EXHIBIT 1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2003, including reconciliation to U.S. GAAP (Note 19)

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 54 to 89 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 54 to 57. If alternate accounting methods exist, management has chosen those policies it deems the most appropriate in the circumstances. In discharging its responsibilities for the integrity and reliability of the financial statements, management maintains and relies on 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.

In order to provide their opinion on the accompanying consolidated financial statements, PricewaterhouseCoopers LLP, the independent external auditors, review the company’s system of internal controls and conduct their work to the extent that they consider appropriate. The company also retains independent petroleum consultants, Gilbert Laustsen Jung Associates Ltd., to conduct independent evaluations of the company’s oil and gas reserves.

The Audit Committee of the Board of Directors, currently composed of four independent directors, reviews the effectiveness of the company’s financial reporting systems, management information systems, internal control systems and the 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.

/s/ Richard L. George		/s/ J. Kenneth Alley

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

January 27, 2004

Auditors’ Report

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have audited the Consolidated Balance Sheets of Suncor Energy Inc. as at December 31, 2003 and 2002 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, 2003. 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, 2003 and 2002 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2003, in accordance with Canadian generally accepted accounting principles.

/s/ PricewaterhouseCoopers LLP


PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

January 27, 2004

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 January 27, 2004 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.

/s/ PricewaterhouseCoopers LLP


PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

January 27, 2004

Summary of Significant Accounting Policies

Suncor Energy Inc. is an integrated Canadian 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 mined 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 Canadian generally accepted accounting principles (GAAP), which differ in some respects from GAAP in the United States. These differences are quantified and explained in note 19.

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.

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.

(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 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.

(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 and in-situ oil sands crude oil and natural gas 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 the well does not contain proved reserves, the 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 at 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.

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.

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 Denver 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 is included within depreciation expense in the Consolidated Statements of Earnings.

Reclamation and Environmental Remediation Costs

For the years ended December 31, 2003, reclamation and environmental remediation costs for identified downstream sites were estimated and charged against earnings when a regulatory or statutory requirement or contractual agreement existed, or when management made a decision to decommission or restore a site, providing that assessments indicated that such costs were probable and reasonably estimable.

Estimated reclamation costs in the company’s upstream operations were accrued on the unit of production basis. Estimated environmental remediation costs, which were predominantly in the company’s downstream operations, were accrued during the period for those sites where assessments indicated that such work was required.

Costs were accrued based on currently known information, estimated timing of remedial actions, and existing regulatory requirements and technology.

See the section “Recently Issued Canadian Accounting Standards” for further details on the adoption of a new accounting policy for Asset Retirement Obligations.

Impairment

Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less related provisions for reclamation and environmental remediation costs and 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 estimated net recoverable amount 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 an unproved property surrendered or abandoned that is not individually significant, or a partial abandonment of a proved property, is charged to accumulated depreciation, depletion or amortization.

(e) Deferred Charges and Other

Overburden removal may precede mining of the oil sands deposit by as much as two years. 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 note 4), 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 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 proven and probable ore reserves. This expense 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.

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.

(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. Company contributions to the defined contribution plan are expensed as incurred.

(g) Inventories

Inventories of crude oil and refined products are valued at the lower of cost (using the LIFO method) and net realizable value.

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

(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 as part of its risk management strategy to manage exposure to interest 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.

Commencing in the fourth quarter of 2002, the company began to use energy derivatives, including physical and financial swaps, forwards and options to gain market information and to earn trading revenues. Trading activities are accounted for at fair value.

(i) Foreign Currency Translation

Monetary assets and liabilities 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 new 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 12), common share options are granted to executives, employees and non-employee directors.

Compensation expense is recorded in the Consolidated Statements of Earnings 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. Compensation expense for options granted during 2003 and thereafter is determined based on the fair values at the time of grant, the cost of which 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. 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.

(k) Recently Issued Canadian Accounting Standards

Hedging Relationships

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 its hedging documentation and tests of effectiveness are prepared in accordance with the provisions of AcG 13.

Asset Retirement Obligations

Effective January 1, 2004, the company will adopt the new Canadian standard “Asset Retirement Obligations” (ARO), which substantially harmonizes Canadian GAAP with U.S. GAAP (see note 19). This standard requires recognition of a liability for the future retirement obligations associated with the company’s property, plant and equipment. The fair value of the asset retirement obligations are to be recorded on a discounted basis. This amount is to be 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. The impact of adopting this standard will be an increase to property, plant and equipment of $211 million, an increase to future tax assets of $110 million, an increase to accrued liabilities of $318 million, an increase to future tax liabilities of $73 million, and a decrease to retained earnings of $70 million.

Variable Interest Entities

In 2003, Canadian Accounting Guideline 15 (AcG 15) “Consolidation of Variable Interest Entities (VIEs)” was issued. Effective January 1, 2005 AcG 15 requires consolidation of a VIE where the company will absorb a majority of a VIEs losses, receive a majority of its returns, or both. The company will be required to consolidate the VIE related to the sale of equipment as described in note 10(c). The company does not expect a significant impact on net earnings on consolidation of the equipment VIE. The impact on the balance sheet will be an increase to property, plant and equipment and an increase to long-term liabilities of approximately $20 million. The VIE involving the sale of crude oil inventory terminates June 25, 2004, prior to the effective date of AcG 15. The accounts receivable securitization program, as currently structured, does not meet the AcG 15 criteria for consolidation by Suncor.

Liabilities and Equity

In 2003, the Canadian Accounting Standards Board approved an amendment to its Handbook Section 3860 “Financial Instruments – Disclosure and Presentation” requiring certain obligations that must or could be settled with an entity’s own equity instruments to be presented as liabilities. The amendment, effective for the company’s 2005 fiscal year, affects the company’s current presentation of Preferred Securities as equity (see note 11). The reclassification of the Preferred Securities from equity to long-term debt is expected to reduce equity by $485 million, increase long-term debt by $486 million, and increase deferred charges by $1 million.

Consolidated Statements of Earnings

for the years ended December 31 ($ millions)	2003		2002		2001
Revenues
Operating revenues (notes 6, 16, 17 and 18)	6 171		4 883		4 204
Energy marketing and trading activities (note 6c)	129		147		85
Interest	6		2		5
	6 306		5 032		4 294
Expenses
Purchases of crude oil and products	1 570		1 156		1 510
Operating, selling and general	1 507		1 292		1 012
Energy marketing and trading activities	132		142		85
Transportation and other costs (note 16)	133		128		95
Depreciation, depletion and amortization	611		585		360
Exploration (note 18)	51		26		22
Royalties	139		98		134
Taxes other than income taxes (note 18)	426		374		367
(Gain) on disposal of assets	(17	)	(2	)	(7	)
(Gain) on sale of retail natural gas marketing business (note 18)	—		(38	)	—
Project start-up costs	16		3		141
Write-off of oil shale assets	—		—		48
Restructuring	—		—		(2	)
Financing expenses (income) (note 14)	(66	)	124		16
	4 502		3 888		3 781
Earnings Before Income Taxes	1 804		1 144		513
Provision for income taxes (note 9)
Current	38		74		4
Future	682		309		121
	720		383		125
Net Earnings	1 084		761		388
Dividends on Preferred Securities, net of tax (note 11)	(27	)	(28	)	(26	)
Revaluation of US$ Preferred Securities, net of tax	37		1		(11	)
Net earnings attributable to common shareholders	1 094		734		351

See accompanying Summary of Significant Accounting Policies and Notes.

Consolidated Balance Sheets

as at December 31 ($ millions)	2003		2002
Assets
Current assets
Cash and cash equivalents	388		15
Accounts receivable (notes 10c and 18)	505		403
Inventories (note 15)	371		266
Future income taxes (note 9)	28		38
Total current assets	1 292		722
Property, plant and equipment, net (note 3)	8 725		7 641
Deferred charges and other (note 4)	286		185
Future income taxes (note 9)	124		135
Total assets	10 427		8 683
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	31		—
Accounts payable and accrued liabilities (notes 7 and 8)	972		716
Income taxes payable	9		34
Taxes other than income taxes	49		37
Future income taxes (note 9)	14		10
Total current liabilities	1 075		797
Long-term debt (note 5)	2 448		2 686
Accrued liabilities and other (notes 7 and 8)	296		226
Future income taxes (note 9)	2 183		1 516
Total liabilities	6 002		5 225
Commitments and contingencies (note 10)
Shareholders’ equity
Preferred Securities (note 11)	476		523
Share capital (note 12)	604		578
Contributed surplus (note 12)	7		—
Cumulative foreign currency translation	(26	)	—
Retained earnings	3 364		2 357
Total shareholders’ equity	4 425		3 458
Total liabilities and shareholders’ equity	10 427		8 683

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board of Directors:

/s/ R. L. George		/s/ J. T. Ferguson
R. L. George		J. T. Ferguson
Director		Director

Consolidated Statements of Cash Flows

for the years ended December 31 ($ millions)	2003		2002		2001
Operating Activities
Cash flow from operations (a)	2 081		1 440		831
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets)
Accounts receivable	(105	)	(97	)	101
Inventories	(19	)	(8	)	(66	)
Accounts payable and accrued liabilities	256		44		(37	)
Taxes payable	5		77		(17	)
Cash flow from operating activities	2 218		1 456		812
Cash Used in Investing Activities (a)	(1 702	)	(861	)	(1 680	)
Net Cash Surplus (Deficiency) Before Financing Activities	516		595		(868	)
Financing Activities
Increase (decrease) in short-term debt	31		(31	)	(33	)
Proceeds from issuance of long-term debt	651		797		500
Net increase (decrease) in other long-term debt	(716	)	(1 245	)	486
Issuance of common shares under stock option plans	20		19		15
Dividends paid on Preferred Securities	(45	)	(48	)	(48	)
Dividends paid on common shares	(81	)	(73	)	(72	)
Cash flow from (used in) financing activities	(140	)	(581	)	848
Increase (Decrease) in Cash and Cash Equivalents	376		14		(20	)
Effect of Foreign Exchange on Cash and Cash Equivalents	(3	)	—		—
Cash and Cash Equivalents at Beginning of Year	15		1		21
Cash and Cash Equivalents at End of Year	388		15		1

(a) See Schedules of Segmented Data on pages 64 and 65.

See accompanying Summary of Significant Accounting Policies and Notes.

Consolidated Statements of Changes in Shareholders’ Equity

for the years ended December 31 ($ millions)	Preferred Securities		Share Capital	Contributed Surplus	Cumulative Foreign Currency Translation		Retained Earnings
At December 31, 2000	510		537	—	—		1 424
Net earnings	—		—	—	—		388
Dividends paid on Preferred Securities, net of tax	—		—	—	—		(26	)
Dividends paid on common shares	—		—	—	—		(72	)
Issued for cash under stock option plans	—		15	—	—		—
Issued under dividend reinvestment plan	—		3	—	—		(3	)
Revaluation of US$ Preferred Securities	15		—	—	—		(11	)
At December 31, 2001	525		555	—	—		1 700
Net earnings	—		—	—	—		761
Dividends paid on Preferred Securities, net of tax	—		—	—	—		(28	)
Dividends paid on common shares	—		—	—	—		(73	)
Issued for cash under stock option plans	—		19	—	—		—
Issued under dividend reinvestment plan	—		4	—	—		(4	)
Revaluation of US$ Preferred Securities	(2	)	—	—	—		1
At December 31, 2002	523		578	—	—		2 357
Net earnings	—		—	—	—		1 084
Dividends paid on Preferred Securities, net of tax	—		—	—	—		(27	)
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	)	—
Revaluation of US$ Preferred Securities	(47	)	—	—	—		37
At December 31, 2003	476		604	7	(26	)	3 364

See accompanying Summary of Significant Accounting Policies and Notes.

