currency translation adjustment	—	—		(26	)	—
At December 31, 2005, as restated	732	50		(81	)	5 295
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		—		—
Foreign currency translation adjustment	—	—		10		—
Income tax benefit of stock option deductions in the U.S.	—	4		—		—
At December 31, 2006	794	100		(71	)	8 129

See accompanying Summary of Significant Accounting Policies and Notes.

074	Suncor Energy Inc.
	2006 Annual Report

Schedules of segmented data ^(a)

														Energy Marketing
		Oil Sands						Natural Gas						and Refining – Canada
For the years ended December 31 ($ millions)		2006		2005		2004		2006		2005		2004		2006		2005		2004
EARNINGS
Revenues (b)
Operating revenues		6 259		2 938		3 215		554		632		499		3 858		3 536		3 060
Energy marketing
and trading activities		—		—		—		—		—		—		1 607		827		440
Net insurance proceeds		436		572		—		—		—		—		—		—		—
Intersegment revenues (c)		712		455		425		23		47		68		—		—		—
Interest		—		—		—		1		—		—		—		—		—
		7 407		3 965		3 640		578		679		567		5 465		4 363		3 500
Expenses
Purchases of crude oil
and products		89		32		75		—		—		—		2 876		2 585		2 115
Operating, selling and general		2 149		1 432		1 179		107		93		100		432		484		418
Energy marketing
and trading activities		—		—		—		—		—		—		1 572		810		421
Transportation and other costs		162		104		88		25		22		21		6		6		3
Depreciation, depletion
and amortization		385		330		299		152		130		115		94		73		69
Accretion of asset
retirement obligations		28		24		21		5		5		4		1		1		1
Exploration		22		10		17		82		46		38		—		—		—
Royalties (note 4)		911		406		407		127		149		124		—		—		—
Taxes other than income taxes		75		51		72		3		3		2		359		338		352
(Gain) loss on disposal of assets		—		—		4		(4	)	(12	)	(19	)	3		(1	)	(2	)
Project start-up costs		38		25		26		—		—		—		2		—		—
Financing expenses (income)		—		—		—		—		—		—		—		—		—
		3 859		2 414		2 188		497		436		385		5 345		4 296		3 377
Earnings (loss) before
income taxes		3 548		1 551		1 452		81		243		182		120		67		123
Income taxes		(724	)	(575	)	(482	)	28		(88	)	(67	)	(34	)	(26	)	(43	)
Net earnings (loss)		2 824		976		970		109		155		115		86		41		80
As at December 31
TOTAL ASSETS	13 692			11 648		9 000		1 503		1 307		967		2 829		1 955		1 321

(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 2006, 2005 or 2004 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.

Suncor Energy Inc.	075
2006 Annual Report

Schedules of segmented data ^(a)  (continued)

	Refining and Marketing
	U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
EARNINGS
Revenues (b)
Operating revenues	3 123		2 619		1 494		4		3		2		13 798		9 728		8 270
Energy marketing
and trading activities	—		—		—		(25	)	—		(8	)	1 582		827		432
Net insurance proceeds	—		—		—		—		—		—		436		572		—
Intersegment revenues (c)	—		—		—		(735	)	(502	)	(493	)	—		—		—
Interest	5		2		1		7		—		2		13		2		3
	3 128		2 621		1 495		(749	)	(499	)	(497	)	15 829		11 129		8 705
Expenses
Purchases of crude oil
and products	2 477		2 048		1 171		(719	)	(481	)	(494	)	4 723		4 184		2 867
Operating, selling and general	170		167		124		140		241		170		2 998		2 417		1 991
Energy marketing
and trading activities	—		—		—		(31	)	(21	)	(8	)	1 541		789		413
Transportation and other costs	19		20		20		—		—		—		212		152		132
Depreciation, depletion
and amortization	38		23		22		26		12		9		695		568		514
Accretion of asset
retirement obligations	—		—		—		—		—		—		34		30		26
Exploration	—		—		—		—		—		—		104		56		55
Royalties (note 4)	—		—		—		—		—		—		1 038		555		531
Taxes other than income taxes	157		137		114		1		—		—		595		529		540
(Gain) loss on disposal of assets	—		—		1		—		—		—		(1	)	(13	)	(16	)
Project start-up costs	5		—		—		—		—		—		45		25		26
Financing expenses (income)	—		—		—		39		(15	)	24		39		(15	)	24
	2 866		2 395		1 452		(544	)	(264	)	(299	)	12 023		9 277		7 103
Earnings (loss) before
income taxes	262		226		43		(205	)	(235	)	(198	)	3 806		1 852		1 602
Income taxes	(94	)	(84	)	(9	)	(11	)	79		75		(835	)	(694	)	(526	)
Net earnings (loss)	168		142		34		(216	)	(156	)	(123	)	2 971		1 158		1 076
As at December 31
TOTAL ASSETS	1 379		1 235		518		(622	)	(996	)	(32	)	18 781		15 149		11 774

076	Suncor Energy Inc.
	2006 Annual Report

Schedules of segmented data ^(a) (continued)

													Energy Marketing
	Oil Sands						Natural Gas						and Refining – Canada
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
CASH FLOW BEFORE
FINANCING ACTIVITIES
Cash from (used in)
operating activities:
Cash flow from (used in) operations
Net earnings (loss)	2 824		976		970		109		155		115		86		41		80
Exploration expenses	—		—		—		52		46		38		—		—		—
Non-cash items included
in earnings
Depreciation, depletion
and amortization	385		330		299		152		130		115		94		73		69
Income taxes	724		575		482		(28	)	88		67		34		26		43
(Gain) loss on disposal of assets	—		—		4		(4	)	(12	)	(19	)	3		(1	)	(2	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		—
Other	(10	)	11		(29	)	—		5		4		—		13		(3	)
Increase (decrease) in deferred
credits and other	(21	)	(14	)	8		—		—		(1	)	—		—		1
Total cash flow from
(used in) operations	3 902		1 878		1 734		281		412		319		217		152		188
Decrease (increase) in operating
working capital	426		(270	)	24		(27	)	(5	)	(1	)	(87	)	(47	)	(11	)
Total cash from (used in)
operating activities	4 328		1 608		1 758		254		407		318		130		105		177
Cash from (used in)
investing activities:
Capital and exploration
expenditures	(2 463	)	(1 948	)	(1 119	)	(458	)	(363	)	(279	)	(487	)	(442	)	(228	)
Acquisition of Denver refineries
and related assets	—		—		—		—		—		—		—		—		—
Property loss insurance proceeds	36		44		—		—		—		—		—		—		—
Deferred maintenance
shutdown expenditures	—		(65	)	(4	)	—		(2	)	(1	)	(29	)	—		(20	)
Deferred outlays and
other investments	(2	)	(1	)	(9	)	—		—		—		1		3		(14	)
Proceeds from disposals	2		41		45		15		21		29		4		3		3
Decrease (increase) in investing
working capital	197		47		48		—		—		—		(1	)	3		61
Total cash (used in) investing activities	(2 230	)	(1 882	)	(1 039	)	(443	)	(344	)	(251	)	(512	)	(433	)	(198	)
Net cash surplus (deficiency)
before financing activities	2 098		(274	)	719		(189	)	63		67		(382	)	(328	)	(21	)

(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.

Suncor Energy Inc.	077
2006 Annual Report

Schedules of segmented data ^(a) (continued)

	Refining and Marketing
	U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
CASH FLOW BEFORE
FINANCING ACTIVITIES
Cash from (used in)
operating activities:
Cash flow from (used in) operations
Net earnings (loss)	168		142		34		(216	)	(156	)	(123	)	2 971		1 158		1 076
Exploration expenses	—		—		—		—		—		—		52		46		38
Non-cash items included
in earnings
Depreciation, depletion
and amortization	38		23		22		26		12		9		695		568		514
Income taxes	94		84		9		(9	)	(118	)	(144	)	815		655		457
(Gain) loss on disposal of assets	—		—		1		—		—		—		(1	)	(13	)	(16	)
Stock-based compensation expense	—		—		—		53		23		25		53		23		25
Other	(16	)	(2	)	(8	)	12		(60	)	(71	)	(14	)	(33	)	(107	)
Increase (decrease) in deferred
credits and other	(3	)	—		1		(14	)	86		17		(38	)	72		26
Total cash flow from
(used in) operations	281		247		59		(148	)	(213	)	(287	)	4 533		2 476		2 013
Decrease (increase) in operating
working capital	(15	)	17		41		(266	)	177		(8	)	31		(128	)	45
Total cash from (used in)
operating activities	266		264		100		(414	)	(36	)	(295	)	4 564		2 348		2 058
Cash from (used in)
investing activities:
Capital and exploration
expenditures	(178	)	(337	)	(190	)	(27	)	(63	)	(31	)	(3 613	)	(3 153	)	(1 847	)
Acquisition of Denver refineries
and related assets	—		(62	)	—		—		—		—		—		(62	)	—
Property loss insurance proceeds	—		—		—		—		—		—		36		44		—
Deferred maintenance
shutdown expenditures	(51	)	(10	)	(7	)	—		—		—		(80	)	(77	)	(32	)
Deferred outlays and
other investments	6		1		(1	)	(2	)	(6	)	1		3		(3	)	(23	)
Proceeds from disposals	—		—		—		—		—		—		21		65		77
Decrease (increase) in investing
working capital	(52	)	23		27		—		—		—		144		73		136
Total cash (used in) investing activities	(275	)	(385	)	(171	)	(29	)	(69	)	(30	)	(3 489	)	(3 113	)	(1 689	)
Net cash surplus (deficiency)
before financing activities	(9	)	(121	)	(71	)	(443	)	(105	)	(325	)	1 075		(765	)	369

078	Suncor Energy Inc.
	2006 Annual Report

Notes to the consolidated financial statements

1. CHANGES IN ACCOUNTING POLICIES

(a) Overburden Removal Costs

On January 1, 2006, the company retroactively adopted EIC 160 “Stripping Costs Incurred in the Production Phase of a Mining Operation.” Under the new standard, overburden removal costs should be deferred and amortized only in instances where the activity benefits future periods, otherwise the costs should be charged to earnings in the period incurred. At Suncor, overburden removal precedes mining of the oil sands deposit within the normal operating cycle, and is related to current production. In accordance with the new standard, overburden removal costs are treated as variable production costs and expensed as incurred. Previously overburden removal was deferred and amortized on a life-of-mine approach. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, (decrease))	2006		2005
Deferred charges and other	(230	)	(202	)
Total assets	(230	)	(202	)
Future income tax liabilities	(77	)	(68	)
Retained earnings	(153	)	(134	)
Total liabilities and shareholders’ equity	(230	)	(202	)

Change in Consolidated Statements of Earnings

($ millions, increase/(decrease))	2006		2005		2004
Operating, selling and general	337		287		222
Depreciation, depletion and amortization	(309	)	(152	)	(206	)
Future income taxes	(9	)	(48	)	(4	)
Net earnings	(19	)	(87	)	(12	)
Per common share – basic (dollars)	(0.04	)	(0.19	)	(0.03	)
Per common share – diluted (dollars)	(0.04	)	(0.19	)	(0.03	)

(b) Non-monetary Transactions

On January 1, 2006, the company prospectively adopted CICA Handbook section 3831 “Non-monetary Transactions.” The standard requires all non-monetary transactions to be measured at fair value (if determinable) unless future cash flows are not expected to change significantly as a result of a transaction or the transaction is an exchange of a product held for sale in the ordinary course of business. The company was required to record the effects of an existing contract at Oil Sands that exchanges off-gas produced as a by-product of the upgrading operations for natural gas. An equal amount of revenues for the sale of the off-gas and purchases of crude oil and products for the purchase of the natural gas are recorded. The amount of the gross up of revenues and purchases of crude oil and products for the year ended December 31, 2006, was $126 million.

Suncor Energy Inc.	079
2006 Annual Report

2. PROPERTY, PLANT AND EQUIPMENT

	2006		2005
		Accumulated		Accumulated
($ millions)	Cost	Provision	Cost	Provision
Oil Sands
Plant	7 514	1 608	6 042	1 388
Mine and mobile equipment	1 191	320	939	280
In-situ properties	1 946	147	1 608	79
Pipeline	149	34	139	30
Capital leases	38	4	30	6
Major projects in progress	2 887	—	2 484	—
Asset retirement cost	663	94	408	81
	14 388	2 207	11 650	1 864
Natural Gas
Proved properties	1 931	867	1 632	769
Unproved properties	186	21	172	23
Other support facilities and equipment	90	23	53	13
Asset retirement cost	44	7	14	6
	2 251	918	1 871	811
Energy Marketing and Refining – Canada
Refinery	1 441	529	899	481
Marketing	626	250	597	244
Major projects in progress	386	—	464	—
Asset retirement cost	13	7	11	7
	2 466	786	1 971	732
Refining and Marketing – U.S.A.
Refinery and intangible assets	826	55	244	24
Marketing	43	5	36	3
Pipeline	35	3	26	2
Major projects in progress	—	—	453	—
	904	63	759	29
Corporate	208	54	180	29
	20 217	4 028	16 431	3 465
Net property, plant and equipment		16 189		12 966

3. DEFERRED CHARGES AND OTHER

($ millions)	2006	2005
Deferred maintenance shutdown costs	143	160
Deferred government tax credits	74	20
Deferred financing costs	22	23
Other	51	64
Total deferred charges and other	290	267

080	Suncor Energy Inc.
	2006 Annual Report

4. ROYALTIES

Alberta Crown royalties 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. Firebag is treated by the Government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes. During 2004 to 2006, Firebag was subject to the minimum payment of 1% of R. However, for the rest of Oil Sands, the 2004 calendar year was a transitional year, as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed before the 25% R-C royalty applied to 2004 results.

In February 2006, we advised the Government of Alberta we would not proceed with a July 2004 claim we filed against the Crown where we were seeking to overturn the government’s decision on the royalty treatment of our Firebag in-situ operations.

During the fourth quarter of 2006, Suncor exercised its option to move our Oil Sands operations to the bitumen based royalty regime effective January 1, 2009.

Royalty expense for the company’s Oil Sands operations for the year ended December 31, 2006, was $911 million (2005 – $406 million; 2004 – $407 million).

5. LONG-TERM DEBT

A. Fixed-term Debt, Redeemable at the Option of the Company

($ millions)	2006	2005
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	583	583
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	583	583
6.70% Series 2 Medium-term Notes, due in 2011 (i)	500	500
6.80% Medium-term Notes, due in 2007 (i)	250	250
6.10% Medium-term Notes, due in 2007 (i)	150	150
	2 066	2 066
Revolving-term debt, with interest at variable rates (see B. Credit Facilities)
Commercial Paper (interest at December 31, 2006 – 4.3%; 2005 – 3.2%) (ii)	280	890
Total unsecured long-term debt	2 346	2 956
Secured long-term debt with interest rates averaging 6.6% (2005 – 5.2%)	1	1
Capital leases (iii), (iv)	38	30
Variable interest entity long-term debt – See note 10	—	20
Total long-term debt	2 385	3 007

(i)  The company entered into various interest rate swap transactions in 2004. 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		Swap	Effective Interest Rate
Description of Swap Transaction	($ millions	)	Maturity	2006	2005
Swap of 6.70% Medium-term Notes to floating rates	200		2011	5.2%	4.0%
Swap of 6.80% Medium-term Notes to floating rates	250		2007	6.0%	4.6%
Swap of 6.10% Medium-term Notes to floating rates	150		2007	5.3%	4.0%

(ii)  The company is authorized to issue commercial paper to a maximum of $1,200 million having a term not to exceed 364 days. Commercial paper is supported by unutilized credit and term loan facilities (see B. Credit Facilities).

(iii)  Obligations under capital leases are as follows:

($ millions)	2006	2005
Equipment leases with interest rates between prime plus 0.5% and 12.4%
and maturity dates ranging from 2008 to 2035	38	30

Suncor Energy Inc.	081
2006 Annual Report

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

	Capital	Other Long-
($ millions)	Leases	term Debt
2007	3	681	(a)
2008	3	—
2009	3	—
2010	4	—
2011	4	500
Later years	72	1 166
Total minimum payments	89	2 347
Less amount representing imputed interest	51
Present value of obligation under capital leases	38
Long-term Debt (per cent)	2006	2005
Variable rate	37	50
Fixed rate	63	50

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

B. Credit Facilities

During 2006, a $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five-year term maturing in June 2011. The credit limit of this facility was also increased by $500 million to $2 billion. In addition, a $200million credit facility agreement was renegotiated and increased by $100 million to $300 million. As well, a $600 million credit facility agreement matured during the second quarter and was not renewed. At December 31, 2006, the company had available credit facilities of $2,330 million, of which $1,813 million was undrawn, as follows:

($ millions)
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2008	300
Facility that is fully revolving for a period of five years and expires in 2011	2 000
Facilities that can be terminated at any time at the option of the lenders	30
Total available credit facilities	2 330
Credit facilities supporting outstanding commercial paper and standby letters of credit	517
Total undrawn credit facilities	1 813

At December 31, 2006, the company had issued $237 million (2005 – $185 million) in letters of credit to various third parties and had outstanding commercial paper of $280 million (2005 – $890 million).

082	Suncor Energy Inc.
	2006 Annual Report

6. 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 change 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.

(a) Balance Sheet Financial Instruments

The company’s financial instruments recognized in the Consolidated Balance Sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, substantially all current liabilities (except for the current portions of asset retirement and pension obligations), and long-term debt.

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

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

		2006			2005
	Carrying		Fair	Carrying		Fair
($ millions)	Amount		Value	Amount		Value
Cash and cash equivalents	521		521	165		165
Accounts receivable	1 050		1 050	1 139		1 139
Current liabilities	1 987		1 987	1 826		1 826
Long-term debt
Fixed-term	2 066		2 208	2 066		2 299
Revolving-term	280		280	890		890
Other	1		1	21		21
Capital leases	38		38	30		30

The fair values of the company’s fixed and revolving-term long-term debt, capital leases, and other long-term debt were determined through comparisons to similar debt instruments.

Suncor Energy Inc.	083
2006 Annual Report

(b) Unrecognized Derivative Financial Instruments

The company is also a party to certain derivative financial instruments that are not recognized in the Consolidated Balance Sheets, as follows:

Revenue, Cost and Margin Hedges

Suncor operates in a global industry where the market price of its petroleum and natural gas products is determined based on floating benchmark indices denominated in U.S. dollars. The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude sales price variability by entering into West Texas Intermediate (WTI) derivative transactions. As at December 31, 2006, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2007 and 2008. As at December 31, 2006, the company had outstanding costless collar agreements covering 60,000 barrels per day (bpd) in 2007 and 10,000 bpd in 2008. Prices for these barrels are fixed within a range of US$51.64 to US$93.26 per barrel in 2007 and US$59.85 to US$101.06 per barrel in 2008. The company has not hedged any portion of the foreign exchange component of these forecasted cash flows.

At December 31, 2006, the company had hedged a portion of its forecasted cash flows related to natural gas production and refinery operations, as well as a portion of its Euro dollar exposure created by the anticipated purchase of equipment payable in Euros in 2007.

The financial instrument contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company’s sales revenues or crude oil purchase costs. For collars, if market rates are not different than, or are within the range of contract prices, the options contracts making up the collar will expire with no exchange of cash. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.

Contracts outstanding at December 31 were as follows:

		Average		Revenue
Revenue Hedges	Quantity	Price		Hedged		Hedge
Strategic Crude Oil	(bpd)	(US$/bbl)	(a)	(Cdn$ millions)	(b)	Period	(c)
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
As at December 31, 2004
Crude oil swaps	36 000	23		364		2005

		Average	Revenue
	Quantity	Price	Hedged	Hedge
Natural Gas	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period	(c)
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
As at December 31, 2004
Natural Gas Swaps	4 000	7	10	2005
Natural Gas Swaps	4 000	7	10	2006
Natural Gas Swaps	4 000	6	9	2007
Costless collars	10 000	8 – 9	7 – 8	2005	(f)

084	Suncor Energy Inc.
	2006 Annual Report

		Average	Margin
	Quantity	Margin	Hedged		Hedge
Margin Hedges	(bpd)	US$/bbl	(Cdn$ millions)	(b)	Period	(c)
Refined product sale and crude purchase swaps
As at December 31, 2006	—	—	—		—
As at December 31, 2005	5 100	11.69	10		2006	(g)
As at December 31, 2004	6 300	7	15		2005	(h)

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

(a)   Average price for crude oil swaps and 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 for convenience purposes.

(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 March 2005, inclusive.

(g)   For the period January to May 2006, inclusive.

(h)   For the period January to September 2005, inclusive.

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

(j)    Settlement for applicable forward was March 2006.

Interest Rate Hedges

The company periodically enters into interest rate swap contracts as part of its risk management strategy to manage its exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense.

The notional amounts of interest rate swap contracts outstanding at December 31, 2006, are detailed in note 5, Long-term Debt.

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 the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:

($ millions)	2006		2005
Revenue hedge swaps and collars	22		(4	)
Margin hedge swaps	—		1
Interest rate and cross-currency interest rate swaps	16		22
Specific cash flow hedges of individual transactions	(4	)	5
Fair value of outstanding hedging derivative financial instruments	34		24

Suncor Energy Inc.	085
2006 Annual Report

(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 trading activities are accounted for using the mark-to-market method and as such, all financial 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. The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss)

($ millions)	2006		2005		2004
Physical energy contracts trading activity	41		15		12
Financial energy contracts trading activity	(3	)	5		11
General and administrative costs	(3	)	(3	)	(4	)
Total	35		17		19

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

($ millions)	2006	2005
Energy trading assets	16	82
Energy trading liabilities	13	70
Net energy trading assets	3	12

Change in Fair Value of Net Assets

($ millions)	2006
Fair value of contracts at December 31, 2005	12
Fair value of contracts realized during 2006	(6	)
Fair value of contracts entered into during the period	2
Changes in values attributable to market price and other market changes	(5	)
Fair value of contracts outstanding at December 31, 2006	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 entering into agreements with counterparties, of which substantially all are 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)	2006	2005
Derivative contracts not accounted for as hedges	16	82
Unrecognized derivative contracts accounted for as a hedge	35	30
Total	51	112

086	Suncor Energy Inc.
	2006 Annual Report

7. ACCRUED LIABILITIES AND OTHER

($ millions)	2006	2005
Asset retirement obligations (a)	704	489
Employee future benefits liability (see note 8)	170	190
Employee and director incentive plans (b)	143	110
Deferred revenue	143	140
Environmental remediation costs (c)	26	33
Other	28	43
Total	1 214	1 005

(a) Asset Retirement Obligations (ARO)

The asset retirement obligation also includes an additional $104 million in current liabilities (2005 – $54 million). 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)	2006		2005
Asset retirement obligations, beginning of year	543		476
Liabilities incurred	286		71
Liabilities settled	(54	)	(34	)
Accretion of asset retirement obligations	33		30
Asset retirement obligations, end of year	808		543

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2006, was approximately $1.7 billion (2005 – $1.2 billion). The liability recognized in 2006 was discounted using the Company’s credit-adjusted risk-free rate of 5.5% (2005 – 5.6%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

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

(b) Employee and Director Incentive Plans

Total employee and director incentive plans also include an additional $32 million in current liabilities (2005 – $4 million).

