EXHIBIT 3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the first fiscal
quarter ended March 31, 2004

Consolidated Statements of Earnings
(unaudited)

	Three months ended March 31
($ millions)	2004		2003

REVENUES	1 795		1 700
EXPENSES
Purchases of crude oil and products	531		411
Operating, selling and general (notes 2 and 6)	400		361
Energy marketing and trading activities (note 3)	67		50
Transportation and other costs	27		34
Depreciation, depletion and amortization (note 2)	174		157
Accretion of asset retirement obligations (note 2)	6		6
Exploration	33		17
Royalties	91		42
Taxes other than income taxes	119		89
(Gain) on disposal of assets	(1	)	(1	)
Project start-up costs	22		2
Financing expenses (income) (note 4)	44		(22	)
	1 513		1 146
EARNINGS BEFORE INCOME TAXES	282		554
PROVISION FOR INCOME TAXES (notes 2 and 9)
Current	20		21
Future	35		167
	55		188
NET EARNINGS	227		366
Dividends on preferred securities, net of tax (note 11)	(6	)	(7	)
Revaluation of US$ preferred securities, net of tax (note 11)	(6	)	14
Net earnings attributable to common shareholders	215		373

PER COMMON SHARE (dollars)
Net earnings attributable to common shareholders (note 5)
Basic	0.48		0.84
Diluted	0.46		0.77
Cash dividends	0.05		0.0425

See accompanying notes.

Consolidated Balance Sheets
(unaudited)

($ millions)	March 31 2004	December 31 2003

ASSETS
Current assets
Cash and cash equivalents	57	388
Accounts receivable	637	505
Inventories	404	371
Future income taxes	39	28
Total current assets	1 137	1 292
Property, plant and equipment, net (note 2)	9 148	8 936
Deferred charges and other	310	286
Future income taxes (note 2)	232	234
Total assets	10 827	10 748
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	38	31
Accounts payable and accrued liabilities	1 081	970
Income taxes payable	6	9
Taxes other than income taxes	60	49
Future income taxes	16	14
Total current liabilities	1 201	1 073
Long-term debt (note 10)	2 607	2 448
Accrued liabilities and other (note 2)	634	616
Future income taxes (note 2)	2 297	2 256
Shareholders’ equity (see below)	4 088	4 355
Total liabilities and shareholders’ equity	10 827	10 748

SHAREHOLDERS’ EQUITY

	Number			Number
	(thousands)			(thousands)

Preferred securities (note 11)	—	—		17 540	476
Share capital	452 677	623		451 184	604
Contributed surplus		11			7
Cumulative foreign currency translation		(22	)		(26	)
Retained earnings (note 2)		3 476			3 294
		4 088			4 355

See accompanying notes.

Consolidated Statements of Cash Flows
(unaudited)

	Three months ended March 31
($ millions)	2004		2003

OPERATING ACTIVITIES
Cash flow from operations	422		613
Decrease (increase) in operating working capital
Accounts receivable	(132	)	(114	)
Inventories	(33	)	(32	)
Accounts payable and accrued liabilities	111		132
Taxes payable	8		—
Cash flow from operating activities	376		599
CASH USED IN INVESTING ACTIVITIES	(349	)	(301	)
NET CASH SURPLUS BEFORE FINANCING ACTIVITIES	27		298
FINANCING ACTIVITIES
Increase in short-term debt	7		4
Net increase (decrease) in other long-term debt	141		(284	)
Redemption of preferred securities (note 11)	(493	)	—
Issuance of common shares under stock option plan	17		4
Dividends paid on preferred securities	(9	)	(12	)
Dividends paid on common shares	(21	)	(18	)
Cash (used in) financing activities	(358	)	(306	)
(DECREASE) IN CASH AND CASH EQUIVALENTS	(331	)	(8	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	388		15
CASH AND CASH EQUIVALENTS AT END OF PERIOD	57		7

See accompanying notes.