Schedules of Segmented Data (a)

	Oil Sands						Natural Gas						Energy Marketing and Refining Canada
for the years ended December 31 ($ millions)	2003		2002		2001		2003		2002		2001		2003		2002		2001
EARNINGS
Revenues (b)
Operating revenues (note 16)	2 676		2 241		1 214		436		279		405		2 542		2 361		2 585
Energy marketing and trading activities	—		—		—		—		—		—		129		147		85
Intersegment revenues (c)	385		375		158		76		60		76		—		—		3
Interest	—		—		—		—		—		—		—		—		—
	3 061		2 616		1 372		512		339		481		2 671		2 508		2 673
Expenses
Purchases of crude oil and products	12		7		14		—		16		9		1 679		1 564		1 721
Operating, selling and general	890		806		481		77		69		64		359		352		350
Energy marketing and trading activities	—		—		—		—		—		—		132		142		85
Transportation and other costs (note 16)	101		104		72		24		24		23		3		—		—
Depreciation, depletion and amortization	451		450		233		91		75		70		59		58		56
Exploration	11		9		—		40		17		22		—		—		—
Royalties	33		33		30		106		65		104		—		—		—
Taxes other than income taxes	24		23		12		3		2		3		342		348		351
(Gain) loss on disposal of assets	(1	)	2		1		(12	)	(4	)	(8	)	(4	)	—		—
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		—		—		(38	)	—
Project start-up costs	10		3		141		—		—		—		—		—		—
Write-off of oil shale assets	—		—		—		—		—		—		—		—		—
Restructuring	—		—		—		—		—		(2	)	—		—		—
Financing expenses (income)	—		—		—		—		—		—		—		—		—
	1 531		1 437		984		329		264		285		2 570		2 426		2 563
Earnings (loss) before income taxes	1 530		1 179		388		183		75		196		101		82		110
Provision for income taxes	(642	)	(389	)	(105	)	(54	)	(40	)	(79	)	(48	)	(18	)	(30	)
Net earnings (loss)	888		790		283		129		35		117		53		64		80

As at December 31
TOTAL ASSETS	7 762		6 896		6 409		784		765		722		1 079		968		934
CAPITAL EMPLOYED (d)	4 078		4 540		1 398		436		449		317		558		491		483

(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 2003 consolidated revenues (2002 – one customer represented 10% or more ($641 million); 2001 – one customer represented 10% or more ($450 million)).

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

(d) Capital Employed – the sum of shareholders’ equity and short-term plus long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable).

See accompanying Summary of Significant Accounting Policies and Notes.

	Refining and Marketing U.S.A.				Corporate and Eliminations						Total
for the years ended December 31 ($ millions)	2003		2002	2001	2003		2002		2001		2003		2002		2001
EARNINGS
Revenues (b)
Operating revenues (note 16)	515		—	—	2		2		—		6 171		4 883		4 204
Energy marketing and trading activities	—		—	—	—		—		—		129		147		85
Intersegment revenues (c)	—		—	—	(461	)	(435	)	(237	)	—		—		—
Interest	—		—	—	6		2		5		6		2		5
	515		—	—	(453	)	(431	)	(232	)	6 306		5 032		4 294
Expenses
Purchases of crude oil and products	342		—	—	(463	)	(431	)	(234	)	1 570		1 156		1 510
Operating, selling and general	68		—	—	113		65		117		1 507		1 292		1 012
Energy marketing and trading activities	—		—	—	—		—		—		132		142		85
Transportation and other costs (note 16)	5		—	—	—		—		—		133		128		95
Depreciation, depletion and amortization	6		—	—	4		2		1		611		585		360
Exploration	—		—	—	—		—		—		51		26		22
Royalties	—		—	—	—		—		—		139		98		134
Taxes other than income taxes	57		—	—	—		1		1		426		374		367
(Gain) loss on disposal of assets	—		—	—	—		—		—		(17	)	(2	)	(7	)
(Gain) on sale of retail natural gas marketing business	—		—	—	—		—		—		—		(38	)	—
Project start-up costs	6		—	—	—		—		—		16		3		141
Write-off of oil shale assets	—		—	—	—		—		48		—		—		48
Restructuring	—		—	—	—		—		—		—		—		(2	)
Financing expenses (income)	—		—	—	(66	)	124		16		(66	)	124		16
	484		—	—	(412	)	(239	)	(51	)	4 502		3 888		3 781
Earnings (loss) before income taxes	31		—	—	(41	)	(192	)	(181	)	1 804		1 144		513
Provision for income taxes	(13	)	—	—	37		64		89		(720	)	(383	)	(125	)
Net earnings (loss)	18		—	—	(4	)	(128	)	(92	)	1 084		761		388

As at December 31
TOTAL ASSETS	438		—	—	364		54		29		10 427		8 683		8 094
CAPITAL EMPLOYED (d)	270		—	—	52		138		34		5 394		5 618		2 232

	Oil Sands						Natural Gas						Energy Marketing and Refining Canada
for the years ended December 31 ($ millions)	2003		2002		2001		2003		2002		2001		2003		2002		2001
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	888		790		283		129		35		117		53		64		80
Exploration expenses
Cash	—		—		—		8		6		12		—		—		—
Dry hole costs	—		—		—		32		11		10		—		—		—
Non-cash items included in earnings
Depreciation, depletion and amortization	451		450		233		91		75		70		59		58		56
Future income taxes	628		379		89		52		37		76		20		(35	)	18
Current income tax provision allocated to Corporate	14		10		16		2		3		3		28		53		12
(Gain) loss on disposal of assets	(1	)	2		1		(12	)	(4	)	(8	)	(4	)	—		—
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		—		—		(38	)	—
Write-off of oil shale assets	—		—		—		—		—		—		—		—		—
Restructuring	—		—		—		—		—		(3	)	—		—
Stock-based compensation expense	—		—		—		—		—		—		—		—		—
Other	8		12		(4	)	(2	)	2		3		9		9		2
Overburden removal outlays	(175	)	(160	)	(31	)	—		—		—		—		—		—
Overburden removal outlays – Project Millennium (start-up period)	—		—		(88	)	—		—		—		—		—		—
Increase (decrease) in deferred credits and other	(10	)	(8	)	(13	)	—		(1	)	—		(1	)	1		(3	)
Total cash flow from (used in) operations	1 803		1 475		486		300		164		280		164		112		165
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets)	51		(116	)	(35	)	9		22		44		—		(15	)	17
Total cash from (used in) operating activities	1 854		1 359		451		309		186		324		164		97		182
Cash from (used in) investing activities:
Capital and exploration expenditures	(948	)	(617	)	(1 479	)	(183	)	(163	)	(132	)	(122	)	(60	)	(54	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		—		—		—
Deferred maintenance shutdown expenditures	(100	)	(9	)	(5	)	—		—		(2	)	(17	)	(18	)	(9	)
Deferred outlays and other investments	(10	)	(4	)	(2	)	—		—		(1	)	(2	)	(18	)	(9	)
Proceeds from disposals	3		—		10		17		5		22		6		62		1
Total cash (used in) investing activities	(1 055	)	(630	)	(1 476	)	(166	)	(158	)	(113	)	(135	)	(34	)	(71	)
Net cash surplus (deficiency) before financing activities	799		729		(1 025	)	143		28		211		29		63		111

(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.

	Refining and Marketing U.S.A.				Corporate and Eliminations						Total
for the years ended December 31 ($ millions)	2003		2002	2001	2003		2002		2001		2003		2002		2001
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	18		—	—	(4	)	(128	)	(92	)	1 084		761		388
Exploration expenses
Cash	—		—	—	—		—		—		8		6		12
Dry hole costs	—		—	—	—		—		—		32		11		10
Non-cash items included in earnings
Depreciation, depletion and amortization	6		—	—	4		2		1		611		585		360
Future income taxes	1		—	—	(19	)	(72	)	(62	)	682		309		121
Current income tax provision allocated to Corporate	12		—	—	(56	)	(66	)	(31	)	—		—		—
(Gain) loss on disposal of assets	—		—	—	—		—		—		(17	)	(2	)	(7	)
(Gain) on sale of retail natural gas marketing business	—		—	—	—		—		—		—		(38	)	—
Write-off of oil shale assets	—		—	—	—		—		48		—		—		48
Restructuring	—		—	—	—		—		—		—		—		(3	)
Stock-based compensation expense	—		—	—	7		—		—		7		—		—
Other	(2	)	—	—	(163	)	(3	)	7		(150	)	20		8
Overburden removal outlays	—		—	—	—		—		—		(175	)	(160	)	(31	)
Overburden removal outlays – Project Millennium (start-up period)	—		—	—	—		—		—		—		—		(88	)
Increase (decrease) in deferred credits and other	(1	)	—	—	11		(44	)	29		(1	)	(52	)	13
Total cash flow from (used in) operations	34		—	—	(220	)	(311	)	(100	)	2 081		1 440		831
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets)	46		—	—	31		125		(45	)	137		16		(19	)
Total cash from (used in) operating activities	80		—	—	(189	)	(186	)	(145	)	2 218		1 456		812
Cash from (used in) investing activities:
Capital and exploration expenditures	(31	)	—	—	(32	)	(37	)	(13	)	(1 316	)	(877	)	(1 678	)
Acquisition of Denver refinery and related assets	(272	)	—	—	—		—		—		(272	)	—		—
Deferred maintenance shutdown expenditures	—		—	—	—		—		—		(117	)	(27	)	(16	)
Deferred outlays and other investments	3		—	—	(14	)	(2	)	(7	)	(23	)	(24	)	(19	)
Proceeds from disposals	—		—	—	—		—		—		26		67		33
Total cash (used in) investing activities	(300	)	—	—	(46	)	(39	)	(20	)	(1 702	)	(861	)	(1 680	)
Net cash surplus (deficiency) before financing activities	(220	)	—	—	(235	)	(225	)	(165	)	516		595		(868	)

Notes to the Consolidated Financial Statements

1. CHANGE IN ACCOUNTING POLICY

During the year, the company adopted a new accounting policy for stock-based compensation related to common share options. Pursuant to new transitional rules approved by the Canadian Institute of Chartered Accountants, the company now records stock-based compensation expense in the company’s Consolidated Statements of Earnings for all common share options granted to employees and non-employee directors on or after January 1, 2003 (“2003 options”), with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders’ Equity. Pro forma compensation-related earnings impacts of pre-2003 options are determined in the same manner as 2003 options. (See note 12)

This change in accounting policy has increased operating, selling and general expenses and contributed surplus by $7 million for the year ended December 31, 2003. The disclosures relating to pro forma earnings impacts for these periods have been adjusted by a corresponding amount.

2. ACQUISITION OF REFINERY AND RELATED ASSETS

On August 1, 2003, the company acquired a Denver refinery, 43 retail stations and associated storage, pipeline and distribution facilities, and inventory from ConocoPhillips for cash consideration of $272 million. The purchase price was determined through a competitive bid process. The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition.

The acquisition was accounted for by the purchase method of accounting. The allocation of fair value to the assets acquired and liabilities assumed was:

($ millions)
Property, plant and equipment, and intangible assets	242
Inventory	88
Other assets	9
Total assets acquired	339
Liabilities assumed	(67	)
Net assets acquired	272

Suncor recorded an environmental liability of $9 million at the acquisition date for the estimated costs of environmental clean-up work currently under way. A $9 million receivable was also recorded as ConocoPhillips agreed to indemnify Suncor for these costs. The recorded liability is part of an agreement between Suncor and ConocoPhillips whereby Suncor will be indemnified for any reclamation work identified prior to closing for a period up to 10 years from acquisition date, and up to $30 million. Additional costs ordered by a governmental agency are subject to indemnification from ConocoPhillips on a rolling 10-year limitation period from the date the contamination is discovered by Suncor. There is no time or dollar limit for any third party claims against Suncor for which ConocoPhillips is liable.

Additionally, a $39 million liability was recorded at acquisition for environmental work required pursuant to a consent decree between ConocoPhillips, the Colorado Department of Public Health and the Environment and the United States Environmental Protection Agency.

For segmented reporting purposes, the results of the new Denver-based operations since the date of acquisition are reported in a new operating segment (Refining and Marketing – U.S.A.) in the accompanying Schedules of Segmented Data.

