EXHIBIT 99.1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2005, including reconciliation to U.S. GAAP (Note 18)

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 61 to 97 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, will certify 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 61 to 65. 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
March 1, 2006

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AUDITORS’ REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have audited the Consolidated Balance Sheets of Suncor Energy Inc. (the company) as at December 31, 2005 and 2004 and the Consolidated Statements of Earnings, Cash Flows and Changes in Shareholders’ Equity for each of the years in the three year period ended December 31, 2005. 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 in accordance with Canadian generally accepted auditing standards. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the company as at December 31, 2005 and 2004 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2005, in accordance with Canadian generally accepted accounting principles.

PricewaterhouseCoopers LLP

Chartered Accountants
Calgary, Alberta

March 1, 2006

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 change described in note 1 to the consolidated financial statements. Our report to the shareholders dated March 1, 2006 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

March 1, 2006

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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 and petrochemical products, primarily in Ontario and Quebec. Petrochemical products are also sold in the United States and Europe.

Refining and Marketing – U.S.A. includes the manufacture, transportation and marketing of petroleum products, primarily in Colorado.

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. Revenues associated with multi-element arrangements are recognized on a straight-line basis over the term of associated services.

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(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.

Other specific contractual obligations entered subsequent to January 1, 2005 have been treated as either capital or operating leases as required under Canadian reporting standards.

Gains and losses on the sale and leaseback of assets recorded as capital leases are deferred and amortized to earnings in proportion to the amortization of leased assets.

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.

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

Impairment

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

Disposals

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

(e) Deferred Charges and Other

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

Overburden removal precedes the mining of the related oil sands deposit. Accordingly, the company employs a deferral method of accounting for overburden removal costs where all such costs are initially recorded as a deferred charge (see note3), rather than expensing overburden removal costs as incurred. These deferred charges are allocated to the mining activity in the year on a last-in, first-out (LIFO) basis using stripping ratios based on a life of mine approach for each mine pit whereby all of the overburden to be removed is related to all of the oil sands proved and probable ore reserves. Amortization of deferred overburden removal cost is reported as part of the depreciation, depletion and amortization expense in the Consolidated Statements of Earnings. Stripping ratios are regularly reviewed to reflect changes in operating experience and other factors. See Recently Issued Canadian Accounting Standards, section (l) on page 65, for proposed changes to accounting for overburden.

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 benefit and defined contribution pension plans, as well as other post-retirement benefits.

The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management’s best estimates of demographic and financial assumptions, and such cost is accrued 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.

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(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.

(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 in 2004 and subsequent fiscal years. 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 gain market information and to earn trading revenues. These energy marketing and trading activities are accounted for at fair value.

(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 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 exchange adjustments 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 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.

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(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

Non-monetary Transactions

In 2005, the Canadian Institute of Chartered Accountants (CICA) approved Handbook section 3831 “Non-Monetary Transactions”. Effective January 1, 2006, all non-monetary transactions must be measured at fair value (if determinable) unless the transaction lacks commercial substance, or is an exchange of a product held for sale in the ordinary course of business, or is a product to be sold in the same line of business. Commercial substance exists when the company’s future cash flows are expected to change significantly as a result of a transaction. The company will be 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 will be recorded. The amount of the gross-up of revenues and purchases of crude oil and products will be dependent on the prevailing prices for natural gas. Currently the transaction is recorded net in purchases of crude oil and products. Retroactive adjustment is prohibited by the standard.

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.

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 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.

Overburden Removal Costs

On February 16, 2006, the Emerging Issues Committee of the CICA approved an abstract regarding the treatment of overburden costs in the mining industry effective July 1, 2006. The proposed abstract would require the capitalization of overburden removal costs when such costs represent betterment to the mine property by facilitating access to reserves in future periods. Costs are to be treated as variable production costs and expensed when no betterment exists. The company currently amortizes the cost of overburden removal using stripping ratios based on a life of mine approach. The company is considering expensing overburden costs incurred on a retroactive basis effective January 1, 2006. With the exception of the impact on 2005 net earnings, the effect of adopting the guidance is not expected to be significant. Net earnings in 2005 would be reduced by approximately $87 million due to increased amounts of overburden moved during the year.

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CONSOLIDATED STATEMENTS OF EARNINGS

For the years ended December 31 ($ millions)	2005		2004		2003
Revenues
Operating revenues (notes 6, 16 and 17)	9 749		8 270		6 329
Energy marketing and trading activities (note 6c)	763		392		276
Net insurance proceeds (note 10d)	572		—		—
Interest	2		3		6
	11 086		8 665		6 611
Expenses
Purchases of crude oil and products	4 184		2 867		1 686
Operating, selling and general	2 130		1 769		1 478
Energy marketing and trading activities (note 6c)	746		373		279
Transportation and other costs	152		132		135
Depreciation, depletion and amortization	720		720		622
Accretion of asset retirement obligations	30		26		25
Exploration (note 17)	56		55		51
Royalties (note 4)	555		531		139
Taxes other than income taxes (note 17)	529		540		466
(Gain) on disposal of assets	(13	)	(16	)	(17	)
Project start-up costs	25		26		16
Financing expenses (income) (note 14)	(15	)	24		(74	)
	9 099		7 047		4 806
Earnings Before Income Taxes	1 987		1 618		1 805
Provision for income taxes (note 9)
Current	39		69		38
Future	703		461		680
	742		530		718
Net Earnings	1 245		1 088		1 087
Per Common Share (dollars) (note 12)
Net earnings attributable to common shareholders
Basic	2.73		2.40		2.42
Diluted	2.67		2.36		2.26
Cash dividends	0.24		0.23		0.1925

See accompanying Summary of Significant Accounting Policies and Notes.

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CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)	2005		2004
Assets
Current assets
Cash and cash equivalents	165		88
Accounts receivable (notes 10 and 17)	1 139		627
Inventories (note 15)	523		423
Income taxes receivable	6		—
Future income taxes (note 9)	83		57
Total current assets	1 916		1 195
Property, plant and equipment, net (note 2)	12 966		10 326
Deferred charges and other (note 3)	469		320
Total assets	15 351		11 841
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	49		30
Accounts payable and accrued liabilities (notes 7 and 8)	1 830		1 306
Income taxes payable	—		32
Taxes other than income taxes	56		41
Total current liabilities	1 935		1 409
Long-term debt (note 5)	3 007		2 217
Accrued liabilities and other (notes 7 and 8)	1 005		749
Future income taxes (note 9)	3 274		2 545
Total liabilities	9 221		6 920
Commitments and contingencies (note 10)
Shareholders’ equity
Share capital (note 11)	732		651
Contributed surplus (note 11)	50		32
Cumulative foreign currency translation	(81	)	(55	)
Retained earnings	5 429		4 293
Total shareholders’ equity	6 130		4 921
Total liabilities and shareholders’ equity	15 351		11 841

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
March 1, 2006

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CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions)	2005		2004		2003
Operating Activities
Cash flow from operations (a)	2 476		2 013		2 040
Decrease (increase) in operating working capital
Accounts receivable	(477	)	(121	)	(105	)
Inventories	(63	)	(51	)	(19	)
Accounts payable and accrued liabilities	508		337		258
Taxes payable	(23	)	16		5
Cash flow from operating activities	2 421		2 194		2 179
Cash Used in Investing Activities (a)	(3 186	)	(1 825	)	(1 708	)
Net Cash Surplus (Deficiency) Before Financing Activities	(765	)	369		471
Financing Activities
Increase (decrease) in short-term debt	19		(1	)	31
Proceeds from issuance of long-term debt	—		—		651
Net increase (decrease) in other long-term debt	808		(635	)	(716	)
Issuance of common shares under stock option plans	69		41		20
Dividends paid on common shares	(102	)	(97	)	(81	)
Deferred revenue	50		26		—
Cash flow provided by (used in) financing activities	844		(666	)	(95	)
Increase (Decrease) in Cash and Cash Equivalents	79		(297	)	376
Effect of Foreign Exchange on Cash and Cash Equivalents	(2	)	(3	)	(3	)
Cash and Cash Equivalents at Beginning of Year	88		388		15
Cash and Cash Equivalents at End of Year	165		88		388

(a) See Schedules of Segmented Data on pages 72 and 73.

See accompanying Summary of Significant Accounting Policies and Notes.

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CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

For the years ended December 31 ($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings
At December 31, 2002, as previously reported	578	—		—		2 296
Retroactive adjustment for change in accounting policy, net of tax (note 1)	—	—		—		12
At December 31, 2002, as restated	578	—		—		2 308
Net earnings	—	—		—		1 087
Dividends paid on common shares	—	—		—		(81	)
Issued for cash under stock option plans	20	—		—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	7		—		—
Foreign currency translation adjustment	—	—		(26	)	—
At December 31, 2003, as restated	604	7		(26	)	3 308
Net earnings	—	—		—		1 088
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	)	4 293
Net earnings	—	—		—		1 245
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	732	50		(81	)	5 429

See accompanying Summary of Significant Accounting Policies and Notes.

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SCHEDULES OF SEGMENTED DATA (a)

	Oil Sands						Natural Gas						Energy Marketing and Refining – Canada
For the years ended December 31 ($ millions)	2005		2004		2003		2005		2004		2003		2005		2004		2003
EARNINGS
Revenues (b)
Operating revenues	2 938		3 215		2 716		653		499		436		3 536		3 060		2 660
Energy marketing and trading activities	—		—		—		—		—		—		763		400		276
Net insurance proceeds (note 10d)	572		—		—		—		—		—		—		—		—
Intersegment revenues (c)	455		425		385		26		68		76		—		—		—
Interest	—		—		—		—		—		—		—		—		—
	3 965		3 640		3 101		679		567		512		4 299		3 460		2 936
Expenses
Purchases of crude oil and products	32		75		12		—		—		—		2 585		2 115		1 797
Operating, selling and general	1 128		939		865		93		100		73		484		418		359
Energy marketing and trading activities	—		—		—		—		—		—		746		381		279
Transportation and other costs	104		88		101		22		21		24		6		3		3
Depreciation, depletion and amortization	482		505		459		130		115		91		73		69		59
Accretion of asset retirement obligations	24		21		21		5		4		3		1		1		1
Exploration	10		17		11		46		38		40		—		—		—
Royalties (note 4)	406		407		33		149		124		106		—		—		—
Taxes other than income taxes	51		72		64		3		2		3		338		352		342
(Gain) loss on disposal of assets	—		4		(1	)	(12	)	(19	)	(12	)	(1	)	(2	)	(4	)
Project start-up costs	25		26		10		—		—		—		—		—		—
Financing expenses (income)	—		—		—		—		—		—		—		—		—
	2 262		2 154		1 575		436		385		328		4 232		3 337		2 836
Earnings (loss) before income taxes	1 703		1 486		1 526		243		182		184		67		123		100
Income taxes	(630	)	(492	)	(639	)	(88	)	(67	)	(64	)	(26	)	(43	)	(47	)
Net earnings (loss)	1 073		994		887		155		115		120		41		80		53
As at December 31
TOTAL ASSETS	11 850		9 067		7 970		1 307		967		765		1 955		1 321		1 080

(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 2005, 2004 or 2003 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.