(c) Environmental Remediation Costs

Total accrued environmental remediation costs also include an additional $17 million in current liabilities (2005 – $14 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

Suncor Energy Inc.	087
2006 Annual Report

8. 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, 2006, was $1,024 million (2005 – $889 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of these obligations. In addition, commencing in 2005, the company began to fund its unregistered supplementary pension plan and supplementary 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 2006, Plan Assets to meet the Benefit Obligation were $616 million (2005 – $479 million).

The excess of the Benefit Obligation over Plan Assets of $408 million (2005 – $410 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, commencing in 2005, 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 disburing agents of the benefits to recipients. Plan assets are managed by an employee 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 in 2004. A valuation of the Canadian plan will be performed in 2007.

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 dependents.

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.

088	Suncor Energy Inc.
	2006 Annual 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)	2006		2005		2006		2005
Change in benefit obligation
Benefit obligation at beginning of year	745		624		144		128
Service costs	44		32		5		5
Interest costs	40		38		8		6
Plan participants’ contributions	4		3		—		—
Acquisition (a)	—		1		—		1
Foreign exchange	(2	)	—		—		—
Actuarial loss	67		75		5		8
Benefits paid	(32	)	(28	)	(4	)	(4	)
Benefit obligation at end of year (b), (e)	866		745		158		144
Change in plan assets (c)
Fair value of plan assets at beginning of year	479		399		—		—
Actual return on plan assets	60		41		—		—
Employer contributions	103		61		—		—
Plan participants’ contributions	4		3		—		—
Benefits paid	(30	)	(25	)	—		—
Fair value of plan assets at end of year (e)	616		479		—		—
Net unfunded obligation	(250	)	(266	)	(158	)	(144	)
Items not yet recognized in earnings:
Unamortized net actuarial loss (d)	177		167		52		53
Unamortized past service costs	—		—		(23	)	(26	)
Accrued benefit liability	(73	)	(99	)	(129	)	(117	)
Current liability	(46	)	(37	)	(3	)	(3	)
Long-term liability	(44	)	(76	)	(126	)	(114	)
Long-term asset	17		14		—		—
Total accrued benefit liability	(73	)	(99	)	(129	)	(117	)

(a)   In 2005, in connection with the acquisition of the Colorado Refining Company, the company assumed pension obligations of $1 million and other post-retirement benefit obligations of $1 million. No pension plan assets were acquired.

(b)   Obligations are based on the following assumptions:

	Pension Benefit Obligations		Other Post-retirement
			Benefits Obligation
(per cent)	2006	2005	2006	2005
Discount rate	5.00	5.00	5.00	5.00
Rate of compensation increase	5.00	4.50	4.75	4.25

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				Rate of
	on Plan Assets		Discount Rate		Compensation Increase
	1%	1%	1%	1%	1%	1%
($ millions)	increase	decrease	increase	decrease	increase	decrease
Increase (decrease) to net periodic benefit cost	(5)	5	(18)	21	9	(8)
Increase (decrease) to benefit obligation	—	—	(136)	161	35	(31)

In order to measure the expected cost of other post-retirement benefits, a 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006 (2005 – 10%; 2004 – 11.5%). It is assumed that this rate will decrease by 0.5% annually, to 5% by 2015, and remain at that level thereafter.

Suncor Energy Inc.	089
2006 Annual Report

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

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

(c)  Pension plan assets are not the company’s assets and therefore are not included in the Consolidated Balance Sheets.

(d)  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 (2005 – 11 years; 2004 – 12 years), and over the expected average future service life to full eligibility age of 10 years for other post-retirement benefits (2005 – 9 years; 2004 – 12 years).

(e)  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)	2006	2005	2006	2005
Partially funded plans	866	745	—	—
Unfunded plans	—	—	158	144
Benefit obligation at end of year	866	745	158	144

Components of Net Periodic Benefit Cost ^(a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2006		2005		2004		2006	2005	2004
Current service costs	44		32		25		5	5	5
Interest costs	40		38		34		8	6	7
Expected return on plan assets (b)	(32	)	(28	)	(25	)	—	—	—
Amortization of net actuarial loss	28		21		19		1	1	1
Net periodic benefit cost recognized (c)	80		63		53		14	12	13

Components of Net Incurred Benefit Cost ^(a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2006		2005		2004		2006	2005	2004
Current service costs	44		32		25		5	5	5
Interest costs	40		38		34		8	6	7
Actual (return) loss on plan assets (b)	(60	)	(41	)	(33	)	—	—	—
Actuarial (gain) loss	67		75		21		5	8	4
Net incurred benefit cost	91		104		47		18	19	16

(a)  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.

(b)  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.

(c)  Pension expense is based on the following assumptions:

	Pension Benefit Expense			Other Post-retirement Benefits Expense
(per cent)	2006	2005	2004	2006	2005	2004
Discount rate	5.00	5.75	6.00	5.00	5.75	6.00
Expected return on plan assets	6.50	6.75	7.00	N/A	N/A	N/A
Rate of compensation increase	4.50	4.50	4.00	4.25	4.25	4.00

090	Suncor Energy Inc.
	2006 Annual 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, 2006 and 2005.and the target allocation for 2007 are as follows:

	Target Allocation %	Plan Assets %
	2007	2006	2005
Asset Category
Equities	60	61	60
Fixed income	40	39	40
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 2007 will be $82 million, including approximately $7 million for the company’s supplemental executive and supplemental retirement plans. Expected benefit payments from all of the plans are as follows:

		Other Post-
	Pension	retirement
	Benefits	Benefits
2007	35	5
2008	38	5
2009	41	6
2010	44	6
2011	47	7
2012 – 2016	287	44
Total	492	73

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and two U.S. 401(k) savings plans, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $11 million in 2006 (2005 – $10 million; 2004 – $8 million).

9. INCOME TAXES

The assets and liabilities shown on Suncor’s balance sheets are caculated 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 next page for more technical details and amounts.

Suncor Energy Inc.	091
2006 Annual Report

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:

	2006				2005				2004
($ millions)	Amount		%		Amount		%		Amount		%
Federal tax rate	1 256		33		648		35		577		36
Provincial abatement	(381	)	(10	)	(186	)	(10	)	(161	)	(10	)
Federal surtax	43		1		21		1		18		1
Provincial tax rates	395		10		213		12		188		12
Statutory tax and rate	1 313		34		696		38		622		39
Adjustment of statutory rate for future rate reductions	(146	)	(4	)	(84	)	(5	)	(84	)	(5	)
	1 167		30		612		33		538		34
Add (deduct) the tax effect of:
Crown royalties	125		3		119		6		133		8
Resource allowance (a)	(42	)	(1	)	(48	)	(2	)	(69	)	(4	)
Large corporations tax	2		—		23		1		18		1
Tax rate changes on opening future income taxes (b)	(419	)	(11	)	—		—		(53	)	(3	)
Attributed Canadian royalty income	(23	)	(1	)	(24	)	(1	)	(29	)	(2	)
Stock-based compensation	18		1		8		—		8		—
Assessments and adjustments	(9	)	—		7		—		—		—
Capital gains	—		—		(6	)	—		(18	)	(1	)
Other	16		—		3		—		(2	)	—
Income taxes and effective rate	835		21		694		37		526		33

(a)	The resource allowance is 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.
(b)	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.
	Effective April 1, 2004, the Alberta provincial corporate tax rate decreased by 1%. In 2003, the Ontario government substantively enacted a general corporate tax rate and manufacturing and processing tax rate increase of 1.5% and 1%, respectively, effective January 1, 2004. Accordingly, in 2004, the company revalued its future income tax liabilities and recognized a decrease in future income tax expense of $53 million.

In 2006, net income tax payments totalled $36 million (2005 – $77 million; 2004 – $50 million).

092	Suncor Energy Inc.
	2006 Annual Report

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

	2006			2005
($ millions)	Current	Non-current		Current		Non-current
Future income tax assets:
Employee future benefits	12	—		7		—
Asset retirement obligations	32	—		19		—
Inventories	59	—		67		—
Other	6	—		(10	)	—
	109	—		83		—
Future income tax liabilities:
Excess of book values of assets over tax values	—	4 413		—		3 490
Deferred maintenance shutdown costs	—	43		—		51
Employee future benefits	—	(88	)	—		(87	)
Asset retirement obligations	—	(203	)	—		(162	)
Attributed Canadian royalty income	—	(93	)	—		(86	)
	—	4 072		—		3 206

10. 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, 2006, future minimum amounts payable under these leases and agreements are as follows:

	Pipeline
	Capacity and		Operating
($ millions)	Energy Services	(1)	Leases
2007	242		37
2008	256		32
2009	261		28
2010	264		24
2011	266		20
Later years	3 796		120
	5 085		261

(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.

Suncor Energy Inc.	093
2006 Annual Report

(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 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$1.4 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. The excess coverage of US$1.0 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, effective January 1, 2006, the excess coverage has a ceiling of US$40 WTI and effective January 1, 2007, the excess coverage has a lost production maximum of 150,000 barrels per day in addition to the US$40 WTI ceiling. In addition to this coverage, in December 2005, Suncor formed a self-insurance company which offers business interruption coverage for oil sands with a limit of $150 million and a deductible of the greater of 20 days or US$30 million.

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) Variable Interest Entities, Guarantees and Off-balance Sheet Arrangements

At December 31, 2006, the company had various off-balance sheet arrangements with Variable Interest Entities (VIEs) and 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 (2005 – $340 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, 2006, $170 million (2005 – $340 million) in outstanding accounts receivable had been sold under the program. 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 $72 million in 2006 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, 2006, were $170 million and approximately $623 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2006 (2005 – $4 million; 2004 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE’s sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term 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, 2006, the VIE did not have any assets or liabilities.

The company has agreed to indemnify holders of the 7.15% notes, the 5.95% notes and the company’s credit facility lenders (see note 5) 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.

094	Suncor Energy Inc.
	2006 Annual Report

11. 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.

(b) Issued:	Common Shares
	Number		Amount
	(thousands	)	($ millions	)
Balance as at December 31, 2003	451 184		604
Issued for cash under stock option plans	2 880		41
Issued under dividend reinvestment plan	177		6
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 options plan	2 147		52
Issued under dividend reinvestment plan	132		10
Balance as at December 31, 2006	459 944		794

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:

(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 538,000 common share options in 2006 (2005 – 518,000; 2004 – 1,346,000) to non-employee directors and certain executives and other senior employees of the company. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted have a 10-year life and vest annually over a three-year period.

(ii) SUNSHARE PERFORMANCE STOCK OPTION PLAN During 2006, the company granted 1,637,000 options (2005 – 1,253,000; 2004 – 1,742,000) 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, 2,062,000 SunShare options vested, representing approximately 25% of the then outstanding unvested options 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. The remaining 50% of the outstanding, unvested SunShare options may vest on April 30, 2008 if the final predetermined performance criterion is met. If the performance criterion is not met, the unvested options that have not previously expired or been cancelled will automatically vest on January 1, 2012. Management believes that it is highly likely the final performance criterion will be met and that all unvested SunShare options at April 30, 2008 will vest. During the fourth quarter of 2006, stock-based compensation expense was adjusted to reflect this assumption.

Suncor Energy Inc.	095
2006 Annual Report

(iii) KEY CONTRIBUTOR STOCK OPTION PLAN In 2004, the Board of Directors approved the establishment of the new Key Contributor stock option plan, under which 5,200,000 options were made available for grant to non-insider senior managers and key employees. Under this plan, the company granted 1,050,000 common share options in 2006 (2005 – 901,000; 2004 – nil) to senior managers and key employees. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted have a 10-year life and vest annually over a three-year period.

(iv) DEFERRED SHARE UNITS (DSUs) The company had 1,170,000 DSUs outstanding at December 31, 2006 (1,190,000 at December 31, 2005). 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 2006, 59,000 DSUs were redeemed for cash consideration of $5 million (2005 – 81,000 redeemed for cash consideration of $5 million; 2004 – no redemption). 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, 2006, the total liability related to the DSUs was $107 million (2005 – $87 million), of which $2 million (2005 – $4 million) was classified as current.

During 2006, total pretax compensation expense related to DSU’s was $25 million (2005 – $39 million; 2004 – $12 million).

(v) PERFORMANCE SHARE UNITS (PSUs) During 2006, the company issued 397,000 PSUs (2005 – 453,000; 2004 – 354,000) 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 2006 was $42 million (2005 – $21 million; 2004 – $5 million).

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

					Weighted-
			Range of		average
	Number		Exercise Prices		Exercise Price
	(thousands	)	Per Share ($	)	Per Share ($	)
Outstanding, December 31, 2003	21 016		4.11 – 29.85		21.69
Granted	3 088		30.63 – 42.02		34.52
Exercised	(2 880	)	4.11 – 40.67		13.94
Cancelled	(537	)	23.93 – 41.38		28.71
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	)	5.28 – 61.92		20.99
Cancelled	(471	)	25.00 – 96.10		46.66
Outstanding, December 31, 2006	19 809		7.77 – 101.79		38.48
Exercisable, December 31, 2006	8 627		7.77 – 94.08		24.06

096	Suncor Energy Inc.
	2006 Annual Report

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)	2006	2005	2004
	7 970	10 724	4 342

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2006:

			Outstanding			Exercisable
			Weighted-	Weighted-				Weighted-
	Number		average Remaining	average Exercise		Number		average Exercise
Exercise Prices ($)	(thousands	)	Contractual Life	Price Per Share ($	)	(thousands	)	Price Per Share ($	)
7.77 – 10.13	577		2	10.01		577		10.01
12.28 – 21.35	2 329		3	15.65		2 329		15.65
23.93 – 30.53	9 604		5	27.16		4 507		26.46
32.24 – 43.65	3 130		7	37.88		1 161		36.86
45.51 – 77.39	1 099		6	57.99		41		53.14
80.00 – 101.79	3 070		7	90.20		12		92.74
Total	19 809		6	38.48		8 627		24.06

(vi) FAIR VALUE OF OPTIONS GRANTED The fair values of all common share options granted are estimated as at the grant date using the Black-Scholes option-pricing model. The weighted-average fair values of the options granted during the year and the weighted-average assumptions used in their determination are as noted below:

	2006	2005	2004
Annual dividend per share	$0.30	$0.24	$0.23
Risk-free interest rate	4.08%	3.69%	3.79%
Expected life	5 years	6 years	6 years
Expected volatility	29%	28%	29%
Weighted-average fair value per option	$29.17	$15.42	$12.02

Stock-based compensation expense recognized for the year ended December 31, 2006, related to stock option plans was $53 million (2005 – $23 million; 2004 – $25 million).

Common share options granted prior to January 1, 2003, are not recognized as compensation expense in the Consolidated Statements of Earnings. 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)	2006	2005	2004
Net earnings attributable to common shareholders – as reported	2 971	1 158	1 076
Less: compensation cost under the fair value method for pre-2003 options	15	13	47
Pro forma net earnings attributable to common shareholders for pre-2003 options	2 956	1 145	1 029
Basic earnings per share
As reported	6.47	2.54	2.38
Pro forma	6.44	2.51	2.27
Diluted earnings per share
As reported	6.32	2.48	2.33
Pro forma	6.29	2.46	2.23

Suncor Energy Inc.	097
2006 Annual Report

12. EARNINGS PER COMMON SHARE

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

($ millions)	2006	2005	2004
Net earnings attributable to common shareholders	2 971	1 158	1 076
(millions of common shares)
Weighted-average number of common shares	459	456	453
Dilutive securities:
Shares issued under stock-based compensation plans	11	10	9
Weighted-average number of diluted common shares	470	466	462
(dollars per common share)
Basic earnings per share (a)	6.47	2.54	2.38
Diluted earnings per share (b)	6.32	2.48	2.33

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.

13. 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 – U.S.A. segment in the Schedules of Segmented Data.

14. FINANCING EXPENSES (INCOME)

($ millions)	2006		2005		2004
Interest on debt	150		151		157
Capitalized interest	(129	)	(119	)	(62	)
Net interest expense	21		32		95
Foreign exchange (gain) on long-term debt	—		(37	)	(82	)
Other foreign exchange (gain) loss	18		(10	)	11
Total financing expenses (income)	39		(15	)	24

Cash interest payments in 2006 totalled $146 million (2005 – $149 million; 2004 – $152 million).

098	Suncor Energy Inc.
	2006 Annual Report

15. INVENTORIES

($ millions)	2006	2005
Crude oil	249	279
Refined products	200	124
Materials, supplies and merchandise	140	120
Total	589	523

The replacement cost of crude oil and refined product inventories exceeded their LIFO carrying value by $243 million (2005 – $202 million) as at December 31, 2006.

During 2006, the company recorded a pretax gain of $6 million related to a permanent reduction in LIFO inventory layers (2005 – $16 million pretax gain).

16. 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)	2006	2005	2004
Operating revenues
Sales to Energy Marketing and Refining – Canada segment joint ventures:
Refined products	294	327	320
Petrochemicals	136	279	272

The company has supply agreements with two Energy Marketing and Refining – Canada segment joint ventures for the sale of refined products. The company also has a supply agreement with an Energy Marketing and Refining – Canada segment joint venture for the sale of petrochemicals.

At December 31, 2006, amounts due from Energy Marketing and Refining – Canada segment joint ventures were $20 million (2005 – $22 million).

Sales to and balances with Energy Marketing and Refining – Canada segment joint ventures are established and agreed to by the various parties and approximate fair value.

Suncor Energy Inc.	099
2006 Annual Report

17. SUPPLEMENTAL INFORMATION

($ millions)	2006	2005	2004
Export sales (a)	810	648	693
Exploration expenses
Geological and geophysical	51	22	33
Other	1	1	1
Cash costs	52	23	34
Dry hole costs	52	33	21
Cash and dry hole costs (b)	104	56	55
Leasehold impairment (c)	2	13	8
	106	69	63
Taxes other than income taxes
Excise taxes (d)	538	482	496
Production, property and other taxes	57	47	44
	595	529	540
Allowance for doubtful accounts	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 exploration expenses in the Consolidated Statements of Earnings.

(c) Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings.

(d) Included in operating revenues in the Consolidated Statements of Earnings.

18. 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	2006		2005		2004
Net earnings as reported, Canadian GAAP		2 971		1 158		1 076
Adjustments
Derivatives and hedging activities	(a)	11		83		92
Stock-based compensation	(b)	(19	)	(26	)	(10	)
Income tax expense		(3	)	(28	)	(27	)
Net earnings from continuing operations, U.S. GAAP		2 960		1 187		1 131
Cumulative effect of change in accounting principles, net of income taxes of $2 (2005 – $nil; 2004 – $nil)	(b)	(4	)	—		—
Net earnings, U.S. GAAP		2 956		1 187		1 131
Derivatives and hedging activities, net of income taxes of $3 (2005 – $70; 2004 – $35)	(a)	6		140		(67	)
Minimum pension liability, net of income taxes of $20 (2005 – $8; 2004 – $3)	(c)	39		(15	)	5
Unfunded pension obligation, net of income taxes of $60	(c)	(127	)	—		—
Foreign currency translation adjustment	(d)	10		(26	)	(29	)
Comprehensive income, U.S. GAAP		2 884		1 286		1 040

per common share (dollars)	2006	2005	2004
Net earnings per share from continuing operations, U.S. GAAP
Basic	6.45	2.60	2.50
Diluted	6.29	2.55	2.45
Net earnings per share, U.S. GAAP
Basic	6.44	2.60	2.50
Diluted	6.29	2.55	2.45

100	Suncor Energy Inc.
	2006 Annual Report

The application of U.S. GAAP would have the following effects on the Consolidated Balance Sheets as reported:

		December 31, 2006				December 31, 2005
		As		U.S.		As		U.S.
	Notes	Reported		GAAP		Reported		GAAP
Current assets		2 302		2 302		1 916		1 916
Property, plant and equipment, net		16 189		16 189		12 966		12 966
Deferred charges and other	(a,c)	290		316		267		298
Total assets		18 781		18 807		15 149		15 180
Current liabilities		2 158		2 158		1 935		1 935
Long-term borrowings	(a)	2 385		2 398		3 007		3 029
Accrued liabilities and other	(b,c)	1 214		1 430		1 005		1 092
Future income taxes	(a,c)	4 072		4 002		3 206		3 179
Share capital	(b)	794		842		732		780
Contributed surplus	(b)	100		153		50		88
Cumulative foreign currency translation	(d)	(71	)	—		(81	)	—
Retained earnings	(a,b)	8 129		8 026		5 295		5 207
Accumulated other comprehensive income	(a,c,d)	—		(202	)	—		(130	)
Total liabilities and shareholders’ equity		18 781		18 807		15 149		15 180

(a) Derivative Financial Instruments

The company accounts for its derivative financial instruments under Canadian GAAP as described in note 6. Financial Accounting Standards Board Statement (Statement) 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by Statements 138 and 149 (the Standards), establishes U.S. GAAP accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding 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 each period are recognized in the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income (OCI) each period and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Accordingly, 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 earnings statement caption as the hedged item.

The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges is based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

Commodity Price Risk

As described in note 6, Suncor manages crude price variability by entering into WTI derivative transactions and has historically, in certain instances, combined U.S. dollar WTI derivative transactions and Canadian/U.S. foreign exchange derivative contracts. As at December 31, 2006, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2007 and 2008.

U.S. GAAP requires the company to consider all cash flows arising from forecasted Canadian dollar denominated crude oil sales when measuring the ineffectiveness of its cash flow hedges. In periods of significant Canadian/U.S. dollar foreign exchange fluctuations, material hedge ineffectiveness can result from unhedged foreign exchange exposures. This ineffectiveness arises despite the company’s assessment that its U.S. dollar WTI hedging instruments are highly effective in achieving offsetting changes in cash flows attributable to its forecasted Canadian dollar denominated crude oil sales.

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 will not be recognized for Canadian GAAP purposes until the related forecasted sales occur.

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2006 Annual Report

Interest Rate Risk

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest-bearing debt. At December 31, 2006, the company had interest rate derivatives classified as fair value hedges outstanding for up to five years relating to fixed rate debt.

Non-designated Hedging Instruments

In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting as the company did not have purchase price risk associated with the repurchase of the inventory. This derivative did not represent a U.S. GAAP difference as the company recorded this derivative at fair value for Canadian purposes. The inventory was repurchased in 2004.