3. PROPERTY, PLANT AND EQUIPMENT

	2003		2002
($ millions)	Cost	Accumulated Provision	Cost	Accumulated Provision
Oil Sands
Plant	5 424	828	5 340	691
Mine and mobile equipment	1 267	426	1 154	381
Pipeline	100	46	81	26
Capital leases	130	18	121	12
Major projects in progress	1 396	—	702	—
	8 317	1 318	7 398	1 110
Natural Gas
Proved properties	1 206	552	1 074	480
Unproved properties	114	38	129	41
Pipeline	—	—	20	18
Other support facilities and equipment	18	12	16	11
	1 338	602	1 239	550
Energy Marketing and Refining – Canada
Refinery	874	443	800	417
Marketing	494	239	461	229
	1 368	682	1 261	646
Refining and Marketing – U.S.A.
Refinery and intangible assets	165	2	—	—
Marketing	39	1	—	—
Pipeline	27	—	—	—
	231	3	—	—
Corporate	86	10	55	6
	11 340	2 615	9 953	2 312
Net property, plant and equipment		8 725		7 641

4. DEFERRED CHARGES AND OTHER

($ millions)	2003		2002
Oil Sands overburden removal costs (see below)	51		68
Deferred maintenance shutdown costs	137		44
Other	98		73
Total deferred charges and other	286		185
Oil Sands overburden removal costs
Balance – beginning of year	68		101
Outlays during the year	175		160
Depreciation on equipment during year	16		9
	259		270
Amortization during year	(208	)	(202	)
Balance – end of year	51		68

5. LONG-TERM DEBT

($ millions)	2003	2002
Fixed-term debt, redeemable at the option of the company
5.95% Notes, denominated in U.S. dollars, due in 2034 (a)	646	—
7.15% Notes, denominated in U.S. dollars, due in 2032 (a)	646	790
6.70% Series 2 Medium Term Notes, due in 2011 (b)	500	500
6.80% Medium Term Notes, due in 2007 (b)	250	250
6.10% Medium Term Notes, due in 2007 (b)	150	150
7.40% Debentures, Series C, due in 2004	125	125
	2 317	1 815
Revolving-term debt, with interest at variable rates (see Credit Facilities)
Commercial Paper (interest at December 31, 2002 – 2.9%) (c)	—	548
Bank debt (interest at December 31, 2002 – 3.5%)	—	199
Total unsecured long-term debt	2 317	2 562
Secured long-term debt with interest rates averaging 5.6% (2002 – 6.1%)	4	5
Capital leases (d), (e)	127	119
Total long-term debt	2 448	2 686

(a) In 2003, the company issued 5.95% Notes with a principal amount of $US500 million (Cdn$ equivalent of $651 million). In 2002, the company issued 7.15% Notes with a principal amount of $US500 million (Cdn$ equivalent of $797 million).

(b) The company has entered into various interest rate swap transactions at December 31, 2003. 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.

Description of Swap Transaction	Principal Swapped ($ millions)	Swap Maturity	2003 Effective Interest Rate
Swap of 6.10% Medium Term Notes to floating rates	150	2007	4.3	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	4.9	%
Swap of 6.70% Medium Term Notes to floating rates	200	2011	4.2	%

(c) The company is also authorized to issue commercial paper to a maximum of $900 million having a term not to exceed 364 days. Commercial paper is supported by unutilized credit and term loan facilities.

(d) Obligations under capital leases are as follows:

($ millions)	2003	2002
Energy services assets lease with interest at 6.82%, maturing in 2004	101	101
Other equipment leases with interest rates between prime plus 0.5% and 12.4% and maturity dates ranging from 2008 to 2029	26	18
	127	119

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

($ millions)	Capital Leases	Other Long- term debt
2004	117	125
2005	3	1
2006	3	—
2007	3	400
2008	3	—
Later years	28	1 795
Total minimum payments	157	2 321
Less amount representing imputed interest	30
Present value of obligation under capital leases	127

Credit Facilities

At December 31, 2003, the company had available credit and term loan facilities of $1,730 million, of which $1,577 million was undrawn, as follows:

($ millions)
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2005		750
Facility that is fully revolving for a period of three years and expires in 2006		750
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2005		200
Facilities that can be terminated at any time at the option of the lenders		30
Total available credit facilities		1 730
Drawn from credit facilities		31
Credit facilities supporting outstanding commercial paper and standby letters of credit		122
Total undrawn credit facilities		1 577

At December 31, 2003, the company had issued $122 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 owner, 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 limits the holder’s exposure to changes in prices to within a specific range. The “costless” nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).

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

See below for more technical details and amounts.

(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 income taxes payable, future income taxes and reclamation and environmental remediation costs), 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:

	2003		2002
($ millions)	Carrying Amount	Fair Value	Carrying Amount	Fair Value
Cash and cash equivalents	388	388	15	15
Accounts receivable	505	505	403	403
Derivatives receivable	49	49	22	22
Derivatives payable	19	19	—	—
Current liabilities	978	978	705	705
Investments in Southern Pacific Petroleum	—	—	1	1
Long-term debt
Fixed term	2 317	2 502	1 815	1 991
Revolving term	—	—	747	747
Other	4	4	5	5
Capital leases	127	127	119	119

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, which are not recognized in the Consolidated Balance Sheets, as follows:

Revenue 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 and options to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude price variability by entering into U.S. dollar West Texas Intermediate (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, 2003, the company had hedged a portion of its forecasted Canadian dollar denominatedcash flows subject to U.S. dollar WTI commodity price risk for up to two years. The company had not hedged anyportion of the foreign exchange component of these forecasted cash flows.

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

Contracts outstanding at December 31 were as follows:

Crude Oil Hedges	Quantity (bbl/day)	Average Price(a)	Revenue Hedged ($ millions)		Hedge Period
As at December 31, 2003
Crude oil swaps	68 000	24	772	(c)	2004
Costless collars	11 000	21 – 24	109 – 125	(c)	2004
Crude oil swaps	36 000	23	390	(c)	2005

As at December 31, 2002
Crude oil swaps	10 000	30	57	(c)	2003	(b)
Crude oil swaps	15 000	24	208	(c)	2003
Costless collars	60 000	21 – 26	726 – 899	(c)	2003
Crude oil swaps	25 000	23	332	(c)	2004
Costless collars	11 000	21 – 24	133 – 152	(c)	2004
Crude oil swaps	21 000	22	266	(c)	2005

As at December 31, 2001
Crude oil swaps	40 576	20	444	(d)	2002
Crude oil swaps	424	21	5	(c)	2002
Costless collars	43 000	22 – 27	550 – 675	(c)	2002
Costless collars	44 000	21 – 26	537 – 665	(c)	2003
Costless collars	11 000	21 – 24	134 – 153	(c)	2004
Crude oil swaps	15 000	22	192	(c)	2005

Margin Hedges	Quantity (bbl/day)	Average Margin US$/bbl	Margin Hedged		Hedge Period
Refined product sale and crude purchase swaps
As at December 31, 2003	6 600	5	3	(c)	2004	(e)
As at December 31, 2002	20 700	5	9	(c)	2003	(f)
As at December 31, 2001	—	—	—		—

Natural Gas Hedges	Quantity (GJ/day)	Average Price Cdn$/GJ	Revenue Hedged	Hedge Period
Swaps and costless collars
As at December 31, 2003	30 000	6	16	2004	(g)
As at December 31, 2002	25 000	4 – 6	9 – 14	2003	(h)
As at December 31, 2001	—	—	—	—

(a) Average price for crude oil swaps is US$ WTI per barrel at Cushing, Oklahoma.

(b) For the period January to April 2003, inclusive. All other crude oil positions are for the full year.

(d) The revenue hedged was fixed in Cdn$ as the company had foreign exchange swaps in place for these crude oil swaps.

(e) For the period January and February 2004.

(f) For the period January and February 2003.

(g) For the period January to March 2004.

(h) For the period January to March 2003.

Interest Rate Hedges

The company periodically enters into interest rate and cross-currency 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 cross- currency swap contracts involve an exchange of Canadian dollar interest payments and U.S. dollar interest payments, and an exchange of Canadian and U.S. dollar principal amounts at the maturity date of the underlying borrowing to which the swaps relate. 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, 2003 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 third party market data 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)	2003		2002
Revenue hedge swaps and collars	(285	)	(133	)
Margin hedge swaps	2		1
Interest rate and cross-currency interest rate swaps	32		35
	(251	)	(97	)

(c) Energy Marketing and Trading Activities

In November 2002, Suncor commenced energy trading activities. In addition to those financial derivatives used for hedging activities, the company also uses energy derivatives, including physical and financial swaps, forwards and options to gain market information and earn trading revenues. These energy trading activities are accounted for using the mark-to-market method and as such physical and financial energy contracts are recorded at fair value at each balance sheet date. For the year ended December 31, 2003 a net pretax loss of $3 million (2002 – $nil) from the settlement and revaluation of these contracts was reported as energy trading and marketing activities in the Consolidated Statements of Earnings.

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

($ millions)	2003	2002
Energy trading assets	5	2
Energy trading liabilities	5	2

The source of the valuations of the above contracts is based on actively quoted prices.

(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 only entering into agreements with investment grade counterparties, and through regular management review of potential exposure to, and credit ratings of, such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2003	2002
Derivative contracts not accounted for as hedges	30	28
Unrecognized derivative contracts	27	23
	57	51

7. ACCRUED LIABILITIES AND OTHER

(a) Reclamation and Environmental Remediation Costs

Total accrued reclamation and environmental remediation costs also include $60 million in current liabilities (2002 – $32 million). Payments during 2003 totalled $27 million (2002 – $15 million; 2001 – $28 million), while expense recorded in 2003 was $31 million (2002 – $20 million; 2001 – $15 million). Reclamation expense in 2003 was based on estimated total costs of $950 million (2002 – $650 million).

(b) Employee and Director Incentive Plans

Included in accrued liabilities and other is accrued compensation expense related to the company’s employee long-term incentive plans (see note 12b). Accrued liabilities and other also include accrued compensation expense in the form of deferred share units received under the directors’ compensation plan. Accrued directors’ compensation expense is not significant.

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, 2003 was $685 million.

As required by government regulations and plan performance, Suncor sets aside funds, with an independent trustee, to meet certain of these obligations. At the end of December 2003, Plan Assets to meet the Benefit Obligation were $336 million.

The excess of the Benefit Obligation over Plan Assets of $349 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 unfunded, unregistered supplementary benefits that are paid directly to recipients. Company contributions to the funded plans are deposited with independent trustees who act as custodians of the funded pension 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 and every year in the United States.

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. Retirees share in the cost of providing these benefits.

The expense and obligations for both funded and unfunded benefits are determined in accordance with Canadian generally accepted accounting principles 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.

In 2003, in connection with the acquisition of the Denver refinery and related assets from ConocoPhillips (see note 2), the company assumed a pension benefit obligation of $14 million and other post-retirement benefit obligations of $6 million. No pension plan assets were acquired.

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)	2003		2002		2003		2002
Change in benefit obligation
Benefit obligation at beginning of year	489		461		97		93
Service costs	18		17		3		4
Interest costs	32		30		6		6
Plan participants’ contributions	3		4		—		—
Acquisition	14		—		6		—
Foreign exchange	(1	)	—		—		—
Amendments	—		—		—		(34	)
Actuarial (gain) loss	37		(1	)	8		30
Benefits paid	(24	)	(22	)	(3	)	(2	)
Benefit obligation at end of year (a), (e)	568		489		117		97
Change in plan assets (b)
Fair value of plan assets at beginning of year	273		301		—		—
Actual return (loss) on plan assets	45		(24	)	—		—
Employer contributions	36		14		—		—
Plan participants’ contributions	3		4		—		—
Benefits paid	(21	)	(22	)	—		—
Fair value of plan assets at end of year (e)	336		273		—		—
Net unfunded obligation	(232	)	(216	)	(117	)	(97	)
Items not yet recognized in earnings:
Unamortized net actuarial loss (c)	133		142		50		46
Unamortized past service costs (d)	—		—		(31	)	(34	)
Accrued Benefit Liability	(99	)	(74	)	(98	)	(85	)

(a) Obligations are based on the following assumptions:

A 1% change in the assumptions at which pension benefits and other post-retirement benefits liabilities could be effectively settled is as follows:

	Rate of Return on Plan Assets			Discount Rate			Rate of Compensation Increase
($ millions)	1% increase		1% decrease	1% increase		1% decrease	1% increase	1% decrease
Increase (decrease) to net periodic benefit cost	(3	)	3	(8	)	10	4	(3	)
Increase (decrease) to benefit obligation	—		—	(83	)	95	24	(22	)

In order to measure the expected cost of other post-retirement benefits, a 12% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2003. It is assumed that this rate will decrease by 0.5% annually, to 5% for 2017, and remain at that level thereafter.