70

SCHEDULES OF SEGMENTED DATA (a) (continued)

	Refining and Marketing U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2005		2004		2003		2005		2004		2003		2005		2004		2003
EARNINGS
Revenues (b)
Operating revenues	2 619		1 494		515		3		2		2		9 749		8 270		6 329
Energy marketing and trading activities	—		—		—		—		(8	)	—		763		392		276
Net insurance proceeds (note 10d)	—		—		—		—		—		—		572		—		—
Intersegment revenues (c)	—		—		—		(481	)	(493	)	(461	)	—		—		—
Interest	2		1		—		—		2		6		2		3		6
	2 621		1 495		515		(478	)	(497	)	(453	)	11 086		8 665		6 611
Expenses
Purchases of crude oil and products	2 048		1 171		340		(481	)	(494	)	(463	)	4 184		2 867		1 686
Operating, selling and general	167		124		68		258		188		113		2 130		1 769		1 478
Energy marketing and trading activities	—		—		—		—		(8	)	—		746		373		279
Transportation and other costs	20		20		7		—		—		—		152		132		135
Depreciation, depletion and amortization	23		22		6		12		9		7		720		720		622
Accretion of asset retirement obligations	—		—		—		—		—		—		30		26		25
Exploration	—		—		—		—		—		—		56		55		51
Royalties (note 4)	—		—		—		—		—		—		555		531		139
Taxes other than income taxes	137		114		57		—		—		—		529		540		466
(Gain) loss on disposal of assets	—		1		—		—		—		—		(13	)	(16	)	(17	)
Project start-up costs	—		—		6		—		—		—		25		26		16
Financing expenses (income)	—		—		—		(15	)	24		(74	)	(15	)	24		(74	)
	2 395		1 452		484		(226	)	(281	)	(417	)	9 099		7 047		4 806
Earnings (loss) before income taxes	226		43		31		(252	)	(216	)	(36	)	1 987		1 618		1 805
Income taxes	(84	)	(9	)	(13	)	86		81		45		(742	)	(530	)	(718	)
Net earnings (loss)	142		34		18		(166	)	(135	)	9		1 245		1 088		1 087
As at December 31
TOTAL ASSETS	1 235		518		442		(996	)	(32	)	283		15 351		11 841		10 540

71

SCHEDULES OF SEGMENTED DATA (a) (continued)

	Oil Sands						Natural Gas						Energy Marketing and Refining –  Canada
For the years ended December 31 ($ millions)	2005		2004		2003		2005		2004		2003		2005		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	1 073		994		887		155		115		120		41		80		53
Exploration expenses	—		—		—		46		38		40		—		—		—
Non-cash items included in earnings
Depreciation, depletion and amortization	482		505		459		130		115		91		73		69		59
Income taxes	630		492		639		88		67		64		26		43		47
(Gain) loss on disposal of assets	—		4		(1	)	(12	)	(19	)	(12	)	(1	)	(2	)	(4	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		—
Other	11		(29	)	4		5		4		(5	)	13		(3	)	10
Overburden removal outlays	(287	)	(222	)	(175	)	—		—		—		—		—		—
Increase (decrease) in deferred credits and other	(14	)	8		(10	)	—		(1	)	—		—		1		(1	)
Total cash flow from (used in) operations	1 895		1 752		1 803		412		319		298		152		188		164
Decrease (increase) in operating working capital	(223	)	72		56		(5	)	(1	)	12		(44	)	50		—
Total cash from (used in) operating activities	1 672		1 824		1 859		407		318		310		108		238		164
Cash from (used in) investing activities:
Capital and exploration expenditures	(1 948	)	(1 119	)	(953	)	(363	)	(279	)	(184	)	(442	)	(228	)	(122	)
Acquisition of Denver refineries and related assets	—		—		—		—		—		—		—		—		—
Proceeds from property loss	44		—		—		—		—		—		—		—		—
Deferred maintenance shutdown expenditures	(65	)	(4	)	(100	)	(2	)	(1	)	—		—		(20	)	(17	)
Deferred outlays and other investments	(1	)	(9	)	(10	)	—		—		—		3		(14	)	(2	)
Proceeds from disposals	41		45		3		21		29		17		3		3		6
Total cash (used in) investing activities	(1 929	)	(1 087	)	(1 060	)	(344	)	(251	)	(167	)	(436	)	(259	)	(135	)
Net cash surplus (deficiency) before financing activities	(257	)	737		799		63		67		143		(328	)	(21	)	29

(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.

72

SCHEDULES OF SEGMENTED DATA (a) (continued)

	Refining and Marketing U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2005		2004		2003		2005		2004		2003		2005		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	142		34		18		(166	)	(135	)	9		1 245		1 088		1 087
Exploration expenses	—		—		—		—		—		—		46		38		40
Non-cash items included in earnings
Depreciation, depletion and amortization	23		22		6		12		9		7		720		720		622
Income taxes	84		9		13		(125	)	(150	)	(83	)	703		461		680
(Gain) loss on disposal of assets	—		1		—		—		—		—		(13	)	(16	)	(17	)
Stock-based compensation expense	—		—		—		23		25		7		23		25		7
Other	(2	)	(8	)	(2	)	(60	)	(71	)	(210	)	(33	)	(107	)	(203	)
Overburden removal outlays	—		—		—		—		—		—		(287	)	(222	)	(175	)
Increase (decrease) in deferred credits and other	—		1		(1	)	86		17		11		72		26		(1	)
Total cash flow from (used in) operations	247		59		34		(230	)	(305	)	(259	)	2 476		2 013		2 040
Decrease (increase) in operating working capital	40		68		46		177		(8	)	25		(55	)	181		139
Total cash from (used in) operating activities	287		127		80		(53	)	(313	)	(234	)	2 421		2 194		2 179
Cash from (used in) investing activities:
Capital and exploration expenditures	(337	)	(190	)	(31	)	(63	)	(31	)	(32	)	(3 153	)	(1 847	)	(1 322	)
Acquisition of Denver refineries and related assets	(62	)	—		(272	)	—		—		—		(62	)	—		(272	)
Proceeds from property loss	—		—		—		—		—		—		44		—		—
Deferred maintenance shutdown expenditures	(10	)	(7	)	—		—		—		—		(77	)	(32	)	(117	)
Deferred outlays and other investments	1		(1	)	3		(6	)	1		(14	)	(3	)	(23	)	(23	)
Proceeds from disposals	—		—		—		—		—		—		65		77		26
Total cash (used in) investing activities	(408	)	(198	)	(300	)	(69	)	(30	)	(46	)	(3 186	)	(1 825	)	(1 708	)
Net cash surplus (deficiency) before financing activities	(121	)	(71	)	(220	)	(122	)	(343	)	(280	)	(765	)	369		471

73

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGE IN ACCOUNTING POLICY

(a) Preferred Securities

On January 1, 2005, the company retroactively adopted the Canadian accounting standard related to disclosure and presentation of financial instruments. Accordingly, the company’s preferred securities, which were redeemed in March 2004, have been reclassified as long-term debt, and the preferred dividend payments have been reclassified to financing expense. The company has restated its property, plant and equipment and depreciation, depletion and amortization to reflect capitalized interest that would have been incurred and amortized had the preferred securities been classified as debt during the period in which they were outstanding. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase)	2005	2004
Property, plant and equipment	35	37
Total assets	35	37
Future income tax liabilities	12	13
Retained earnings	23	24
Total liabilities and shareholders’ equity	35	37

Change in Consolidated Statements of Earnings

($ millions, increase/(decrease))	2005		2004		2003
Depreciation, depletion and amortization	2		3		4
Financing expenses	—		15		(8	)
Future income taxes	(1	)	(6	)	(8	)
Net earnings (loss)	(1	)	(12	)	12
Per common share – basic (dollars)	—		—		—
Per common share – diluted (dollars)	—		—		—

(b) Consolidation of Variable Interest Entities

On January 1, 2005 the company prospectively adopted Canadian Accounting Guideline 15 – “Consolidation of Variable Interest Entities”(VIEs). Accordingly, the company has consolidated the VIE related to the sale of equipment as described in note 10c. The impact of adopting this standard was an increase to property, plant and equipment of $14 million, an increase to materials and supplies inventory of $8 million and an increase to long-term debt of $22 million. There was no impact to net earnings.

74

2. PROPERTY, PLANT AND EQUIPMENT

	2005		2004
($ millions)	Cost	Accumulated Provision	Cost	Accumulated Provision
Oil Sands
Plant	5 644	1 107	5 197	935
Mine and mobile equipment	1 358	561	1 313	480
In-situ properties	1 610	60	1 267	26
Pipeline	107	50	101	48
Capital leases	39	5	29	25
Major projects in progress	2 484	—	1 486	—
Asset retirement cost	408	81	325	71
	11 650	1 864	9 718	1 585
Natural Gas
Proved properties	1 632	769	1 387	652
Unproved properties	172	23	125	18
Other support facilities and equipment	53	13	28	14
Asset retirement cost	14	6	27	3
	1 871	811	1 567	687
Energy Marketing and Refining – Canada
Refinery	899	481	875	468
Marketing	597	244	525	248
Major projects in progress	464	—	171	—
Asset retirement cost	11	7	11	5
	1 971	732	1 582	721
Refining and Marketing – U.S.A.
Refinery and intangible assets	244	24	175	11
Marketing	36	3	38	2
Pipeline	26	2	25	1
Major projects in progress	453	—	128	—
	759	29	366	14
Corporate	180	29	118	18
	16 431	3 465	13 351	3 025
Net property, plant and equipment		12 966		10 326

3. DEFERRED CHARGES AND OTHER

($ millions)	2005		2004
Oil Sands overburden removal costs (see below)	202		67
Deferred maintenance shutdown costs	160		129
Deferred financing costs	23		25
Other	84		99
Total deferred charges and other	469		320
Oil Sands overburden removal costs
Balance – beginning of year	67		51
Outlays during the year	287		222
Depreciation on equipment during year	26		19
	380		292
Amortization during year	(178	)	(225	)
Balance – end of year	202		67

75

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 being treated by the Government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes. During 2004 and 2005, 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.