Accumulated OCI 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)	2006		2005
OCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $1 (2005 – $69)	2		(138	)
Current period net changes arising from cash flow hedges, net of income taxes of $4 (2005 – $2)	9		(3	)
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $1 (2005 – $72)	(3	)	143
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $4 (2005 – $1)	8		2

For the year ended December 31, 2006, assets increased by $26 million and liabilities increased by $13 million as a result of recording all derivative instruments at fair value in accordance with U.S. GAAP.

The earnings gain associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $5 million, net of income taxes of $3 million (2005 – loss of $3 million, net of income taxes of $2 million; 2004 – loss of $130 million, net of income taxes of $66 million). The company estimates that $2 million of after-tax hedging gains will be reclassified from OCI to current period earnings within the next 12 months as a result of forecasted sales occurring.

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; 2004 – increased net earnings of $65 million, net of income taxes of $27 million) to reflect the impact of the above items.

(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. SFAS 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 SFAS 123(R), our PSUs for U.S. GAAP have been measured using a Monte Carlo Simulation approach to determine fair value. This change results in a cumulative effect of a change in accounting policy of $4 million, net of income taxes of $2 million. The impact on net earnings for the year ended December 31, 2006, is an increase in stock-based compensation expense of $3 million, 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. SFAS 123(R) requires the immediate recognition of expense related to the unvested portion of the company’s pre-2003 options. This resulted in an increase to stock-based compensation expense of $15 million (there was no impact on income taxes) for the year ended December 31, 2006.

102	Suncor Energy Inc.
	2006 Annual Report

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

In September 2006, FASB issued SFAS 158 “Employers Accounting for Defined Benefit and Other Post-retirement Plans.” The standard requires the recognition of the overfunded or underfunded 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 tax. This standard has been applied prospectively effective December 31, 2006, as retrospective application is not permitted.

For the current year up to the adoption of SFAS 158 on December 31, 2006, and for prior year comparative balances previously disclosed under U.S. GAAP, recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is 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 is required under Canadian GAAP. As required under SFAS 158, the minimum pension liability adjustment from prior years is reversed in the current year.

At December 31, 2006, the company would have recognized a minimum pension liability of $35 million (2005 – $87 million), an intangible asset of $16 million (2005 – $9 million) and an accumulated other comprehensive loss of $12 million, net of income taxes of $7 million (2005 – $51 million, net of income taxes of $27 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; 2004 – an increase in other comprehensive income of $5 million, net of income taxes of $3 million).

Under U.S. GAAP, the impact on future benefit obligations recorded to the balance sheet as at December 31, 2006, as a result of adopting SFAS 158 are as follows:

•   Unfunded pension benefits – $177 million

•   Unfunded other post-retirement benefits – $29 million

In total, other comprehensive income was decreased by $139 million, net of income taxes at December 31, 2006.

Accumulated OCI and U.S. GAAP Net Earnings Impacts

($ millions)	2006		2005
OCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $27 million (2005 – $19 million)	(51	)	(36	)
Minimum pension liability, net of income taxes of $20 million (2005 – $8 million)	39		(15	)
Reversal of minimum pension liability upon adoption of SFAS 158, net of income taxes of $7 million	12		—
Unamortized net actuarial loss, net of income taxes of $74 million	(155	)	—
Unamortized past service costs, net of income taxes of $7 million	16		—
OCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $67 million (2005 – $27 million)	(139	)	(51	)

Total amount included in accumulated OCI expected to be recognized as components of net periodic benefit cost during 2007 are as follows:

•   Amortization of net actuarial loss – $29 million

•   Amortization of past service costs – $nil

(d) Cumulative Foreign Currency Translation

Under Canadian GAAP, foreign currency gains of $10 million (2005 – losses of $26 million; 2004 – losses of $29 million) arising on translation of the company’s U.S. based foreign operations have been recorded directly to shareholders’ equity. Under U.S. GAAP, these foreign currency translation losses would be 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

Suncor Energy Inc.	103
2006 Annual Report

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)	2006		2005		2004
Balance, beginning of year	15		5		1
Additions pending determination of proved reserves	21		14		5
Charged to dry hole expense	—		(2	)	—
Reclassifications to proved properties	(13	)	(2	)	(1	)
Balance, end of year	23		15		5
Capitalized for a period greater than one year ($ millions)	2		1		—
Number of projects that have exploratory well costs capitalized for a period greater than 12 months	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 statements of earnings. 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 downstream operating segments.

In addition, the R&M segment sells finished product and buys 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, are recorded at fair value in “revenue” and “purchases of crude oil and products” in the statements of income in accordance with the consensus for Issue 2 in EITF 04-13.

The purchase/sale of contract amounts included in revenue for 2006, 2005 and 2004 are shown below.

($ millions)	2006	2005	2004
Consolidated revenues	15 829	11 129	8 705
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	5	16	7

(1) Associated costs are in “purchases of crude oil and products.”

Recently Issued Accounting Standards

In September 2006, FASB issued SFAS 157 “Fair Value Measurements.” The standard, effective January 1, 2008, establishes a recognized framework for measuring fair value, and expands disclosures 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.

In June 2006, FASB issued FIN 48 “Accounting for Uncertainty in Income Taxes.” The standard, effective January 1, 2007, requires recognition of uncertain tax positions only where positions are determined to be more likely than not, defined as greater than 50%, to be sustained on audit. All tax positions will be required to meet the recognition threshold as of the effective date of this standard, with the cumulative effect of application shown as an adjustment to the opening balance of retained earnings. The effect of this standard has not yet been determined.

104	Suncor Energy Inc.
	2006 Annual Report

Quarterly summary (unaudited)

FINANCIAL DATA

									Total										Total
			For the Quarter Ended						Year				For the Quarter Ended						Year
	Mar		June		Sept		Dec				Mar		June		Sept		Dec
	31		30		30		31				31		30		30		31
($ millions except per share amounts)	2006		2006		2006		2006		2006		2005		2005		2005		2005		2005
Revenues	3 858		4 070		4 114		3 787		15 829		2 074		2 385		3 149		3 521		11 129
Net earnings (loss)
Oil Sands	720		1 109		583		412		2 824		83		85		225		583		976
Natural Gas	42		60		12		(5	)	109		26		27		24		78		155
Energy Marketing
and Refining – Canada	18		63		17		(12	)	86		(3	)	5		17		22		41
Refining and Marketing – U.S.A. (c)	(2	)	57		70		43		168		6		31		50		55		142
Corporate and eliminations	(65	)	(71	)	—		(80	)	(216	)	(45	)	(65	)	(1	)	(45	)	(156	)
	713		1 218		682		358		2 971		67		83		315		693		1 158
Per common share
Net earnings attributable
to common shareholders
Basic	1.56		2.65		1.48		0.78		6.47		0.15		0.18		0.69		1.52		2.54
Diluted	1.52		2.59		1.45		0.76		6.32		0.14		0.18		0.67		1.48		2.48
Cash dividends	0.06		0.08		0.08		0.08		0.30		0.06		0.06		0.06		0.06		0.24
Cash flow from (used in) operations
Oil Sands	1 209		1 099		926		668		3902		248		210		441		979		1 878
Natural Gas	100		65		68		48		281		83		81		104		144		412
Energy Marketing and Refining – Canada	51		102		51		13		217		22		26		44		60		152
Refining and Marketing – U.S.A. (c)	—		96		118		67		281		18		52		82		95		247
Corporate and eliminations	(46	)	(42	)	(10	)	(50	)	(148	)	(77	)	(64	)	(20	)	(52	)	(213	)
	1 314		1 320		1 153		746		4 533		294		305		651		1 226		2 476

OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
Total operations	264.4	267.3	242.8	266.4	260.0	139.9	128.2	148.2	267.7	171.3
Firebag	27.4	35.0	37.2	35.1	33.7	18.7	8.7	23.0	26.0	19.1
Sales
Light sweet crude oil	119.2	124.7	84.9	113.7	110.5	75.3	48.3	69.9	108.6	73.3
Diesel	35.1	32.9	20.7	24.0	28.2	11.8	9.0	10.6	30.7	15.6
Light sour crude oil	121.0	99.2	125.8	126.8	118.2	38.5	54.2	41.7	104.2	59.8
Bitumen	—	8.5	6.6	9.7	6.2	18.4	9.6	22.3	7.2	16.6
	275.3	265.3	238.0	274.2	263.1	144.0	121.1	144.5	250.7	165.3

Suncor Energy Inc.	105
2006 Annual Report

Quarterly summary (unaudited) (continued)

OPERATING DATA (continued)

					Total					Total
	For the Quarter Ended				Year	For the Quarter Ended				Year
	Mar	June	Sept	Dec		Mar	June	Sept	Dec
	31	30	30	31		31	30	30	31
	2006	2006	2006	2006	2006	2005	2005	2005	2005	2005
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
Light sweet crude oil	69.00	78.27	78.11	64.51	71.98	45.41	39.20	52.08	55.96	49.93
Other (diesel, light sour crude oil and bitumen)	63.28	72.75	68.60	57.91	65.17	47.31	50.47	59.70	63.84	56.90
Total	65.75	75.34	71.99	60.65	68.03	46.44	45.98	56.01	60.42	53.81
Total (a)	65.75	75.34	71.99	60.65	68.03	54.80	57.24	67.95	66.68	62.68
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs	15.55	15.65	21.00	22.65	18.70	20.55	23.50	21.65	16.20	19.60
Natural gas	3.45	2.55	2.60	3.00	2.90	5.40	3.60	6.00	4.65	4.90
Imported bitumen	0.05	0.10	0.10	—	0.10	0.10	—	—	0.05	0.05
Cash operating costs (3)	19.05	18.30	23.70	25.65	21.70	26.05	27.10	27.65	20.90	24.55
Firebag start-up costs	0.90	—	—	—	0.20	—	—	—	0.30	0.10
Total cash operating costs (4)	19.95	18.30	23.70	25.65	21.90	26.05	27.10	27.65	21.20	24.65
Depreciation, depletion and amortization	3.90	3.80	4.30	4.25	4.05	6.25	6.75	6.10	3.60	5.30
Total operating costs (5)	23.85	22.10	28.00	29.90	25.95	32.30	33.85	33.75	24.80	29.95
Cash operating costs and total operating costs – In-situ Bitumen Production Only (excluding upgrading costs)
Cash costs	5.70	8.50	5.55	8.05	8.95	8.90	21.50	7.55	6.70	9.15
Natural gas	7.70	8.15	7.60	9.90	8.35	10.10	16.40	13.25	13.80	13.05
Cash operating costs (6)	13.40	16.65	13.15	17.95	17.30	19.00	37.90	20.80	20.50	22.20
Firebag start-up costs	8.50	—	—	—	1.70	—	—	—	2.90	1.00
Total cash operating costs (7)	21.90	16.65	13.15	17.95	19.00	19.00	37.90	20.80	23.40	23.20
Depreciation, depletion and amortization	6.90	3.75	5.55	6.20	5.55	4.75	7.60	4.25	4.60	4.90
Total operating costs (8)	28.80	20.40	18.70	24.15	24.55	23.75	45.50	25.05	28.00	28.10
NATURAL GAS
Gross production (b)
Natural gas
(millions of cubic feet per day)	196	189	191	192	191	191	175	200	193	190
Natural gas liquids
(thousands of barrels per day)	2.4	2.6	2.1	2.1	2.3	3.0	2.2	2.2	2.3	2.4
Crude oil
(thousands of barrels per day)	0.8	0.9	0.7	0.5	0.7	0.9	1.0	0.7	0.6	0.8
Total (barrels of oil equivalent
per day at 6:1 for natural gas)	35.9	35.1	34.6	34.7	34.8	35.7	32.4	36.3	35.0	34.8
Average sales price (2)
Natural gas
(dollars per thousand cubic feet)	9.03	6.38	6.33	6.55	7.15	6.81	7.29	8.32	11.66	8.57
Natural gas (a) (dollars per
thousand cubic feet)	8.75	6.22	6.13	6.40	6.95	6.74	7.26	8.34	11.83	8.59
Natural gas liquids
(dollars per barrel)	51.75	60.14	53.11	44.20	44.96	38.32	52.52	58.00	57.85	50.70
Crude oil – conventional
(dollars per barrel)	60.30	74.18	84.95	51.20	74.83	61.40	63.86	63.77	72.60	64.85

106	Suncor Energy Inc.
	2006 Annual Report

Quarterly summary (unaudited) (continued)

OPERATING DATA (continued)

					Total					Total
	For the Quarter Ended				Year	For the Quarter Ended				Year
	Mar	June	Sept	Dec		Mar	June	Sept	Dec
	31	30	30	31		31	30	30	31
	2006	2006	2006	2006	2006	2005	2005	2005	2005	2005
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)	15.3	15.4	15.2	14.9	15.1	15.1	16.1	15.6	14.3	15.2
Utilization of refining capacity (%)	86	89	85	51	78	91	100	96	95	95
REFINING AND MARKETING – U.S.A. (c)
Refined product sales (thousands of cubic metres per day)	11.3	16.2	16.2	14.2	14.4	10.1	12.6	17.3	14.5	13.7
Utilization of refining capacity (%)	65	102	104	96	92	96	102	104	91	98

(a)Excludes the impact of hedging activities.

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

(c)Refining and Marketing – U.S.A reflects results of operations from assets acquired May 31, 2005.

Definitions

(1)	Total operations production – Total operations production includes total production from both mining and in-situ operations.
(2)	Average sales price – This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(3)	Cash operating costs – Total operations – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non-GAAP financial measure see Management’s Discussion and Analysis.
(4)	Total cash operating costs – Total operations – Include cash operating costs – Total operations as defined above and cash start-up costs for in-situ operations. 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 operating costs. 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.	107
2006 Annual Report

Five-year financial summary (unaudited)

($ millions except for ratios)	2006		2005	(a)	2004		2003	(a)	2002
Revenues
Oil Sands	7 407		3 965		3 640		3 101		2 655
Natural Gas	578		679		567		512		339
Energy Marketing and Refining – Canada	5 465		4 363		3 500		2 936		2 508
Refining and Marketing – U.S.A.	3 128		2 621		1 495		515		—
Corporate and eliminations	(749	)	(499	)	(497	)	(453	)	(431	)
	15 829		11 129		8 705		6 611		5 071
Net earnings (loss)
Oil Sands	2 824		976		970		895		804
Natural Gas	109		155		115		120		34
Energy Marketing and Refining – Canada	86		41		80		53		61
Refining and Marketing – U.S.A.	168		142		34		18		—
Corporate and eliminations	(216	)	(156	)	(123	)	14		(156	)
	2 971		1 158		1 076		1 100		743
Cash flow from (used in) operations
Oil Sands	3 902		1 878		1 734		1 794		1 475
Natural Gas	281		412		319		298		164
Energy Marketing and Refining – Canada	217		152		188		164		112
Refining and Marketing – U.S.A.	281		247		59		34		—
Corporate and eliminations	(148	)	(213	)	(287	)	(250	)	(358	)
	4 533		2 476		2 013		2 040		1 393
Capital and exploration expenditures
Oil Sands	2 463		1 948		1 119		953		618
Natural Gas	458		363		279		184		163
Energy Marketing and Refining – Canada	487		442		228		122		60
Refining and Marketing – U.S.A.	178		337		190		31		—
Corporate	27		63		31		32		37
	3 613		3 153		1 847		1 322		878
Total assets	18 781		15 149		11 774		10 489		8 978
Capital employed (b)
Short-term and long-term debt, less cash and cash equivalents	1 871		2 891		2 159		2 577		3 204
Shareholders’ equity	8 952		5 996		4 874		3 858		2 838
	10 823		8 887		7 033		6 435		6 042
Less capitalized costs related to major projects in progress	(2 476	)	(2 175	)	(1 467	)	(1 122	)	(511	)
	8 347		6 712		5 566		5 313		5 531
Total Suncor employees (number at year-end)	5 766		5 152		4 605		4 231		3 422

108	Suncor Energy Inc.
	2006 Annual Report

Five-year financial summary (unaudited) (continued)

	2006	2005	(a)	2004	2003	(a)	2002
Dollars per common share
Net earnings attributable to common shareholders	6.47	2.54		2.38	2.45		1.66
Cash dividends	0.30	0.24		0.23	0.1925		0.17
Cash flow from operations	9.87	5.43		4.44	4.54		3.11
Ratios
Return on capital employed (%) (b), (c)	40.6	19.7		18.9	18.7		15.1
Return on capital employed (%) (d)	30.4	14.3		16.0	16.3		14.2
Return on shareholders’ equity (%) (e)	39.7	21.3		24.6	32.9		29.8
Debt to debt plus shareholders’ equity (%) (f)	21.1	33.8		31.6	43.5		53.2
Net debt to cash flow from operations (times) (g)	0.4	1.2		1.1	1.3		2.3
Interest coverage – cash flow basis (times) (h)	30.5	16.9		13.7	11.9		8.1
Interest coverage – net earnings basis (times) (i)	25.5	12.5		10.8	10.5		6.4

(a)	Refining and Marketing – U.S.A. reflects the results of operations since acquisitions on August 1, 2003 and May 31, 2005.
(b)	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).
(c)	Net earnings adjusted for after-tax financing expenses (income) for the 12 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 58 of Management’s Discussion and Analysis.
(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)	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.
(f)	Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders’ equity.
(g)	Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.
(h)	Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(i)	Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

Suncor Energy Inc.	109
2006 Annual Report

Share trading information (unaudited)

Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU.

	For the Quarter Ended				For the Quarter Ended
	Mar 31	June 30	Sept 30	Dec 31	Mar 31	June 30	Sept 30	Dec 31
	2006	2006	2006	2006	2005	2005	2005	2005
Share ownership
Average number outstanding, weighted monthly (thousands) (a)	458 230	458 596	458 859	459 069	454 911	456 141	456 996	457 429
Share price (dollars)
Toronto Stock Exchange
High	93.85	102.18	97.12	95.00	50.07	60.24	73.25	76.05
Low	75.58	75.00	71.18	72.26	38.76	44.00	57.75	57.00
Close	89.63	90.34	80.19	91.79	48.73	57.92	70.42	73.32
New York Stock Exchange – US$
High	82.15	89.86	86.78	82.08	41.70	48.95	62.50	66.00
Low	64.00	67.36	63.77	64.06	31.33	35.38	47.40	48.09
Close	77.02	81.01	72.05	78.91	40.21	47.32	60.53	63.13
Shares traded (thousands)
Toronto Stock Exchange	107 797	101 626	106 348	99 704	107 080	102 317	108 384	107 502
New York Stock Exchange	114 031	116 492	100 714	94 676	84 285	89 244	139 214	175 618
Per common shareinformation (dollars)
Net earnings attributable to common shareholders	1.56	2.65	1.48	0.78	0.15	0.18	0.69	1.52
Cash dividends	0.06	0.08	0.08	0.08	0.06	0.06	0.06	0.06

(a) The company had approximately 2,388 holders of record of common shares as at January 31, 2007.

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 who owns at least 10% of the voting shares of the company.

110	Suncor Energy Inc.
	2006 Annual Report

Supplemental financial and operating information (unaudited)

	2006	2005	2004	2003	2002
OIL SANDS
Production (thousands of barrels per day)	260.0	171.3	226.5	216.6	205.8
Sales (thousands of barrels per day)
Light sweet crude oil	110.5	73.3	114.9	112.3	104.7
Diesel	28.2	15.6	27.9	26.3	23.0
Light sour crude oil	118.2	59.8	75.1	73.3	68.3
Bitumen	6.2	16.6	8.4	6.4	9.3
	263.1	165.3	226.3	218.3	205.3
Average sales price (dollars per barrel)
Light sweet crude oil	71.98	49.93	45.60	40.26	37.56
Other (diesel, light sour crude oil and bitumen)	65.17	56.90	39.13	33.93	29.58
Total	68.03	53.81	42.28	37.19	33.65
Total (a)	68.03	62.68	49.78	40.22	36.94
Cash operating costs – total operations (b)	21.70	24.55	15.15	13.80	13.30
Total cash operating costs – total operations (b)	21.90	24.65	15.45	13.80	13.30
Total operating costs – total operations (b)	25.95	29.95	19.05	17.15	16.80
Cash operating costs – in-situ bitumen production (b), (e), (f)	17.30	22.20	22.05	—	—
Total cash operating costs – in-situ bitumen production (b), (e), (f)	19.00	23.20	28.90	—	—
Total operating costs – in-situ bitumen production (b), (e), (f)	24.55	28.10	34.90	—	—
Capital employed excluding major projects in progress	5 092	4 472	4 105	4 010	4 464
Return on capital employed (%) (c)	53.7	22.7	22.6	21.1	17.4
Return on capital employed (%) (d)	40.4	16.3	18.5	17.7	16.2

(a)	Excludes the impact of hedging activities.
(b)	Dollars per barrel rounded to the nearest $0.05. See definitions on page 106.
(c)	See definitions on page 108.
(d)	If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e)	In-situ bitumen production commenced commercial operations on April 1, 2004.
(f)	In-situ bitumen production costs exclude upgrading costs.

Suncor Energy Inc.	111
2006 Annual Report

Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
Gross	191	190	200	187	179
Net	141	137	147	142	124
Natural gas liquids (thousands of barrels per day)
Gross	2.3	2.4	2.5	2.3	2.4
Net	1.7	1.9	1.8	1.7	1.7
Crude oil (thousands of barrels per day)
Gross	0.7	0.8	1.0	1.4	1.5
Net	0.6	0.7	0.8	1.1	1.2
Total (thousands of boe (a) per day)
Gross	34.8	34.8	36.8	34.9	33.7
Net	25.8	25.3	27.1	26.4	23.6
Average sales price
Natural gas (dollars per thousand cubic feet)	7.15	8.57	6.70	6.42	3.91
Natural gas (dollars per thousand cubic feet) (b)	6.95	8.59	6.73	6.42	3.91
Natural gas liquids (dollars per barrel)	44.96	50.70	42.82	36.08	29.35
Crude oil – conventional (dollars per barrel)	74.83	64.85	50.41	40.29	31.72
Capital employed	861	563	448	400	422
Return on capital employed (%) (e)	15.3	30.7	27.1	29.2	9.5
Undeveloped landholdings (c)
Oil and gas (millions of acres)
Western Canada
Gross	1.2	0.6	0.7	0.5	0.5
Net	0.7	0.4	0.5	0.4	0.4
International
Gross	0.1	0.4	0.7	0.9	1.2
Net	—	0.2	0.4	0.2	0.7
Net wells drilled (d)
Exploratory
Oil	—	—	—	—	—
Gas	3	8	5	2	2
Dry	5	4	5	31	19
Development
Oil	1	1	—	1	—
Gas	13	18	16	16	18
Dry	4	3	—	4	4
	26	34	26	54	43

(a)   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.