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

($ millions)	1% increase	1% decrease
Increase (decrease) to total of service and interest cost components of net periodic post-retirement health care benefit cost	1	(1	)
Increase (decrease) to the health care component of the accumulated post-retirement benefit obligation	12	(10	)

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

(c) The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 12 years for pension benefits (2002 and 2001 – 13 years), and over the expected average future service life to full eligibility age of 12 years for other post-retirement benefits (2002 – 12 years; 2001 – 11 years).

(d) Effective April 1, 2003, the company implemented amendments to its post-retirement benefits program to manage its exposures to future health care and life insurance costs. Certain of the company’s employees will continue to receive post-retirement benefits under the old plan provisions. These plan amendments reduced the company’s other post-retirement benefits obligation at December 31, 2002, by $34 million.

(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 funded and unfunded plans, as follows:

	Pension benefits		Other Post-retirement Benefits
($ millions)	2003	2002	2003	2002
Funded plan	498	423	—	—
Unfunded plans	70	66	117	97
Benefit obligation at end of year	568	489	117	97

Components of Net Periodic Benefit Cost

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2003		2002		2001		2003	2002	2001
Current service costs	18		17		14		3	4	3
Interest costs	32		30		28		6	6	6
Expected return on plan assets (a)	(20	)	(22	)	(23	)	—	—	—
Amortization of transitional asset	—		—		(8	)	—	—	—
Amortization of net actuarial loss	22		15		9		1	2	1
Net periodic benefit cost	52		40		20		10	12	10

(a) The expected return on plan assets is the expected long-term rate of return on plan assets for the year 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 12 years for pension benefits, and over the expected average future service life to full eligibility age of 10 years for post-retirement 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.

Plan Assets and Investment Objectives

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

The company’s pension plan asset allocation based on market values as at December 31, 2003 and 2002, and the target allocation for 2004 is as follows:

	Target Allocation% 2004	Percentage of Plan Assets
Asset Category	Target Allocation% 2004	2003	2002
Canadian equities	20	20	20
U.S. equities	22	22	22
International equities	18	19	18
Canadian fixed income	40	39	40
Total	100	100	100

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

Cash Flows

The company expects that contributions to its pension plans in 2004 will be $50 million. Expected contributions for other post-retirement benefits in 2004 are $3 million.

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and a U.S. 401(k) savings plan, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $6 million in 2003 (2002 – $5 million; 2001 – $4 million).

9. INCOME TAXES

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

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

See below for more technical details and amounts.

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

	2003				2002				2001
($ millions)	Amount		%		Amount		%		Amount		%
Federal tax rate	667		37		435		38		195		38
Provincial abatement	(180	)	(10	)	(114	)	(10	)	(51	)	(10	)
Federal surtax	20		1		13		1		6		1
Provincial tax rates	226		13		150		13		69		14
Statutory tax and rate	733		41		484		42		219		43
Adjustment of statutory rate for future rate reductions	(100	)	(6	)	—		—		—		—
	633		35		484		42		219		43
Add (deduct) the tax effect of:
Crown royalties	50		3		39		3		48		9
Resource allowance	(31	)	(2	)	(34	)	(3	)	(28	)	(5	)
Temporary difference in resource allowance	—		—		(120	)	(10	)	(49	)	(10	)
Large corporations tax	19		1		17		1		16		3
Tax rate changes on opening future income taxes	89		5		(10	)	(1	)	(52	)	(11	)
Attributed Canadian royalty income	(8	)	—		(2	)	—		(6	)	(1	)
Non-deductible foreign expenses	—		—		—		—		(17	)	(3	)
Assessments and adjustments	—		—		10		1		(11	)	(2	)
Capital gains	(34	)	(2	)	—		—		—		—
Other	2		—		(1	)	—		5		1
Income taxes and effective rate	720		40		383		33		125		24

In 2003 net income tax payments totalled $45 million (2002 – $8 million refund; 2001 – $23 million payment).

The resource allowance is a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by generally accepted accounting principles in Canada, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate.

Effective January 1, 2003, the Canadian government enacted changes to the federal taxation policies relating to the resource sector. The changes are to be phased in over the next five years and include a 7% reduction of the federal tax rate, deductibility of provincial Crown royalties and the elimination of the federal resource allowance deduction. For 2003, a 1% federal rate reduction was effected.

Effective April 1, 2003, the Alberta provincial corporate rate decreased by 0.5%. The Ontario general corporate tax rate and manufacturing and processing tax rate were increased by 1.5% and 1% respectively, effective January 1, 2004.

Accordingly, the company revalued its future income tax liabilities and recognized an increase in future income tax expense of $100 million (including $89 million related to the revaluation of opening future income tax liabilities).

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

	2003		2002
($ millions)	Current	Non-current	Current	Non-current
Future income tax assets:
Employee future benefits	4	57	4	48
Reclamation and environmental remediation costs	9	7	16	28
Alberta royalties	—	47	—	43
Employee incentive plans	—	13	—	16
Inventories	15	—	18	—
	28	124	38	135
Future income tax liabilities:
Depreciation	—	2 095	—	1 473
Overburden removal costs	—	16	—	20
Maintenance shutdown costs	—	41	—	15
Inventories	1	—	—	—
Other	13	31	10	8
	14	2 183	10	1 516

10. COMMITMENTS, CONTINGENCIES AND GUARANTEES

(a) Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2003, future minimum amounts payable under these leases and agreements are as follows:

($ millions)	Pipeline Capacity and Energy Services (a)	Operating Leases
2004	149	38
2005	167	32
2006	179	27
2007	184	25
2008	202	19
Later years	3 691	62
	4 572	203

(a) Includes annual tolls payable under a transportation service agreement with a major pipeline company to use a portion of its pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreement commenced in 1999 and extends to 2028. As the initial shipper on the pipeline, Suncor’s tolls payable under the agreement are subject to annual adjustments.

To meet the energy needs of its oil sands operation, Suncor has a commitment under long-term energy agreements to obtain a portion of the power and all of the steam generated by a cogeneration facility owned by a major energy company. Since October 1999, this company has managed the operations of Suncor’s existing energy services facility.

(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 reclamation and environmental remediation costs. Up to December 31, 2003, these costs were accrued at the company’s Natural Gas and Oil Sands operations on the unit of production basis. A provision was not made for currently operated facilities such as the Oil Sands processing facilities, the Sarnia and Denver refineries and service stations. The company had determined that until there was cessation of operations and completion of site investigations for these facilities, reclamation and environmental remediation costs would not be estimable. Effective January 1, 2004, the company adopted new Canadian accounting standards that required recognition of a liability for the future retirement obligations associated with the company’s property, plant and equipment (see Summary of Significant Accounting Policies). Estimates of future environmental remediation costs can change significantly based on such factors as operating experience, changes in legislation and regulations and cost.

To mitigate its exposure to property and business interruption losses, the company has purchased insurance policies with a combined coverage of up to US$1,150 million, net of deductible amounts. The policies stipulate a property loss deductible of US$10 million per incident, and a business interruption loss deductible per incident, based on the greater of US$50 million or 30 days of gross earnings lost (as defined in the respective insurance policies). Gross earnings can be influenced by such factors as production levels, commodity prices and the U.S. dollar exchange rate.

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 provided 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 and Guarantees

At December 31, 2003, the company had various off-balance sheet arrangements with Variable Interest Entities and indemnification agreements with third parties as described below.

The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable 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, 2003, $170 million in outstanding accounts receivable had been sold under the program. Under the recourse provisions, the company will provide indemnification against credit losses to a maximum of $70 million. 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, 2003, were nil and approximately $2,328 million, respectively. The company recorded an after-tax loss of approximately $3 million on the securitization program in each of the last three years.

In 1999, the company sold 2,130,000 barrels of its crude oil inventory for $49 million to a third party while retaining the right to use the inventory for its operations through a usage agreement for a five-year period. The third party’s sole asset is the inventory sold to it by the company. The company pays an annual usage fee of $7 million to the third party and receives a $4 million annual storage fee. The company has the right, but is not obligated, to repurchase the inventory at the spot price at the end of the agreement in June 2004. In order to reduce the exposure to the spot price should it elect to repurchase the inventory, the company has entered into crude oil and U.S. dollar swap contracts fixing the purchase price of the crude oil on June 25, 2004 at Cdn$49 million.

In 1999, the company entered into an equipment sale and leaseback arrangement with a third party for proceeds of $30 million. The third party’s sole asset is the equipment sold to it and leased back by the company. 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. An early termination purchase option allows for the repurchase of the equipment at specified dates in 2003, 2004 and 2005. Had the company elected to terminate the lease at December 31, 2003, the total cost would have been $30 million. Annualized equipment lease payments in 2003 were $4 million (2002 and 2001 – $2 million).

The company has agreed to indemnify holders of the 9.125% Preferred Securities, 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, the crude oil inventory monetization agreement 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.

11. PREFERRED SECURITIES

During 1999, the company completed a Canadian offering of $276 million of 9.05% Preferred Securities and a U.S. offering of US$162.5 million of 9.125% Preferred Securities for net proceeds of Cdn$507 million after issue costs of $17 million ($10 million after income taxes). The Preferred Securities are comprised of unsecured junior subordinated debentures, due in 2048 and redeemable at the company’s option. Accordingly, the Preferred Securities are classified as share capital in the Consolidated Balance Sheet and the interest distributions thereon, net of income taxes, are classified as dividends. On January 15, 2004, the company gave formal notice to the holders of the Preferred Securities that it will redeem the securities for cash consideration on March 15, 2004.

In 2003, dividends of $45 million were paid on the Preferred Securities (2002 – $48 million; 2001 – $48 million).

12. SHARE CAPITAL

(a) Authorized:

Common Shares

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

Preferred Shares

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

(b) Issued:

The number of common shares and common share options outstanding, common share prices and per share calculations, for both current and prior periods, reflect a two-for-one split of the company’s common shares during 2002.

	Common Shares
	Number (thousands)	Amount ($ millions)
Balance as at December 31, 2001	445 956	555
Issued for cash under stock option plans	1 777	19
Issued under employee long-term incentive plan	1 090	—
Issued under dividend reinvestment plan	149	4
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

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 that hold options must earn the right to exercise them. This is done by the employee 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. Options granted to non-employee directors vest and are exercisable immediately.

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

See below for more technical details and amounts on the company’s stock option plans.

(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 1,902,000 common share options in 2003 (2002 – 1,803,000) to non-employee directors and certain executives and other senior employees of the company (see note 1). The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted to non-employee directors have a 10-year life and are exercisable immediately. Options granted to employees have a 10-year life and vest annually over a three-year period.

(ii) SUNSHARE PERFORMANCE STOCK OPTION PLAN During 2003, the company granted 1,305,000 options (2002 – 8,938,000) to all eligible permanent full-time and part-time employees, both executive and non-executive, under its new employee stock option incentive plan (“SunShare”). Under SunShare, meeting specified performance targets may accelerate the vesting of some or all options, such that 20% of outstanding options may vest as early as 2004, up to an additional 20% of outstanding options may vest as early as 2005 and the remaining 60% of outstanding options may vest on April 30, 2008. All unvested options, which have not previously expired or been cancelled, will automatically vest on January 1, 2012.