Royalty expense for the company’s Oil Sands operations for the year ended December 31, 2005 was $406 million (2004 – $407 million, 2003 – $33 million).

In July 2004, we issued a statement of claim against the Crown, seeking, among other things, to overturn the government’s decision on the royalty treatment of our Firebag in-situ operations. In February 2006, we advised the Government of Alberta that we had elected not to proceed with our claim relating to the royalty treatment of Firebag.

5. LONG-TERM DEBT

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

($ millions)	2005	2004
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	583	602
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	583	602
6.70% Series 2 Medium Term Notes, due in 2011 (a)	500	500
6.80% Medium Term Notes, due in 2007 (a)	250	250
6.10% Medium Term Notes, due in 2007 (a)	150	150
	2 066	2 104
Revolving-term debt, with interest at variable rates (see B. Credit Facilities)
Commercial paper (interest at December 31, 2005 – 3.2%, 2004 – 2.3%) (b)	890	89
Total unsecured long-term debt	2 956	2 193
Secured long-term debt with interest rates averaging 5.2% (2004 – 5.4%)	1	5
Capital leases (c), (d)	30	19
Variable interest entity long-term debt – see note 1(b)	20	—
Total long-term debt	3 007	2 217

(a)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	2005 Effective		2004 Effective
Description of Swap Transaction	($ millions)	Maturity	Interest Rate		Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	4.0	%	3.5	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	4.6	%	4.3	%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	4.0	%	3.6	%

(b)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).

(c)Obligations under capital leases are as follows:

($ millions)	2005	2004
Equipment leases with interest rates between prime plus 0.5% and 12.4% and maturing on dates ranging from 2008 and 2035	30	19
	30	19

76

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

($ millions)	Capital Leases	Other Long- term Debt
2006	3	910
2007	3	401
2008	3	—
2009	3	—
2010	3	—
Later years	71	1 666
Total minimum payments	86	2 977
Less amount representing imputed interest	56
Present value of obligation under capital leases	30

Long-term Debt (per cent)	2005	2004
Variable rate	50	31
Fixed rate	50	69

B. Credit Facilities

At December 31, 2005, the company had available credit and term loan facilities of $2,330 million, of which $1,255 million was undrawn, as follows:

($ millions)
Facility that is fully revolving for 364 days and expires in 2006	600
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2007	200
Facility that is fully revolving for a period of three years and expires in 2007	1 500
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	1 075
Total undrawn credit facilities	1 255

At December 31, 2005, the company had issued $185 million (2004 – $131 million) in letters of credit to various third parties.

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 changes in prices to within a specific range. The “costless” nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).

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

See next page for more technical details and amounts.

77

(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:

	2005		2004
($ millions)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Cash and cash equivalents	165	165	88	88
Accounts receivable	1 139	1 139	627	627
Current liabilities	1 826	1 826	1 252	1 252
Long-term debt
Fixed-term	2 066	2 299	2 104	2 339
Revolving-term	890	890	89	89
Other	21	21	5	5
Capital leases	30	30	19	19

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.

(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 U.S. dollar West Texas Intermediate (WTI) derivative transactions. During 2005, the company resumed its strategic crude oil hedging program, fixing a price or range of prices for a percentage of total production of crude oil for specified periods of time. During 2005, the company entered into agreements covering 7,000 barrels per day (bpd) beginning January 1, 2006 and ending December 31, 2007. Prices for these barrels are fixed within a range of US$50.00 per barrel to an average of US$92.57 per barrel WTI. The company has not hedged any portion of the foreign exchange component of these forecasted cash flows.

At December 31, 2005, 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 2006 and 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 option 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.

78

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, 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
As at December 31, 2003
Crude oil swaps	68 000	24	772	2004
Costless collars	11 000	21 – 24	109 – 125	2004
Crude oil swaps	36 000	23	390	2005

		Average	Revenue
	Quantity	Price	Hedged	Hedge
Natural Gas	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period (c)
As at December 31, 2005
Swaps	4 000	6.58	10	2006
Costless collars	25 000	10.76 – 16.13	24 – 36	2006	(g)
Costless collars	10 000	8.75 – 13.38	19 – 29	2006	(h)
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	(i)
As at December 31, 2003	30 000	6	16	2004	(j)

		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, 2005	5 100	11.69	10	2006	(d)
As at December 31, 2004	6 300	7	15	2005	(e)
As at December 31, 2003	6 600	5	3	2004	(f)

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

(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 May 2006, inclusive.
(e)	For the period January to September 2005, inclusive.
(f)	For the period January and February 2004.
(g)	For the period January to March 2006, inclusive.
(h)	For the period April to October 2006, inclusive.
(i)	For the period January to March 2005, inclusive.
(j)	For the period January to March 2004, inclusive.
(k)	Settlement for applicable forward is March 2006.
(l)	Settlements for applicable forwards occurring within the period April to September 2007.

79

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, 2005 are detailed in note 5, Long-term debt.

Fair Value of 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)	2005		2004
Revenue hedge swaps and collars	(4	)	(305	)
Margin hedge swaps	1		5
Interest rate swaps and foreign currency forwards	22		36
Fair value of outstanding hedging derivative financial instruments	19		(264	)

(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 gain market information and earn trading and marketing revenues.  These energy 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.  The results of these activities are reported as revenue and as energy trading and marketing expenses in the Consolidated Statements of Earnings.

Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers.  For the year ended December 31, 2005 physical energy marketing contracts resulted in a net pretax gain of $15 million (2004 – pretax gain of $12 million; 2003 – pretax gain of $2 million).

The company also enters into various financial energy contracts for trading activities.  The following information presents all positions for the financial instruments only.  For the year ended December 31, 2005, a net pretax gain of $5 million (2004 – pretax gain $11 million; 2003 – pretax loss of $3 million) resulted from the settlement and revaluation of the financial energy contracts.  The above amounts do not include the impact of related general and administrative costs.

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

($ millions)	2005	2004
Energy trading assets	82	26
Energy trading liabilities	70	9
Net energy trading assets	12	17

Change in fair value of net assets

($ millions)	2005
Fair value of contracts at December 31, 2004	17
Changes in values attributable to market price and other market changes	(108	)
Fair value of contracts entered into during the period	115
Fair value of contracts realized during 2005	(12	)
Fair value of contracts outstanding at December 31, 2005	12

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

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(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)	2005	2004
Derivative contracts not accounted for as hedges	82	7
Unrecognized derivative contracts accounted for as a hedge	30	21
Total	112	28

7. ACCRUED LIABILITIES AND OTHER

($ millions)	2005	2004
Asset retirement obligations (a)	489	429
Employee future benefits liability (see note 8)	190	183
Employee and director incentive plans	110	50
Deferred revenue	140	64
Environmental remediation costs  (b)	33	8
Other	43	15
Total	1 005	749

(a) Asset Retirement Obligations

The asset retirement obligation (ARO) also includes $54 million in current liabilities (2004 – $47 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)	2005		2004
Asset retirement obligations, beginning of year	476		401
Liabilities incurred	71		82
Liabilities settled	(34	)	(33	)
Accretion of asset retirement obligations	30		26
Asset retirement obligations, end of year	543		476

The total undiscounted amount of estimated cash flows required to settle the obligations at December 31, 2005 was approximately $1.2 billion (2004 – $1.1 billion).  The liability recognized in 2005 has been discounted using a credit-adjusted risk-free rate of 5.6% (2004 – 6.0%).  Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

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 will be recorded in the first period in which the lives of the assets are determinable.

(b) Environmental Remediation Costs

Total accrued environmental remediation costs include an additional $14 million in current liabilities (2004 – $35 million).  Environmental remediation costs include obligations assumed through the purchase of the Commerce City refineries.  There is no associated asset retirement obligation for these assets as the assets have an indeterminate life.

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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, 2005 was $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 senior executive retirement plan on a voluntary basis.  The amount and timing of future funding for these supplementary plans is subject to capital availability and is at the company’s discretion.  At the end of December 2005, Plan Assets to meet the Benefit Obligation were $479 million.

The excess of the Benefit Obligation over Plan Assets of $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 disbursing agents of the benefits to recipients.  Plan assets are managed by a pension committee on behalf of beneficiaries.  The committee retains independent managers and advisors.

Funding of the registered retirement plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, depending on funding status, and every year in the United States.  The most recent valuation for the Canadian plan was performed in 2004.

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

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

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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)	2005		2004		2005		2004
Change in benefit obligation
Benefit obligation at beginning of year	624		568		128		117
Service costs	32		25		5		5
Interest costs	38		34		6		7
Plan participants’ contributions	3		3		—		—
Acquisition (a)	1		—		1		—
Foreign exchange	—		(2	)	—		(1	)
Actuarial loss	75		21		8		4
Benefits paid	(28	)	(25	)	(4	)	(4	)
Benefit obligation at end of year (b), (e)	745		624		144		128
Change in plan assets (c)
Fair value of plan assets at beginning of year	399		336		—		—
Actual return on plan assets	41		33		—		—
Employer contributions	61		49		—		—
Plan participants’ contributions	3		3		—		—
Benefits paid	(25	)	(22	)	—		—
Fair value of plan assets at end of year (e)	479		399		—		—
Net unfunded obligation	(266	)	(225	)	(144	)	(128	)
Items not yet recognized in earnings:
Unamortized net actuarial loss (d)	167		125		53		49
Unamortized past service costs	—		—		(26	)	(29	)
Accrued benefit liability	(99	)	(100	)	(117	)	(108	)
Current liability	(37	)	(40	)	(3	)	(3	)
Long-term liability	(76	)	(78	)	(114	)	(105	)
Long-term asset	14		18		—		—
Total accrued benefit liability	(99	)	(100	)	(117	)	(108	)

(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:

			Other Post-retirement
	Pension Benefit Obligations		Benefits Obligation
(per cent)	2005	2004	2005	2004
Discount rate	5.00	5.75	5.00	5.75
Rate of compensation increase	4.50	4.50	4.25	4.25

A one per cent 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	(4	)	4	(15	)	17	7	(7	)
Increase (decrease) to benefit obligation	—		—	(119	)	140	35	(33	)

In order to measure the expected cost of other post-retirement benefits, a 10% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2005 (2004 – 11.5%; 2003 – 12%).  It is assumed that this rate will decrease by 0.5% annually, to 5% by 2015, and remain at that level thereafter.