(b)   Excludes the impact of hedging activities.

(c)   Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres

(d)   Excludes interests in 7 net exploratory wells and 18 net development wells in progress at the end of 2006.

(e)   See definitions on page 108.

112	Suncor Energy Inc.
	2006 Annual Report

Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail	4.6	4.5	4.6	4.4	4.5
Other	3.8	3.9	4.1	4.2	4.4
Jet fuel	0.7	0.9	0.9	0.7	0.4
Diesel	3.2	3.3	3.1	3.0	2.9
	12.3	12.6	12.7	12.3	12.2
Petrochemicals	0.9	0.7	0.8	0.8	0.6
Heating oils	0.5	0.4	0.4	0.5	0.4
Heavy fuel oils	0.8	1.0	0.7	0.8	0.6
Other	0.6	0.5	0.8	0.6	0.7
	15.1	15.2	15.4	15.0	14.5
Crude oil supply and refining
Processed at Sarnia refinery (thousands of cubic metres per day)	8.6	10.6	11.1	10.5	10.6
Utilization of refining capacity (%)	78	95	100	95	95
Capital employed excluding major projects in progress	1 023	486	512	551	485
Return on capital employed (%) (d)	12.5	8.1	14.6	10.3	12.0
Return on capital employed (%) (d), (e)	7.4	5.2	13.6	10.3	12.0
Retail outlets (f) (number at year-end)	374	374	378	379	384

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Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
REFINING AND MARKETING – U.S.A. (a)
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail (b)	0.7	0.7	0.7	0.7	—
Other	6.8	6.2	3.8	3.5	—
Jet fuel	1.0	0.8	0.5	0.5	—
Diesel	3.6	3.3	2.2	2.3	—
	12.1	11.0	7.2	7.0	—
Asphalt	1.2	1.6	1.5	1.7	—
Other	1.1	1.1	0.6	0.4	—
	14.4	13.7	9.3	9.1	—
Crude oil supply and refining
Processed at Denver refinery (thousands of cubic metres per day)	13.1	12.1	8.8	9.4	—
Utilization of refining capacity (%)	92	98	92	98	—
Capital employed excluding major projects in progress	831	327	232	270	—
Return on capital employed (%) (d), (h)	34.2	49.4	12.2	—	—
Return on capital employed (%) (d), (e), (h)	22.6	28.9	11.1	—	—
Retail outlets (g) (number at year-end)	43	43	43	43	—

(a) Refining and Marketing – U.S.A. reflects the results of operations since acquisitions on August 1, 2003 and May 31, 2005.

(b) Excludes sales through joint venture interests.

(c) Excludes the impact of hedging activities.

(d) See definitions on page 108.

(e) 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.

(f) Sunoco-branded service stations, other private brands managed by EM&R and EM&R’s interest in service stations managed through joint ventures. Outlets are located mainly in Ontario.

(g) Phillips 66-branded service stations. Outlets are primarily located in the Denver, Colorado area.

(h) For 2003, represents five months of operations since acquisition August 1, 2003, therefore no annual ROCE was calculated.

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Investor information

Stock Trading Symbols and Exchange Listing

Common shares are listed on the Toronto Stock Exchange (TSX) and New York Stock Exchange (NYSE) under the symbol SU.

Dividends

Suncor’s Board of Directors reviews its dividend policy quarterly. In 2006, Suncor paid an aggregate dividend of $0.30 per common share.

Dividend Reinvestment and Common Share Purchase Plan

Suncor’s Dividend Reinvestment and Common Share Purchase Plan enables shareholders to invest cash dividends in common shares or acquire additional shares through cash payments without payment of brokerage commissions, service charges or other costs associated with administration of the plan. To obtain additional information, call Computershare Trust Company of Canada at 1-877-982-8760. Information regarding the purchase plan is also available in the dividend information section of our website at www.suncor.com/dividend.

Stock Transfer Agent and Registrar

In Canada, Suncor’s agent is Computershare Trust Company of Canada. In the United States, Suncor’s agent is Computershare Trust Company, Inc.

Independent Auditors

PricewaterhouseCoopers LLP

Independent Reserve Evaluators

GLJ Petroleum Consultants Ltd.

Annual Meeting

Suncor’s annual and special meeting of shareholders will be held at 10:30 a.m. MT on April 26, 2007, at the Metropolitan Centre, 333 Fourth Avenue S.W., Calgary, Alberta. Presentations from the meeting will be web-cast live at www.suncor.com/webcasts.

Corporate Office

Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, T2P 2V5

Telephone: 403-269-8100  Toll-free number: 1-866-SUNCOR-1

Fax: 403-269-6217  E-mail: info@suncor.com

Analyst and Investor Inquiries

John Rogers, vice president, Investor Relations

Telephone: 403-269-8670  Fax: 403-269-6217  E-mail: invest@suncor.com

For further information, to subscribe or cancel duplicate mailings

In addition to Annual and Quarterly Reports, Suncor publishes a biennial Report on Sustainability. All Suncor publications, as well as updates on company news as it happens, are available on our website at www.suncor.com. To receive Suncor news as it happens, subscribe to E-news, which can be found on our website. To order copies of Suncor’s print materials call 1-800-558-9071.

If you do not receive our Annual or Quarterly Reports, but would like to receive these reports, call Computershare Trust Company of Canada at 1-877-982-8760 or visit their website at www.computershare.com. Computershare will update your account information accordingly.

Shareholders can help reduce mailing costs and paper waste by electing to receive Suncor’s Annual Report and other documents electronically. To register for electronic delivery, registered shareholders should visit www.computershare.com.

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2006 Annual Report

Corporate governance

Providing strategic guidance to the company, setting policy direction and ensuring Suncor is fairly reporting its progress are central to the work of Suncor’s Board of Directors.

The Board’s oversight role encompasses Suncor’s strategic planning process, risk management, standards of business conduct and communication with investors and other stakeholders. Suncor’s Board is also responsible for selecting, monitoring and evaluating executive leadership and aligning management’s decision making with long-term shareholder interest.

There are no significant differences between Suncor’s governance practices and those prescribed by the New York Stock Exchange (NYSE), with the exception of the requirements applicable to equity compensation plans. A comprehensive description of Suncor’s governance practices, including differences between Toronto Stock Exchange (TSX) and NYSE requirements related to equity compensation plans, is available in the company’s Management Proxy Circular on Suncor’s website at www.suncor.com/financialreporting or by calling 1-800-558-9071.

Independence

As of December 31, 2006, Suncor’s Board of Directors comprised 12 directors, 11 of whom have been determined by the Board to be independent of management under the guidelines established by the TSX and NYSE. The role of chair is assumed by an independent director and is separate from the role of chief executive officer. All Board committees are comprised entirely of independent directors.

The selection of new nominees for membership on the Board is conducted by the Board Policy, Strategy Review and Governance Committee, comprised solely of independent directors. The selection process includes an annual assessment of the competencies and skills the Board as a whole should possess, and of current director capabilities. The Board Policy, Strategy Review and Governance Committee utilizes the services of executive search consulting firms to assist with the selection process. Ultimately, the committee provides its recommendation to the full Board, which approves a nominee for submission to shareholders for election to the Board.

Additionally, the committee annually assesses and evaluates the overall performance and effectiveness of the Board, its committees, and individual directors. Each year, a confidential questionnaire including a self-assessment and peer review is completed by each director. The resulting data is analyzed by the Board Policy, Strategy Review and Governance Committee, which then reports to the full Board with any recommendations for enhancing or strengthening effectiveness.

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Committee Key Responsibilities

Committee	Key Responsibilities
Board Policy, Strategy Review and Governance Committee	Oversees Suncor’s values, beliefs and standards of ethical conduct. Reviews key matters pertaining to governance, including organization, composition and effectiveness of the Board. Reviews preliminary stages of key strategic initiatives and projects. Reviews and assesses processes relating to long-range and strategic planning and budgeting.
Human Resources and Compensation Committee	Reviews and ensures Suncor’s overall goals and objectives are supported by appropriate executive compensation philosophy and programs. Annually evaluates the performance of the chief executive officer (CEO) against predetermined goals and criteria, and recommends to the Board the total compensation for the CEO. Annually reviews the CEO’s evaluation and recommendations for total compensation of the other executive roles, the executive succession planning process and results, and all major human resources programs.
Environment, Health and Safety Committee	Reviews the effectiveness with which Suncor meets its obligations pertaining to environment, health and safety, including the establishment of appropriate policies with regard to legal, industry and community standards and related management systems and compliance.
Audit Committee	Assists the Board in matters relating to Suncor’s internal controls, internal and external auditors and the external audit process, oil and natural gas reserves reporting, financial reporting, public communication and certain other key financial matters. Provides an open avenue of communication between management, the internal and external auditors and the Board. Approves Suncor’s interim financial statements and management’s discussion and analysis.

Share Ownership

The Board has set guidelines for its own, as well as executive share ownership. These guidelines, as well as the amount of shares held by each Board member and named executive are reported annually in Suncor’s Management Proxy Circular.

For further information about Suncor’s corporate governance practices and the company’s code of corporate conduct, visit www.suncor.com or call 1-800-558-9071 to order a copy of Suncor’s Management Proxy Circular.

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2006 Annual Report

Board of directors

JR Shaw ^(2,3)

Calgary, Alberta

Chairman of the Board of Directors

Director since 1998

JR Shaw has been the chairman of the Board of Suncor since 2001. He is also the executive chair of Shaw Communications Inc., the company he founded in 1966. Mr. Shaw is also president of the Shaw Foundation and serves as a director of Darian Resources. Mr. Shaw is an Officer of the Order of Canada.

Mel E. Benson ^(3,4)

Calgary, Alberta

Chair, Environment, Health and Safety Committee

Director since 2000

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 also a director of Kanetax Energy Inc., Tenax Energy Inc., Winalta Homes Inc. and Poplar Point Energy. He is active with several charitable organizations including Hull Family Services, the Council for Advancement of Native Development Officers 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

Brian Canfield is the chairman of TELUS Corporation, a telecommunications company. Mr. Canfield is also a director and chair of the governance committee of the Canadian Public Accountability Board. In 1998, Mr. Canfield was appointed to the Order of British Columbia. In 2007, he was appointed a Member of the Order of Canada.

Bryan P. Davies ^(3,4)

Etobicoke, Ontario

Chair, Human Resources and Compensation Committee

Director 1991 to 1996 and since 2000

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 of regulatory affairs with the Royal Bank Financial Group. Mr. Davies serves as past chair of the Canadian Merit Scholarship Foundation and a director of the Foundation for International Training.

Brian A. Felesky ^(1,4)

Calgary, Alberta

Director since 2002

Brian Felesky is counsel to the law firm 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, Fairquest Energy Ltd. and Resin Systems Inc. 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 and the Calgary Arts Development Authority. Mr. Felesky is a Member of the Order of Canada.

John T. Ferguson ^(1,2)

Edmonton, Alberta

Chair, Audit Committee

Director since 1995

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. 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 the Institute of Corporate Directors.

W. Douglas (Doug) Ford ^(2,3)

Downers Grove, Illinois

Director since 2004

Doug 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 (Rick) L. George

Calgary, Alberta

Director since 1991

Rick 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, GlobalSantaFe Corporation, and chair of the 2008 Governor General’s Canadian Leadership Conference. In 2006, he was named a member of the North American Competitiveness Council by Canadian Prime Minister Stephen Harper. He served as chairman of the Canadian Council of Chief Executives from 2003 to 2006.

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John R. Huff ^(2,3)

Houston, Texas

Chair, Board Policy, Strategy Review

and Governance Committee

Director since 1998

John Huff is chairman of the board of Oceaneering International Inc., an oil field services company. Mr. Huff is also a director of BJ Services Company and Rowan Companies Inc. He is a member of the National Petroleum Council, and is active in 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

Ann McCaig is 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 honorary 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. She is past co-chair of the Alberta Children’s Hospital Foundation.

Michael W. O’Brien ^(1,4)

Canmore, Alberta

Director since 2002

Michael O’Brien served as executive vice president, corporate development and chief financial officer of Suncor Energy Inc. before his retirement in 2002. Mr. O’Brien serves on the boards of Prime West Energy Inc. and Shaw Communications Inc. and as an advisor to CRA International. As well, he is past chair of the board of trustees for Nature Conservancy of 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

Eira Thomas has been president and 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 and director of Stornoway Ventures Ltd. She is a director of Strongbow Exploration Inc. and Fortress Minerals Corp. As well, Ms. Thomas is a director of the University of Toronto’s Alumni Association, Lassonde Advisory Board of the University of Toronto, Prospectors and Developers Association of Canada and the Northwest Territories and Nunavut Chamber of Mines. She is also a member of the University of Toronto’s President’s Internal Advisory Council.

(1) Audit Committee

(2) Board Policy, Strategy Review and Governance Committee

(3) Human Resources and Compensation Committee

(4) Environment, Health and Safety Committee

Suncor’s most recently filed Form 40-F included, as exhibits, the certifications of our Chief Executive Officer and Chief Financial Officer required by Sections 302 and 906 of the United States Sarbanes-Oxley Act of 2002.

Corporate Officers*

Richard L. George	Sue Lee
President and Chief Executive Officer	Senior Vice President,
	Human Resources and Communications
J. Kenneth Alley
	Kevin D. Nabholz
Senior Vice President
and Chief Financial Officer	Executive Vice President,
	Major Projects
M. (Mike) Ashar
	Janice B. Odegaard
Executive Vice President,
Refining and Marketing – U.S.A.	Vice President,
	Associate General Counsel and Corporate Secretary
David W. Byler
	Thomas L. Ryley
Executive Vice President,
Natural Gas and Renewable Energy	Executive Vice President,
	Energy Marketing and Refining – Canada
Bart W. Demosky
	Jay Thornton
Vice President and Treasurer
	Senior Vice President,
Terrence J. Hopwood	Business Integration
Senior Vice President	Steven W. Williams
and General Counsel
	Executive Vice President,
	Oil Sands

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 (U.S.A.) Inc., Suncor’s U.S.-based downstream subsidiary; Mr. Ryley is the president of Suncor’s Canada-based downstream subsidiaries, Suncor Energy Marketing Inc. and Suncor Energy Products Inc., respectively; 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.

* This information reflects the positions of officers at December 31, 2006. In March 2007, Suncor announced a restructuring of the company’s executive management team. See page 16 for details.

The Dow Jones Sustainability Index (DJSI) follows a best-in-class approach comprising the sustainability leaders from each industry. Suncor has been part of the index since the DJSI was launched in 1999.	As an Imagine Caring Company, Suncor contributes 1% of its domestic pretax profit to registered charities.

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	Suncor is committed to working in an environmentally responsible manner. This annual report is printed on paper containing 30% post-consumer waste and is acid free.
	Please recycle this annual report.

EX-99.2

Exhibit 99.2

018	Suncor Energy Inc.
	2006 Annual Report

Management’s discussion and analysis

February 28, 2007

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 60 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 58.

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 commissions 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. All such references are inactive, textual references only.

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 and the range of cost estimates associated with an “on-budget” project, see the “Significant Capital Project Update” on page 27.

Suncor Energy Inc.	019
2006 Annual Report

Suncor overview and strategic priorities

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate four 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 (NG) produces natural gas in Western Canada, providing revenues and serving as a price hedge against the company’s internal natural gas consumption in our oil sands and downstream operations. This business also supports Suncor’s sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

•Energy Marketing and Refining – Canada (EM&R) operates a 70,000 barrel per day (bpd) capacity refinery and a 200 million litre per year ethanol plant, both in Sarnia, Ontario. As well, EM&R markets refined petroleum products to customers primarily in Ontario and Quebec. EM&R also manages our company-wide energy marketing and trading activities and sales of all Oil Sands and NG production. Financial results relating to the sales of Oil Sands and NG production are reported in the respective business segments.

•Refining and Marketing – U.S.A. (R&M) operates a 90,000 bpd capacity refinery in Commerce City, Colorado, as well as related pipeline assets. R&M markets refined petroleum products to customers throughout Colorado.

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

Suncor’s strategic priorities are:

Operational:

•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 that meet market demand.

•Increasing production capacity and improving reliability through staged expansion, continued focus on operational excellence and worksite safety.

•Integrating Oil Sands production into the North American energy market through Suncor’s refineries and the refineries of other customers to reduce vulnerability to supply and demand imbalances.

•Managing environmental and social performance to reduce intensity of our water use, air and greenhouse gas emission and our impact on the 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.

•Maintaining a strong balance sheet by closely managing debt and capital spending.

We expect our current growth to 350,000 bpd in 2008 to support an annual average 15% return on capital employed (ROCE) assuming a US$35 West Texas Intermediate (WTI) crude oil price and a Cdn$/US$ exchange rate of $0.80. Longer term, we are targeting a 15% ROCE at a sustainable long-term crude oil price. Estimates of ROCE are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs.

020	Suncor Energy Inc.
	2006 Annual Report

2006 Overview

•Combined oil sands and natural gas production in 2006 was 294,800 barrels of oil equivalent (boe) per day, compared to 206,100 boe per day in 2005. Oil sands production averaged 260,000 bpd in 2006 (253,800 bpd of synthetic crude oil and 6,200 bpd of bitumen sold directly to the market), compared to 171,300 bpd in 2005. Natural gas production averaged 191 million cubic feet (mmcf) per day, compared to an average 190 mmcf per day in 2005.

•Oil sands cash operating costs averaged $21.70 per barrel during 2006 compared to $24.55 per barrel in 2005. The decrease in 2006 was primarily due to fixed operating costs being spread over higher production volumes, as well as lower natural gas costs.

•Suncor continued to make progress on the addition of the coker unit to Upgrader 2. At year-end, construction was approximately 70% complete. The project remains on schedule and within budget.

•Average daily in-situ bitumen production from Suncor’s Firebag facilities increased to 33,700 bpd in 2006 from 19,100 bpd in 2005.

•Plans for Suncor’s next major stage of oil sands growth were also advanced in 2006 with receipt of regulatory approval for a planned third upgrader, a key component in the company’s Voyageur Strategy to increase production to 500,000 to 550,000 bpd in 2010 to 2012.

•In its U.S. downstream operations, Suncor completed modifications in June to the company’s Commerce City refining operation that enabled production of ultra low sulphur diesel fuel and the integration of up to 15,000 bpd of oil sands sour crude into the refinery’s feedstock.

•In Suncor’s Canadian downstream operations, modifications were completed in July to enable the company’s Sarnia refinery to meet ultra low sulphur diesel requirements. The second stage of this project, slated for completion in the fourth quarter of 2007, is planned to integrate up to 40,000 bpd of oil sands sour crude into the facility’s feedstock and to improve the economic performance of the refinery.

•While continuing to expand its integrated oil sands and downstream refining and marketing businesses, Suncor also made advances in its renewable energy strategy with the opening of Canada’s largest ethanol plant and the commissioning of its third wind farm. Further investment in ethanol-based biofuels and a fourth wind farm are planned for 2007.

•Maintaining a strong balance sheet remained a priority in 2006. Suncor’s net debt (short and long-term debt less cash and cash equivalents) at December 31, 2006, was $1.9 billion (approximately 0.4 times cash flow from operations). Year-end net debt in 2005 was $2.9 billion (approximately 1.2 times cash flow from operations).

•Suncor achieved a company-wide return on capital employed of 40.6% in 2006 (excluding capitalized costs for major projects in progress), compared to 19.7% in 2005. Including capitalized costs related to major projects in progress, return on capital employed was 30.4% in 2006, and 14.3% in 2005.

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Selected financial information

Annual Financial Data

Year ended December 31 ($ millions except per share data)	2006	2005	2004
Revenues	15 829	11 129	8 705
Net earnings	2 971	1 158	1 076
Total assets	18 781	15 149	11 774
Long-term debt	2 385	3 007	2 217
Dividends on common shares	127	102	97
Net earnings attributable to common shareholders per share – basic	6.47	2.54	2.38
Net earnings attributable to common shareholders per share – diluted	6.32	2.48	2.33
Cash dividends per share	0.30	0.24	0.23

Outstanding Share Data

As at December 31, 2006 (thousands)
Number of common shares	459 944
Number of common share options	19 809
Number of common share options – exercisable	8 627

Quarterly Financial Data

	2006				2005
	Quarter ended				Quarter ended
($ millions except per share)	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Revenues	3 787	4 114	4 070	3 858	3 521	3 149	2 385	2 074
Net earnings	358	682	1 218	713	693	315	83	67
Net earnings attributable to common shareholders per share
Basic	0.78	1.48	2.65	1.56	1.52	0.69	0.18	0.15
Diluted	0.76	1.45	2.59	1.52	1.48	0.67	0.18	0.14

Net Earnings⁽¹⁾

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	2 824	976	970
Natural Gas	109	155	115
Energy Marketing and Refining – Canada	86	41	80
Refining and Marketing – U.S.A.(3)	168	142	34

Cash Flow from Operations⁽¹⁾

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	3 902	1 878	1 734
Natural Gas	281	412	319
Energy Marketing and Refining – Canada	217	152	188
Refining and Marketing – U.S.A.(3)	281	247	59

Capital Employed^{(1) (2)}

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	5 092	4 472	4 105
Natural Gas	861	563	448
Energy Marketing and Refining – Canada	1 023	486	512
Refining and Marketing – U.S.A.(3)	831	327	232

(1)Excludes Corporate and Eliminations segment.

(2)Excludes major projects in progress.

(3)Refining and Marketing – U.S.A. 2006 and 2005 data includes results of the former Colorado Refining Company, acquired May 31, 2005.

022	Suncor Energy Inc.
	2006 Annual Report

Fluctuations in quarterly net earnings for 2006 and 2005 were due to a number of factors:

•Significantly higher Oil Sands production and sales volumes during 2006, following the September 2005 completion of recovery work to repair portions of the facilities damaged in the January 2005 fire, and the subsequent expansion of synthetic crude oil production capacity (to 260,000 bpd from 225,000 bpd).

•Changes in U.S. dollar denominated crude oil and natural gas prices. WTI averaged US$66.20 per barrel (bbl) in 2006 compared to US$56.55/bbl in 2005, and Henry Hub natural gas prices averaged US$7.25/mcf in 2006, compared to US$8.55/mcf in 2005.

•Cash operating costs varied due to variations in Oil Sands production levels, the timing and amount of maintenance activities, increased insurance expenses, and the price and volume of natural gas used for energy in Oil Sands operations.

•Alberta Oil Sands Crown royalties fluctuated as a result of changes in crude oil commodity prices and the extent and timing of annual capital and operating expenditures.

•Commodity and 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 prices have historically reflected higher demand for vehicle fuels and asphalt in summer and heating fuels in winter, although 2006 saw these variations reduced significantly. Improved refining margins in 2006 compared to 2005 were partially offset by decreasing retail margins resulting from competitive market conditions.