Consolidated Statements of Changes in Shareholders’ Equity
(unaudited)

($ millions)	Preferred Securities		Share Capital	Contributed Surplus	Cumulative Foreign Currency Translation		Retained Earnings

At December 31, 2002, as previously reported	523		578	—	—		2 357
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—		—	—	—		(61	)
At December 31, 2002, as restated	523		578	—	—		2 296
Net earnings	—		—	—	—		366
Dividends paid on preferred securities, net of tax	—		—	—	—		(7	)
Dividends paid on common shares	—		—	—	—		(18	)
Issued for cash under stock option plan	—		4	—	—		—
Issued under dividend reinvestment plan	—		1	—	—		(1	)
Revaluation of US$ preferred securities	(18	)	—	—	—		14
At March 31, 2003	505		583	—	—		2 650
At December 31, 2003, as previously reported	476		604	7	(26	)	3 364
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—		—	—	—		(70	)
At December 31, 2003, as restated	476		604	7	(26	)	3 294
Net earnings	—		—	—	—		227
Dividends paid on preferred securities, net of tax	—		—	—	—		(6	)
Dividends paid on common shares	—		—	—	—		(21	)
Issued for cash under stock option plan	—		17	—	—		—
Issued under dividend reinvestment plan	—		2	—	—		(2	)
Stock-based compensation expense	—		—	4	—		—
Foreign currency translation adjustment	—		—	—	4		—
Revaluation of US$ preferred securities	7		—	—	—		(6	)
Reclassification of issue costs	10		—	—	—		(10	)
Redemption of preferred securities (note 11)	(493	)	—	—	—		—
At March 31, 2004	—		623	11	(22	)	3 476

See accompanying notes.

Schedules of Segmented Data
(unaudited)

																Three months ended March 31

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
EARNINGS
Revenues
Operating revenues	666		757		91		136		678		758		289		—	—		—		1 724		1 651
Energy marketing and trading activities	—		—		—		—		78		49		—		—	(8	)	—		70		49
Intersegment revenues	99		108		42		7		—		—		—		—	(141	)	(115	)	—		—
Interest	—		—		—		—		—		—		—		—	1		—		1		—
	765		865		133		143		756		807		289		—	(148	)	(115	)	1 795		1 700
Expenses
Purchases of crude oil and products	12		2		—		—		438		527		224		—	(143	)	(118	)	531		411
Operating, selling and general	214		225		20		19		96		100		33		—	37		17		400		361
Energy marketing and trading activities	—		—		—		—		75		50		—		—	(8	)	—		67		50
Transportation and other costs	17		28		5		6		1		—		4		—	—		—		27		34
Depreciation, depletion and amortization	124		120		28		21		17		15		3		—	2		1		174		157
Accretion of asset retirement obligations	5		5		1		1		—		—		—		—	—		—		6		6
Exploration	13		9		20		8		—		—		—		—	—		—		33		17
Royalties	62		10		29		32		—		—		—		—	—		—		91		42
Taxes other than income taxes	7		6		—		—		83		83		29		—	—		—		119		89
(Gain) on disposal of assets	—		—		(1	)	—		—		(1	)	—		—	—		—		(1	)	(1	)
Project start-up costs	22		2		—		—		—		—		—		—	—		—		22		2
Financing expenses (income)	—		—		—		—		—		—		—		—	44		(22	)	44		(22	)
	476		407		102		87		710		774		293		—	(68	)	(122	)	1 513		1 146
Earnings (loss) before income taxes	289		458		31		56		46		33		(4	)	—	(80	)	7		282		554
Income taxes	(51	)	(153	)	(9	)	(29	)	(16	)	(12	)	1		—	20		6		(55	)	(188	)
Net earnings (loss)	238		305		22		27		30		21		(3	)	—	(60	)	13		227		366

As at March 31
TOTAL ASSETS	8 362		7 426		835		850		1 160		989		420		—	50		63		10 827		9 328
CAPITAL EMPLOYED(1)	4 725		4 366		418		406		567		464		307		—	118		185		6 135		5 421

(1) Excludes capitalized costs related to major projects in progress.