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Assumed health care cost trend rates have a significant effect on the amounts reported for other post-retirement benefit obligations.  A one per cent 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	13	(11	)

(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 (2004 and 2003 – 12 years), and over the expected average future service life to full eligibility age of 9 years for other post-retirement benefits (2004 and 2003 – 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)	2005	2004	2005	2004
Partially funded plans	745	537	—	—
Unfunded plans	—	87	144	128
Benefit obligation at end of year	745	624	144	128

Components of Net Periodic Benefit Cost (a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2005		2004		2003		2005	2004	2003
Current service costs	32		25		18		5	5	3
Interest costs	38		34		32		6	7	6
Expected return on plan assets (b)	(28	)	(25	)	(20	)	—	—	—
Amortization of net actuarial loss	21		19		22		1	1	1
Net periodic benefit cost recognized (c)	63		53		52		12	13	10

Components of Net Incurred Benefit Cost (a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2005		2004		2003		2005	2004	2003
Current service costs	32		25		18		5	5	3
Interest costs	38		34		32		6	7	6
Actual (return) loss on plan assets (b)	(41	)	(33	)	(45	)	—	—	—
Actuarial (gain) loss	75		21		37		8	4	8
Net incurred benefit cost	104		47		42		19	16	17

(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)	2005	2004	2003	2005	2004	2003
Discount rate	5.75	6.00	6.50	5.75	6.00	6.50
Expected return on plan assets	6.75	7.00	7.25	—	—	—
Rate of compensation increase	4.50	4.00	4.00	4.25	4.00	4.00

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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, 2005 and 2004, and the target allocation for 2006 are as follows:

	Target Allocation %	Percentage of Plan Assets
	2006	2005	2004
Asset Category
Equities	60	60	60
Fixed income	40	40	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 2006 will be $64 million, including approximately $12 million for the company’s senior executive and supplemental retirement plans.  Expected benefit payments from all of our plans are as follows:

		Other Post-
	Pension	retirement
	Benefits	Benefits
2006	29	4
2007	31	5
2008	33	5
2009	35	6
2010	37	6
2011 – 2015	227	39
Total	392	65

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 $10 million in 2005 (2004 – $8 million; 2003 – $6 million).

9. INCOME TAXES

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

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

See next page for more technical details and amounts.

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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:

	2005				2004				2003
($ millions)	Amount		%		Amount		%		Amount		%
Federal tax rate	696		35		582		36		668		37
Provincial abatement	(199	)	(10	)	(162	)	(10	)	(181	)	(10	)
Federal surtax	22		1		18		1		20		1
Provincial tax rates	229		12		190		12		226		13
Statutory tax and rate	748		38		628		39		733		41
Adjustment of statutory rate for future rate reductions	(88	)	(5	)	(86	)	(5	)	(100	)	(6	)
	660		33		542		34		633		35
Add (deduct) the tax effect of:
Crown royalties	119		6		133		8		50		3
Resource allowance (a)	(48	)	(2	)	(69	)	(4	)	(31	)	(2	)
Large corporations tax	23		1		18		1		19		1
Tax rate changes on opening future income taxes (b)	—		—		(53	)	(3	)	89		5
Attributed Canadian royalty income	(24	)	(1	)	(29	)	(2	)	(8	)	—
Stock-based compensation	8		—		8		—		3		—
Assessments and adjustments	7		—		—		—		—		—
Capital gains	(6	)	—		(18	)	(1	)	(34	)	(2	)
Other	3		—		(2	)	—		(3	)	—
Income taxes and effective rate	742		37		530		33		718		40

(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)Effective January 1, 2003, the Canadian government enacted changes to the federal taxation policies relating to the resource sector.  The changes are to be fully phased in by 2007 and include a 7% reduction of the federal rate, deductibility of provincial Crown royalties and the elimination of the federal resource allowance deduction.  In 2005 and 2004, the company’s future income tax liabilities related to its resource operations were based on the future tax rates with the full 7% federal tax rate reduction.

In 2005 net income tax payments totalled $77 million (2004 – $50 million payment; 2003 – $45 million payment).

Effective April 1, 2004, the Alberta provincial corporate tax rate decreased by 1% (2003 – decrease of 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 (2003 – an increase of $89 million).

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

	2005				2004
($ millions)	Current		Non-current		Current	Non-current
Future income tax assets:
Employee future benefits	7		—		14	—
Asset retirement obligations	19		—		16	—
Inventories	67		—		27	—
Other	(10	)	—		—	—
	83		—		57	—
Future income tax liabilities:
Depreciation	—		3 294		—	2 747
Overburden removal costs	—		68		—	20
Deferred maintenance shutdown costs	—		51		—	44
Reorganization adjustment	—		197		—	—
Employee future benefits	—		(87	)	—	(77	)
Asset retirement obligations	—		(162	)	—	(139	)
Attributed Canadian royalty income	—		(86	)	—	(69	)
Other	—		(1	)	—	19
	—		3 274		—	2 545

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

(a) Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment.  Under contracts existing at December 31, 2005, future minimum amounts payable under these leases and agreements are as follows:

	Pipeline
	Capacity and	Operating
($ millions)	Energy Services (1)	Leases
2006	222	36
2007	216	32
2008	232	27
2009	242	22
2010	245	20
Later years	4 018	96
	5 175	233

(1)Includes annual tolls payable under transportation service agreements with major pipeline companies to use a portion of their pipeline capacity and tankage, as applicable, including the shipment of crude oil from Fort McMurray to Hardisty, Alberta.  The agreements commenced in 1999 and extend up to 2033.  As the initial shipper on one of the pipelines, Suncor’s tolls payable are subject to annual adjustments.

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

(b) Contingencies

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

The company carries both primary and excess property loss and business interruption insurance policies with a combined coverage limit of up to US$1,150 million, net of deductible amounts.  The primary property loss policy of US$250 million has a deductible of US$10 million per incident and the primary business interruption policy of US$200 million has a deductible per incident of the greater of US$50 million gross earnings lost (as defined in the insurance policy) or 30 days from the incident.  The excess coverage of US$700 million can be used for either property loss or business interruption coverage for its oil sands operations.  For business interruption purposes, this excess coverage begins the later of full utilization of the primary business interruption coverage or 90 days from the date of the incident.  Effective January 1, 2006, the excess coverage has a ceiling of US$40 WTI for the purposes of determining the loss for business interruption claims.

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, 2005, 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 $340 million of accounts receivable (2004 – $170 million) having a maturity of 45 days or less, to a third party.  The third party is a multiple party securitization vehicle that provides funding for numerous asset pools.  As at December 31, 2005, $340 million in outstanding accounts receivable had been sold under the program.  Under the recourse provisions, the company will provide indemnification against credit losses for certain counterparties, which did not exceed $58 million in 2005.  A liability has not 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, 2005, were $170 million and approximately $2,220 million, respectively.  The company recorded an after-tax loss of approximately $4 million on the securitization program in 2005 (2004 – $2 million; 2003 – $3 million).

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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.  As described in note 1, 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 has provided a residual value guarantee on the equipment of up to $7 million should it elect not to repurchase the equipment at the end of the lease term.  Had the company elected to terminate the lease at December 31, 2005, the total cost would have been $21 million (2004 – $25 million).  Annualized equipment lease payments in 2005 were $5 million (2004 – $6 million; 2003 – $4 million).

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.

(d) Subsequent Event

In January and February 2006, the company received an additional $175 million in proceeds related to its business interruption insurance coverage.  The proceeds related to business activity during 2005 and have accordingly been recognized as revenue in the fourth quarter of 2005.  This brings total proceeds from our business interruption claim to US$500 million out of the US$900 million available.  The company is currently negotiating a final settlement with its business interruption insurers.  Any subsequent proceeds will be recorded when unconditionally received or receivable.

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, 2002	448 972	578
Issued for cash under stock option plans	1 977	20
Issued under dividend reinvestment plan	235	6
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

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 criteria.  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 next page for more technical details and amounts on the company’s stock option plans.

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(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 518,000 common share options in 2005 (2004 – 1,346,000; 2003 – 1,902,000) 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 2005, the company granted 1,253,000 options (2004 –1,742,000; 2003 – 1,305,000) 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.  As the company had been accruing costs of these options, the impact on net earnings for 2005 was not significant.  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 criteria is not met, the unvested options that have not previously expired or been cancelled, will automatically vest on January 1, 2012.

(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 901,000 common share options in 2005 (2004 – nil, 2003 – 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 1,190,000 DSUs outstanding at December 31, 2005 (1,228,000 at December 31, 2004).  DSUs were granted to certain executives under the company’s former employee long-term incentive program.  Certain members of the Board of Directors have also elected to receive DSUs in lieu of cash compensation.  DSUs are only redeemable at the time a unitholder ceases employment or Board membership, as applicable.

In 2005, 81,000 DSUs were redeemed for cash consideration of $5 million (2004 – no redemption, 2003 – 185,000 redeemed for cash consideration of $5 million).  Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments.  Final DSU redemption amounts are subject to change depending on the company’s share price at the time of exercise.  Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period.  As at December 31, 2005, the total liability related to the DSUs was $87 million, of which $4 million was classified as current (see note 7).

During 2005, total pretax compensation expense related to deferred share units was $39 million (2004 – $12 million; 2003 – $8 million).

(v) PERFORMANCE SHARE UNITS (PSUs) During 2005, the company issued 453,000 PSUs (2004 – 354,000; 2003 – nil) under its new employee incentive 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 2005 was $21 million (2004 – $5 million; 2003 – $nil).