(iii) EMPLOYEE LONG-TERM INCENTIVE PLAN Suncor’s previous employee long-term incentive plan matured in 2002. At maturity, employees received 1,090,000 common shares from treasury for nil cash consideration, along with aggregate cash payments of $34 million. In addition, 2,132,000 common share options, previously granted to senior employees, vested and became exercisable. No compensation expense was recorded related to the employees’ receipt of common shares from treasury as these common shares were treated as stock option grants.

In addition, 1,462,000 deferred share units (DSUs) with a cash settlement value of $42 million, which had previously been granted to certain executives, vested. These executives also received cash payments of $44 million.

DSUs are only redeemable at the time a unitholder ceases employment. In 2003, 185,000 (2002 – 220,000) DSUs were redeemed for cash consideration of $5 million (2002 – $6 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, 2003, 1,071,000 DSUs were outstanding with a total liability of $35 million, all of which was classified as long-term (see note 7).

During 2003, total pretax compensation expense related to the above-noted long-term incentive plan was $8 million (2002 – $10 million; 2001 – $42 million).

(iv) REVISED EMPLOYEE INCENTIVE COMPENSATION PLAN In November 2003, Suncor’s Board of Directors approved a revised employee incentive compensation program to be implemented in 2004. The revised program consists of a combination of time-vesting common share options and performance-vesting share units (PSUs) to replace the current program whereby only time-vesting common share options are granted.

The exercise price of a time-vested option will continue to be equal to the market value of the common shares at the date of grant. Options granted will have a 10-year life and vest annually over a three-year period.

PSUs will be payable in cash three years from grant date, based on meeting certain corporate performance measures compared to a peer group of companies.

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

	Number (thousands)		Range of Exercise Price ($)	Weighted- average Exercise Price Per Share ($)
Outstanding, December 31, 2000	11 722		2.38 – 19.28	10.28
Granted	2 181		15.94 – 21.35	17.63
Exercised	(2 029	)	2.38 – 16.48	7.30
Cancelled	(106	)	10.13 – 20.20	14.21
Outstanding, December 31, 2001	11 768		2.38 – 21.35	12.12
Granted	10 741		23.93 – 28.14	27.08
Exercised	(1 777	)	2.38 – 17.45	10.42
Cancelled	(406	)	13.04 – 27.65	26.48
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

Exercisable, December 31, 2003	8 191		4.11 – 28.14	13.77

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

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2003:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted- average Remaining Contractual Life	Weighted- average Exercise Price Per Share ($)	Number (thousands)	Weighted- average Exercise Price Per Share ($)
4.11 – 7.85	1 333	3	6.53	1 333	6.53
10.13 – 15.69	4 649	5	12.83	4 649	12.83
15.75 – 23.98	3 496	8	20.40	1 994	19.45
24.09 – 29.85	11 538	8	27.40	215	26.32
Total	21 016	7	21.69	8 191	13.77

(v) 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:

	2003			2002			2001
Annual dividend per share	$	0.1925		$	0.17		$	0.17
Risk-free interest rate	4.39		%	5.39		%	5.07		%
Expected life	7 years			8 years			5 years
Expected volatility	32		%	31		%	35		%
Weighted-average fair value per option	$	9.94		$	12.08		$	6.41

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)	2003	2002	2001
Net earnings attributable to common shareholders - as reported	1 094	734	351
Less: compensation cost under the fair value method for pre-2003 options	30	32	9
Pro forma net earnings attributable to common shareholders for pre-2003 options	1 064	702	342
Basic earnings per share
As reported	2.43	1.64	0.79
Pro forma	2.37	1.57	0.77
Diluted earnings per share
As reported	2.26	1.61	0.78
Pro forma	2.20	1.54	0.76

13. EARNINGS PER COMMON SHARE

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

($ millions)	2003		2002		2001
Net earnings attributable to common shareholders	1 094		734		351
Dividends on Preferred Securities, net of tax	27		28		—	(a)
Revaluation of US$ Preferred Securities, net of tax	(37	)	(1	)	—	(a)
Adjusted net earnings attributable to common shareholders	1 084		761		351

(millions of common shares)
Weighted-average number of common shares	450		448		445
Dilutive securities:
Options issued under stock-based compensation plans	8		5		6
Redemption of Preferred Securities by the issuance of common shares	22		20		—	(a)
Weighted-average number of diluted common shares	480		473		451

(dollars per common share)
Basic earnings per share (b)	2.43		1.64		0.79
Diluted earnings per share	2.26	(c)	1.61	(c)	0.78	(a)

Common share and earnings per common share amounts in the above table reflect a two-for-one share split effective May 15, 2002.

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) For the year ended December 31, 2001, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares. Dividends on Preferred Securities, the revaluation of US$ Preferred Securities and the redemption of Preferred Securities by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share.

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

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

14. FINANCING EXPENSES (INCOME)

($ millions)	2003		2002		2001
Interest on debt	140		155		143
Capitalized interest	(57	)	(22	)	(125	)
Net interest expense	83		133		18
Foreign exchange (gain) loss on long-term debt	(166	)	(9	)	—
Other foreign exchange (gain) loss	17		—		(2	)
Total financing expenses (income)	(66	)	124		16

Cash interest payments in 2003 totalled $139 million (2002 – $134 million; 2001 – $129 million).

15. INVENTORIES

As at December 31, 2003, the replacement cost of crude oil and refined product inventories, valued using the LIFO cost method, exceeded their carrying value by $48 million (2002 – $84 million).

16. TRANSPORTATION COSTS AND OTHER COMPARATIVE FIGURES

Effective January 2003, 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. Previously, these costs were netted against revenue. Prior period amounts have been reclassified for comparative purposes.

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

17. RELATED PARTY TRANSACTIONS

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

($ millions)	2003	2002	2001
Operating revenues
Sales to Energy Marketing and Refining – Canada segment joint ventures:
Refined products	301	321	300
Petrochemicals	187	142	131

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, 2003, amounts due from Energy Marketing and Refining – Canada segment joint ventures were $36 million (2002 – $30 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.

18. SUPPLEMENTAL INFORMATION

($ millions)	2003	2002	2001
Export sales (a)	549	501	590
Exploration expenses
Geological and geophysical	18	13	11
Other	1	2	1
Cash costs	19	15	12
Dry hole costs	32	11	10
Cash and dry hole costs (b)	51	26	22
Leasehold impairment (c)	16	10	9
	67	36	31
Taxes other than income taxes
Excise taxes (d)	388	340	343
Production, property and other taxes	38	34	24
	426	374	367
Allowance for doubtful accounts	4	3

(a) Sales of crude oil, natural gas and refined products 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.

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

In 2002, the company sold its retail natural gas marketing business in the Energy Marketing and Refining – Canada segment for cash consideration of $62 million, net of related closing costs and adjustments of $4 million, resulting in an after-tax gain of $35 million.

19. 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		2003		2002		2001
Net earnings as reported, Canadian GAAP			1 084		761		388
Adjustments net of applicable income taxes
Derivatives and hedging activities	(a	)	(120	)	6		(55	)
Stock-based compensation	(b	)	(2	)	(12	)	(14	)
Preferred Securities	(c	)	12		(29	)	(27	)
Accounting for income taxes	(d	)	—		—		6
Write-off of oil shale assets	(e	)	—		—		64
Start-up costs	(f	)	—		—		10
Asset retirement obligations	(g	)	(4	)	—		—
Cumulative effect of change in accounting principles	(g	)	(66	)	—		47
Net earnings attributable to discontinued operations	(i	)	—		(56	)	5
Net earnings from continuing operations, U.S. GAAP			904		670		424
Net earnings (loss) from discontinued operations, U.S. GAAP	(i	)	—		56		(5	)
Derivatives and hedging activities, net of income taxes of $7 (2002 – $54; 2001 – $16)	(a	)	18		(118	)	29
Minimum pension liability, net of income taxes of $nil (2002 – $10; 2001 – $11)	(h	)	7		(20	)	(26	)
Foreign currency translation adjustment	(j	)	(26	)	—		—
Comprehensive income, U.S. GAAP			903		588		422

per common share (dollars)	2003	2002	2001
Net earnings per share from continuing operations
Basic	2.01	1.50	0.95
Diluted	1.86	1.47	0.94
Net earnings per share from discontinued operations
Basic	—	0.12	(0.01	)
Diluted	—	0.12	(0.01	)

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

			December 31, 2003				December 31, 2002
	Notes		As Reported		U.S. GAAP		As Reported	U.S. GAAP
Current assets	(a	)	1 292		1 388		722	767
Property, plant and equipment, net	(c,g	)	8 725		8 974		7 641	7 674
Deferred charges and other	(a,c,h	)	286		333		185	231
Future income taxes	(a,g,h	)	124		266		135	165
Total assets			10 427		10 961		8 683	8 837

Current liabilities	(a	)	1 075		1 364		797	933
Long-term borrowings	(a,c	)	2 448		2 967		2 686	3 251
Accrued liabilities and other	(g,h	)	296		690		226	306
Future income taxes	(a,c,g	)	2 183		2 281		1 516	1 539
Preferred Securities	(c	)	476		—		523	—
Share capital	(b	)	604		652		578	626
Contributed surplus	(b	)	7		9		—	—
Cumulative foreign currency translation	(j	)	(26	)	—		—	—
Retained earnings			3 364		3 136		2 357	2 319
Accumulated other comprehensive income	(a,h,j	)	—		(138	)	—	(137	)
Total liabilities and shareholders’ equity			10 427		10 961		8 683	8 837

(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 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”) 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, 2003, the company had hedged a portion of its forecasted Canadian dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for up to two years. The company had 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.

Under U.S. GAAP, for the year ended December 31, 2003, the company would have recognized $141 million of hedge ineffectiveness relating to forecasted cash flows in 2004 and 2005 primarily due to foreign exchange fluctuations during the period. The net earnings impact of this ineffectiveness will not be recognized for Canadian GAAP purposes until the related forecasted crude oil sales occur.

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, 2003, the company had interest rate derivatives classified as fair value hedges outstanding for up to eight 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 is probable that the underlying forecasted crude oil sales will occur, the related $28 million pretax gain on monetization of the call options has been deferred and will be recognized as additional crude oil revenues during 2004. For U.S. GAAP purposes, the company would have 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 does not have purchase price risk associated with the repurchase of the inventory. This derivative does not represent a U.S. GAAP difference as the company records this derivative at fair value for Canadian purposes.

During the fourth quarter of 2001, the company made a payment of $29 million to terminate a long-term natural gas contract. The contract had been designated as a hedge under Canadian GAAP, and the resulting settlement loss of $18 million, net of income taxes of $11 million, was to be deferred and recognized as the hedged item was settled. During 2002, in connection with the sale of the company’s retail natural gas marketing business (see note 18), the company disposed of the related hedged item. Accordingly, for Canadian GAAP purposes, the company recognized the entire settlement loss of $18 million during 2002. For U.S. GAAP purposes, the long-term contract would have been designated as a normal purchase and sale transaction, and the after-tax loss of $18 million would have been recognized in 2001 on the initial settlement of the contract.

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)	2003		2002
OCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $41 (2002 – $13)	(89	)	29
Current period net changes arising from cash flow hedges, net of income taxes of $26 (2002 – $57)	(54	)	(123	)
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $33 (2002 – $3)	72		5
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $34 (2002 – $41)	(71	)	(89	)

For the year ended December 31, 2003, assets increased by $139 million and liabilities increased by $332 million as a result of recording all derivative instruments at fair value.

The loss associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $199 million, net of income taxes of $93 million (2002 – $19 million, net of income taxes of $9 million). The company estimates that $55 million of after-tax hedging losses 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, 2003, U.S. GAAP net earnings would have been reduced by $120 million, net of income taxes of $56 million (2002 – increased net earnings of $6 million, net of income taxes of $4 million; 2001 – decreased net earnings of $55 million, net of income taxes of $37 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 new 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 would have been 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, 2003, U.S. GAAP net earnings would have been reduced by $2 million (2002 – $12 million; 2001 – $14 million) to reflect additional stock-based compensation expense.

As described in note 1, the company adopted a new stock-based compensation accounting policy for 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.

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, 2003 would have been reduced by $27 million (2002 – $24 million; 2001 – $9 million) and $0.06 per share (2002 – $0.05; 2001 – $0.02), respectively.