•Realized commodity prices were unfavourably impacted by continued increases in the 2006 and 2005 average Cdn$/US$ exchange rates, which reduced the Canadian dollar revenues earned. The minimal increase in the year-end exchange rate resulted in no net foreign exchange gains for the U.S. dollar denominated debt in 2006, after a $37 million pretax gain in 2005.

•Reductions in both the federal and Alberta provincial corporate tax rates during the second quarter of 2006 increased 2006 net earnings by $419 million.

•The timing and amount of insurance receipts in both 2006 and 2005 related to the 2005 Oil Sands fire.

Consolidated Financial Analysis

This analysis provides an overview of our consolidated financial results for 2006 compared to 2005. For a detailed analysis, see the various business segment analyses.

Net Earnings

Our net earnings were $2.971 billion in 2006, compared with $1.158 billion in 2005 (2004 – $1.076 billion). The increase was primarily due to higher Oil Sands production coupled with increased U.S. dollar benchmark crude oil prices, strong refining margins in our downstream operations, and the substantive enactment of both federal and Alberta provincial income tax rate reductions in 2006. These positive impacts were partially offset by higher royalty expenses, increased maintenance and labour expenses, and additional third party insurance premium during 2006. The impact of a stronger Canadian dollar also reduced the sales value of Suncor’s U.S. dollar denominated products.

Net Earnings Components ⁽¹⁾

Year ended December 31 ($ millions, after-tax)	2006		2005		2004
Net earnings before the following items:	2 333		838		969
Firebag in-situ start-up costs	(13	)	(4	)	(14	)
Oil Sands fire accrued insurance proceeds (2)	232		293		—
Impact of income tax rate reductions on opening net future income tax liabilities	419		—		53
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	—		31		68
Net earnings as reported	2 971		1 158		1 076

(1)This table explains 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.

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Industry Indicators

(Average for the year unless otherwise noted)	2006		2005	2004
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	66.20		56.55	41.40
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	73.05		69.00	52.55
Light/heavy crude oil differential US$/barrel WTI at Cushing less Lloydminster Blend at Hardisty	21.85		20.90	13.55
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	7.25		8.55	6.20
Natural gas (Alberta spot) Cdn$/mcf at AECO	7.00		8.50	6.80
New York Harbour 3-2-1 crack US$/barrel (1)	9.80		9.50	6.90
Ontario refined product demand percentage change over prior year (2)	(1.6	)	0.1	4.3
Colorado light product demand percentage change over prior year (3)	2.2		2.5	7.2
Exchange rate: Cdn$/US$	0.88		0.83	0.77

(1)New York Harbour 3-2-1 crack is an industry indicator measuring the margin on 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.

(2)Figures for 2004 and 2005 are based on published government data. Figure for 2006 is an internal estimate based on preliminary government data.

(3)Figures for 2004 and 2005 are based on public reporting by state and government agencies. The 2006 figure is based on consensus estimates by third party consultants.

Revenues were $15.8 billion in 2006, compared with $11.1 billion in 2005 (2004 – $8.7 billion). Excluding the impact of net insurance proceeds related to the January 2005 fire at our Oil Sands operations, the increase was primarily due to the following:

•Production and sales volumes increased significantly during 2006, reflecting the October 2005 production capacity expansion to 260,000 bpd from 225,000, and the completion of recovery work from damage caused by the January 2005 fire.

•Average crude oil prices were higher in 2006 than in 2005. A 17% increase in average U.S. dollar WTI benchmark prices increased the selling price of Oil Sands crude oil production. This was partially offset by a 5% widening of the average light/heavy crude oil differentials compared to the WTI benchmark index. A 6% increase in the average Cdn$/US$ exchange rate resulted in lower realizations on our crude oil sales basket. Because crude oil is primarily sold based on U.S. dollar benchmark prices, a narrowing of the exchange rate difference produced a corresponding reduction in the Canadian dollar value of our products.

•Refined product wholesale prices in both EM&R and R&M were higher due to higher crude oil benchmark prices. In addition, 2006 reflects a full year of refined product sales volumes in R&M attributable to our acquisition of the Colorado Refining Company in the second quarter of 2005.

•The absence of strategic crude oil hedging losses in 2006 increased revenues by $535 million. During 2005, we sold 36,000 bpd of our crude oil production at an average fixed price of US$23/bbl. These hedges expired at December 31, 2005.

•Energy marketing and trading revenues increased to $1,582 million in 2006 compared to $827 million in 2005. The increase is due primarily to increased physical trading activities and higher average commodity prices. The results of energy marketing and trading are evaluated net of energy marketing and trading expenses. For a discussion of these net results, see page 33.

Partially offsetting these increases were the following:

•Retail prices in both EM&R and R&M reflected increasingly competitive pricing markets in the Ontario and Colorado regions.

•Lower price realizations on natural gas. Realized natural gas prices were $7.15 per thousand cubic feet (mcf) in 2006 compared to $8.57 per mcf in 2005, reflecting lower benchmark commodity prices.

Overall, increased production in our Oil Sands operations increased revenues by approximately $2.2 billion; higher crude oil prices, net of the impact of the higher average Cdn$/US$ exchange rate, increased total revenues by approximately $745 million; and the absence of hedging losses increased revenues by approximately $535 million.

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	2006 Annual Report

Purchases of crude oil and products were $4.7 billion in 2006 compared with $4.2 billion in 2005 (2004 – $2.9 billion). The increase was primarily due to the following:

•Higher benchmark crude oil prices. This had the largest impact on product purchases for EM&R and R&M as WTI increased 17% over the prior year.

•Increased purchases of crude oil feedstock and refined products to meet sales commitments during planned maintenance shutdowns in both EM&R and R&M, and to more fully utilize the additional refining capacity acquired by R&M in the second quarter of 2005.

•Additional purchases of crude oil and products to meet plant and customer demands associated with unplanned maintenance at our Oil Sands operations.

Operating, selling and general expenses were $3.0 billion in 2006 compared with $2.4 billion in 2005 (2004 – $2.0 billion). The primary reasons for the increase were:

•An increase in the costs associated with planned and unplanned maintenance activities and labour costs.

•Higher stock-based compensation expenses as a result of the increase in our share price.

Transportation and other costs were $212 million in 2006 compared to $152 million in 2005 (2004 – $132 million). The increase in transportation costs was primarily due to increased volumes shipped out of the Fort McMurray area, and the increased shipments of Oil Sands sour crude blends to the U.S. Gulf Coast market.

Depreciation, depletion and amortization (DD&A) was $695 million in 2006, compared to $568 million in 2005 (2004 – $514 million). DD&A at Oil Sands increased by $55 million, primarily due to the inclusion of newly commissioned upgrading facilities and Firebag Stage 2 operations in our depreciable cost base during the fourth quarter of 2005. The DD&A for EM&R and R&M increased by $21 million and $15 million respectively in 2006 as a result of the completion of capital projects during the year, and the inclusion of these costs in our depreciable cost base. The capital projects for both EM&R and R&M were facility upgrades to enable production of ultra low sulphur diesel, in addition to the new ethanol facility completed in EM&R.

Royalty expenses were $1,038 million in 2006 compared with $555 million in 2005 (2004 – $531 million). The increase in 2006 was primarily due to increased Oil Sands royalties reflecting higher sales volumes, and higher price realizations. For a discussion of Oil Sands Crown royalties, see page 29.

Taxes other than income taxes were $595 million in 2006 compared to $529 million in 2005 (2004 – $540 million). The increase was primarily due to higher sales volumes subject to fuel excise taxes in our Oil Sands operations.

Financing expenses were $39 million in 2006 compared with income of $15 million in 2005 (2004 – expenses of $24 million). The increase in financing expenses was primarily due to the absence of any offsetting foreign exchange gains on our U.S. dollar denominated long-term debt. Interest expense on long-term debt was consistent with the prior year, with the impact of higher interest rates offset by lower debt levels. Total interest expense, net of capitalized interest, was $21 million in 2006 compared to $32 million in 2005. Capitalized interest was $129 million in 2006 compared to $119 million in 2005.

Income tax expense was $835 million in 2006 (22% effective tax rate), compared to $694 million in 2005 (37% effective tax rate) and $526 million in 2004 (33% effective tax rate). Income tax expense in both 2006 and 2004 included the effects of reductions in federal and Alberta provincial tax rates that reduced opening future income tax liabilities as follows:

Impact of Tax Rate Changes on Segmented Earnings

			Energy
			Marketing
			& Refining			2006	2005	2004
($ millions, increase (decrease) in earnings)	Oil Sands	Natural Gas	– Canada	Corporate		Total	Total	Total
Federal	290	36	5	(39	)	292	—	—
Provincial	139	17	—	(29	)	127	—	53
	429	53	5	(68	)	419	—	53

Excluding these adjustments, income tax expense in 2006 was $1,254 million (33% effective tax rate) and $579 million in 2004 (36% effective tax rate).

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2006 Annual Report

Corporate Expenses

After-tax net corporate expenses were $216 million in 2006 compared to $156 million in 2005 (2004 – $123 million). Excluding the impact of group elimination entries, actual after-tax net corporate expenses were $222 million in 2006 (2005 – $167 million; 2004 – $111 million). The increase in net expenses resulted primarily from additional future tax expense as a result of the revaluation of future income taxes, higher stock-based compensation expenses and an increase in DD&A relating to our new enterprise resource planning system implemented throughout 2006. These factors were partially offset by the elimination of the self-insurance entity premium expense (fully offset in our Oil Sands segment). Corporate had a net cash deficiency of $443 million in 2006, compared with $105 million in 2005 (2004 – $325 million). The additional deficiency in 2006 was primarily due to changes in working capital.

Breakdown of Net Corporate Expense

Year ended December 31,
($ millions)	2006		2005		2004
Corporate expenses	222		167		111
Group eliminations	(6	)	(11	)	12
Total	216		156		123

Consolidated Cash Flow from Operations

Cash flow from operations was $4.533 billion in 2006 compared to $2.476 billion in 2005 (2004 – $2.013 billion). The increase in cash flow from operations was primarily due to the same factors that impacted net earnings, with the exception of DD&A, foreign exchange gains on our U.S. dollar denominated long-term debt in 2005, and future income taxes, all of which are non-cash items.

Dividends

Total dividends paid during 2006 were $0.30 per share, compared with $0.24 per share in 2005 (2004 – $0.23 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 2006, the Board approved an increase in the quarterly dividend to $0.08 per share from $0.06 per share.

Liquidity and Capital Resources

At December 31, 2006, our capital resources consisted 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 Cdn$/US$ exchange rates.

At December 31, 2006, our net debt was approximately $1.9 billion compared to $2.9 billion at December 31, 2005. The decrease in debt levels was primarily a result of higher cash flow from operations.

In 2006, the following changes to our available credit facilities were completed:

•A $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five-year term maturing in June 2011. In addition, the credit limit was increased by $500 million to $2 billion total funds available.

•A $200 million credit facility agreement was renegotiated and the credit limit was increased by $100 million to $300 million total funds available.

•A $600 million credit facility agreement matured and was not renewed.

Our undrawn lines of credit at December 31, 2006, were approximately $1.8 billion. Suncor’s current long-term senior debt ratings are A- by Standard & Poor’s, A(low) by Dominion Bond Rating Service and A3 by Moody’s Investors Service. All debt ratings have a stable outlook.

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 continuing at low levels. To manage fixed versus floating rate exposure, we have entered into interest rate swaps with investment grade counterparties, resulting in the swapping of $600 million of fixed rate debt to variable rate borrowings.

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 managing project costs and debt levels.

We believe we have the capital resources to fund our 2007 capital spending program of $5.3 billion and to meet current working capital requirements. If additional capital is required, we believe adequate additional financing is available at commercial terms and rates.

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We anticipate our growth plan will be financed from internal cash flow, which is dependent on commodity prices and production levels, as well as debt. We plan to continue to evaluate strategic crude oil hedging opportunities to provide downside protection against adverse changes in commodity prices (See page 31 for a discussion of our crude oil hedging program). After 2006, to support our growth strategy and sustain operations, we are projecting an annual capital spending program of approximately $5 billion. Actual spending is subject to change due to such factors as internal and external approvals and capital availability. Refer to the discussion under Risk Factors Affecting Performance on page 30 for additional factors that can have an impact on our ability to generate funds to support investing activities.

During the fourth quarter of 2006, we received the final settlement of our property damage claim related to the January 2005 Oil Sands fire.

Effective May 15, 2006, our primary business interruption insurer discontinued operations. During the third quarter 2006, we recorded additional premium expenses related to losses incurred by this insurer primarily relating to hurricane activity in the Gulf of Mexico during the summer of 2005.

Aggregate Contractual Obligations and Off-balance Sheet Financing

	Payments Due by Period
($ millions)	Total	2007	2008-09	2010-11	Later Years
Fixed-term debt, commercial paper (1)	2 347	681	—	500	1 166
Capital leases	38	1	3	3	31
Interest payments on fixed-term debt, commercial paper and capital leases (1)	2 393	144	222	224	1 803
Employee future benefits (2)	565	40	90	104	331
Asset retirement obligations (3)	1 657	104	175	96	1 282
Non-cancellable capital spending commitments (4)	216	216	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	5 346	279	577	574	3 916
Total	12 562	1 465	1 067	1 501	8 529

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 resold shortly after purchase, are one example of excluded items.

(1)Includes $2,066 million of U.S. and Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2007 to 2034. Interest rates vary from 5.95% to 7.15%. We entered into various interest rate swap transactions maturing in 2007 and 2011 that resulted in an average effective interest rate in 2005 ranging from 5.2% to 6.0% on $600 million of our medium-term notes. Approximately $280 million of commercial paper with an effective interest rate of 4.3% was issued and outstanding at December 31, 2006.

(2)Represents the undiscounted expected funding by the company to its pension plans as well as benefit payments to retirees for other post-employment 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 $216 million at the end of 2006. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2007, we anticipate spending approximately $900 million at our Oil Sands operations 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.

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 28) 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, 2006, we were in compliance with all covenants and our debt ratings were investment grade with a stable outlook. For more information, see page 25.

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2006 Annual Report

Significant Capital Project Update

We spent $3.5 billion on capital investing activities in 2006 compared to $2.7 billion ($3.1 billion including the cost of the fire rebuild and capitalized interest) in 2005 (2004 – $1.7 billion). The projects listed below represent the significant individual capital projects underway to support both our growth and sustaining capital needs. For a discussion of our Oil Sands growth strategy, refer to page 46. All projects listed below have received Board of Directors approval.

	Cost		Spent		Total Spent
	Estimate		in 2006		to Date
Description	($ millions)	(1)	($ millions)		($ millions)		Status (1)
Oil Sands
Coker unit (2)	2 100		665		1 590		Project is on schedule and on budget.
Millennium naphtha unit (3)	650		80		85		Project is on schedule and on budget.
Steepbank extraction plant (4)	880		55		65		Project is on schedule and on budget.
Firebag cogeneration and expansion	400		190		315		Project is on schedule and on budget.
EM&R
Diesel desulphurization
and oil sands integration	960		320		800		Project is on schedule; and cost estimate has been revised from the April 2005 estimate of $800 million. (5)
R&M
Diesel desulphurization	540		115		530
and oil sands integration	(US$445	)	(US$95	)	(US$435	)	Project complete. (6)

(1)Estimating and budgeting for major capital projects is a process that involves uncertainties and that evolves in stages, each with progressively more refined data and a correspondingly narrower range of uncertainty. At very early stages, when broad engineering design specifications are developed, the level of uncertainty can result in price ranges with -30%/+50% (or similar) levels of uncertainty. As project engineering progresses, vendor bids are studied, goods and materials ordered and we move closer to the build stage, the level of uncertainty narrows. Generally, when projects receive final approval from our Board of Directors, our cost estimates have a range of uncertainty that has narrowed to the -10%/+10% or similar range. The projects noted in the above table have cost estimates within this range of uncertainty. These ranges establish an expected high and low capital cost estimate for a project. When we say that a project is “on budget,” we mean that we still expect the final project capital cost to fall within the current range of uncertainty for the project. Even at this stage, the uncertainties in the estimating process and the impact of future events, can and will cause actual results to differ, in some cases materially, from our estimates.

(2)Excludes costs associated with bitumen feed.

(3)The Millennium naphtha unit project is expected to enhance the product mix of our oil sands production.

(4)The Steepbank extraction plant will replace and enhance existing base plant extraction facilities.

(5)See page 52 for discussion.

(6)In the first quarter of 2006, the project budget was increased to a final expected cost of US$445 million from then-current estimates of US$390 million. The original cost estimate was US$300 million.

The addition of a third upgrader has not yet been approved by Suncor’s Board of Directors. Suncor has not yet announced firm capital cost estimates for this project as the cost estimate, together with the final configuration of the project, is still under development. However, preliminary figures including those in Suncor’s regulatory approval application are under upward pressure. Detailed engineering is expected in 2007, at which time final approval to proceed with the project will be considered by Suncor’s Board of Directors. Subject to Board approval, the project will be included in the above table at that time.

To date approximately $900 million has been approved for planning and scoping initiatives related to project design for the third upgrader.

Suncor’s Firebag Stage 3 project is expected to be submitted for final Board of Director’s approval in 2007. To date approximately $550 million has been approved for planning and scoping initiatives related to project design.

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	2006 Annual Report

Variable Interest Entities and Guarantees and Off-balance Sheet Arrangements

At December 31, 2006, we had off-balance sheet arrangements with Variable Interest Entities (VIEs), and indemnification agreements with other third parties, as described below.

We have a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million (2005 – $340 million) of accounts receivable 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, 2006, $170 million (2005 – $340 million) in outstanding accounts receivable had been sold under the program. Although the company does not believe it has any significant exposure to credit losses, under the recourse provisions, we provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $72 million in 2006 and no contingent liability or earnings impact have 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, 2006, were $170 million and approximately $623 million, respectively. We recorded an after-tax loss of approximately $2 million on the securitization program in 2006 (2005 – $4 million; 2004 – $2 million).

In 1999, we entered into an equipment sale and leaseback arrangement with a 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 January1, 2005. The initial lease term covered a period of seven years, and had been accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2006, the VIE did not have any assets or liabilities.

We have agreed to indemnify holders of the 7.15% fixed-term U.S. dollar notes, the 5.95% fixed-term U.S. dollar notes 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.

Outlook

During 2007, management will focus on the following operational priorities:

•Achieve annual oil sands production (including bitumen sold directly to the market) of 260,000 to 270,000 bpd with a cash operating cost average of $21.50 to $22.50 per barrel. Steady and reliable production will help us manage cash operating costs.

•Increase natural gas production (including natural gas liquids and crude oil) to an average 215 to 220 mmcf equivalent per day. We expect to bring several existing wells into production and will continue to focus on high-volume deep gas prospects in 2007.

•Advance plans for increased bitumen supply. Launch the regulatory, consultation and engineering work required to determine mine development potential for Voyageur South (Lease 23), receive Board of Director approval for our Firebag Stage 3 in-situ development, including cost estimates.

•Safely complete all planned expansion tie ins. Complete a 50-day shutdown on Upgrader 2 to perform planned maintenance and tie in expanded facilities that are expected to increase production to 350,000 bpd in 2008. At the Sarnia refinery, complete a
65-day shutdown to tie in new and modified equipment to allow the processing of up to 40,000 bpd of oil sands sour crude.

•Advance plans for increased upgrader capacity. Complete the Engineering Design Study (EDS) phase, which is necessary to seek Board of Directors approval to proceed with construction of our planned third oil sands upgrader, a key component of achieving more than half a million bpd by 2010 to 2012.

•Continue to improve safety performance.

•Focus on enterprise-wide efficiency. For example, improved operational reliability is the goal of establishing a single-vendor, performance-based maintenance contract for all Canadian facilities.

•Maintain a strong balance sheet. With capital spending plans of more than $5 billion, a strong balance sheet will be critical. Suncor is targeting debt at a maximum of two times cash flow.

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2006 Annual Report

•Continue to pursue energy efficiencies, greenhouse gas offsets and new, renewable energy projects. We plan to continue investment in biofuels and to commission our fourth – and largest yet – joint venture wind power project in 2007. Complete the stakeholder consultation and preliminary engineering needed to determine feasibility of expanding the St. Clair Ethanol facility.

Oil Sands Crown Royalties and Cash Income Taxes

Under the current Province of Alberta oil sands royalty regime, Alberta Crown royalties for oil sands projects are 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 at 1% of R. The Alberta government has classified Suncor’s current Oil Sands operations as two distinct “projects” for royalty purposes: Suncor’s base oil sands mining and associated upgrading operations with royalties based on upgraded product values, and the current Firebag in-situ project with royalties based on bitumen values under the government’s generic bitumen-based royalty regime for oil sands projects.

In 1997, Suncor was granted an option by the government to transition our base operations on January 1, 2009, to the generic bitumen-based royalty regime, subject to finalizing certain terms of transition. Suncor and the government reached agreement on the terms and conditions of our option in the third quarter of 2005. In November 2006, we exercised our option to convert to the bitumen-based royalty. As a result, starting January 1, 2009, we expect to pay a royalty in respect of our base operations of 25% of R-C, with “R” based on bitumen rather than upgraded product values, and “C” excluding substantially all of the upgrading costs.

In 2006, the Department of Energy proposed a new methodology for determining the “R” related to bitumen using an synthetic crude oil (SCO) value less an upgrading processing cost of service charge. This methodology would generally result in higher attributed bitumen values than those used under the current formula. The Crown is consulting with industry, with a decision on the methodology anticipated by January1, 2008.

A new bitumen pricing methodology is not expected to affect base operation royalties until our transition to the bitumen-based regime effective January 1, 2009. However, for our Firebag operations the pricing methodology could be retroactively applied to November 1, 2003, when Firebag commenced production. The outcome of this review is uncertain, and future royalties payable as well as the determination of net reserves may be affected.

In addition, the Government of Alberta has announced a review of its Crown royalties, to be completed by the summer of 2007.

Assuming anticipated levels of operating expenses and capital expenditures for each project remain relatively constant, and there are no changes to the current Government of Alberta oil sands royalty regime or the government’s application of the applicable rules (including no changes to the bitumen pricing methodology), and no other unanticipated events occur, we believe future variability in Oil Sands royalty expense will primarily be a function of changes in annual Oil Sands revenue. On that basis, we would generally expect Alberta Crown royalty expense for Oil Sands to range as set forth in the following chart. For years after 2008, this percentage range may decline as anticipated new in-situ production attracts royalties based on bitumen values at 1% until project payout. Although we have assumed there will be no change in the methodology for determining the price of bitumen used to determine “R,” the methodology is not likely to be finalized until 2008, and as a result, the potential impacts are not currently known but may be material.