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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, 2002	20 326		3.80 – 28.14	19.89
Granted	3 207		23.65 – 29.85	26.70
Exercised	(1 977	)	3.80 – 23.93	10.35
Cancelled	(540	)	10.13 – 27.93	20.94
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
Exercisable, December 31, 2005	9 361		5.28 – 42.65	21.77

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)	2005	2004	2003
	10 724	4 342	6 893

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2005:

	Outstanding		Exercisable
		Weighted-	Weighted-		Weighted-
	Number	average Remaining	average Exercise	Number	average Exercise
Exercise Prices ($ )	(thousands)	Contractual Life	Price Per Share ($)	(thousands)	Price Per Share ($)
5.28 – 10.13	912	3	9.51	912	9.51
12.28 – 21.35	3 074	4	15.38	3 074	15.38
23.65 – 31.45	10 586	6	27.12	4 753	26.51
32.22 – 43.45	3 505	8	37.79	622	35.20
45.51 – 71.13	1 126	7	57.26	—	—
Total	19 203	6	28.12	9 361	21.77

(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:

	2005			2004			2003
Annual dividend per share	$	0.24		$	0.23		$	0.1925
Risk-free interest rate	3.69		%	3.79		%	4.39		%
Expected life	6 years			6 years			7 years
Expected volatility	28		%	29		%	32		%
Weighted-average fair value per option	$	15.42		$	12.02		$	9.94

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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)	2005	2004	2003
Net earnings attributable to common shareholders – as reported	1 245	1 088	1 087
Less: compensation cost under the fair value method for pre-2003 options	13	47	30
Pro forma net earnings attributable to common shareholders for pre-2003 options	1 232	1 041	1 057
Basic earnings per share
As reported	2.73	2.40	2.42
Pro forma	2.70	2.30	2.35
Diluted earnings per share
As reported	2.67	2.36	2.26
Pro forma	2.64	2.26	2.20

12. EARNINGS PER COMMON SHARE

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

($ millions)	2005	2004	2003
Net earnings attributable to common shareholders	1 245	1 088	1 087
(millions of common shares)
Weighted-average number of common shares	456	453	450
Dilutive securities:
Options issued under stock-based compensation plans	10	9	8
Redemption of preferred securities by the issuance of common shares	—	—	22
Weighted-average number of diluted common shares	466	462	480
(dollars per common share)
Basic earnings per share (a)	2.73	2.40	2.42
Diluted earnings per share (b)	2.67	2.36	2.26

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.

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14. FINANCING EXPENSES (INCOME)

($ millions)	2005		2004		2003
Interest on debt	151		157		185
Capitalized interest	(119	)	(62	)	(63	)
Net interest expense	32		95		122
Foreign exchange (gain) on long-term debt	(37	)	(82	)	(213	)
Other foreign exchange (gain) loss	(10	)	11		17
Total financing expenses (income)	(15	)	24		(74	)

Cash interest payments in 2005 totalled $149 million (2004 – $152 million; 2003 – $184 million).

15. INVENTORIES

($ millions)	2005	2004
Crude oil	279	194
Refined products	124	120
Materials, supplies and merchandise	120	109
Total	523	423

The replacement cost of crude oil and refined product inventories exceeded their LIFO carrying value by $202 million (2004 – $65 million) as at December 31, 2005.

During 2005, the company recorded a pretax gain of $16 million related to a permanent reduction in LIFO inventory layers (2004 – $8 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)	2005	2004	2003
Operating revenues
Sales to Energy Marketing and Refining – Canada segment joint ventures:
Refined products	327	320	301
Petrochemicals	279	272	187

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, 2005, amounts due from Energy Marketing and Refining – Canada segment joint ventures were $22 million (2004 – $17 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.

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17. SUPPLEMENTAL INFORMATION

($ millions)	2005	2004	2003
Export sales (a)	648	693	549
Exploration expenses
Geological and geophysical	22	33	18
Other	1	1	1
Cash costs	23	34	19
Dry hole costs	33	21	32
Cash and dry hole costs (b)	56	55	51
Leasehold impairment (c)	13	8	16
	69	63	67
Taxes other than income taxes
Excise taxes (d)	482	496	428
Production, property and other taxes	47	44	38
	529	540	466
Allowance for doubtful accounts	4	3

(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	2005		2004		2003
Net earnings as reported, Canadian GAAP		1 245		1 088		1 087
Adjustments
Derivatives and hedging activities	(a)	83		92		(176	)
Stock-based compensation	(b)	(26	)	(10	)	(2	)
Asset retirement obligations	(c)	—		—		7
Income tax expense		(28	)	(27	)	54
Net earnings from continuing operations, U.S. GAAP		1 274		1 143		970
Cumulative effect of change in accounting principles, net of income taxes of $nil (2004 – $nil; 2003 – $23)	(c)	—		—		(66	)
Net earnings, U.S. GAAP		1 274		1 143		904
Derivatives and hedging activities, net of income taxes of $70 (2004 – $35; 2003 – $7)	(a)	140		(67	)	18
Minimum pension liability, net of income taxes of $8 (2004 – $3; 2003 – $nil)	(d)	(15	)	5		7
Foreign currency translation adjustment	(e)	(26	)	(29	)	(26	)
Comprehensive income, U.S. GAAP		1 373		1 052		903

per common share (dollars)	2005	2004	2003
Net earnings per share from continuing operations, U.S. GAAP
Basic	2.79	2.52	2.16
Diluted	2.73	2.47	2.02
Net earnings per share, U.S. GAAP
Basic	2.79	2.52	2.01
Diluted	2.73	2.47	1.88

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

		December 31, 2005				December 31, 2004
		As		U.S.		As		U.S.
	Notes	Reported		GAAP		Reported		GAAP
Current assets	(a,f)	1 916		1 916		1 195		1 300
Property, plant and equipment, net	(f)	12 966		12 966		10 326		10 340
Deferred charges and other	(a,d)	469		500		320		367
Total assets		15 351		15 382		11 841		12 007
Current liabilities	(a)	1 935		1 935		1 409		1 701
Long-term borrowings	(a,f)	3 007		3 029		2 217		2 275
Accrued liabilities and other	(d)	1 005		1 092		749		815
Future income taxes	(a,d)	3 274		3 247		2 545		2 526
Share capital	(b)	732		780		651		699
Contributed surplus	(b)	50		88		32		44
Cumulative foreign currency translation	(e)	(81	)	—		(55	)	—
Retained earnings		5 429		5 341		4 293		4 176
Accumulated other comprehensive income	(a,d,e)	—		(130	)	—		(229	)
Total liabilities and shareholders’ equity		15 351		15 382		11 841		12 007

(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 U.S. dollar 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, 2005 the company had hedged a portion of its forecasted Canadian dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2006 and 2007.  The company has not hedged any portion of the foreign exchange component of these forecasted cash flows.

While the company’s current strategic intent is to only manage the exposure relating to changes in the U.S. dollar WTI component of its crude oil sales, 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.

During 2005, the company recognized $2 million of hedging losses that, under U.S. GAAP, would have been recognized as hedge ineffectiveness losses in prior periods. Under U.S. GAAP, for the year ended December 31, 2005, the company would have recognized $2 million of hedge ineffectiveness relating to forecasted cash flows in 2006 and 2007 primarily due to foreign exchange fluctuations during the period (2004 – $57 million ineffectiveness relating to 2005 forecasted cash flows).  The net earnings impact of this ineffectiveness will not be recognized for Canadian GAAP purposes until the related forecasted crude oil sales occur.

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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, 2005, the company had interest rate derivatives classified as fair value hedges outstanding for up to six years relating to fixed rate debt.

De-designated Hedging Instruments

During 2003, the company de-designated and monetized purchased crude oil call option hedging instruments for net proceeds of $28 million.  For Canadian GAAP purposes, as it was probable that the underlying forecasted crude oil sales would occur, the related $28 million pretax gain on monetization of the call options was deferred and recognized as additional crude oil revenues during 2004.  For U.S. GAAP purposes, the company recognized the $28 million pretax gain as hedge ineffectiveness income during 2003.

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)	2005		2004
OCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $69 (2004 – $34)	(138	)	(71	)
Current period net changes arising from cash flow hedges, net of income taxes of $2 (2004 – $61)	(3	)	(122	)
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $72 (2004 – $26)	143		55
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $1 (2004 – $69)	2		(138	)

For the year ended December 31, 2005, assets increased by $22 million and liabilities increased by $22 million as a result of recording all derivative instruments at fair value in accordance with U.S. GAAP.

The earnings loss associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $3 million, net of income taxes of $2 million (2004 – loss of $130 million, net of income taxes of $66 million; 2003 – loss of $199 million, net of income taxes of $93 million).  The company estimates that $4 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, 2005 U.S. GAAP net earnings increased by $55 million, net of income taxes of $28 million (2004 – increased net earnings of $65 million, net of income taxes of $27 million; 2003 – decreased net earnings of $120 million, net of income taxes of $56 million) to reflect the impact of the above items.

(b) Stock-based Compensation

Under Canadian GAAP, compensation expense has not been recognized for common share options granted prior to January 1, 2003, including options issued in connection with both the company’s SunShare long-term incentive plan, as well as those common shares and common share options awarded to employees under the company’s previous long-term incentive program that matured April 1, 2002. Under U.S. GAAP, certain of the SunShare options would have been accounted for using the variable method of accounting for employee stock compensation.  Further, for U.S. GAAP purposes, compensation expense is recognized ratably over the life of the previous long-term incentive program for those options and common shares awarded under that plan.  For the year ended December 31, 2005, U.S. GAAP net earnings would have been reduced by $26 million (2004 – $10 million; 2003 – $2 million) to reflect additional stock-based compensation expense.

Under Canadian GAAP, the company now expenses the compensation cost of all common share options issued after January 1, 2003 ratably over the estimated vesting period of the respective options.  For U.S. GAAP purposes, the company would have adopted Statement 148 in 2003, permitting the company to expense common share options issued after January 1, 2003 in a manner consistent with Canadian GAAP.

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Consistent with Canadian GAAP, for U.S. GAAP purposes the company would have continued to disclose pro forma stock-based compensation cost for common stock options awarded prior to January 1, 2003 (“pre-2003 options”) as if the fair value method had been adopted.  Under U.S. GAAP, had the company accounted for its pre-2003 options using the fair value method (excluding the earnings effect of the SunShare and long-term employee incentive options described above), pro forma net earnings and pro forma basic earnings per share for the year ended December 31, 2005 would have been reduced by $4million (2004 – $37 million; 2003 – $27 million) and $0.01 per share (2004 – $0.08; 2003 – $0.06), respectively.

(c) Asset Retirement Obligations

Under Canadian GAAP, the company retroactively adopted Canadian accounting standards related to asset retirement obligations on January 1, 2004, with restatements of all prior period comparative amounts.  Under U.S. GAAP the company would have adopted asset retirement obligations on January 1, 2003 and would have been required to record the cumulative effect of the change in accounting policy in 2003 earnings.  This GAAP difference would have decreased U.S. GAAP net earnings by $61 million in 2003 (net of future income taxes of $21 million).