(c) Preferred Securities

Under Canadian GAAP, Preferred Securities are classified as share capital and the interest distributions thereon, net of income taxes, are accounted for as dividends. Under U.S. GAAP, the Preferred Securities would have been classified as long-term debt and the interest distributions thereon would have been accounted for as financing expenses. Preferred Securities denominated in U.S. dollars of US$163 million would have been revalued at the rate in effect at the related balance sheet date, with any foreign exchange gains (losses) recognized in the Consolidated Statements of Earnings. Further, under U.S. GAAP the interest distributions would have been eligible for interest capitalization.

Under Canadian GAAP, issue costs of the Preferred Securities, net of the related income tax credits, were charged against share capital. Under U.S. GAAP, these issue costs would have been deferred and amortized to earnings over the term of the related long-term debt.

For U.S. GAAP purposes, these differences would have increased net earnings for the year ended December 31, 2003 by $12 million, including an income tax recovery of $8 million (2002 – a reduction to net earnings of $29 million, net of income taxes of $20 million; 2001 – a reduction to net earnings of $27 million, net of income taxes of $18 million).

Under Canadian GAAP, the 2003 interest distributions on the Preferred Securities for the year ended December 31, 2003 of $45 million (2002 – $48 million; 2001 – $48 million) are classified as financing activities in the Consolidated Statements of Cash Flows. Under U.S. GAAP, the interest distributions of $45 million (2002 – $48 million; 2001 – $48 million) and the amortization of issue costs for the year ended December 31, 2003 of $3 million (2002 – $3 million; 2001 – $3 million) would have been classified as operating activities.

The Preferred Securities, which are publicly traded, had a fair value, based on quoted market prices, of $493 million at December 31, 2003 (2002 – $568 million; 2001 – $575 million).

(d) Income Taxes

Under Canadian GAAP, changes in tax laws and rates are recognized when they are considered substantially enacted, whereas under U.S. GAAP, changes in tax laws and rates are only considered after they have been enacted into law. This GAAP difference would have no impact on U.S. GAAP net earnings for the year ended December 31, 2003 (2002 – no impact; 2001 – an increase of $6 million).

(e) Asset Impairment

Under Canadian GAAP, the company reduced the carrying amount of its interest in the Stuart Oil Shale Project in 2000, based on a non-discounted cash flow analysis. Had the carrying amount been determined using a discounted cash flow analysis as required under U.S. GAAP, an additional write-down of $64 million, net of income taxes of $55 million, would have been recorded in 2000. Effective April 5, 2001, the company sold its interest in the project. Due to the difference in determining the carrying value of the project for Canadian and U.S. GAAP purposes in 2000, net earnings for U.S. GAAP purposes for the year ended December 31, 2001 would have increased by $64 million.

(f) Start-up Costs

In 2001, under Canadian GAAP, all remaining capitalized start-up costs associated with the Stuart Oil Shale Project were written down. Under U.S. GAAP, these start-up costs would have been fully expensed in 1999. As a result, net earnings for U.S. GAAP purposes for 2001 would have been increased by $10 million, net of income taxes of $7 million.

(g) Asset Retirement Obligations

For the years ended December 31, 2003, for Canadian GAAP purposes, estimated reclamation costs in the company’s upstream operations were accrued on the unit of production basis. Estimated environmental remediation costs, which are predominantly in the company’s downstream operations, were accrued during the period for those sites where assessments indicated that such work was required. On January 1, 2003, the company would have adopted Statement 143 “Accounting for Asset Retirement Obligations” for U.S. GAAP reporting purposes. Statement 143 requires recognition of a liability for the future retirement obligations associated with the company’s property, plant and equipment. The fair value of the asset retirement obligations are recorded on a discounted basis as incurred. 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.

For U.S. GAAP purposes, the company’s adoption of Statement 143 effective January 1, 2003 would have increased total assets by $331 million, increased total liabilities by $397 million, and decreased net income due to the cumulative effect of a change in accounting principles by $66 million, net of income taxes of $34 million.

Had Statement 143 been applied during all periods presented, the company’s asset retirement obligation would have been $388 million at January 1, 2002, $400 million at December 31, 2002 and $401 million at December 31, 2003.

Under Canadian GAAP, net earnings for the year ended December 31, 2003 include site restoration and abandonment expense of $19 million, net of income taxes of $10 million (2002 – $12 million, net of income taxes of $5 million; 2001 – $6 million, net of income taxes of $3 million). Under U.S. GAAP, net earnings for the year ended December 31, 2003 would have reflected accretion expense of $17 million (2002 – $16 million; 2001 – $16 million) and depreciation, depletion and amortization expense of $6 million (2002 – $6 million; 2001 – $6 million), net of taxes of $12 million (2002 – $10 million; 2001 – $11 million). On a pro forma basis, this would have decreased net earnings per common share by $0.01 (2002 – $0.02; 2001 – $0.04). Under U.S. GAAP, at December 31, 2003, the company would have recorded a decrease to total liabilities of $6 million.

The company owns interests in several assets for which the fair value of the asset retirement obligation 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.

(h) 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. 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, 2003, the company would have recognized a minimum pension liability of $76 million (2002 – $80 million), an intangible asset of $13 million (2002 – $10 million) and other comprehensive loss of $41 million, net of income taxes of $22 million (2002 – $48 million, net of income taxes of $22 million). Other comprehensive income for the year ended December 31, 2003 would have increased by $7 million, net of income taxes of $nil (2002 –a decrease in other comprehensive income of $20 million, net of income taxes of $10 million; 2001 – a decrease in other comprehensive income of $26 million, net of income taxes of $11 million).

(i) Discontinued Operations

During 2002, the company disposed of its retail natural gas business for net proceeds of $62 million, and recognized an after-tax gain on sale of $35 million for Canadian GAAP purposes. The retail natural gas marketing business was not considered significant to the company’s overall business operations, and was not classified as a business segment for the purposes of discontinued operations reporting. Accordingly, financial results of the retail natural gas marketing business were not segregated from the financial results of the company’s other operations prior to the date of disposal of the business.

For U.S. GAAP purposes, the company would have adopted Statement 144 “Accounting for the Impairment and Disposal of Long-Lived Assets” effective January 1, 2002. For the purposes of Statement 144, the retail natural gas business would have been considered a distinguishable component of the company, and reflected as a discontinued operation for the year ended December 31, 2002. For segmented reporting purposes, the retail natural gas marketing business was included in the Energy Marketing and Refining – Canada operating segment in 2002 and 2001.

Selected financial information regarding the discontinued retail natural gas business is as follows for the year ended December 31:

($ millions)	2003	2002	2001
Revenues included in discontinued operations	—	81	196
Income from retail natural gas business operations, net of income taxes of $nil (2002 – $4; 2001 – recovery of $3)	—	8	(5	)
Gain on disposal of retail natural gas business, net of income taxes of $nil (2002 – $10; 2001 – $nil)	—	48	—

There were no remaining assets or liabilities related to the discontinued operations at December 31, 2003 or at December 31, 2002.

(j) Cumulative Foreign Currency Translation

Under Canadian GAAP, foreign currency losses of $26 million arising on translation of the company’s Denver-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.

Recently Issued Accounting Standards

Consolidation of Variable Interest Entities

In January 2003, the Financial Accounting Standards Board issued interpretation 46 (“FIN 46”), "Consolidation of Variable Interest Entities (VIEs)." VIEs, commonly referred to as Special Purpose Entities or SPEs, are entities in which the equity investors do not have a controlling financial interest or do not have sufficient equity at risk to absorb future losses. Effective for 2004, FIN 46 requires consolidation of a VIE where the company will absorb a majority of a VIEs losses, receive a majority of its returns, or both. The company will be required to consolidate the VIE related to the sale of equipment as described in note 10(c). The company does not expect a significant impact on net income on consolidation of the equipment VIE. The impact on the balance sheet would be an increase to property, plant and equipment and an increase to long-term liabilities. The VIE involving the sale of crude oil inventory terminates June 25, 2004, and is not anticipated to have a significant impact on Suncor’s reported results of operations or financial position for U.S. GAAP purposes. The accounts receivable securitization program, as currently structured, does not meet the FIN 46 criteria for consolidation by Suncor.

Quarterly Summary (unaudited)

FINANCIAL DATA

	For the Quarter Ended										For the Quarter Ended
($ millions except per share amounts)	Mar		June		Sept		Dec		Total		Mar		June		Sept		Dec		Total
	31		30		30		31		Year		31		30		30		31		Year
	2003		2003		2003		2003		2003		2002		2002		2002		2002		2002
Revenues	1 676		1 292		1 700		1 638		6 306		1 077		1 289		1 257		1 409		5 032
Net earnings (loss)
Oil Sands	306		67		261		254		888		111		201		233		245		790
Natural Gas	28		37		27		37		129		5		12		1		17		35
Energy Marketing and Refining – Canada	21		16		10		6		53		7		27		10		20		64
Refining and Marketing – U.S.A. (c)	—		—		14		4		18		—		—		—		—		—
Corporate and eliminations	13		1		(17	)	(1	)	(4	)	(33	)	(11	)	(60	)	(24	)	(128	)
	368		121		295		300		1 084		90		229		184		258		761
Per common share
Net earnings attributable to common shareholders
Basic	0.84		0.29		0.64		0.67		2.43		0.18		0.52		0.38		0.56		1.64
Diluted	0.77		0.26		0.62		0.61		2.26		0.18		0.49		0.37		0.55		1.61
Cash dividends	0.0425		0.05		0.05		0.05		0.1925		0.0425		0.0425		0.0425		0.0425		0.17
Cash flow from (used in) operations
Oil Sands	541		321		488		453		1 803		213		366		443		453		1 475
Natural Gas	88		66		80		66		300		34		41		36		53		164
Energy Marketing and Refining – Canada	49		41		27		47		164		28		—		35		49		112
Refining and Marketing – U.S.A. (c)	—		—		25		9		34		—		—		—		—		—
Corporate and eliminations	(65	)	(70	)	(36	)	(49	)	(220	)	(94	)	(55	)	(67	)	(95	)	(311	)
	613		358		584		526		2 081		181		352		447		460		1 440

OPERATING 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
	2003	2003	2003	2003	2003	2002	2002	2002	2002	2002
OIL SANDS (thousands of barrels per day)
Production	211.1	188.2	231.5	235.2	216.6	179.3	207.6	207.9	227.6	205.8
Sales
Light sweet crude oil	120.7	86.4	109.0	132.7	112.3	96.8	90.8	114.1	116.7	104.7
Diesel	30.1	22.9	24.8	27.2	26.3	20.2	23.8	22.4	25.6	23.0
Light sour crude oil	60.4	73.9	77.5	81.3	73.3	70.8	73.8	54.8	73.9	68.3
Bitumen	—	1.2	16.1	8.3	6.4	0.3	8.9	15.4	12.2	9.3
	211.2	184.4	227.4	249.5	218.3	188.1	197.3	206.7	228.4	205.3
Average sales price (1) (dollars per barrel)
Light sweet crude oil	46.69	39.87	37.96	36.67	40.26	33.55	37.07	39.80	39.02	37.56
Other (diesel, light sour crude oil and bitumen)	40.62	32.94	32.92	30.72	33.93	25.53	30.33	30.86	31.04	29.58
Total	44.09	36.19	35.34	33.89	37.19	29.66	33.43	35.79	35.12	33.65
Total (a)	48.77	38.14	38.05	36.63	40.22	30.62	36.68	40.40	39.11	36.94