Schedules of Segmented Data (continued)
(unaudited)

																Three months ended March 31

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from(used in) operations
Net earnings (loss)	238		305		22		27		30		21		(3	)	—	(60	)	13		227		366
Exploration expenses
Cash	—		—		8		4		—		—		—		—	—		—		8		4
Dry hole costs	—		—		12		4		—		—		—		—	—		—		12		4
Non-cash items included in earnings
Depreciation, depletion and amortization	124		120		28		21		17		15		3		—	2		1		174		157
Future income taxes	47		150		9		28		(4	)	(3	)	(1	)	—	(16	)	(8	)	35		167
Current income tax provision allocated to Corporate	4		3		—		1		20		15		—		—	(24	)	(19	)	—		—
(Gain) on disposal of assets	—		—		(1	)	—		—		(1	)	—		—	—		—		(1	)	(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	4		—		4		—
Other	(11	)	4		4		2		(8	)	2		(7	)	—	13		(53	)	(9	)	(45	)
Overburden removal outlays	(54	)	(44	)	—		—		—		—		—		—	—		—		(54	)	(44	)
Increase (decrease) in deferred credits and other	17		3		1		1		1		—		2		—	5		1		26		5
Total cash flow from (used in) operations	365		541		83		88		56		49		(6	)	—	(76	)	(65	)	422		613
Decrease (increase) in operating working capital	10		25		(13	)	(9	)	32		18		(24	)	—	(51	)	(48	)	(46	)	(14	)
Total cash flow from (used in) operating activities	375		566		70		79		88		67		(30	)	—	(127	)	(113	)	376		599
Cash from (used in) investing activities:
Capital and exploration expenditures	(227	)	(241	)	(70	)	(39	)	(25	)	(13	)	(18	)	—	(6	)	(2	)	(346	)	(295	)
Deferred maintenance shutdown expenditures	—		(9	)	—		—		(1	)	—		—		—	—		—		(1	)	(9	)
Deferred outlays and other investments	(2	)	—		—		—		(4	)	—		—		—	—		—		(6	)	—
Proceeds from disposals	—		—		4		2		—		1		—		—	—		—		4		3
Total cash (used in) investing activities	(229	)	(250	)	(66	)	(37	)	(30	)	(12	)	(18	)	—	(6	)	(2	)	(349	)	(301	)
Net cash surplus (deficiency) before financing activities	146		316		4		42		58		55		(48	)	—	(133	)	(115	)	27		298

>> Notes to the Consolidated Financial Statements
(unaudited)

1. ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and follow the same accounting policies and methods of computation as, and should be read in conjunction with, the most recent annual financial statements, except for the accounting policy change as described in note 2, Asset Retirement Obligations.

In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature necessary to present fairly Suncor Energy Inc.’s (Suncor) financial position at March 31, 2004 and the results of its operations and cash flows for the three month periods ended March 31, 2004 and 2003.

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

2. ASSET RETIREMENT OBLIGATIONS

On January 1, 2004, the company retroactively adopted the new Canadian accounting standard related to “Asset Retirement Obligations” (ARO). Under the new standard a liability is recognized for the future retirement obligations associated with the company’s property, plant and equipment. The fair value of the ARO is recorded on a discounted basis. This amount is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the company settles the obligation. The 2003 and estimated 2004 impact of adopting this standard compared to the previous standard is:

CHANGE IN CONSOLIDATED BALANCE SHEETS

	As at March 31
($ millions, increase/(decrease))	2004		2003

Property, plant and equipment	209		216
Future income tax assets	108		110
Total assets	317		326

Accrued liabilities and other	314		321
Future income tax liabilities	72		68
Retained earnings	(69	)	(63	)
Total liabilities and shareholders’ equity	317		326

CHANGE IN CONSOLIDATED STATEMENTS OF EARNINGS

	Three months ended March 31
($ millions, increase/(decrease))	2004		2003

Depreciation, depletion and amortization	2		2
Accretion of asset retirement obligations	6		6
Operating, selling and general expenses	(10	)	(5	)
Future income taxes	1		(1	)
Net earnings	1		(2	)
Per common share – basic (dollars)	—		—
Per common share – diluted (dollars)	—		—