(d) Minimum Pension Liability

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.

Under U.S. GAAP, at December 31, 2005, the company would have recognized a minimum pension liability of $87 million (2004 – $66 million), an intangible asset of $9 million (2004 – $11 million) and an other comprehensive loss of $51 million, net of income taxes of $27 million (2004 – $36 million, net of income taxes of $19 million).  Other comprehensive income for the year ended December 31, 2005 would have decreased by $15 million, net of income taxes of $8 million (2004 – an increase in other comprehensive income of $5 million, net of income taxes of $3 million; 2003 – an increase in other comprehensive income of $7 million, net of income taxes of $nil).

(e) Cumulative Foreign Currency Translation

Under Canadian GAAP, foreign currency losses of $26 million (2004 – $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.

(f) Variable Interest Entities

For U.S. GAAP purposes, the company consolidated the VIE related to the sale of equipment as described in note 10c as of January 1, 2004.  The impact on the December 31, 2004 balance sheet would be an increase to property, plant and equipment of $14 million, an increase to materials and supplies inventory of $8 million and an increase to long-term debt of $22 million.  The VIE was consolidated for Canadian GAAP purposes effective January 1, 2005 without restatement of prior periods (see note 1).

The accounts receivable securitization program, as currently structured, does not meet the FIN 46 (R) criteria for consolidation by Suncor (see note 10c).

(g) Suspended Exploratory Well Costs

Effective January 1, 2005, Suncor adopted Financial Accounting Standards Board Staff Position 19-1 (FSP 19-1), “Accounting for Suspended Well Costs”. FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies”, to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.  There were no capitalized exploratory well costs charged to expense upon the adoption of FSP 19-1.

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

Change in Capitalized Suspended Exploratory Well Costs

($ millions)	2005		2004		2003
Balance, beginning of year	5		1		—
Additions pending determination of proved reserves	14		5		1
Charged to dry hole expense	(2	)	—		—
Reclassifications to proved properties	(2	)	(1	)	—
Balance, end of year	15		5		1
Capitalized for a period greater than one year ($ millions)	1		—		—
Number of projects that have exploratory well costs capitalized for a period greater than 12 months	2		—		—

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h) 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 (net versus gross reported).  The EITF is effective for transactions entered into subsequent to April 1, 2006.

As required by EITF 04-13, we record certain crude oil, natural gas, petroleum product and chemical purchases and sales entered into contemporaneously with the same counterparty on a net basis within the “purchases of crude oil and products” line in the Consolidated Statements of Earnings.  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 2005, 2004 and 2003 are shown below.

($ millions)	2005	2004	2003
Consolidated revenues	11 086	8 665	6 611
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	16	7	—

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

Recently Issued Accounting Standards

In December 2004, the U.S. Financial Accounting Standards Board issued SFAS 123(R), “Share-Based Payment”.  The standard, effective January 1, 2006, 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, SFAS 123(R) requires recognition of compensation expense for the portion of outstanding unvested awards granted prior to the effective date.  The company currently records an expense under Canadian GAAP for all common share options issued on or after January 1, 2003, with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders’ Equity.  The company expects the adoption of SFAS 123R on January 1, 2006, for U.S. GAAP reporting purposes will not have a significant impact on net earnings.

In 2005, the FASB issued SFAS 153, “Exchange of Non-monetary Assets”.  Effective January 1, 2006, all non-monetary transactions must be measured at fair value (if determinable) unless the transaction lacks commercial substance, or is an exchange of a product held for sale in the ordinary course of business, or is a product to be sold in the same line of business.  Commercial substance exists when the company’s future cash flows are expected to change significantly as a result of a transaction.  The company will be 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 will be recorded.  The amount of the gross up of revenues and purchases of crude oil products will be dependent on the prevailing prices for natural gas.  Currently the transaction is recorded net in purchases of crude oil and products.  Retroactive adjustment is prohibited by the standard.

In May 2005, the FASB issued SFAS No. 154, “Accounting Changes and Error Corrections”.  Among other changes, this Statement requires retrospective application for voluntary changes in accounting principle, unless it is impractical to do so.  This Statement is effective on a prospective basis beginning January 1, 2006.

In November 2004, the FASB issued SFAS No. 151, “Inventory Costs, an amendment of ARB No. 43, Chapter 4.” This Statement clarifies that items, such as abnormal idle facility expense, excessive spoilage, double freight, and handling costs, be recognized as current-period charges.  In addition, the Statement requires that allocation of fixed production overheads to the costs of conversion be based on the normal capacity of the production facilities.  Suncor is required to implement this Statement in 2006.  The company does not expect the standard to have a significant impact on earnings or financial position.

The U.S. Emerging Issues Task Force (EITF) has issued EITF Abstract 04-6 “Accounting for Stripping Costs Incurred during Production in the Mining Industry”.  The abstract is effective January 1, 2006.  The EITF consensus is that stripping (overburden removal) costs incurred during the production phase of a mine are variable production costs that should be included in the costs of inventory produced during the period.  Up until December 31, 2005, the company has deferred and amortized stripping costs for Canadian GAAP purposes.  The company is currently assessing whether to expense overburden stripping costs as incurred (see Summary of Significant Accounting Policies page 65).

97

QUARTERLY SUMMARY (unaudited)

FINANCIAL DATA

	For the Quarter Ended										For the Quarter Ended
	Mar		June		Sept		Dec		Total		Mar		June		Sept		Dec		Total
	31		30		30		31		Year		31		30		30		31		Year
($ millions except per share amounts)	2005		2005		2005		2005		2005		2004		2004		2004		2004		2004
Revenues	2 061		2 380		3 142		3 503		11 086		1 806		2 212		2 326		2 321		8 665
Net earnings (loss)
Oil Sands	117		117		253		586		1 073		239		231		263		261		994
Natural Gas	26		27		24		78		155		22		35		23		35		115
Energy Marketing and Refining – Canada	(3	)	5		17		22		41		30		(3	)	29		24		80
Refining and Marketing – U.S.A. (c)	6		31		50		55		142		(3	)	12		15		10		34
Corporate and eliminations	(48	)	(68	)	(3	)	(47	)	(166	)	(72	)	(73	)	7		3		(135	)
	98		112		341		694		1 245		216		202		337		333		1 088
Per common share
Net earnings attributable to common shareholders
Basic	0.22		0.24		0.75		1.52		2.73		0.48		0.45		0.74		0.73		2.40
Diluted	0.21		0.24		0.73		1.48		2.67		0.46		0.43		0.73		0.72		2.36
Cash dividends	0.06		0.06		0.06		0.06		0.24		0.05		0.06		0.06		0.06		0.23
Cash flow from (used in) operations
Oil Sands	252		215		445		983		1 895		365		421		509		457		1 752
Natural Gas	83		81		104		144		412		83		90		80		66		319
Energy Marketing and Refining – Canada	22		26		44		60		152		56		23		52		57		188
Refining and Marketing – U.S.A. (c)	18		52		82		95		247		(6	)	21		21		23		59
Corporate and eliminations	(81	)	(69	)	(24	)	(56	)	(230	)	(84	)	(65	)	(77	)	(79	)	(305	)
	294		305		651		1 226		2 476		414		490		585		524		2 013
OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
Base operations	121.2		119.5		125.2		263.3		157.6		213.9		210.8		230.2		206.9		215.6
Firebag	18.7		8.7		23.0		26.0		19.1		5.9		15.1		7.3		15.6		10.9
	139.9		128.2		148.2		267.7		171.3		219.8		225.9		237.5		222.5		226.5
Sales
Light sweet crude oil	75.3		48.3		69.9		108.6		73.3		112.2		118.7		113.5		115.3		114.9
Diesel	11.8		9.0		10.6		30.7		15.6		27.5		29.7		28.7		25.5		27.9
Light sour crude oil	38.5		54.2		41.7		104.2		59.8		74.3		68.9		76.3		80.9		75.1
Bitumen	18.4		9.6		22.3		7.2		16.6		—		14.5		7.9		11.0		8.4
	144.0		121.1		144.5		250.7		165.3		214.0		231.8		226.4		232.7		226.3

98

	For the Quarter Ended					For the Quarter Ended
	Mar	June	Sept	Dec	Total	Mar	June	Sept	Dec	Total
	31	30	30	31	Year	31	30	30	31	Year
	2005	2005	2005	2005	2005	2004	2004	2004	2004	2004
OPERATING DATA (continued)
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
Light sweet crude oil	45.41	39.20	52.08	55.96	49.93	40.26	45.70	46.03	50.55	45.60
Other (diesel, light sour crude oil and bitumen)	47.31	50.47	59.70	63.84	56.90	35.85	38.28	42.29	39.62	39.13
Total	46.44	45.98	56.01	60.42	53.81	38.16	41.88	44.08	44.68	42.28
Total (a)	54.80	57.24	67.95	66.68	62.68	43.28	48.18	52.72	54.40	49.78
Cash operating costs and total operating costs – Base Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs	15.10	16.30	18.00	12.90	14.95	9.65	9.75	9.00	10.90	9.80
Natural gas	4.70	2.65	4.60	3.40	3.75	2.10	2.30	1.40	2.20	2.00
Firebag bitumen	—	—	—	1.60	0.75	—	—	—	—	—
Imported bitumen	0.10	—	—	0.10	0.05	0.40	0.05	0.10	0.10	0.15
Cash operating costs (3)	19.90	18.95	22.60	18.00	19.50	12.15	12.10	10.50	13.20	11.95
Firebag start-up costs	—	—	—	0.30	0.10	1.20	—	—	—	0.30
Total cash operating costs (4)	19.90	18.95	22.60	18.30	19.60	13.35	12.10	10.50	13.20	12.25
Depreciation, depletion and amortization	9.05	9.45	9.00	6.20	8.00	6.20	6.20	5.70	6.25	6.10
Total operating costs (5)	28.95	28.40	31.60	24.50	27.60	19.55	18.30	16.20	19.45	18.35
Cash operating costs and total operating costs – Firebag
Cash costs	8.90	18.95	6.85	6.25	8.45	—	6.55	14.90	7.00	8.30
Natural gas	10.10	16.40	13.70	13.40	13.05	—	11.65	11.90	10.45	11.20
Cash operating costs (6)	19.00	35.35	20.55	19.65	21.50	—	18.20	26.80	17.45	19.50
Depreciation, depletion and amortization	4.75	7.60	4.10	4.60	4.90	—	5.80	7.45	5.55	6.00
Total operating costs (7)	23.75	42.95	24.65	24.25	26.40	—	24.00	34.25	23.00	25.50
NATURAL GAS
Gross production (b)
Natural gas
(millions of cubic feet per day)	191	175	200	193	190	197	209	201	193	200
Natural gas liquids
(thousands of barrels per day)	3.0	2.2	2.2	2.3	2.4	2.2	2.2	2.6	2.9	2.5
Crude oil
(thousands of barrels per day)	0.9	1.0	0.7	0.6	0.8	0.9	1.1	1.0	1.0	1.0
Total (barrels of oil equivalent
per day at 6:1 for natural gas)	35.7	32.4	36.3	35.0	34.8	35.9	38.1	37.1	36.1	36.8
Average sales price (2)
Natural gas
(dollars per thousand cubic feet)	6.81	7.29	8.32	11.66	8.57	6.54	6.77	6.49	7.02	6.70
Natural gas (a) (dollars per
thousand cubic feet)	6.74	7.26	8.34	11.83	8.59	6.59	6.84	6.53	6.98	6.73
Natural gas liquids
(dollars per barrel)	38.32	52.52	58.00	57.85	50.70	38.13	43.53	42.06	46.46	42.82
Crude oil – conventional
(dollars per barrel)	61.40	63.86	63.77	72.60	64.85	44.14	47.08	55.43	55.26	50.41