	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
	2003	2003	2003	2003	2003	2002	2002	2002	2002	2002
OIL SANDS (continued) (dollars per barrel sold rounded to the nearest $0.05)
Cash operating costs and total operating costs
New definition:
Cash costs	9.20	10.70	8.20	9.45	9.30	11.25	9.50	9.35	8.30	9.50
Natural gas	3.10	2.40	1.65	1.60	2.15	2.25	1.40	1.05	1.75	1.55
Imported bitumen	0.10	0.10	—	—	0.05	—	—	—	0.15	0.05
Cash operating costs (2)	12.40	13.20	9.85	11.05	11.50	13.50	10.90	10.40	10.20	11.10
Depreciation, depletion and amortization	6.20	6.25	5.20	5.30	5.70	6.15	5.50	6.25	6.05	6.00
Total operating costs (3)	18.60	19.45	15.05	16.35	17.20	19.65	16.40	16.65	16.25	17.10
As previously defined:
Cash costs	9.35	10.70	8.10	9.65	9.40	11.05	9.40	9.15	8.55	9.45
Natural gas	3.10	2.50	1.65	1.50	2.15	2.15	1.45	1.05	1.75	1.60
Cash overburden spending	2.30	3.20	1.70	1.85	2.20	3.15	1.75	1.75	2.00	2.10
Imported bitumen	0.10	0.10	—	—	0.05	—	—	—	0.15	0.05
Project start-up costs	0.10	0.15	0.15	0.10	0.10	—	—	0.10	0.05	0.05
Cash operating costs (4)	14.95	16.65	11.60	13.10	13.90	16.35	12.60	12.05	12.50	13.25
Depreciation, depletion and amortization (net of cash overburden spending)	3.90	3.25	3.65	3.10	3.45	2.70	4.05	4.50	4.05	3.90
Total operating costs (5)	18.85	19.90	15.25	16.20	17.35	19.05	16.65	16.55	16.55	17.15
NATURAL GAS
Gross production (b)
Natural gas (millions of cubic feet per day)	184	175	194	194	187	175	179	181	182	179
Natural gas liquids (thousands of barrels per day)	2.4	2.1	2.5	2.4	2.3	2.5	2.5	2.3	2.4	2.4
Crude oil (thousands of barrels per day)	1.4	1.6	1.6	1.0	1.4	1.4	1.7	1.3	1.5	1.5
Total (barrel of oil equivalent per day at 6:1 for natural gas)	34.5	32.8	36.4	35.7	34.9	33.0	34.0	33.8	34.2	33.7
Average sales price (1)
Natural gas (dollars per thousand cubic feet)	7.54	6.63	6.07	5.53	6.42	3.21	3.92	3.56	4.91	3.91
Natural gas (a) (dollars per thousand cubic feet)	7.59	6.65	6.04	5.51	6.42	3.21	3.92	3.56	4.91	3.91

Natural gas liquids (dollars per barrel)	41.65	33.45	33.50	35.45	36.08	22.53	28.25	31.66	35.14	29.35
Crude oil – conventional (dollars per barrel)	47.75	37.82	38.31	36.91	40.29	29.15	30.99	33.57	33.20	31.72

	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
	2003	2003	2003	2003	2003	2002	2002	2002	2002	2002

ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)	15.7	14.9	15.2	14.2	15.0	13.5	14.9	14.1	15.8	14.5
Margins
Refining (6) (cents per litre)	7.5	4.7	6.5	7.0	6.5	4.1	3.8	4.4	6.6	4.8
Refining (6), (a) (cents per litre)	7.8	4.2	6.4	6.9	6.4	4.1	3.8	4.4	6.6	4.8
Retail (7) (cents per litre)	7.0	6.2	7.0	6.3	6.6	6.1	6.8	6.9	6.5	6.6
Utilization of refining capacity (%)	103	100	91	86	95	102	70	100	108	95

REFINING AND MARKETING – U.S.A. (c)
Refined product sales (thousands of cubic metres per day)	—	—	9.8	8.6	9.1	—	—	—	—	—
Margins
Refining (6) (cents per litre)	—	—	7.9	4.6	5.9	—	—	—	—	—
Refining (6), (a) (cents per litre)	—	—	7.9	4.6	5.9	—	—	—	—	—
Retail (7) (cents per litre)	—	—	6.4	4.8	5.6	—	—	—	—	—
Utilization of refining capacity (%)	—	—	101	96	98	—	—	—	—	—

(a) Excludes the impact of hedging activities.

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

Definitions

(1) Average sales price – This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).

(2) Cash operating costs – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on production volumes. For a detailed annual reconciliation of this non-GAAP financial measure see page 50 of Management’s Discussion and Analysis (MD&A).

(3) Total operating costs – Include cash operating costs as defined in (2) above and non-cash operating costs. Per barrel amounts are based on production volumes.

(4) Cash operating costs (as previously defined) – Included cash costs that were defined as operating, selling and general expenses (including inventory changes), certain financing expenses, taxes other than income taxes and cash overburden spending. Per barrel amounts were based on sales volumes.

(5) Total operating costs (as previously defined) – Included cash operating costs as defined in (4) above and non-cash operating costs (excluding cash overburden spending). Per barrel amounts were based on sales volumes.

(6) Refining margin – This operating statistic is calculated as the average wholesale unit price from all products less the average unit cost of crude oil.

(7) Retail margin – This operating statistic is 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 and other adjustments, less refining gasoline transfer price.

Metric conversion

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

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

Five-year Financial Summary (unaudited)

($ millions except for ratios)	2003(a)		2002		2001		2000		1999
Revenues
Oil Sands	3 061		2 616		1 372		1 402		923
Natural Gas	512		339		481		458		337
Energy Marketing and Refining – Canada	2 671		2 508		2 673		2 604		1 779
Refining and Marketing – U.S.A.	515		—		—		—		—
Corporate and eliminations	(453	)	(431	)	(232	)	(980	)	(587	)
	6 306		5 032		4 294		3 484		2 452
Net earnings (loss)
Oil Sands	888		790		283		315		167
Natural Gas	129		35		117		98		41
Energy Marketing and Refining – Canada	53		64		80		81		27
Refining and Marketing – U.S.A.	18		—		—		—		—
Corporate and eliminations	(4	)	(128	)	(92	)	(117	)	(49	)
	1 084		761		388		377		186
Cash flow from (used in) operations
Oil Sands	1 803		1 475		486		655		405
Natural Gas	300		164		280		238		172
Energy Marketing and Refining – Canada	164		112		165		174		103
Refining and Marketing – U.S.A.	34		—		—		—		—
Corporate and eliminations	(220	)	(311	)	(100	)	(109	)	(89	)
	2 081		1 440		831		958		591
Capital and exploration expenditures
Oil Sands	948		617		1 479		1 808		1 057
Natural Gas	183		163		132		127		200
Energy Marketing and Refining – Canada	122		60		54		45		42
Refining and Marketing – U.S.A.	31		—		—		—		—
Corporate	32		37		13		18		51
	1 316		877		1 678		1 998		1 350
Total assets	10 427		8 683		8 094		6 833		5 176

Capital employed (b)

Short-term and long-term debt, less cash and cash equivalents	2 091		2 671		3 143		2 235		1 334
Shareholders’ equity	4 425		3 458		2 780		2 472		2 108
	6 516		6 129		5 923		4 707		3 442
Less capitalized costs related to major projects in progress	(1 122	)	(511	)	(3 691	)	(2 497	)	(1 084	)
	5 394		5 618		2 232		2 210		2 358

Total Suncor employees (number at year-end)	4 372		3 422		3 307		3 043		2 796

Dollars per common share
Net earnings attributable to common shareholders	2.43		1.64		0.79		0.78		0.39
Cash dividends	0.1925		0.17		0.17		0.17		0.17
Cash flow from operations	4.63		3.22		1.87		2.16		1.34
Cash flow from operations after deducting dividends paid on Preferred Securities	4.53		3.11		1.76		2.06		1.26

	2003	2002	2001	2000	1999
Ratios
Return on capital employed (%) (c)	18.3	14.6	17.8	16.6	8.3
Return on capital employed (%) (d)	15.9	13.8	7.5	9.3	6.4
Return on shareholders’ equity (%) (e)	27.5	24.4	14.8	16.5	10.3
Debt to debt plus shareholders’ equity (f) (%)	35.9	43.7	53.1	47.7	38.9
Net debt to cash flow from operations (times) (g)	1.0	1.9	3.8	2.3	2.3
Interest coverage – cash flow basis (times) (h)	15.7	10.6	5.9	9.0	9.1
Interest coverage – net earnings basis (times) (i)	13.5	8.2	3.7	5.6	5.1

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

(b) Capital employed – see page 62.

(c) Net earnings adjusted for after-tax financing expenses (income) for the 12-month period ended, divided by average capital employed. Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable), at the beginning and end of the year, divided by two. For a detailed annual reconciliation of this non-GAAP financial measure see page 50 of MD&A.

(d) If return on capital employed were to include capitalized costs related to major projects in progress, it 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.

Share Trading Information (unaudited)

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

The following share trading information reflects a two-for-one split of the company’s common shares during 2002.

For the Quarter Ended

Mar 31
2003

June 30
2003

Sept 30
2003

Dec 31
2003

Mar 31
2002

June 30
2002

Sept 30
2002

Dec 31
2002

Share ownership

Average number outstanding, weighted monthly (thousands) (a)

449 187

449 485

449 756

450 505

446 270

447 685

448 412

448 839

Share price (dollars)

Toronto Stock Exchange

High

27.50

26.60

27.14

32.85

30.00

29.50

28.51

27.20

Low

23.87

23.31

24.75

25.07

23.31

24.66

22.30

22.56

25.61

25.34

24.93

32.50

28.75

26.60

27.31

24.70

New York Stock Exchange – US$

High

18.50

19.68

19.59

25.42

18.57

18.25

17.16

Low

15.32

16.10

17.86

18.57

14.68

16.10

13.95

14.20

17.47

18.75

18.55

25.06

18.08

17.86

16.95

15.67

Shares traded (thousands)

Toronto Stock Exchange

83 756

67 815

64 875

93 538

108 140

96 043

93 144

91 947

New York Stock Exchange

23 600

23 369

21 725

27 138

16 971

23 680

19 420

19 933

Per common share information (dollars)

Net earnings attributable to common shareholders

0.84

0.29

0.64

0.67

0.18

0.52

0.38

0.56

Cash dividends

0.0425

0.05

0.0425

(a) The company had approximately 2,154 holders of record of common shares as at January 30, 2004.

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.

Supplemental Financial and Operating Information (unaudited)

	2003	2002	2001	2000	1999

OIL SANDS
Production (thousands of barrels per day)	216.6	205.8	123.2	113.9	105.6
Sales (thousands of barrels per day)
Light sweet crude oil	112.3	104.7	56.2	64.3	52.7
Diesel	26.3	23.0	14.8	9.3	8.2
Light sour crude oil	73.3	68.3	42.0	35.8	37.5
Bitumen	6.4	9.3	8.5	6.2	3.8
	218.3	205.3	121.5	115.6	102.2
Average sales price (dollars per barrel)
Light sweet crude oil	40.26	37.56	34.17	35.31	26.06
Other (diesel, light sour crude oil and bitumen)	33.93	29.58	24.86	27.09	21.48
Total	37.19	33.65	29.17	31.67	23.84
Total (a)	40.22	36.94	34.21	41.29	25.89

Cash operating costs – new definition (b)	11.50	11.10	11.10	11.25	9.90
Total operating costs – new definition (b)	17.20	17.10	16.25	16.80	14.50

Cash operating costs – as previously defined (b)	13.90	13.25	17.00	13.55	11.70
Total operating costs – as previously defined (b)	17.35	17.15	19.60	17.25	15.05

Return on capital employed (%) (c)	20.6	16.8	20.1	22.8	12.9
Return on capital employed (%) (d)	17.3	15.6	6.4	10.6	9.2

(a) Excludes the impact of hedging activities.

(b) Dollars per barrel rounded to the nearest $0.05. See definitions on page 92.

(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.