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

	As at March 31
($ millions)	2004		2003

Asset retirement obligations, beginning of period	401		400
Liabilities incurred	—		—
Liabilities settled	(6	)	(7	)
Accretion of asset retirement obligations	6		6
Other	—		—
Asset retirement obligations, end of period	401		399

The total undiscounted amount of estimated cash flows required to settle the obligations is approximately $1 billion for each of 2003 and 2004 and has been discounted using a credit-adjusted risk free rate of 6%. Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

3. ENERGY MARKETING AND 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 three months ended March 31, 2004 a net pretax gain of $3 million (2003 – pretax loss of $2 million) from the settlement and revaluation of these contracts was reported as energy marketing and trading activities in the Consolidated Statements of Earnings.

The fair value of unsettled (unrealized) energy trading assets and liabilities are as follows:

($ millions)	March 31 2004	December 31 2003

Energy trading assets	12	5
Energy trading liabilities	9	5

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

4. FINANCING EXPENSES (INCOME)

	Three months ended March 31
($ millions)	2004		2003

Interest on debt	40		36
Capitalized interest	(10	)	(10	)
Net interest expense	30		26
Foreign exchange (gain) loss on long-term debt	18		(55	)
Other foreign exchange (gain) loss	(4	)	7
Total financing expenses (income)	44		(22	)

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Three months ended March 31
($ millions)	2004		2003
Net earnings attributable to common shareholders	215		373
Dividends on preferred securities, net of tax	—	(a)	7
Revaluation of US$ preferred securities, net of tax	—	(a)	(14	)
Adjusted net earnings attributable to common shareholders	215		366

(millions of common shares)
Weighted-average number of common shares	452		449
Dilutive securities:
Options issued under stock-based compensation plans	13		5
Redemption of preferred securities by the issuance of common shares	—	(a)	22
Weighted-average number of diluted common shares	465		476

(dollars per common share)
Basic earnings per share (b)	0.48		0.84
Diluted earnings per share	0.46	(a)	0.77	(c)

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 three months ended March 31, 2004, 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.

6. STOCK-BASED COMPENSATION

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

After the date of grant, employees 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, is 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 option is granted.

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

(a) Stock Option Plans

Under the SunShare long-term incentive plan, the company granted 810,000 options to new employees in the first quarter of 2004 (253,000 options granted during the first quarter of 2003).

Under the company’s other plans, 1,226,000 options were granted in the first quarter of 2004 (1,721,000 options granted during the first quarter of 2003).

The fair values of all common share options granted during the period 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 various periods and the weighted-average assumptions used in their determination are as noted below:

	Three months ended March 31
	2004			2003

Quarterly dividend per share	$	0.05		$	0.0425
Risk-free interest rate	3.72		%	4.37		%
Expected life	6 years			6 years
Expected volatility	29		%	33		%
Weighted-average fair value per option	$	11.76		$	10.10

Expense recognized in the first quarter of 2004 related to stock option plans was $4 million (2003 – $nil).

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

	Three months ended March 31
($ millions, except per share amounts)	2004	2003

Net earnings attributable to common shareholders – as reported	215	373
Less: compensation cost under the fair value method for pre-2003 options	15	14
Pro forma net earnings attributable to common shareholders for pre-2003 options	200	359
Basic earnings per share
As reported	0.48	0.84
Pro forma	0.45	0.81
Diluted earnings per share
As reported	0.46	0.77
Pro forma	0.43	0.74

(b) Performance Share Units (PSUs)

As a means of providing better alignment between incentive plans and shareholder interest, in the first quarter of 2004 the company issued 351,000 PSUs under a new employee incentive compensation plan. PSUs granted replace the remuneration value of reduced grants under the company’s stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor’s performance. Performance is measured by reference to the Company’s total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the probability of vesting. This expense is recognized on a straight-line basis over the term of the grant. The accrued expense and obligation for PSUs for first quarter 2004 was $1 million.