Anticipated Royalty Expense Based on Certain Assumptions

For the period from 2007-2012
WTI Price/bbl (US$)	40	50	60
Natural gas price per mcf at Henry Hub (US$)	6.75	8.25	10.00
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast (US$)	9.60	12.60	15.10
Cdn$/US$ exchange rate	0.80	0.85	0.90
Crown Royalty Expense % (based on percentage of total Oil Sands revenue)
2007-2008 (all cases 2007 @ $50)	7-8	7-10	7-12
2009-2012 (1)	4-5	5-7	6-8

(1) During 2006, we exercised our option to transition our base operations in 2009 to the generic bitumen-based royalty regime.

The federal opposition parties and others have requested an elimination of the oil sands accelerated depreciation of capital costs incurred; however, to date no changes have been made. Assuming there are no changes to the current

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income tax regime for 2007, we estimate we will have partial cash taxes in the range of 70-100% of expected effective tax rates, based on current prices, and current forecasts of production, capital and operating costs for 2007. Any cash tax in 2007 would be due in February 2008. Assuming there are no changes to the current income tax regime, we do not expect any significant cash tax in subsequent years until the next decade, primarily due to the company’s investment in the expansion of its oil sands operations to 500,000 to 550,000 bpd. In any particular year, our Oil Sands and Natural Gas operations may be subject to some cash income tax due to sensitivity to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for income tax purposes.

Alberta Crown royalties and cash taxes are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project. In addition, all aspects of the current Alberta oil sands royalty regime, including royalty rates and the royalty base, are subject to alteration by the Government of Alberta. Accordingly, in light of these uncertainties and the potential for unanticipated events to occur, we strongly caution that it is impossible to predict even a range of annualized royalty expense as a percentage of revenues or the impact royalties may have on our financial results, and actual differences may be material. 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.

The information in the preceding paragraphs under Oil Sands Crown Royalties and Cash Income Taxes incorporates operating and capital cost assumptions included in our current budget and long-range plan, and is not an estimate, forecast or prediction of actual future events or circumstances.

Climate Change

Our effort to reduce greenhouse gas emissions is reflected in our pursuit of greater internal energy efficiency, investment in renewable energy including wind power, carbon capture research and development, and emissions offsets.

We continue to consult with governments about the impact of the Kyoto Protocol and we plan to continue to actively manage our greenhouse gas emissions. As the announced Clean Air Act by the Conservative Government has been referred to a special committee for review and revision, the ultimate regulatory outcome is unknown. In the meantime, Suncor will continue to actively manage its air emissions, including greenhouse gases, and to advance opportunities such as carbon capture and geological sequestration, and renewable and alternate forms of energy such as wind power and biofuels.

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 and application of such legislation, stakeholder support for growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors 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/Form 40-F, filed with securities regulatory authorities. We are continually working to mitigate the impact of potential risks to our businesses. This process includes an entity wide risk review. The internal review is completed annually to ensure that all significant risks are identified and appropriately managed.

Commodity Prices, Refined Product Margins and Exchange Rates

Our future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by many factors including global and regional supply and demand, seasonality, worldwide political events and weather. These factors, among others, can result in a high degree of price volatility. For example, from 2004 to 2006 the monthly average price for benchmark WTI crude oil ranged from a low of US$34.22/bbl to a high of US$74.46/bbl. During the same three-year period, the natural gas Henry Hub benchmark monthly average price ranged from a low of US$4.40/mcf to a high of US$14.07/mcf. We believe commodity price volatility will continue.

Crude oil and natural gas prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the Cdn$/US$ 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

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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.

Changes to the Cdn$/US$ exchange rate relationship can create significant volatility in foreign exchange gains or losses.

On the outstanding US$1 billion in debt at the end of 2006, a $0.01 change in the Cdn$/US$ exchange rate would change net earnings by approximately $11 million after-tax.

Future U.S. capital projects may be partially funded from Canadian operations. A weaker Canadian dollar would result in a higher funding requirement for these projects.

Sensitivity Analysis ⁽¹⁾

			Approximate Change in
			Cash Flow
			from	After-tax
	2006		Operations	Earnings
	Average	Change	($ millions)	($ millions)
Oil Sands
Price of crude oil ($/barrel) (2)	$68.03	US$1.00	82	55
Sweet/sour differential ($/barrel)	$8.84	US$1.00	37	25
Sales (bpd)	263 100	1 000	13	9
Natural Gas
Price of natural gas ($/mcf) (2)	$7.15	0.10	5	4
Production/sales of natural gas (mmcf/d)	191	10	16	7
Consolidated
Exchange rate: Cdn$/US$	0.88	0.01	43	29

(1)The sensitivity analysis shows the main factors affecting Suncor’s annual cash flow from operations and earnings based on actual 2006 operations. The table illustrates the potential financial impact of these factors applied to Suncor’s 2006 results. A change in any one factor could compound or offset other factors.

(2)Includes the impact of hedging activities.

Derivative Financial Instruments

We periodically enter into commodity-based derivative financial instruments such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to variations in underlying commodity indices. In addition, we periodically enter into derivative financial instrument contracts such as interest rate swaps and foreign currency contracts as part of our risk management strategy to manage exposure to interest rate and foreign exchange fluctuations.

We also use energy derivatives, including physical and financial swaps, forwards and options to earn trading revenues. These trading activities are accounted for at fair value in our Consolidated Financial Statements.

Derivative contracts accounted for as hedges are not recognized in the Consolidated Balance Sheets. Realized and unrealized gains or losses on these contracts, including realized gains and losses on derivative hedging contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. See page 42 for a discussion of changes to the accounting for hedges effective January 1, 2007.

Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.

Commodity Hedging Activities 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.

To provide an element of stability to future earnings and cash flow, we resumed our strategic crude oil hedging program in the third quarter of 2005, receiving Board approval to fix a price or range of prices for up to approximately 30% of our total production of crude oil for specified periods of time. At December 31, 2006, we had entered into US$ WTI costless collar agreements covering 60,000 bpd of crude oil beginning January 1, 2007 and ending December 31, 2007, and 10,000 bpd from

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January 1, 2008 to December 31, 2008. Prices for these barrels are fixed within a range from an average of US$51.64/bbl up to an average of US$101.06/bbl.

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. On settlement of swap agreements, 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. Such cash receipts or payments offset corresponding decreases or increases in our sales revenues or crude oil 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 Segmented Statements of Earnings. In 2006, there was no net earnings impact due to crude oil hedging, compared to a decrease of $337 million in 2005 (2004 – decrease of $397 million).

Crude oil hedge contracts outstanding at December 31, 2006, were as follows:

Swap Transactions

		Average		Revenue
	Quantity	Price		Hedged		Hedge
	(bpd)	(US$/bbl)	(a)	(Cdn$ millions)	(b)	Period	(c)
Costless collars	60 000	51.64 – 93.26		1 318 – 2 380		2007
Costless collars	10 000	59.85 – 101.06		255 – 431		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 Cdn$/US$ exchange rate fluctuates during the hedge period.

(c)Original hedge term is for the full year.

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.

We have entered into various interest rate swap transactions at December 31, 2006. 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	Swap	2006 Effective
Description of swap transaction	($ millions)	Maturity	Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.2	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	6.0	%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	5.3	%

In 2006, these interest rate swap transactions reduced pretax financing expense by $6 million compared to a pretax reduction of $14 million in 2005 (2004 – $17 million pretax).

At December 31, 2006, we had also hedged €20.6 million in 2007 Euro exposure created by the anticipated purchase of equipment during the year.

Fair Value of Strategic Derivative Hedging Instruments

The fair value of derivative hedging 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 unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:

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Fair Value of Hedging Derivative Financial Instruments

($ millions)	2006		2005
Revenue hedge swaps and collars	22		(4	)
Margin hedge swaps	—		1
Interest rate and cross-currency interest rate swaps	16		22
Specific cash flow hedges of individual transactions	(4	)	5
Total	34		24

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 trading activities are accounted for using the mark-to-market method and as such all financial 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.

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

Net Pretax Earnings (Loss)

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

The fair value of unsettled financial energy trading assets and liabilities at December 31 was as follows:

Fair Value of Unsettled Financial Energy Trading Assets and Liabilities

($ millions)	2006	2005
Energy trading assets	16	82
Energy trading liabilities	13	70
Net energy trading assets	3	12

Change in Fair Value of Net Assets

($ millions)	2006
Fair value of contracts outstanding at December 31, 2005	12
Fair value of contracts realized during 2006	(6	)
Fair value of contracts entered into during the period	2
Changes in values attributable to market price and other market changes	(5	)
Fair value of contracts outstanding at December 31, 2006	3

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

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 net 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:

Counterparty Credit Risk

($ millions)	2006	2005
Derivative contracts not accounted for as hedges	16	82
Unrecognized derivative contracts accounted for as hedges	35	30
Total	51	112

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

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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. Suncor’s Oil Sands operating licence was temporarily extended in 2006 and we anticipate receipt of a new operating licence in 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 Athabasca region

•Storage, treatment, and disposal of hazardous or industrial waste

•The need to reduce or stabilize various emissions to air and withdrawals 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.

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

Another area of risk for Suncor and the oil sands industry 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 the 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 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, 2005 ($14 million as at December 31, 2005) as security for the estimated cost of our reclamation activity. Since there has been no production from Leases 86/17 in 2006, the amount of security remained unchanged.

For the Millennium and Steepbank mines, we have posted irrevocable letters of credit equal to approximately $163 million, representing security for the maximum reclamation liability in the period March 31, 2006 through March 31, 2007. For more information about our reclamation and environmental remediation obligations, refer to “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta, and is currently planned for implementation June 30, 2007. The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement of reserve life. As currently proposed, initial security deposits for oil sands mining would be reduced. 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 can involve 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.

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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. We believe the following are the most critical accounting estimates used in the preparation of our consolidated financial statements.

Reserves Estimates

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

Pursuant to U.S. disclosure requirements, we also disclose gross and net proved and probable mining reserves. The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80%. During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen-based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves. The estimate of our net mining reserves reflects the relative value of Alberta Crown and freehold royalty burdens under constant December 31 bitumen pricing and our exercise of the option to transfer to a bitumen-based Crown royalty effective 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 Alberta Crown royalty based on bitumen, rather than synthetic crude oil (for a full discussion of our oil sands Crown royalties, see “Oil Sands Crown Royalties and Cash Income Taxes” on page 29).

In addition to required disclosure, our exemption issued by Canadian securities administrators permits us to provide further disclosure voluntarily. We provide this additional voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and reserves from our Firebag in-situ leases. In our voluntary disclosure we report our aggregate reserves on the following basis:

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

•Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on normalized constant dollar cost and pricing assumptions. 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%.

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

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

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

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

Under the U.S. disclosure requirements described above, our Firebag in-situ reserves were determined to be entirely uneconomic at December 31, 2004. In 2005, Constant Cost and Pricing assumptions were again applied to assess economic viability of our in-situ reserves. This assessment resulted in the rebooking of proved reserves at December 31, 2005. At December 31, 2006, pricing assumptions were again considered economically viable and our proved reserves disclosures reflect this. (See “Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves”).

Under our voluntary disclosure, the year-end 2006 bitumen price determined pursuant to SEC pricing methodology was not materially different than the price determined pursuant to CSA Staff Notice 51-315. Consequently, for 2006 only one constant price scenario was used for year end disclosures. Refer to “Voluntary Oil Sands Reserves Disclosure - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations.”

Comparisons of reserve estimates under required U.S. Oil and Gas Mining Disclosure and Voluntary Oil Sands Reserve Disclosure 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 more significant during 2004 and 2005 with considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing.

All of our reserves have been evaluated as at December 31, 2006, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (GLJ). In reports dated February 9, 2007 (“GLJ Oil Sands Reports”), GLJ evaluated our proved and probable reserves on our oil sands mining and Firebag in-situ leases pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions.

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

For Firebag in-situ reserve estimates, GLJ considered similar factors such as our regulatory approval or likely impediments to the receipt of pending regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects and drill density. Our proved reserves are delineated to within 80 acre spacing with 3-D seismic control (or 40 acre spacing without 3-D 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 underway but have not yet received final approval from our Board.

In a report dated February 9, 2007 (“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, 2006.

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 working interest in total reserves after deducting Crown Royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about future prices, production levels, operating costs, capital expenditures, and the current Government of Alberta Royalty regime. These assumptions reflect market and regulatory conditions, as required, at December 31, 2006, 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.

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Required U.S. Oil and Gas and Mining Disclosure

Proved and Probable Oil Sands Mining Reserves

	Oil Sands Mining Leases
	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, 2005	1 528		1 440		896		862		2 424		2 302
Revisions of previous estimates	266		140		(262	)	(298	)	4		(158	)
Extensions and discoveries	—		—		—		—		—		—
Production	(85	)	(73	)	—		—		(85	)	(73	)
December 31, 2006	1 709		1 507		634		564		2 343		2 071

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80% (2005 – 80%).

(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 royalty burdens under constant December 31st pricing and incorporates our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.

Proved Conventional Oil and Gas Reserves

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

Net Proved Reserves ⁽¹⁾

Crude Oil, Natural Gas Liquids and Natural Gas

			Natural Gas
	Oil Sands business:		business: crude
	Firebag – crude		oil and natural				Natural Gas
	oil (millions		gas liquids		Total		business: natural
	of barrels		(millions		(millions		gas (billions
Constant Cost and Pricing as at December 31	of bitumen)	(2) (3) (4)	of barrels)		of barrels)		of cubic feet)
December 31, 2005	632	(3)	7		639		449
Revisions on previous estimates (5)	(57	)	—		(57	)	5
Improved recovery (6)	340		—		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

(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.

(3)   Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31. In 2004, due to unusually low year-end posted benchmark oil prices and unusually high year-end diluent prices, our proved reserves were determined to be uneconomic. Under 2005 Constant Cost and Pricing assumptions, we have rebooked our proved reserves, and these continue to be economically viable in 2006.

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

(5)   Natural gas infill drilling included in total revisions for 2006 was 11 billion cubic feet (bcf).

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

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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, 2005, to December 31, 2006, based on the GLJ Oil Sands Reports.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

													Total Mining
	Oil Sands Mining Leases (1) (2)						Firebag In-situ Leases (1) (3)						and In-situ (3)
					Proved						Proved		Proved
Millions of barrels of synthetic crude oil (1)	Proved		Probable		& Probable		Proved		Probable		& Probable		& Probable
December 31, 2005	1 528		896		2 424		561		2 137		2 698		5 122
Revisions of previous estimates	266		(262	)	4		—		22		22		26
Improved recovery	—		—		—		252		(252	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(85	)	—		(85	)	(10	)	—		(10	)	(95	)
December 31, 2006	1 709		634		2 343		803		1 907		2 710		5 053

Estimated Net Proved and Probable Oil Sands Reserves Reconciliation

													Total Mining
	Oil Sands Mining Leases (1) (2)						Firebag In-situ Leases (1) (3)						and In-situ (3)
					Proved						Proved		Proved
Millions of barrels of synthetic crude oil (1)	Proved		Probable		& Probable		Proved		Probable		& Probable		& Probable
December 31, 2005	1 440		862		2 302		556		2 029		2 585		4 887
Revisions of previous estimates	140		(298	)	(158	)	(50	)	(164	)	(214	)	(372	)
Improved recovery	—		—		—		226		(226	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(73	)	—		(73	)	(10	)	—		(10	)	(83	)
December 31, 2006	1 507		564		2 071		722		1 639		2 361		4 432

(1)   Synthetic crude oil reserves are based on a net coker, or synthetic crude oil yield from bitumen of 80% for reserves under Oil Sands Mining and under Firebag in-situ Leases. Although virtually all of our bitumen from the Oil Sands mining leases is upgraded into synthetic crude oil, we have the option of selling the bitumen produced from our Firebag in-situ leases and/or upgrading this bitumen into synthetic crude oil. Accordingly, these bitumen reserves are converted to synthetic crude oil for comparison purposes only.

(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 under constant December 31st pricing and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.

(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 three ways. Reserves from Firebag in-situ leases under our voluntary disclosure:

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

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

(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 our Firebag in-situ leases as we believe this information is useful to investors, and allows us to aggregate our mining and 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.

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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 and discounted to present value using a credit-adjusted risk-free discount rate of 5.5% (2005 – 5.6%). 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 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 35 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 Oil Sands and NG completed in the fourth quarter of 2006, we increased our estimated undiscounted total obligation to approximately $1.66 billion from the previous estimate of $1.22 billion. The increase was primarily due to a change in the Oil Sands estimate from $1.08 billion to $1.47 billion, primarily reflecting increased estimated costs related to tailings projects and increased land reclamation. The majority of the costs in Oil Sands are projected to occur over a time horizon extending to approximately 2060. In 2007, these changes in the ARO estimate are anticipated to result in additional after-tax expenses of approximately $19 million. The discounted amount of our ARO liability was $808 million at December 31, 2006, compared to $543 million at December 31, 2005.

The greatest area of judgment and uncertainty with respect to our asset retirement obligations relates to our Oil Sands mining leases where there is a requirement to provide for land productivity equivalent to pre-disturbed conditions. To reclaim tailings ponds, we are using a process referred to as consolidated tailings technology. At this time, no ponds have been fully reclaimed using this technology, although work is underway. The success and time to reclaim the tailings ponds could increase or decrease the current asset retirement cost estimates. The company continues to monitor and assess other possible technologies and/or modifications to the consolidated tailings process now being used.

Employee Future Benefits

We provide a range of benefits to our employees and retired employees, including pensions and other post-retirement benefits. The determination of obligations under our benefit plans and related expenses requires the use of actuarial valuation methods and assumptions. Assumptions typically used in determining these amounts include, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, return on plan assets, mortality rates and future medical costs. The fair value of plan assets is determined using market values. Actuarial valuations are subject to management judgment. Management continually reviews these assumptions in light of actual experience and expectations for the future. Changes in assumptions are accounted for on a prospective basis. Employee future benefit costs are reported as part of operating, selling and general expenses in our Consolidated Statements of Earnings and Schedules of Segmented Data. 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

040	Suncor Energy Inc.
	2006 Annual Report

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. A 1% change in the assumptions at which pension benefits and other post-retirement benefit liabilities could be effectively settled is as noted below.

Employee Future Benefits Liability – Sensitivity Analysis

	Rate of Return						Rate of
	on Plan Assets			Discount Rate			Compensation Increase
	1%		1%	1%		1%	1%	1%
($ millions)	Increase		Decrease	Increase		Decrease	Increase	Decrease
Increase (decrease) to net periodic benefit cost	(5	)	5	(18	)	21	9	(8	)
Increase (decrease) to benefit obligation	—		—	(136	)	161	35	(31	)

Health care costs comprise a significant element of our post-retirement benefit obligation and is an area where there is increasing cost pressure due to an aging North American population. We have assumed a 9.5% annual rate of increase in the per capita cost of covered health care benefits for 2006, with an assumption that this rate will decrease by 0.5% annually, to 5% by 2015, and remain at that level thereafter.

A 1% change in the assumed health care cost trend rate would have the following effect:

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

Property, Plant and Equipment

We account for our Oil Sands in-situ and NG 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 Oil Sands and NG exploration expenses in the Consolidated Statements of Earnings. 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 and/or adjustments in reserves. 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 management assesses that a property is fully or partially impaired, the book value of the property is reduced to fair value and either completely removed (“written off”) or partially removed (“written down”) in our records and reported as part of Oil Sands and NG DD&A expenses in the Consolidated Statements of Earnings.

Negative revisions in NG reserves estimates will result in an increase in depletion expenses.

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2006 Annual Report

The remainder of our plant and equipment are depreciated on a straight-line basis over the estimated useful life of the assets. The straight-line basis reflects asset usage as a function of time rather than production levels. For example, the useful life of plant and equipment at our Oil Sands base operations and our Firebag operations are not based on recorded reserves as we have access to other undeveloped properties, and bitumen feedstock from third parties, as well as the ability to provide processing services for other producers’ bitumen. Firebag and NG property costs are depleted on a unit of production (UOP) basis. UOP amortization is used where that method better matches the asset utilization with the production associated with the asset. In each case, the expense is shown on the DD&A line in both the Consolidated Statements of Earnings and in the Schedules of Segmented Earnings.

We determine useful life based on prior experience with similar assets and, as necessary, in consultation with others who have expertise with the assets in question. However, the actual useful life of the assets may differ from our original estimate due to factors such as technological obsolescence, regulatory requirements and maintenance activity. As the majority of assets are depreciated on a straight-line basis, a 10% reduction in the useful life of plant and equipment would increase annual DD&A by approximately 10%. This impact would be reflected in all of our business segments with the majority of the impact being in Oil Sands.

We also continuously look at ways to further utilize technological advancements and opportunities for future growth. The classification of research and development costs as either capital or expense is dependent upon specific criteria, including production feasibility, available resources and management commitment.

Control Environment

Based on their evaluation as of December 31, 2006, 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 SEC rules and forms. In addition, other than as described below, as of December 31, 2006, there were no changes in our internal control over financial reporting that occurred during 2006 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.

During 2006, we largely completed the implementation of an enterprise resource planning (ERP) system in all of our businesses to facilitate our growth plan. We believe we took the necessary steps to monitor and maintain appropriate internal control over financial reporting during this transition period. These steps included deploying resources to mitigate internal control risks and performing additional verifications and testing to ensure data integrity.

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, 2006, the company’s internal control over financial reporting was found to be operating free of any material weaknesses.

Change In Accounting Policies

Non-monetary Transactions

On January 1, 2006, the company prospectively adopted The Canadian Institute of Chartered Accountants (CICA) Handbook section 3831 “Non-monetary Transactions.” The standard requires all non-monetary transactions to be measured at fair value (if determinable) unless future cash flows are not expected to change significantly as a result of a transaction or the transaction is an exchange of a product held for sale in the ordinary course of business. The company was required to record the effects of an existing contract at Oil Sands that exchanges off-gas produced as a by-product of the upgrading operations for natural gas. An equal amount of revenues for the sale of the off-gas and purchases of crude oil and products for the purchase of the natural gas are recorded. The amount of the gross up of revenues and purchases of crude oil and products for the year ended December 31, 2006 was $126 million.

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	2006 Annual Report

Overburden Removal Costs

On January 1, 2006, the company retroactively adopted Emerging Issues Committee abstract (EIC 160) “Stripping Costs Incurred in the Production Phase of a Mining Operation.” Under the new standard, overburden removal costs should be deferred and amortized only in instances where the activity benefits future periods, otherwise the costs should be charged to earnings in the period incurred. At Suncor, overburden removal precedes mining of the oil sands deposit within the normal operating cycle, and is related to current production. In accordance with the new standard, overburden removal costs are treated as variable production costs and expensed as incurred. Previously, overburden removal was deferred and amortized on a life-of-mine approach.