	2003	2002	2001	2000	1999

NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
Gross	187	179	177	200	226
Net	142	124	124	142	170
Natural gas liquids (thousands of barrels per day)
Gross	2.3	2.4	2.4	3.0	4.2
Net	1.7	1.7	1.7	2.1	3.0
Crude oil (thousands of barrels per day)
Gross	1.4	1.5	1.5	4.2	9.2
Net	1.1	1.2	1.1	3.3	7.5
Total (thousands of boe (a) per day)
Gross	34.9	33.7	33.4	40.5	51.1
Net	26.4	23.6	23.5	29.1	38.8

Average sales price
Natural gas (dollars per thousand cubic feet)	6.42	3.91	6.09	4.72	2.44
Natural gas (dollars per thousand cubic feet) (b)	6.42	3.91	6.12	4.73	2.48
Natural gas liquids (dollars per barrel)	36.08	29.35	34.38	36.66	19.32
Crude oil – conventional (dollars per barrel)	40.29	31.72	33.92	29.50	20.94

Return on capital employed (%) (e)	29.2	9.2	32.1	17.2	5.5

Undeveloped landholdings (c)
Oil and gas (millions of acres)
Western provinces
Gross	0.5	0.5	0.6	1.4	1.5
Net	0.4	0.4	0.5	1.1	1.2
International
Gross	0.9	1.2	1.7	1.3	—
Net	0.2	0.7	1.3	1.1	—

Net wells drilled (d)
Exploratory
Oil	—	—	—	—	1
Gas	2	2	4	1	5
Dry	31	19	16	15	13
Development
Oil	1	—	—	2	2
Gas	16	18	16	14	4
Dry	4	4	2	3	1
	54	43	38	35	26

(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.

(d) Excludes interests in one net exploratory well and three net development wells in progress at the end of 2003.

(e) See definitions on page 94.

	2003	2002	2001	2000	1999
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail (b)	4.4	4.5	4.3	4.2	4.1
Other	4.2	4.4	4.4	4.0	3.7
Jet fuel	0.7	0.4	0.7	1.1	1.1
Diesel	3.0	2.9	3.1	3.1	2.7
	12.3	12.2	12.5	12.4	11.6
Petrochemicals	0.8	0.6	0.5	0.6	0.7
Heating oils	0.5	0.4	0.4	0.4	0.4
Heavy fuel oils	0.8	0.6	0.8	0.6	0.5
Other	0.6	0.7	0.6	0.6	0.6
	15.0	14.5	14.8	14.6	13.8
Margins (cents per litre)
Refining	6.5	4.8	5.7	5.9	4.0
Refining (c)	6.4	4.8	5.7	5.9	4.0
Retail	6.6	6.6	6.6	6.6	7.4

Crude oil supply and refining
Processed at Sarnia refinery (thousands of cubic metres per day)	10.5	10.6	10.2	10.9	10.6
Utilization of refining capacity (%)	95	95	92	98	95

Return on capital employed (%) (d)	10.2	12.5	18.4	20.5	6.0
Retail outlets (e) (number at year-end)	379	384	400	402	415

REFINING AND MARKETING – U.S.A. (a)
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail (b)	0.7	—	—	—	—
Other	3.5	—	—	—	—
Jet fuel	0.5	—	—	—	—
Diesel	2.3	—	—	—	—
	7.0	—	—	—	—
Asphalt	1.7	—	—	—	—
Other	0.4	—	—	—	—
	9.1	—	—	—	—

Margins (cents per litre)
Refining	5.9	—	—	—	—
Refining (c)	5.9	—	—	—	—
Retail	5.6	—	—	—	—

Crude oil supply and refining
Processed at Denver refinery (thousands of cubic metres per day)	9.4	—	—	—	—
Utilization of refining capacity (%)	98	—	—	—	—
Retail outlets (f) (number at year-end)	43	—	—	—	—

(a) For the year ended 2003, Refining and Marketing – U.S.A. reflects the results of operations since acquisition from August 1 to December 31, 2003.

(b) Excludes sales through joint venture interests.

(d) See definitions on page 94.

(e) 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.

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

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 regularly. Effective the second quarter of 2003, dividends were increased to $0.05 per share from $0.0425 per share resulting in an aggregate 2003 dividend of $0.1925 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. For more information, call Computershare Trust Company of Canada at 1-888-267-6555 or visit the investor information section of our web site at www.suncor.com.

Stock Transfer Agent and Registrar

In Canada, Suncor’s agent is Computershare Trust Company of Canada, with locations in Calgary, Edmonton, Toronto, Montreal and Vancouver. In the United States, Computershare Trust Company, Inc. is located in Denver, Colorado.

Independent Auditors

PricewaterhouseCoopers LLP

Independent Petroleum Consultants

Gilbert Laustsen Jung Associates Ltd.

Annual Meeting

Suncor’s annual and special meeting of shareholders will be held at 10:30 a.m. MT on April 29, 2004, at the Hotel Macdonald, 10065 - 100 Street, Edmonton, Alberta. Presentations from the meeting will be web-cast live at www.suncor.com

Corporate Office

Box 38, 112 – 4th Avenue SW, Calgary, Alberta T2P 2V5

Telephone: 403-269-8100 Toll-free number in Canada and the United States: 1-866-SUNCOR-1 (1-866-786-2671) 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 E-mail: invest@suncor.com

For further information, to subscribe or cancel duplicate mailings

In addition to Annual and Quarterly Reports, Suncor publishes a biennial Report on Sustainability. All of Suncor’s publications, as well as updates on company news as it happens, are available on our web site at www.suncor.com To subscribe to Suncor e-news, go to the newsroom section of our web site. To order copies of Suncor’s print materials call 1-800-558-9071.

Sometimes shareholders receive more than one copy of our Annual Report. If you receive but do not require more than one mailing, call Computershare Trust Company of Canada at 1-888-267-6555. Computershare will update your account information accordingly.

Shareholders can help reduce mailing costs and paper waste by electing to receive Suncor’s Annual Report and other documents electronically. To register for electronic delivery, go to www.investordeliverycanada.com and follow the instructions for enrollment. You will need the 12-character control number enclosed with the Voting Instruction Form sent to shareholders. If you hold Suncor shares in multiple accounts, you will receive meeting packages and a corresponding control number for each account. You must register for each account.

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, communication with investors and other stakeholders, and standards of business conduct. Suncor’s Board is also responsible for selecting, monitoring and evaluating executive leadership and aligning management’s decision making with long-term shareholder interest. A comprehensive description of Suncor’s governance practices is available in the company’s annual proxy circular on Suncor’s web site at www.suncor.com or by calling 1-800-558-9071.

Independence

As of December 31, 2003, Suncor’s Board of Directors comprised 12 directors, 10 of whom have been determined by the Board to be independent of management under the guidelines established by the Toronto Stock Exchange and New York Stock Exchange. The role of chair is assumed by an independent director and is separate from the role of chief executive officer. Independent directors also chair the four committees of the Board.

Committee		Key Responsibilities
Board Policy, Strategy Review and Governance Committee >>		Reviews preliminary stages of key strategic initiatives and projects. Reviews and assesses processes relating to long-range planning and budgeting. Oversees key matters pertaining to corporate values, beliefs and standards of ethical conduct. Reviews key matters pertaining to governance, including organization, composition and effectiveness of the Board.

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. The committee also 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 Resource 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 >>		Oversees external audit and reviews annual disclosure documents such as financial statements, management’s discussion and analysis (MD&A) and the annual information form, including reserves data; approves quarterly financial disclosure documents including quarterly financial statements and MD&A.

>> comprised entirely of independent directors as of December 31, 2003.

In 2003, the Board of Directors met six times. With the exception of one Board member absent from one meeting, all members attended all Board meetings in 2003. Committees of the Board generally meet four or five times per year with the exception of the Audit Committee, which meets more frequently.

Share Ownership

The Board has set guidelines for its own, as well as executive share ownership. Shares held by each Board member and guidelines for executive share ownership are reported annually in Suncor’s Proxy Circular.

Board of Directors

JR Shaw (2,3)

Calgary, Alberta

Chairman of the Board of Directors

Director since 1998

JR Shaw has been the chairman of the Board of Suncor since 2001. He is also the executive chair of Shaw Communications Inc. Mr. Shaw is also a director of the Shaw Foundation.

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. From 1996 to 2000 Mr. Benson was the senior operations advisor, African Development, Exxon Co. International. Mr. Benson is also an active member of several charitable and Aboriginal organizations, including the Counsel for Advancement of Native Development Officers, the Canadian Aboriginal Professional Association and the National Aboriginal Business Association.

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. In addition to serving on Suncor’s Board, Mr. Canfield is also on the boards of Terasen Inc. and the Toronto Stock Exchange.

Susan E. Crocker (2,3)

Toronto, Ontario

Director since 2003

Susan Crocker is a corporate director and management consultant who serves as a director on the boards of Brascan Financial Corporation and RioCan Real Estate Investment Trust. Ms. Crocker also serves as a director of a number of arts and community organizations, including Canadian Stage Theatre Company, and the Toronto Community Foundation. She is a managing director and founder of IQ Alliance, a strategic advisory firm formed in 2002. From 1996 to 1999, she was senior vice president, Equity and Derivative Markets with the Toronto Stock Exchange and from 1999 to 2001 was the president and chief executive officer of the Hospitals of Ontario Pension Plan.

Bryan P. Davies (1,4)

Toronto, Ontario

Director 1991 to 1996 and since 2000

Bryan Davies is superintendent, Financial Services and chief executive officer of the Financial Services Commission of Ontario, an agency of the Ontario government that regulates pensions, insurance companies and deposit institutions. Prior to that he was senior vice president, Regulatory Affairs with the Royal Bank Financial Group. Mr. Davies is also active in a number of not-for-profit charitable organizations, including serving as chair of the Canadian Merit Scholarship Foundation and as a director of the National Gallery Foundation.

Brian A. Felesky (1,4)

Calgary, Alberta
Director since 2002

Brian Felesky is a partner in the law firm of Felesky Flynn in Calgary, Alberta. Mr. Felesky also serves as a director on the board of TransCanada Power, L.P. Mr. Felesky is actively involved in not-for-profit and charitable organizations. He is the chair of Homefront on Domestic Violence, a director of the United Way of Calgary and Area and the Canada West Foundation, as well as a member of the Board of Governors of the Council for Canadian Unity.

John T. Ferguson (1,2)

Edmonton, Alberta

Chair, Audit Committee

Director since 1995

John Ferguson is chairman of Princeton Developments Ltd., a real estate company in Edmonton, Alberta, as well as chairman of TransAlta Corporation. Mr. Ferguson is also a director of Bellanca Developments Ltd. and the Royal Bank of Canada. He is a director of the C.D. Howe Institute and an advisory member of the Canadian Institute for Advanced Research. His involvement in the community includes acting as chancellor of the University of Alberta.

Richard L. George

Calgary, Alberta

Director since 1991

Richard George is president and chief executive officer of Suncor. Mr. George is also a director of Enbridge Inc. and GlobalSantaFe Corporation. Mr. George serves as the 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, serving as a director for the American Bureau of Shipping and the Marine Resources Foundation, Key Largo. He is a trustee for the Houston Museum of Natural Science.

Robert W. Korthals (1,2)

Toronto, Ontario

Director since 1996

Robert Korthals is the former president of the Toronto-Dominion Bank. He is currently chairman of the Ontario Teachers’ Pension Plan, and is also a director of Jannock Properties Limited, Rogers Communications Inc., Cognos Inc., and several publicly traded investment funds sponsored by Mulvihill Investments. He is a commissioner with the Ontario Securities Commission and also 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. Ms. 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 “All for One-All for Kids $50 million Campaign,” and a trustee of the Killam Estate. She is also chancellor emeritus of the University of Calgary.

Michael W. O’ Brien (4)

Canmore, Alberta

Director since 2002

Michael O’Brien is the former executive vice president, Corporate Development and chief financial officer of Suncor, having retired in 2002. Prior to that, Mr. O’Brien was executive vice president of Suncor’s wholly owned subsidiary, Suncor Energy Products Inc. (formerly Sunoco Inc.) from 1992 to 2000. Mr. O’Brien also serves on the boards of PrimeWest Energy Inc., Terasen Inc. and Shaw Communications Inc. In addition, he is currently a director and past chair of the Nature Conservancy of Canada.

(1) Audit Committee

(2) Board Policy, Strategy Review and Governance Committee

(3) Human Resources and Compensation Committee

(4) Environment, Health and Safety Committee

100

Margin Hedges

Natural Gas Hedges