7. EMPLOYEE FUTURE BENEFITS LIABILITY

The company’s pension plans are described in the notes to the 2003 Consolidated Financial Statements. The following is the status of the net periodic benefit cost for the three months ended March 31.

	Periodic Benefits				Other Post-retirement Benefits
	2004		2003		2004	2003

Current service costs	6		5		1	1
Interest costs	8		8		2	2
Expected return on plan assets	(6	)	(5	)	—	—
Amortization of net actuarial loss	5		5		—	—
Net periodic benefit cost	13		13		3	3

8. SUPPLEMENTAL INFORMATION

	Three months ended March 31
($ millions)	2004	2003

Interest paid	55	62
Income taxes paid	20	25

CRUDE OIL HEDGES AT MARCH 31, 2004

	Quantity (bbl/day)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)

Swaps	68 000	23.93	586	2004
Costless collars	11 000	21.00 – 23.65	83 – 94	2004
Swaps	36 000	22.77	392	2005

MARGIN HEDGES AT MARCH 31, 2004

	Quantity (bbl/day)	Average Price (US$/bbl)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period

Refined product and crude swaps	8 000	8.16	24	2004	(d)

NATURAL GAS HEDGES AT MARCH 31, 2004

	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period

Swaps	30 000	5.95	38	2004	(e)

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

(b) The revenue and margin hedged is translated to Cdn$ at the March 31, 2004 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(d) For the period April to December 2004, inclusive.

(e) For the period April to October 2004, inclusive.

9. INCOME TAXES

During the first quarter the province of Alberta substantively enacted a 1% reduction to its provincial corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $53 million related to the revaluation of its opening future income tax balances.

10. LONG-TERM DEBT

In February, 2004 the company retired all of its then outstanding 7.4% Debentures for $125 million.

11. PREFERRED SECURITIES

On March 15, 2004 the company redeemed all of its then outstanding 9.05% and 9.125% preferred securities for total cash consideration of $493 million.

12. CONSOLIDATION OF 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) on page 78 of the company’s 2003 Annual Report. The company does not expect a significant impact on net income upon consolidation of the equipment VIE. The impact on the balance sheet upon adoption in 2005 will be an increase to property, plant and equipment and an increase to 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.

Highlights
(unaudited)

	2004	2003

CASH FLOW FROM OPERATIONS
(dollars per common share)

For the three months ended March 31
Cash flow from operations (1)	0.93	1.37
Dividends paid on preferred securities (pretax) (2)	0.02	0.03

Cash flow from operations after deducting dividends paid on preferred securities (3)	0.91	1.34

RATIOS
For the twelve months ended March 31
Return on capital employed (%) (4)	15.9	18.9
Return on capital employed (%) (5)	14.4	17.5

Net debt to cash flow from operations (times) (6)	1.4	1.3
Interest coverage on long-term debt (times)
Net earnings (7)	11.2	10.9
Cash flow from operations (8)	14.0	13.5

As at March 31
Debt to debt plus shareholders’ equity (%) (9)	39.3	38.1

COMMON SHARE INFORMATION
As at March 31
Share price at end of trading
Toronto Stock Exchange – Cdn$	35.97	25.61
New York Stock Exchange – US$	27.35	17.47
Common share options outstanding (thousands)	21 524	21 872

For the three months ended March 31
Average number outstanding, weighted monthly (thousands)	452 123	449 187

Refer to the Quarterly Operating Summary for a discussion of financial measures not prepared in accordance with generally accepted accounting principles (GAAP).

(1) Cash flow from operations for the period; divided by the weighted average number of common shares outstanding during the period.

(2) Dividends paid on preferred securities for the period, before income taxes; divided by the weighted-average number of common shares outstanding during the period.

(3) Cash flow from operations minus pretax dividends paid on preferred securities, for the period; divided by the weighted-average number of common shares outstanding for the period.