99

	For the Quarter Ended					For the Quarter Ended
	Mar	June	Sept	Dec	Total	Mar	June	Sept	Dec	Total
	31	30	30	31	Year	31	30	30	31	Year
	2005	2005	2005	2005	2005	2004	2004	2004	2004	2004
OPERATING DATA (continued)
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)	15.1	16.1	15.6	14.3	15.2	15.2	15.5	15.3	15.6	15.4
Margins
Refining (8) (cents per litre)	4.8	7.3	9.2	9.0	7.6	7.8	7.4	8.8	7.9	8.0
Refining (8), (a) (cents per litre)	4.8	7.6	10.1	9.3	8.0	7.8	8.0	8.8	7.8	8.1
Retail (9) (cents per litre)	4.7	3.8	5.4	6.4	5.1	5.0	4.3	3.7	4.5	4.4
Utilization of refining capacity (%)	91	100	96	95	95	108	85	104	101	100
REFINING AND MARKETING – U.S.A. (c)
Refined product sales (thousands of cubic metres per day)	10.1	12.6	17.3	14.5	13.7	8.1	8.9	10.9	9.5	9.3
Margins
Refining (8) (cents per litre)	6.3	9.5	8.9	10.4	9.0	5.0	9.0	5.1	7.7	6.7
Refining (8), (a) (cents per litre)	6.3	9.5	8.9	10.4	9.0	5.0	9.3	5.3	7.7	6.8
Retail (9) (cents per litre)	3.3	4.3	7.5	5.4	5.1	5.0	6.2	4.2	6.0	5.4
Utilization of refining capacity (%)	96	102	104	91	98	85	86	99	100	92

(a)   Excludes the impact of hedging activities.

(b)   Currently all 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 production – In the fourth quarter of 2005, base operations production included barrels from both mining and in-situ operations that were upgraded. Firebag production reported in the operating summary includes all in-situ production irrespective of whether it was upgraded or sold to third parties. As such these production figures as reported in the operating summary are not additive in the fourth quarter of 2005 and the year ended December 31, 2005.
(2)	Average sales price – Calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(3)	Cash operating costs – base 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 production volumes that are processed through the upgrader facilities. For a reconciliation of this non GAAP financial measure see page 57 of MD&A.
(4)	Total cash operating costs – base operations – Include cash operating costs – Base operations as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on all production volumes that are processed through the upgrader facilities.
(5)	Total operating costs – base operations – Include total cash operating costs – Base operations as defined above and non-cash operating costs. Per barrel amounts are based on all production volumes that are processed through the upgrader facilities.
(6)	Cash operating costs – Firebag – 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.
(7)	Total operating costs – Firebag – Include cash operating costs – Firebag as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes.
(8)	Refining margin – Calculated as the average wholesale unit price from all products less average unit cost of crude oil.
(9)	Retail margin – Calculated as the average street price of Sunoco (Energy, Marketing and Refining – Canada) and Phillips 66-branded (Refining and Marketing – U.S.A.) retail gasoline net of federal excise tax, as applicable, and other adjustments, less refining gasoline transfer price.

Metric conversion

Crude oil, refined products, etc. – 1m³ (cubic metre) = approximately 6.29 barrels

Natural gas – 1m³ (cubic metre) = approximately 35.49 cubic feet

100

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions except for ratios)	2005(a)		2004		2003(a)		2002		2001
Revenues
Oil Sands	3 965		3 640		3 101		2 655		1 404
Natural Gas	679		567		512		339		481
Energy Marketing and Refining – Canada	4 299		3 460		2 936		2 508		2 673
Refining and Marketing – U.S.A.	2 621		1 495		515		—		—
Corporate and eliminations	(478	)	(497	)	(453	)	(431	)	(232	)
	11 086		8 665		6 611		5 071		4 326
Net earnings (loss)
Oil Sands	1 073		994		887		781		271
Natural Gas	155		115		120		34		116
Energy Marketing and Refining – Canada	41		80		53		61		79
Refining and Marketing – U.S.A.	142		34		18		—		—
Corporate and eliminations	(166	)	(135	)	9		(156	)	(117	)
	1 245		1 088		1 087		720		349
Cash flow from (used in) operations
Oil Sands	1 895		1 752		1 803		1 475		486
Natural Gas	412		319		298		164		280
Energy Marketing and Refining – Canada	152		188		164		112		165
Refining and Marketing – U.S.A.	247		59		34		—		—
Corporate and eliminations	(230	)	(305	)	(259	)	(358	)	(132	)
	2 476		2 013		2 040		1 393		799
Capital and exploration expenditures
Oil Sands	1 948		1 119		953		618		1 495
Natural Gas	363		279		184		163		132
Energy Marketing and Refining – Canada	442		228		122		60		54
Refining and Marketing – U.S.A.	337		190		31		—		—
Corporate	63		31		32		37		13
	3 153		1 847		1 322		878		1 694
Total assets	15 351		11 841		10 540		9 046		8 467
Capital employed (b)
Short-term and long-term debt, less cash and cash equivalents	2 891		2 159		2 577		3 204		3 678
Shareholders’ equity	6 130		4 921		3 893		2 886		2 220
	9 021		7 080		6 470		6 090		5 898
Less capitalized costs related to major projects in progress	(2 175	)	(1 467	)	(1 122	)	(511	)	(3 691	)
	6 846		5 613		5 348		5 579		2 207
Total Suncor employees (number at year-end)	5 152		4 605		4 231		3 422		3 307

101

	2005 (a)	2004	2003(a)	2002	2001
Dollars per common share
Net earnings attributable to common shareholders	2.73	2.40	2.42	1.61	0.78
Cash dividends	0.24	0.23	0.1925	0.17	0.17
Cash flow from operations	5.43	4.44	4.53	3.11	1.79
Ratios
Return on capital employed (%) (b), (c)	20.9	19.0	18.3	14.5	17.8
Return on capital employed (%) (d)	15.3	16.1	16.0	13.7	7.3
Return on shareholders’ equity (%) (e)	22.5	24.7	32.1	28.2	16.8
Debt to debt plus shareholders’ equity (%) (f)	33.3	31.4	43.2	52.7	62.4
Net debt to cash flow from operations (times) (g)	1.2	1.1	1.3	2.3	4.6
Interest coverage – cash flow basis (times) (h)	16.9	13.8	11.5	8.1	4.2
Interest coverage – net earnings basis (times) (i)	13.4	10.9	10.1	6.2	2.5

(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 and short-term debt plus 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 twelve month period ended; divided by average capital employed. Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non GAAP financial measure see page 56 of MD&A.

(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.

102

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
	2005	2005	2005	2005	2004	2004	2004	2004
Share ownership
Average number outstanding, weighted monthly (thousands) (a)	454 911	456 141	456 996	457 429	452 123	452 283	452 565	453 900
Share price (dollars)
Toronto Stock Exchange
High	50.07	60.24	73.25	76.05	38.02	36.80	41.49	44.49
Low	38.76	44.00	57.75	57.00	31.62	30.95	32.80	38.20
Close	48.73	57.92	70.42	73.32	35.97	34.01	40.40	42.40
New York Stock Exchange – US$
High	41.70	48.95	62.50	66.00	28.75	28.09	32.63	36.15
Low	31.33	35.38	47.40	48.09	24.68	22.55	24.90	31.16
Close	40.21	47.32	60.53	63.13	27.35	25.61	32.01	35.40
Shares traded (thousands)
Toronto Stock Exchange	107 080	102 317	108 384	107 502	100 401	109 073	102 460	86 424
New York Stock Exchange	84 285	89 244	139 214	175 618	45 120	59 254	64 519	66 536
Per common share information (dollars)
Net earnings attributable to common shareholders	0.22	0.24	0.75	1.52	0.48	0.45	0.74	0.73
Cash dividends	0.06	0.06	0.06	0.06	0.05	0.06	0.06	0.06

(a)The company had approximately 2,420 holders of record of common shares as at January 31, 2006.

Information for Security Holders Outside Canada

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to Canadian non-resident withholding tax of 15%. The withholding tax rate is reduced to 5% on dividends paid to a corporation if it is a resident of the United States that owns at least 10% of the voting shares of the company.

103

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2005	2004	2003	2002	2001
OIL SANDS
Production (thousands of barrels per day)	171.3	226.5	216.6	205.8	123.2
Sales (thousands of barrels per day)
Light sweet crude oil	73.3	114.9	112.3	104.7	56.2
Diesel	15.6	27.9	26.3	23.0	14.8
Light sour crude oil	59.8	75.1	73.3	68.3	42.0
Bitumen	16.6	8.4	6.4	9.3	8.5
	165.3	226.3	218.3	205.3	121.5
Average sales price (dollars per barrel)
Light sweet crude oil	49.93	45.60	40.26	37.56	34.17
Other (diesel, light sour crude oil and bitumen)	56.90	39.13	33.93	29.58	24.86
Total	53.81	42.28	37.19	33.65	29.17
Total (a)	62.68	49.78	40.22	36.94	34.21
Cash operating costs – base operations (b)	19.50	11.95	11.45	11.15	11.35
Total cash operating costs – base operations (b)	19.60	12.25	11.45	11.15	11.35
Total operating costs – base operations (b)	27.60	18.35	17.25	17.25	16.70
Cash operating costs – Firebag (b), (e)	21.50	19.50	—	—	—
Total operating costs – Firebag (b), (e)	26.40	25.50	—	—	—
Capital employed excluding major projects in progress	4 633	4 169	4 050	4 512	1 378
Return on capital employed (%) (c)	24.3	22.9	20.8	16.7	19.6
Return on capital employed (%) (d)	17.6	18.8	17.4	15.6	6.2

(a)Excludes the impact of hedging activities.