Recently Issued Canadian Accounting Standards

Financial Instruments/Other Comprehensive Income/Hedges

In 2005, the CICA approved Handbook section 3855 “Financial Instruments – Recognition and Measurement,” section 1530 “Comprehensive Income” and section 3865 “Hedges.” Effective January 1, 2007, these standards require the presentation of financial instruments at fair value on the balance sheet. These standards must be applied prospectively with an initial recognition adjustment to retained earnings and accumulated other comprehensive income.

For specific transactions identified as hedges, changes in fair value are recognized in net earnings or other comprehensive income based on the type and effectiveness of the individual instruments. Upon adoption of these standards the company’s presentation will be more aligned with the current U.S. GAAP reporting as outlined in note 18 to the consolidated financial statements.

Other comprehensive income will represent the foreign currency translation of self-sustaining subsidiaries, the fair value gains/losses of specific financial investments (available for sale) and the effective portion of gains/losses of cash flow hedges. Presentation of other comprehensive income will require a change in the presentation of the Consolidated Statements of Earnings, and result in a new Statement of Comprehensive Income.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments will be recorded to the balance sheet:

Financial assets	$26 million
Financial liabilities	$13 million
Retained earnings	$5 million
Cumulative foreign currency translation	$71 million
Accumulated other comprehensive loss	$63 million

No restatement of comparative balances is permitted.

The CICA has approved additional financial instrument and capital disclosure requirements. These new requirements will become effective on January 1, 2008.

Accounting Changes

In 2006, the CICA approved revisions to Handbook section 1506 “Accounting Changes.” Effective January 1, 2007, accounting policy changes are permitted only in the event a change is made within a primary source of GAAP, or where a change is warranted to provide more relevant and reliable information. All accounting policy changes are to be applied retrospectively, unless impracticable. Any prior period errors identified also require retrospective application. The revised standards will not impact net earnings or financial position.

Stock-based Compensation

On July 6, 2006, the Emerging Issues Committee of the CICA approved an abstract (EIC 162) addressing the recognition of stock-based compensation expenses for employees eligible to retire prior to the vesting date of any award(s) issued. The abstract requires that the compensation expense be recognized over the term until the employee is eligible to retire, when earlier than the award vesting date. If the employee is eligible to retire at the time of grant, the award is to be expensed immediately. The abstract was applied retrospectively, effective December 31, 2006. No material adjustment was required in applying this standard.

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2006 Annual Report

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 strategic sales of bitumen when market conditions are favourable.

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 that meet market demand.

•Increasing production capacity and improving reliability through staged expansion, continued focus on operational excellence and work site 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)	2006	2005		2004
Revenue	7 407	3 965		3 640
Production (thousands of bpd)	260.0	171.3		226.5
Average sales price ($/barrel)	68.03	53.81		42.28
Net earnings	2 824	976		970
Cash flow from operations (1)	3 902	1 878		1 734
Total assets	13 692	11 648		9 000
Cash used in investing activities	2 230	1 882		1 039
Net cash surplus (deficiency)	2 098	(274	)	719
Sales mix (light/heavy mix)	53/47	54/46		63/37
Cash operating costs ($/barrel) (1)	21.70	24.55		15.15
ROCE (%) (2)	53.7	22.7		22.6
ROCE (%) (3)	40.4	16.3		18.5

(1)Non-GAAP measure. See page 58.

(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 58.

(3)Includes capitalized costs related to major projects in progress. See page 58.

2006 Overview

•Oil Sands recorded significantly higher production and sales volumes during 2006, following the September 2005 completion of recovery work to repair portions of the facilities damaged in a January 2005 fire, and the subsequent expansion of synthetic crude oil production capacity (to 260,000 bpd from 225,000 bpd).

•In November, the Alberta Energy and Utilities Board (EUB) approved Suncor’s application to build a third oil sands upgrader, designed to increase our production to 500,000 to 550,000 bpd in the 2010 to 2012 time frame. The EUB also conditionally approved our application to proceed with our proposed North Steepbank mine extension.

044	Suncor Energy Inc.
	2006 Annual Report

•Construction continued on the estimated $2.1 billion project that, when complete in 2008, is expected to increase upgrading capacity to 350,000 bpd. The centrepiece of this expansion is the addition of a third coker to Upgrader 2. The project remains on schedule and within budget projections. See page 27.

•Commercial operations for Stage 2 of our Firebag in-situ operations commenced as expected during the first quarter of 2006.

•In January 2007, Suncor commissioned new cogeneration facilities at its in-situ operations. A related expansion of in-situ production capacity is expected to be completed in 2007.

Analysis of Net Earnings

Net earnings were $2,824 million in 2006 compared to $976 million in 2005 (2004 – $970 million). The increase in net earnings was mainly the result of increased production and sales volumes reflecting the October 2005 production capacity expansion to 260,000 bpd and reduced production in 2005 as a result of the fire in January of that year, coupled with higher benchmark WTI prices in 2006. Net earnings also increased during 2006 as a result of the reduction of federal and Alberta provincial income tax rates. These positive impacts were partially offset by higher royalty expense resulting from higher net sales volumes and commodity prices, higher operating expenses, and increased insurance premium expense (a portion of which was paid to our self-insurance entity and is fully offset in the corporate segment with no impact on consolidated results).

Oil Sands average production was 260,000 bpd in 2006, compared to 171,300 bpd in 2005 (including bitumen sold to third parties). Sales volumes in 2006 averaged 263,100bpd compared with 165,300 bpd in 2005. Higher sales volumes increased 2006 net earnings by $1,461 million. Production and sales volumes were significantly higher in 2006 due largely to the completion of recovery work relating to the January 2005 fire, and the production capacity expansion to 260,000 bpd.

Sales volume mix of high value diesel fuel and sweet crude products remained relatively consistent year over year (2006 – 53%; 2005 – 54%). Operating issues, plant maintenance activities and the sale of minor amounts of bitumen directly to market have impacted this mix.

Sales price realizations averaged $68.03 per barrel in 2006 (with no pretax hedging losses) compared with $53.81 per barrel in 2005 (including the impact of pretax hedging losses of $535 million). The average sales price realization was favourably impacted by the absence of hedging losses and stronger WTI benchmark crude oil prices, partially offset by widening differentials for synthetic crude oil, negative impacts on sour crude oil prices due to sales of more sour crude blends at the U.S. Gulf Coast, and by a higher average Cdn$/US$ exchange rate. As crude oil is sold based on U.S. dollar benchmark prices, the increased average Cdn$/US$ exchange rate decreased the Canadian dollar value of crude oil products.

The net impact of the above pricing factors increased net earnings by $955 million in 2006.

Bridge Analysis of Net Earnings

($ millions)

Net Fire Proceeds

In 2006, we recognized $436 million in insurance proceeds (2005 – $572 million), net of the write-off of damaged assets and related expenses. During 2006, we reached final settlement on all our insurance claims relating to the January 2005 fire. This included $92 million (2005 – $115 million) from our property loss policy and $385 million

Suncor Energy Inc.	045
2006 Annual Report

Production

Year ended December 31 (thousands of bpd)	02	03	04	05	06
	205.8	216.6	226.5	171.3	260.0

(2005 – $594 million) in proceeds from our Business Interruption policies. For further discussion of our insurance activities during the year, see page 26.

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, increased to $2,497 million from $1,629 million in 2005 (2004 - $1,431 million). Expenses were higher year over year due to the following factors:

•Higher total production and sales levels.

•Higher costs associated with unplanned maintenance, including an increase in the purchases of crude oil and products to meet plant and customer demands during maintenance outages.

•Increased transportation costs primarily due to increased volumes shipped out of the Fort McMurray area, and the increased shipments of Oil Sands sour crude blends to the U.S. Gulf Coast market.

•Higher labour costs, including costs associated with maintenance as well as contract labour costs related to managing operations to minimize impacts of the global shortage of heavy vehicle tires.

Overall, increased cash expenses reduced net earnings by $552 million.

Royalties

Oil Sands Alberta Crown royalties increased to $911 million in 2006 compared to $406 million in 2005 (2004 – $407 million). The higher royalty expense reflects the impact of higher sales volumes and commodity prices during 2006. Alberta Oil Sands Crown royalties are subject to change as policies arising from the government’s position are finalized and audits of 2006 and prior years are completed. 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 29.

Non-cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $385 million from $330 million in 2005 (2004 – $299 million). The increase was primarily due to the inclusion of newly commissioned upgrading facilities and Firebag Stage 2 operations in our depreciable cost base, during the fourth quarter of 2005. Higher non-cash expenses decreased net earnings by $40 million.

A change in accounting policy for certain non-monetary transactions (see page 41) resulted in certain natural gas costs and offsetting revenues, previously not recorded, being recorded in 2006. The amounts reflected in revenue and expense for 2006 totaled $126 million. There was no impact to net earnings or cash flow from operations.

Tax Adjustments

In the second quarter of 2006, reductions to the federal and Alberta provincial income tax rates resulted in a $429 million increase in the net earnings of the Oil Sands segment. These adjustments reduced Oil Sands opening future income tax balances.

Cash Operating Costs per Barrel

Effective January 1, 2006, cash operating costs per barrel, before commissioning and start-up costs, reflect a change in accounting policy to expense overburden costs as incurred (see page 42), as well as the inclusion of research and development costs. The change in accounting policy for overburden resulted in higher cash costs and lower non-cash costs. Therefore, recorded cash operating costs per barrel have increased, but total operating costs were not significantly impacted. Cash operating costs per barrel now reflect total Oil Sands operations including mining and in-situ production costs. In the past, operating costs per barrel for base (mining and upgrading) operations and in-situ operations were disclosed separately. All comparative balances have been retroactively restated for these changes in all 2006 Reports to Shareholders.

Cash operating costs increased to $2,057 million in 2006 from $1,536 million in 2005, as a result of higher maintenance activities, increased labour expenses and insurance related expenses. However, due to these costs being applied to significantly more barrels of production, cash operating costs on a per barrel basis decreased to $21.70 in 2006 from $24.55 in 2005. Refer to page 58 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

046	Suncor Energy Inc.
	2006 Annual Report

Bridge Analysis of Net Cash Surplus (Deficiency)

($ millions)

Net Cash Surplus (Deficiency) Analysis

Cash flow from operations was $3,902 million in 2006 compared to $1,878 million in 2005 (2004 – $1,734 million). The increase was primarily due to the same factors that impacted net earnings, excluding the impact of depreciation, depletion and amortization, and the revaluation of future tax balances resulting from the reduction of federal and Alberta provincial income tax rates.

Cash flow used in investing activities increased to $2,230 million in 2006 from $1,882 million in 2005 (2004 – $1,039 million). During 2006, capital spending related primarily to continued progress on the Coker Unit, Firebag in-situ, and Voyageur projects (see “Expansion to 500,000 bpd to 550,000 bpd” below). In addition, during the fourth quarter of 2006 we acquired two separate gross overriding royalty interests relating to a specific land lease, for cash consideration totaling approximately $174 million.

Outlook

Our Oil Sands operations continue to be the focus of our business strategy. In 2007, we anticipate Oil Sands production will average 260,000 to 270,000 bpd from our existing upgrading assets including bitumen sold directly to the market. Our future plans for Oil Sands remain focused on activities and investments anticipated to increase production, identify cost improvements and improve environment, health and safety performance.

For 2007, we have budgeted capital spending of approximately $4.4 billion, of which $900 million is slated for sustaining projects with the remainder earmarked for growth. Approximately $1 billion is allotted to project spending towards the goal of increasing production to 350,000 bpd in 2008, with the remaining $2.5 billion directed toward projects to support the Company’s goal of producing more than half a million barrels per day in the 2010 to 2012 time frame.

Expansion to 350,000 bpd

Work to increase production capacity to 350,000 bpd in 2008 continues, and these efforts are proceeding on schedule. During 2007, construction is planned to continue on the Coker Unit and Firebag expansion projects. As a result of this ongoing construction, a 50 day shutdown of Upgrader 2 is planned for 2007 to enable key tie ins for the project. The company intends to take advantage of this planned shutdown to perform necessary maintenance activities. Upgrader 1 is expected to continue to operate at normal capacity during the shutdown. For an update on the progress of these significant capital projects, see page 27.

In addition to our plans to expand our proprietary sources of bitumen supply, incremental bitumen to feed expanded upgrading capacity is also expected to be provided under a processing agreement between Suncor and Petro-Canada, expected to take effect in 2008. Under the agreement, Oil Sands 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.

Expansion to 500,000 bpd to 550,000 bpd

In November 2006, the EUB approved our application to construct a third oil sands upgrader, a critical component of our Voyageur strategy, which targets a further expansion of Oil Sands production to 500,000 to 550,000 bpd in 2010 to 2012. The EUB has also conditionally approved our application to develop the North Steepbank mine extension, which is expected to replace bitumen supply from depleted mining leases. Both projects are expected to advance development plans and cost estimates to a level appropriate to seek Board of Directors approval in 2007.

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2006 Annual Report

In addition to the planned third upgrader and extension of the Steepbank mine, Suncor’s Voyageur strategy also includes the development of Stages 3 to 6 of in-situ bitumen supply from our Firebag leases and infrastructure related to the expansion including an overpass connecting planned facilities on the west side of Highway 63 to existing assets on the east side of the road. As Suncor continues to develop its in-situ projects, we expect to seek Board of Directors approval for Firebag Stage 3 in 2007.

Suncor expects to apply in 2007 for permission to build and extend its mining area to Lease 23 (Voyageur South), west of our existing operations. Pending regulatory and Board of Directors’ approval, construction could begin as early as 2009 with mining operations starting in 2011. In addition to pursuing future bitumen supply, Suncor is in the initial stages of investigating future expansion of upgrading capacity. As part of this investigation, we have secured land options northeast of Edmonton, Alberta. There are no firm plans to develop this land, nor are there firm plans about the configuration of any potential future upgrading expansion.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect performance 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 25.

•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, services 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 carefully managed maintenance scheduling.

•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. (See page 29 for a discussion of anticipated changes).

•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 2,000 Oil Sands employees. The current collective agreement with the union expires on May 1, 2007.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Also refer to Suncor Overview, Risk Factors Affecting Performance on page 30.

048	Suncor Energy Inc.
	2006 Annual Report

Natural Gas

Suncor’s Natural Gas (NG) business primarily produces conventional natural gas in Western Canada. NG’s production serves as a price hedge that provides us with a degree of protection from volatile market prices of natural gas purchased for internal consumption in our Oil Sands and downstream operations.

NG’s stragtegy 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.

NG’s long-term goal is to achieve a sustainable return on capital employed (ROCE) ⁽²⁾ of 12% to 15% at mid-cycle prices. To offset company-wide natural gas purchases, NG is targeting production increases of 3% to 5% per year.

HIGHLIGHTS

Summary of Results

Year ended December 31

($ millions unless otherwise noted)	2006		2005	2004
Revenue	578		679	567
Natural gas production (mmcf/day)	191		190	200
Average natural gas sales price ($/mcf)	7.15		8.57	6.70
Net earnings	109		155	115
Cash flow from operations (1)	281		412	319
Total assets	1 503		1 307	967
Cash used in investing activities	443		344	251
Net cash surplus (deficiency)	(189	)	63	67
ROCE (%) (2)	15.3		30.7	27.1

(1)	Non-GAAP measure. See page 58.
(2)	ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 58.

2006 Overview

•Natural gas production averaged 191 million cubic feet (mmcf) per day in 2006 compared to 190 mmcf/day in 2005. Company-wide purchases for internal consumption were approximately 170 mmcf/day during 2006. Production in 2006 was below initial targets due to shut-in production as a result of pipeline and processing facility constraints, delays in bringing new production on stream, and an increase in exploratory dry holes compared to 2005.

•During the first quarter of 2006, Suncor sold a 15% interest in the South Rosevear gas plant for proceeds of $12 million. We currently retain a 60.4% interest and continue to operate the plant.

Total Net	02	03	04	05	06
Proved Reserves
Year ended December 31
(millions of boe) (3)
Natural gas liquids and crude oil	10	8	8	7	7
Natural gas	86	76	74	75	71
Total	96	84	82	82	78
Production	02	03	04	05	06
Year ended December 31
(thousands of boe/d) (3)
Natural gas liquids and crude oil	3.9	3.7	3.5	3.2	3.0
Natural gas	29.8	31.2	33.3	31.6	31.8
Total	33.7	34.9	36.8	34.8	34.8

(3) For details on barrels of oil equivalent (boe), see page 18.

Suncor Energy Inc.	049
2006 Annual Report

Analysis of Net Earnings

NG net earnings were $109 million in 2006, compared to $155 million in 2005 (2004 – $115 million). The decrease in net earnings was due primarily to lower price realizations, higher seismic and dry hole costs, higher operational costs resulting from an inflationary marketplace, and higher depreciation, depletion and amortization (DD&A). The average realized price for natural gas was $7.15 per mcf in 2006, compared to an average of $8.57 per mcf in 2005. These negative factors were partially offset by the reduction in federal and Alberta provincial income tax rates that resulted in a $53 million increase in net earnings during 2006.

NG’s total 2006 production was 209 million cubic feet equivalent per day (mmcfe/d) in 2006, unchanged from the prior year.

Bridge Anaylsis of Net Earnings
($ millions)

Expenses

Royalties on NG production were $127 million ($10.00 per boe) in 2006, compared to $149 million ($11.72 per boe) in 2005 (2004 - $124 million; $9.22 per boe). The decrease was due to lower sales price realizations, reflecting lower benchmark commodity prices.

Operating costs were $107 million in 2006 compared to $93 million in 2005 (2004 - $100 million). The increased operating expenses were mainly a result of higher selling, general & administrative costs as well as higher lifting costs caused by the inflationary environment affecting the oil and gas industry in Alberta.

Exploration expenses increased to $82 million in 2006 from $46 million in 2005 (2004 – $38 million). Dry hole costs recognized in the year totaled $52 million, compared to $33 million in 2005. Seismic expenditures increased to $30 million during 2006, compared to $13 million in 2005.

DD&A expense was $152 million in 2006 compared to $130 million in 2005 (2004 - $115 million). The Increase was due to higher depletion rates associated with increased finding and development costs.

In total, the above noted items reduced net earnings by $35 million.

Lifting and	02	03	04	05	06
Administration Costs
Year ended December 31
($/boe) (1)
Administration	2.34	2.35	2.39	2.52	3.37
Lifting	3.15	3.48	3.84	4.95	5.08
Total	5.49	5.83	6.23	7.47	8.45

(1) For details on barrels of oil equivalent (boe), see page 18.

050	Suncor Energy Inc.
	2006 Annual Report

Net Cash Surplus (Deficiency) Analysis

NG’s net cash deficit was $189 million in 2006 compared with $63 million surplus in 2005 (2004 – $67 million surplus). Cash flow from operations decreased to $281million compared with $412 million in the prior year (2004 – $319 million), largely due to the same factors impacting earnings.

Cash used in investing activities increased to $443 million compared with $344 million in 2005 (2004 – $251 million) as a result of increased drilling and exploration activities offset by reduced expenditures on pipeline and facility construction.

Bridge Analysis of Net Cash Surplus (Deficiency)
($ millions)

Outlook

NG targets increased production of natural gas, natural gas liquids and crude oil from 209 mmcfe/d in 2006 to 215 to 220mmcfe/d in 2007 to offset our internal natural gas demands, maintain existing operations and support the company’s goal of expanding production by 3% to 5% per year.

NG intends to continue to leverage its expertise and existing assets to bring reserves into production in Western Canada. However, increasing production may require expansion through farm-ins⁽¹⁾, joint ventures or additional property acquisitions, which could expand the size and number of operating areas, or involve new operating areas outside of Western Canada.

To support these goals, we have budgeted $350 million in capital spending primarily for exploration and development in 2007.

Natural Gas Production vs. Purchases

Year ended December 31 (mmcf/d)

Risk Factors Affecting Performance

There are certain issues that we strive to manage that may affect performance of the NG business including, but not limited to, the following:

•Consistently and competitively finding and developing reserves that can be brought on stream economically. Positive or negative reserve revisions arising from technical and economic factors can have a corresponding positive or negative impact on asset valuation and depletion rates.

•The impact of market demand for land and services on capital and operating costs. Market demand and the availability of opportunities also influence the cost of acquisitions and the willingness of competitors to allow farm-ins on prospects.

•The impact of market demand for labour and equipment, which in a heated exploration and development market could add to cost or cause delays to projects for NG and its competitors.

•Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in Canada and in the United States. These risks could add to costs 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 with increased costs or reduced production.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

(1)Acquisition of all or part of the operating rights from the working interest owner. The acquirer assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty, but may retain any type of interest.

Suncor Energy Inc.	051
2006 Annual Report

Energy Marketing and Refining – Canada

Energy Marketing and Refining – Canada (EM&R) operates a 70,000 barrel per day (bpd) (approximately 11,100 cubic metres per day) capacity refinery in Sarnia, Ontario, and markets refined products to industrial, wholesale and commercial customers primarily in Ontario and Quebec. Through our Sunoco-branded and joint venture operated service networks, we market products to retail customers in Ontario. The EM&R 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 our Oil Sands and Natural Gas operations. In 2006, EM&R completed construction of Canada’s largest ethanol production plant.

EM&R’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, direct management of growth projects, strategic alliances with key suppliers and customers and continuous improvement of operations.

•Increasing the profitability and efficiency of retail networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2006		2005		2004
Revenue	5 465		4 363		3 500
Refined product sales (millions of litres) Sunoco retail gasoline	1 678		1 656		1 665
Total	5 547		5 570		5 643
Net earnings breakdown:
Total earnings excluding energy, marketing and trading activities	54		30		68
Energy marketing and trading activities	22		11		12
Tax adjustments	10		—		—
Total net earnings	86		41		80
Cash flow from operations (1)	217		152		188
Total assets	2 829		1 955		1 321
Cash used in investing activities	512		433		198
Net cash deficiency	(382	)	(328	)	(21	)
ROCE (%) (2)	12.5		8.1		14.6
ROCE (%) (3)	7.4		5.2		13.6

(1) Non-GAAP measure. See page 58.

(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 58.

(3) Includes capitalized costs related to major projects in progress. See page 58.

052	Suncor Energy Inc.
	2006 Annual Report

2006 Overview

•The first phase of our diesel desulphurization and oil sands integration project was completed in July 2006. This phase of the project enables us to produce ultra low sulphur diesel to meet the new regulatory requirements that came into effect June 30, 2006. Phase two of the project, modifications to allow integration of oil sands sour crude feedstocks, is targeted for completion in 2007. Labour shortages and material supply issues have put upward cost pressures on the overall project. The cost estimate for this project has been increased to $960 million, from $800 million.

•A significant planned shutdown at our Sarnia refinery was completed December 22, 2006. Additional capital work that was not included in the original shutdown plan resulted in an extension to completion timelines and higher than anticipated costs.