(4) Net earnings (2004 – $934 million; 2003 – $1,030 million) adjusted for after-tax financing expenses (2004 – income of $17 million; 2003 – expense of $34 million) for the twelve month period ended; divided by average capital employed (2004 – $5,778 million; 2003 – $5,621 million). 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. Return on capital employed (ROCE) for Suncor operating segments as presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed reconciliation of ROCE prepared on an annual basis, see page 50 of Suncor’s 2003 Annual Report to Shareholders.

(5) If capital employed were to include capitalized costs related to major projects in progress (average capital employed including major projects in progress: 2004 – $6,371 million; 2003 – $6,068 million), the return on capital employed would be as stated on this line.

(6) Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations for the twelve month period then ended.

(7) Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.

(8) Cash flow from operations plus current income taxes and interest expense, divided by the sum of interest expense and capitalized interest.

(9) Short-term debt plus long-term debt, divided by the sum of short-term debt, long-term debt and shareholders’ equity.

Quarterly Operating Summary
(unaudited)

	For the quarter ended					Total year
	Mar 31 2004	Dec 31 2003	Sept 30 2003	June 30 2003	Mar 31 2003	Dec 31 2003

OIL SANDS
Production (a)
Mining	213.9	235.2	231.5	188.2	211.1	216.6
In-situ	5.9	—	—	—	—	—
Total production	219.8	235.2	231.5	188.2	211.1	216.6
Sales (a)
Light sweet crude oil	112.2	132.7	109.0	86.4	120.7	112.3
Diesel	27.5	27.2	24.8	22.9	30.1	26.3
Light sour crude oil	74.3	81.3	77.5	73.9	60.4	73.3
Bitumen	—	8.3	16.1	1.2	—	6.4
Total sales	214.0	249.5	227.4	184.4	211.2	218.3
Average sales price (1),(b)
Light sweet crude oil	40.26	36.67	37.96	39.87	46.69	40.26
Other (diesel, light sour crude oil and bitumen)	35.85	30.72	32.92	32.94	40.62	33.93
Total	38.16	33.89	35.34	36.19	44.09	37.19
Total *	43.28	36.63	38.05	38.14	48.77	40.22

CASH OPERATING COSTS AND TOTAL OPERATING COSTS
Cash costs	9.65	9.25	8.20	10.70	9.20	9.25
Natural gas	2.10	1.60	1.65	2.40	3.10	2.15
Imported bitumen	0.40	—	—	0.10	0.10	0.05
Cash operating costs – mining (2),(c)	12.15	10.85	9.85	13.20	12.40	11.45
In-situ (Firebag) start-up costs	1.20	—	—	—	—	—
Total cash operating costs (3),(c)	13.35	10.85	9.85	13.20	12.40	11.45
Depreciation, depletion and amortization	6.20	5.40	5.30	6.30	6.30	5.80
Total operating costs (4),(c)	19.55	16.25	15.15	19.50	18.70	17.25

(for the period ended)
Capital employed (i)	4 725	4 050	4 163	4 160	4 366

(for the twelve months ended)
Return on capital employed (j)	18.1	20.8	19.8	19.0	21.2
Return on capital employed (j) ****	16.0	17.4	17.2	16.9	19.3

Quarterly Operating Summary (continued)
(unaudited)

	For the quarter ended					Year ended
	Mar 31 2004	Dec 31 2003	Sept 30 2003	June 30 2003	Mar 31 2003	Dec 31 2003

NATURAL GAS
Gross production **
Natural gas (d)	197	194	194	175	184	187
Natural gas liquids (a)	2.2	2.4	2.5	2.1	2.4	2.3
Crude oil (a)	0.9	1.0	1.6	1.6	1.4	1.4
Total gross production (e)	35.9	35.7	36.4	32.8	34.5	34.9
Average sales price (1)
Natural gas (f)	6.54	5.53	6.07	6.63	7.54	6.42
Natural gas (f) *	6.59	5.51	6.04	6.65	7.59	6.42
Natural gas liquids (b)	38.13	35.45	33.50	33.45	41.65	36.08
Crude oil – Conventional (b)	44.14	36.91	38.31	37.82	47.75	40.29
Net wells drilled
Conventional – Exploratory ***	4	5	1	24	3	33
– Development	8	6	9	1	5	21
	12	11	10	25	8	54