(b)Dollars per barrel rounded to the nearest $0.05. See definitions on page 100.

(c)See definitions on page 102.

(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)Firebag stage 1 commenced commercial operations on April 1, 2004.

104

	2005	2004	2003	2002	2001
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
Gross	190	200	187	179	177
Net	137	147	142	124	124
Natural gas liquids (thousands of barrels per day)
Gross	2.4	2.5	2.3	2.4	2.4
Net	1.9	1.8	1.7	1.7	1.7
Crude oil (thousands of barrels per day)
Gross	0.8	1.0	1.4	1.5	1.5
Net	0.7	0.8	1.1	1.2	1.1
Total (thousands of boe (a) per day)
Gross	34.8	36.8	34.9	33.7	33.4
Net	25.3	27.1	26.4	23.6	23.5
Average sales price
Natural gas (dollars per thousand cubic feet)	8.57	6.70	6.42	3.91	6.09
Natural gas (dollars per thousand cubic feet) (b)	8.59	6.73	6.42	3.91	6.12
Natural gas liquids (dollars per barrel)	50.70	42.82	36.08	29.35	34.38
Crude oil – conventional (dollars per barrel)	64.85	50.41	40.29	31.72	33.92
Capital employed	563	448	400	422	291
Return on capital employed (%) (e)	30.7	27.1	29.2	9.5	34.2
Undeveloped landholdings (c)
Oil and gas (millions of acres)
Western Canada
Gross	0.6	0.7	0.5	0.5	0.6
Net	0.4	0.5	0.4	0.4	0.5
International
Gross	0.4	0.7	0.9	1.2	1.7
Net	0.2	0.4	0.2	0.7	1.3
Net wells drilled (d)
Exploratory
Oil	—	—	—	—	—
Gas	8	5	2	2	4
Dry	4	5	31	19	16
Development
Oil	1	—	1	—	—
Gas	18	16	16	18	16
Dry	3	—	4	4	2
	34	26	54	43	38

(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 22 net exploratory wells and 10 net development wells in progress at the end of 2005.

(e)See definitions on page 102.

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	2005	2004	2003	2002	2001
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail (b)	4.5	4.6	4.4	4.5	4.3
Other	3.9	4.1	4.2	4.4	4.4
Jet fuel	0.9	0.9	0.7	0.4	0.7
Diesel	3.3	3.1	3.0	2.9	3.1
	12.6	12.7	12.3	12.2	12.5
Petrochemicals	0.7	0.8	0.8	0.6	0.5
Heating oils	0.4	0.4	0.5	0.4	0.4
Heavy fuel oils	1.0	0.7	0.8	0.6	0.8
Other	0.5	0.8	0.6	0.7	0.6
	15.2	15.4	15.0	14.5	14.8
Margins (cents per litre)
Refining	7.6	8.0	6.5	4.8	5.7
Refining (c)	8.0	8.1	6.4	4.8	5.7
Retail	5.1	4.4	6.6	6.6	6.6
Crude oil supply and refining
Processed at Sarnia refinery
(thousands of cubic metres per day)	10.6	11.1	10.5	10.6	10.2
Utilization of refining capacity (%)	95	100	95	95	92
Capital employed excluding major projects in progress	486	512	551	485	480
Return on capital employed (%) (d)	8.1	14.6	10.3	12.0	18.3
Return on capital employed (%) (d), (e)	5.2	13.6	10.3	12.0	18.3
Retail outlets (f) (number at year-end)	374	378	379	384	400

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	2005	2004	2003	2002	2001
REFINING AND MARKETING – U.S.A. (a)
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	—	—
Other	6.2	3.8	3.5	—	—
Jet fuel	0.8	0.5	0.5	—	—
Diesel	3.3	2.2	2.3	—	—
	11.0	7.2	7.0	—	—
Asphalt	1.6	1.5	1.7	—	—
Other	1.1	0.6	0.4	—	—
	13.7	9.3	9.1	—	—
Margins (cents per litre)
Refining	9.0	6.7	5.9	—	—
Refining (c)	9.0	6.8	5.9	—	—
Retail	5.1	5.4	5.6	—	—
Crude oil supply and refining
Processed at Denver refinery
(thousands of cubic metres per day)	12.1	8.8	9.4	—	—
Utilization of refining capacity (%)	98	92	98	—	—
Capital employed excluding major projects in progress	327	232	270	—	—
Return on capital employed (%) (d), (h)	49.4	12.2	—	—	—
Return on capital employed (%) (d), (e), (h)	28.9	11.0	—	—	—
Retail outlets (g) (number at year-end)	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 102.

(e)If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed (ROCE) 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 and New York Stock Exchange under the symbol SU.

Dividends

Suncor’s Board of Directors reviews its dividend policy quarterly. In 2005, Suncor paid an aggregate dividend of $0.24 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 optional 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 or visit www.computershare.com. Information regarding the purchase plan is also available in the stock information section of www.suncor.com.

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 general meeting of shareholders will be held at 10:30 a.m. MT on April 26, 2006, 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

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

Analyst and Investor Inquiries

John Rogers, vice president, Investor Relations

Telephone: 403-269-8670  Facsimile: 403-269-6217  Email: 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 subscribe to Suncor e-news, go to the newsroom section of our website. To order copies of Suncor’s print materials call 1-800-558-9071.

If you do not receive our annual or quarterly report, but would like to receive these reports regularly, 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 may elect 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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CORPORATE DIRECTORS AND OFFICERS

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, 2005, 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.

Committee	Key Responsibilities
Board Policy, Strategy Review and Governance Committee	Oversees key matters pertaining to 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 and 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.

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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

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 PanGlobal Energy Ltd., Kanetax Energy Inc. and Tenax Inc. He is active with several charitable organizations including Shock Trauma Air Rescue Services (STARS), 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.

Brian A. Canfield (2),(3)

Point Roberts, Washington

Chair, Human Resources
and Compensation Committee
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.

Bryan P. Davies (1),(4)

Toronto, Ontario

Director 1991 to 1996 and since 2000

Bryan Davies is president of Davtak (Canada) Inc., a policy consulting firm based in Toronto. He is also a director of the General Insurance Statistical Agency. He 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 is also active with numerous not-for-profit and charitable organizations, including serving 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 a partner in the law firm of Felesky Flynn LLP in Calgary, Alberta. Mr. Felesky also serves as a director on the board and chair of the audit committee of Epcor Power LP. He is also a member of the board of Precision Drilling Corporation and Fairquest Energy Ltd. Mr. Felesky is actively involved in not-for-profit and charitable organizations. He is the co-chair of Homefront on Domestic Violence, vice chair of the Canada West Foundation, member of the senate of Athol Murray College of Notre Dame, and board member of the Canadian Unity Council and 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., a real estate company in Edmonton, Alberta. 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.

W. Douglas (Doug) Ford (1),(4)

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 serves as chairman of the Canadian Council of Chief Executives.

John R. Huff (2),(3)

Houston, Texas

Chair, Board Policy, Strategy Review
and Governance Committee
Director since 1998

John Huff is chairman and chief executive officer of Oceaneering International Inc., an oil field services company. Mr. Huff is also a director of BJ Services Company. He is active in a variety of non-profit organizations, including the American Bureau of Shipping, the Marine Resources Foundation, and St. Luke’s Episcopal Hospital in Houston.

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Robert W. Korthals (1)

Toronto, Ontario

Director since 1996

Robert Korthals is the former president of the Toronto-Dominion Bank. Mr. Korthals is currently chairman of the Ontario Teachers’ Pension Plan Board. He is a director of Bucyrus International, Inc., Great Lakes Carbon Income Trust, Jannock Properties Limited, Rogers Communications Inc., easyHome Inc., Cognos Inc. and four structured split share funds traded on the TSX sponsored by Mulvihill Investments. In addition, Mr. Korthals serves as a director of the Canadian Parks and Wilderness Foundation.

M. Ann McCaig (3),(4)

Calgary, Alberta

Chair, Environment,
Health and Safety Committee
Director since 1995

Ann McCaig is the president of VPI Investments Ltd., a private investment holding company. Mrs. McCaig is actively involved with charitable and community activities. She is currently chair of the Alberta Adolescent Recovery Centre, co-chair of the Alberta Children’s Hospital Foundation $50 million All for One – All for Kids campaign, 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.

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. From 1992 to 2000, Mr. O’Brien was executive vice president of Suncor’s wholly-owned subsidiary, Suncor Energy Products Inc. (formerly Sunoco Inc.). Mr. O’Brien also serves on the boards of PrimeWest Energy Inc. and Shaw Communications Inc. As well, he is past chair of the board of trustees for Nature Conservancy of Canada, past-chair of Canadian Petroleum Products Institute and past-chair of Canada’s Voluntary Challenge for Global Climate Change.

(1)Audit Committee

(2)Board Policy, Strategy Review and Governance Committee

(3)Human Resources and Compensation Committee

(4)Environment, Health and Safety Committee

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 the company’s management proxy circular.

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.

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OFFICERS

Richard L. George

President and Chief Executive Officer

J. Kenneth Alley

Senior Vice President
and Chief Financial Officer

M. (Mike) Ashar

Executive Vice President,
Refining and Marketing – U.S.A.

David W. Byler

Executive Vice President,

Natural Gas and Renewable Energy

Bart W. Demosky

Vice President and Treasurer

Terrence J. Hopwood

Senior Vice President
and General Counsel

Sue Lee

Senior Vice President, Human
Resources and Communications

Kevin D. Nabholz

Executive Vice President,
Major Projects

Janice B. Odegaard

Vice President, Associate General
Counsel and Corporate Secretary

Thomas L. Ryley

Executive Vice President, Energy
Marketing and Refining – Canada

Jay Thornton

Senior Vice President,
Business Integration

Steven W. Williams

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.

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