•On July 1, 2006, Suncor’s new ethanol facility began production. The facility, the largest of its kind in Canada, is expected to produce approximately 200 million litres of ethanol annually. The ethanol produced will be used for blending purposes in specific refined products and for sales to third parties.

Analysis of Net Earnings

EM&R results include the impact of Suncor’s third party energy marketing and trading activities that are discussed separately on page 53.

Bridge Analysis of Net Earnings
($ millions)

EM&R’s net earnings increased to $86 million in 2006 from $41 million in 2005 (2004 – $80 million). This increase was primarily due to higher refining margins, offset by lower refinery utilization resulting from the major planned shutdown during the fourth quarter of 2006 and lower retail margins. Net earnings also increased by $5 million as a result of reductions to EM&R’s opening future income tax balances (FIT) due to reductions in the federal and Alberta provincial income tax rates during 2006.

Volumes

Total sales volumes averaged 95,000 bpd (15,100 cubic metres per day) in 2006, comparable to the 96,000 bpd (15,200 cubic metres per day) in 2005. Total gasoline sales volumes in the Sunoco-branded retail network increased to 1,678 million litres in 2006 from 1,656 million litres in 2005. Average Sunoco-branded service station site throughput was unchanged from 2005, at approximately 6million litres per site in 2006. Site throughput is an important indicator of network efficiency. EM&R’s Ontario retail gasoline market share, including all Sunoco and joint venture operated retail sites was 18% in 2006 (2005 – 19%). Approximately 90% of EM&R’s refined products were sold to the Ontario market in 2006.

Refinery Utilization

Overall refinery utilization averaged 78% in 2006, compared with 95% in 2005. The reduction in refinery utilization was primarily due to specific operational issues and the extensive planned maintenance activities during 2006.

Suncor Energy Inc.	053
2006 Annual Report

Product Purchase Costs

Refined product purchase costs were higher in 2006 as a result of higher purchased volumes of refined products to meet requirements due to operational issues and the maintenance shutdown, along with higher refined product prices. Increased third party purchase costs decreased 2006 net earnings by $53 million.

Cash and Non-cash Operating Expenses

Overall, cash and non-cash operating expenses increased by $36 million after-tax in 2006 compared to 2005. Cash expenses increased by $19 million after-tax in 2006, primarily due to higher administrative costs. Non-cash expenses increased by $17 million after-tax in 2006, due to increased depreciation as a result of a higher depreciable asset base, following the completion of the diesel desulphurization and ethanol projects during the year.

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 GAAP. EM&R 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)	2006	2005	2004
Operating revenues
Sales to EM&R joint ventures:
Refined products	294	327	320
Petrochemicals	136	279	272

At December 31, 2006, amounts due from EM&R joint ventures were $20 million, compared to $22 million at December 31, 2005.

Energy Marketing and Trading Activities

Third party energy marketing and energy 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 $22 million in 2006 compared to net earnings of $11 million in 2005 (2004 – $12 million).

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. See page 33.

Net Cash Deficiency Analysis

EM&R’s net cash deficiency was $382 million in 2006 compared to a net cash deficiency of $328 million in 2005 (2004 – net cash deficiency of $21 million). Cash flow from operations was $217 million in 2006 compared to $152 million in 2005 (2004 – $188 million). The increase was due to the same factors impacting net earnings, excluding the revaluation of opening future tax balances resulting from the reduction in federal income tax rates in 2006. Net working capital increased by $87 million in 2006, compared to an increase of $47 million in 2005. The increase in net working capital is a result of a decrease in accounts payable liabilities and an increase to our refined product inventory.

Cash used in investing activities was $512 million in 2006 compared to $433 million in 2005 (2004 – $198 million). Capital expenditures in 2006 were mainly associated with the ongoing diesel desulphurization and oil sands integration project, and the completion of the new ethanol facility. Refinery capital maintenance expenditures also increased during 2006 consistent with the planned maintenance shutdown.

Bridge Analysis of Net Cash Deficiency
($ millions)

054	Suncor Energy Inc.
	2006 Annual Report

Outlook

Completion of the oil sands integration project at the Sarnia refinery, planned for the fourth quarter of 2007, is expected to enable us to process up to 40,000 bpd of oil sands sour crude blends. Tie in of new and modified equipment is expected to require a 65 day shutdown of portions of the facility.

Capital spending, including the completion of the oil sands integration project, is expected to be approximately $300 million in 2007.

Suncor is also investigating a potential expansion of our ethanol plant, near Sarnia. Public consultation began in late 2006. No capital costs or firm plans have yet been defined.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect the performance of the EM&R business that include, but are 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, our new facilities for reducing sulphur in on-road diesel fuel should also allow us to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

Suncor Energy Inc.	055
2006 Annual Report

Refining and Marketing – U.S.A.

Refining and Marketing – U.S.A. (R&M) operates a 90,000 barrel per day (bpd) (approximately 14,300 cubic metre per day) capacity refinery in Commerce City, Colorado, and markets refined products to customers primarily in Colorado, including retail marketing through 43 company owned Phillips 66^®-branded retail stations in the Denver area. Assets also include a 100% interest in the 480-kilometre Rocky Mountain pipeline system, a 65% interest in the 140-kilometre Centennial pipeline system and a 100% interest in a products terminal in Grand Junction, Colorado.

R&M’s strategy is focused on:

•Enhancing the profitability of refining operations by improving reliability, product yields and operational flexibility to process a variety of feedstocks, including crude oil streams from our Oil Sands operations.

•Creating additional downstream market opportunities in the United States to capture greater long-term value from Oil Sands production.

•Reducing costs through the application of technologies, economies of scale, direct management of growth projects, strategic alliances with key suppliers and customers and continuous improvement of operations.

•Increasing the profitability and efficiency of our retail network.

HIGHLIGHTS

Summary of Results

Year ended December 31
(Cdn$ millions unless otherwise noted)	2006		2005		2004
Revenue	3 128		2 621		1 495
Refined product sales (millions of litres) Gasoline	2 727		2 517		1 627
Total	5 256		5 004		3 504
Net earnings	168		142		34
Cash flow from operations (1)	281		247		59
Total assets	1 379		1 235		518
Cash used in investing activities	275		385		171
Net cash deficiency	(9	)	(121	)	(71	)
ROCE (%) (2)	34.2		49.4		12.2
ROCE (%) (3)	22.6		28.9		11.1

(1) Non-GAAP measure. See page 58.

(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 58.

(3) Includes capitalized costs related to major projects in progress. See page 58.

2006 Overview

•R&M’s diesel desulphurization project was completed in June 2006. This project enabled production of ultra low sulphur diesel to meet the new regulatory requirements that came into effect June 1, 2006. In addition to improving the refinery’s environmental performance, the project modifications enable the refining facility to process up to 15,000 bpd of oil sands sour synthetic crude oil.

056	Suncor Energy Inc.
	2006 Annual Report

Analysis of Net Earnings

R&M’s net earnings were $168 million in 2006 compared to $142 million in 2005 (2004 – $34 million). Earnings increased due to higher refining margins, higher sales volumes due in part to expansion through the acquisition and integration of our second Commerce City refinery in May 2005, and a stronger sales mix of higher value diesel fuel. These positive impacts were partially offset by increased depreciation, depletion and amortization (DD&A) costs after the completion of our diesel desulphurization and oil sands integration project during 2006.

Volumes and Refinery Utilization

Sales volumes increased in 2006 compared to 2005, primarily as a result of the May 2005 acquisition of our second Commerce City refinery (the Colorado Refining Company), which increased throughput capacity of our Commerce City refining facility to 90,000 bpd from 60,000bpd. This was offset by lower refinery utilization rates resulting from the planned maintenance shutdown in the first quarter of 2006. Refinery utilization was 92% in 2006 compared to 98% in 2005. After the planned maintenance was completed in the first quarter of 2006, utilization rates were comparable with the prior year.

Increased product purchases reduced net earnings by $45million. The higher volume of purchased refined products was primarily due to purchases of additional finished products to meet customer demands.

Bridge Analysis of Net Earnings
($ millions)

Cash and Non-cash Expenses

Increases in refinery cash expenses and non-cash expenses were primarily due to incremental costs associated with the acquisition and operation of the additional refinery capacity throughout 2006. As well, depreciation, depletion and amortization costs increased during 2006 following the completion of our diesel desulphurization and oil sands integration project that increased our depreciable cost base.

Net Cash Deficiency Analysis

R&M’s net cash deficiency was $9 million in 2006, compared to a deficiency of $121 million in 2005 (2004 – $71 million deficiency). The increase in cash flow from operations to $281 million in 2006 from $247 million in 2005 (2004 – $59 million) was impacted by the same factors that affected net earnings. Net working capital increased $15 million in 2006, compared to a decrease of $17 million in 2005 (2004 – $41 million decrease). The increase in 2006 was primarily due to an increase in our refined product inventory.

Cash used in investing activities was $275 million in 2006, compared to $385 million in 2005 (2004 – $171 million). Investing activities in 2006 were primarily related to costs associated with the diesel desulphurization and oil sands integration project.

Bridge Analysis of Net Cash Deficiency
($ millions)

Suncor Energy Inc.	057
2006 Annual Report

Outlook

R&M estimates capital spending of approximately $100 million (approximately US$85 million) in 2007, with planned maintenance shutdowns in progress in February and planned in October.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect the performance of the R&M business including, but not limited to, the following:

•Continuing fluctuations in demand for refined products, margin and price volatility and market competitiveness, including potential new market entrants.

•There are certain risks associated with the execution of capital projects, including the risk of cost overruns. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

058	Suncor Energy Inc.
	2006 Annual Report

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			2006	2005		2004
Cash flow from operations ($ millions)	A		4 533	2 476		2 013
Weighted average number of common shares outstanding (millions of shares)	B		459	456		453
Cash flow from operations (per share)	A/B		9.87	5.43		4.44
ROCE
For the year ended December 31 ($ millions, except ROCE)			2006	2005		2004
Adjusted net earnings
Net earnings			2 971	1 158		1 076
Add: after-tax financing expenses (income)			26	(16	)	1
	D		2 997	1 142		1 077
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents			2 891	2 159		2 577
Shareholders’ equity			5 996	4 874		3 858
	E		8 887	7 033		6 435
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents			1 871	2 891		2 159
Shareholders’ equity			8 952	5 996		4 874
	F		10 823	8 887		7 033
Average capital employed	(E+F)/2=G		9 855	7 960		6 734
Average capitalized costs related to major projects in progress	H		2 476	2 175		1 030
ROCE (%)	D/(G-H	)	40.6	19.7		18.9

Suncor Energy Inc.	059
2006 Annual Report

Oil Sands Operating Costs – Total Operations

		2006			2005			2004
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		2 149			1 432			1 179
Less: natural gas costs and inventory changes		(312	)		(258	)		(181	)
Less: non-monetary transactions		(126	)		—			—
Accretion of asset retirement obligations		28			24			21
Taxes other than income taxes		36			29			28
Cash costs		1 775		18.70	1 227		19.60	1 047		12.60
Natural gas		276		2.90	307		4.90	197		2.40
Imported bitumen (net of other reported product purchases)		6		0.10	2		0.05	13		0.15
Total cash operating costs	A	2 057		21.70	1 536		24.55	1 257		15.15
In-situ (Firebag) start-up costs	B	21		0.20	7		0.10	24		0.30
Total cash operating costs after start-up costs	A+B	2 078		21.90	1 543		24.65	1 281		15.45
Depreciation, depletion and amortization		385		4.05	330		5.30	299		3.60
Total operating costs		2 463		25.95	1 873		29.95	1 580		19.05
Production (thousands of barrels per day)		260.0			171.3			226.5

Oil Sands Operating Costs – In-situ Bitumen Production Only (excluding upgrading costs)

		2006			2005 (1)			2004 (1)
(unaudited)		$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel
Operating, selling and general expenses		209			155			77
Less: natural gas costs and inventory changes		(103	)		(91	)		(39	)
Taxes other than income taxes		4			—			—
Cash costs		110		8.95	64		9.15	38		10.85
Natural gas		103		8.35	91		13.05	39		11.20
Total cash operating costs	A	213		17.30	155		22.20	77		22.05
In-situ (Firebag) start-up costs	B	21		1.70	7		1.00	24		6.85
Total cash operating costs after start-up costs	A+B	234		19.00	162		23.20	101		28.90
Depreciation, depletion and amortization		68		5.55	34		4.90	21		6.00
Total operating costs		302		24.55	196		28.10	122		34.90
Production (thousands of barrels per day)		33.7			19.1			12.7

(1)Firebag start-up costs have not been separately identified in past Annual Reports. We have segregated these costs for comparable information purposes to provide additional detail to the individual components of cash costs.

060	Suncor Energy Inc.
	2006 Annual Report

Forward-looking statements

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 and 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,” “leap,” “strategic,” “slated,” “may,” “laying the groundwork,” “investigating,” “continue,” “hopes,” “strive,” 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 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 Firebag in-situ development and Voyageur) and regulatory projects; 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; 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 or from companies that provide alternative sources of energy; 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 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 blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor.

The 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.

EX-99.3

Suncor Energy Inc.	009
2007 Management Proxy Circular

Appointment of Auditors

The directors and management propose that PricewaterhouseCoopers LLP be appointed as Suncor’s auditors until the close of the next annual meeting. PricewaterhouseCoopers LLP has been the company’s auditors for more than five years.

Fees payable to PricewaterhouseCoopers LLP in 2005 and 2006 are detailed below.

($ )	2005	2006
Audit fees	958 000	1 696 000
Audit-related fees	141 000	258 000
Tax fees	45 000	—
All other fees	20 000	40 000
Total	1 164 000	1 994 000

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. Our audit fees increased by approximately 77% in 2006, primarily due to the increased scope of our auditors’ engagement compared to 2005. Specifically, in 2006 they audited management’s assessment of its internal controls over financial reporting.

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.

032	Suncor Energy Inc.
	2007 Management Proxy Circular

Appendix A: Board of Directors Meetings Held and Attendance of Directors

The information presented below reflects Board of Directors and committee meetings held and attendance of directors for the year ended December 31, 2006.

	Number of Meetings
Board of Directors	6
Environment, Health and Safety Committee	4
Human Resources and Compensation Committee	6
Audit Committee	9
Board Policy, Strategy Review and Governance Committee	5

Summary of Attendance of Directors

Director	Board Meetings Attended	Committee Meetings Attended
Mel E. Benson	6 of 6	9 of 10
Brian A. Canfield (1)	5 of 6	10 of 15
Bryan P. Davies	6 of 6	10 of 10
Brian A. Felesky	6 of 6	14 of 14
John T. Ferguson	6 of 6	15 of 15
W. Douglas Ford	6 of 6	11 of 11
Richard. L. George (2)	6 of 6	N/A
John R. Huff	6 of 6	11 of 11
Robert W. Korthals (3)	4 of 4	3 of 3
M. Ann McCaig	6 of 6	10 of 10
Michael O’Brien	6 of 6	14 of 14
JR Shaw	6 of 6	11 of 11
Eira Thomas (4)	3 of 3	11 of 11

(1)	Mr. Canfield missed one board meeting and three committee meetings due to a death in his family. Mr. Canfield missed an additional two Audit Committee meetings after he was named to the committee. Because the Audit Committee holds meetings outside the dates for regularly scheduled board meetings, Mr. Canfield was unable to attend due to previously scheduled commitments.
(2)	As a member of management, Mr. George does not serve on any of the standing committees of the board.
(3)	Mr. Korthals did not stand for re-election in 2006 and accordingly ceased to be a director as of April 25, 2006. Reported attendance reflects only those meetings held while Mr. Korthals was a director.
(4)	Ms. Thomas became a member of the Board of Directors at the April 25, 2006 annual general meeting of the shareholders of the Corporation. Reported attendance reflects only those meetings held while Ms. Thomas was a director.

The following summarizes the current membership of each committee:

Committee	Committee Members as of March 1, 2007
Audit Committee	John T. Ferguson (Chair)	Michael W. O’Brien
(all members independent)	Brian A. Canfield	Eira Thomas
	Brian A. Felesky
Board Policy, Strategy Review and Governance Committee	John R. Huff (Chair)	W. Douglas Ford
(all members independent)	Brian A. Canfield	JR Shaw
	John T. Ferguson
Environment, Health and Safety Committee	Mel E. Benson (Chair)	M. Ann McCaig
(all members independent)	Bryan P. Davies	Michael W. O’Brien
	Brian A. Felesky	Eira Thomas
Human Resources and Compensation Committee	Bryan P. Davies (Chair)	John R. Huff
(all members independent)	Mel E. Benson	M. Ann McCaig
	W. Douglas Ford	JR Shaw

038	Suncor Energy Inc.
	2007 Management Proxy Circular

In conjunction with board meetings, management presents focused information to directors on topics pertinent to Suncor’s business, including the impact of significant new laws or changes to existing laws, and opportunities presented by new technologies.(15) In an annual survey, directors are asked to suggest topics of interest for future information sessions.

Ethical Business Conduct ⁽¹⁶⁾

Code of Conduct Sound, ethical business practices are fundamental to Suncor’s business. Suncor has a Business Conduct Code (“Code”) that applies to Suncor’s directors, officers, employees and contractors.⁽¹⁷⁾ The Code requires strict compliance with legal requirements and sets Suncor’s standards for the ethical conduct of our business. Topics addressed in the Code include competition, conflict of interest and the protection and proper use of corporate assets and opportunities, confidentiality, disclosure of material information, trading in shares and securities, communications to the public, improper payments, fair dealing in trade relations, and accounting, reporting and business control. Suncor’s Code is supported by detailed policy guidance and standards, and a Code compliance program, under which every Suncor director, officer, non-union employee and independent contractor is required to certify, on an annual basis, his or her compliance with the Code, that he or she has reviewed the Code at least once during the past year, and that he or she understands the requirements of the Code.

Suncor’s board exercises stewardship over the Code in several respects. Suncor’s internal auditors audit the compliance program annually, and the director of internal audit, who has direct reporting relationships with the Audit Committee, reports on compliance to that committee. In addition, at least once annually, the Code is reviewed and if appropriate, updated. Management reports to the Board Policy Committee annually on this process, and any recommended changes are approved by the Board Policy Committee.⁽¹⁸⁾ Any waivers of Code requirements for Suncor’s executive officers or members of the Board of Directors must be approved by the Board of Directors or appropriate committee thereof, and disclosed. No such waivers were granted in 2006.

Suncor encourages employees to raise ethical concerns with Suncor management, our legal, corporate security, human resources or internal audit departments, without fear of retaliation. In addition, the board has established an “Integrity Hotline” to provide a means for Suncor employees to discuss issues of concern anonymously, with a third party service provider. The Integrity Hotline is available 24 hours a day, seven days a week. Any issues of a serious nature are investigated by Suncor’s internal auditors or security staff. The Audit Committee receives regular updates on activities relating to the Integrity Hotline.

Suncor’s Code of Conduct is available on Suncor’s web site, under the “Governance” tab in the Investor Centre.⁽¹⁹⁾

Conflicts of Interest ⁽²⁰⁾

The board has adopted a policy relating to directors’ conflicts of interest. Pursuant to this policy, directors are required to maintain with the Corporate Secretary a current list of all other entities in which they have a material interest, or on which they serve as a director, trustee or in a similar capacity. This list is made available to all directors through the directors’ portal. Directors must immediately advise the Corporate Secretary of any deletions, additions or other changes to any information in their declaration of interest. If the change involves a change in the director’s principal occupation or an appointment as director, officer or trustee of a publicly traded entity, the director must also notify the board chair, who will determine whether the change would be inconsistent with the director’s duties as a member of the board. In appropriate circumstances, the board chair may request the director’s resignation.

The Directors’ Conflict of Interest Policy sets out clear procedures applicable in the event conflicts arise. If a director is a party to, or has an interest in any party to, a contract or transaction before the Board of Directors (regardless of the materiality of the contract or transaction), the director must immediately advise the board chair or the Board Policy Committee chair. The director’s conflict or potential conflict is recorded in the minutes of meeting, and the director is required to absent himself or herself from the meeting for any discussions or deliberations concerning the subject matter of the contract or transaction. The director is not allowed to vote on any resolution in respect of the contract or transaction.

The Corporate Secretary ensures that directors do not receive board materials in situations where the subject matter of those materials could involve an actual or potential conflict of interest.

Suncor Energy Inc.	047
2007 Management Proxy Circular

Appendix A to the Board Terms of Reference – Financial Literacy and Expertise

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.

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 company 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 company’s financial statements and other financial information and to make knowledgeable and thorough inquiries whether:

•The financial statements fairly present the financial condition, results of operations and cash flows of the company 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 company.

048	Suncor Energy Inc.
	2007 Management Proxy Circular

Audit Committee Financial Expert

An “Audit Committee Financial Expert” means a person who, in the judgment of the company’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.

EX-99.4

EXHIBIT 99.4

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 F-10 (File No. 333-14242), Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234), Form S-8 (File No. 333-118648) and Form F-9 (File No. 333-140797) of Suncor Energy Inc., of our report dated February 28, 2007 relating to the consolidated financial statements, management’s assessment of the effectiveness of internal control over financial reporting and the effectiveness of internal control over financial reporting, which appears in the Annual Report to Shareholders.

“PricewaterhouseCoopers LLP”

Chartered Accountants
Calgary, Alberta
March 8, 2007

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.

EX-99.5

EXHIBIT 99.5

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 dated February 9, 2006 (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, 2006;

•the Reserves Assessment and Evaluation of the synthetic crude oil reserves effective December 31, 2006 associated with the Suncor Energy Inc. oil sands operations located near Fort McMurray, Alberta;  and

•the Reserves Assessment and Evaluation of Firebag effective December 31, 2006.

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 2006 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-10 (File No. 333-14242), Form S-8 (File No. 333-87604), Form S-8 (File No. 333-112234) and Form S-8 (File No. 333-118648).

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 8, 2007

Calgary, Alberta

CANADA

EX-99.6

EXHIBIT 99.6

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 8, 2007	“Richard L. George”
		RICHARD L. GEORGE
		President and Chief Executive
		Officer

EX-99.7

EXHIBIT 99.7

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 8, 2007	“J. Kenneth Alley”
		J. KENNETH ALLEY
		Senior Vice President and
		Chief Financial Officer

EX-99.8

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, 2006 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.

“Richard L. George”
RICHARD L. GEORGE
President and Chief Executive Officer
Suncor Energy Inc.
DATE:	March 8, 2007

EX-99.9

EXHIBIT 99.9

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, 2006 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.

“J. Kenneth Alley”
J. KENNETH ALLEY
Senior Vice President and Chief Financial Officer
Suncor Energy Inc.
DATE:	March 8, 2007