(for the period ended)
Capital employed (i)	418	400	373	394	406

(for the twelve months ended)
Return on capital employed (j)	27.7	29.2	24.4	17.3	15.2

ENERGY MARKETING AND REFINING – CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.2	4.4	4.3	4.5	4.4	4.4
Other	4.0	3.9	4.5	4.1	4.2	4.2
Jet fuel	1.0	0.7	0.8	0.7	0.7	0.7
Diesel	2.9	3.1	2.8	3.0	3.0	3.0
Total transportation fuel sales	12.1	12.1	12.4	12.3	12.3	12.3
Petrochemicals	0.9	0.7	0.6	0.9	1.0	0.8
Heating oils	0.8	0.5	0.2	0.3	0.8	0.5
Heavy fuel oils	0.8	0.5	1.4	0.6	0.7	0.8
Other	0.6	0.4	0.6	0.8	0.9	0.6
Total refined product sales	15.2	14.2	15.2	14.9	15.7	15.0

Margins (h)
Refining (5)	7.8	7.0	6.5	4.7	7.5	6.5
Refining (5) *	7.8	6.9	6.4	4.2	7.8	6.4
Retail (6)	5.0	6.3	7.0	6.2	7.0	6.6

Crude oil supply and refining
Processed at Sarnia refinery (g)	12.0	9.6	10.1	11.1	11.5	10.5
Utilization of refining capacity (j)	108	86	91	100	103	95

(for the period ended)
Capital employed (i)	567	551	523	488	464

(for the twelve months ended)
Return on capital employed (j)	11.8	10.3	11.0	13.1	15.5

Quarterly Operating Summary (continued)
(unaudited)

	For the quarter ended			Year ended
	Mar 31 2004	Dec 31 2003	Sep 30 2003	Dec 31 2003

REFINING AND MARKETING – U.S.A. *****
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.7
Other	3.4	3.4	3.5	3.5
Jet fuel	0.4	0.5	0.6	0.5
Diesel	2.2	2.3	2.3	2.3
Total transportation fuel sales	6.7	6.9	7.1	7.0
Asphalt	1.2	1.4	2.1	1.7
Other	0.2	0.3	0.6	0.4
Total refined product sales	8.1	8.6	9.8	9.1

Margins (h)
Refining (5)	5.0	4.6	7.9	5.9
Refining (5) *	5.0	4.6	7.9	5.9
Retail (6)	5.0	4.8	6.4	5.6

Crude oil supply and refining
Processed at Denver refinery (g)	8.1	9.2	9.6	9.4
Utilization of refining capacity (j)	85	96	101	98

Quarterly Operating Summary (continued)

Non GAAP Financial Measures

Certain financial measures referred to in the Highlights and Quarterly Operating Summary are not prescribed by generally accepted accounting principles (GAAP). Suncor includes cash flow from operations, return on capital employed and cash operating costs per barrel data because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

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

(3) Total cash operating costs	–	Include cash operating costs – mining as defined above and cash start-up costs for in-situ operations.

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

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

(6) 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.

Explanatory Notes

*		Excludes the impact of hedging activities.

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

***		Excludes exploratory wells in progress.

****		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.

*****		Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003. Return on capital employed will not be calculated for this segment until there is twelve months of information available on which to base the calculation.

(a)	thousands of barrels per day	(e)	thousands of barrels of oil equivalent per day	(i)	$ millions

(b)	dollars per barrel	(f)	dollars per thousand cubic feet	(j)	percentage

(c)	dollars per barrel rounded to the nearest $0.05	(g)	thousands of cubic metres per day

(d)	millions of cubic feet per day	(h)	cents per litre

Metric conversion

Crude oil, refined products, etc.

1m³(cubic metre) = approx. 6.29 barrels