EXHIBIT 3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the second fiscal quarter ended June 30, 2004

Consolidated Statements of Earnings

(unaudited)

	Second quarter			Six months ended June 30
($ millions)	2004	2003		2004		2003
REVENUES	2 201	1 385		3 996		3 085
EXPENSES
Purchases of crude oil and products	777	341		1 308		752
Operating, selling and general (notes 2 and 6)	445	335		845		696
Energy marketing and trading activities (note 3)	110	87		177		137
Transportation and other costs	29	36		56		70
Depreciation, depletion and amortization (note 2)	177	144		351		301
Accretion of asset retirement obligations (note 2)	7	6		13		12
Exploration	5	16		38		33
Royalties (note 12)	137	38		228		80
Taxes other than income taxes	123	91		242		180
(Gain) loss on disposal of assets	1	(1	)	—		(2	)
Project start-up costs	—	3		22		5
Financing expenses (income) (note 4)	53	(31	)	97		(53	)
	1 864	1 065		3 377		2 211
EARNINGS BEFORE INCOME TAXES	337	320		619		874
PROVISION FOR INCOME TAXES (notes 2 and 9)
Current	4	21		24		42
Future	130	183		165		350
	134	204		189		392
NET EARNINGS	203	116		430		482
Dividends on preferred securities, net of tax (note 11)	—	(6	)	(6	)	(13	)
Revaluation of US$ preferred securities, net of tax (note 11)	—	15		(6	)	29
Net earnings attributable to common shareholders	203	125		418		498

PER COMMON SHARE (dollars)
Net earnings attributable to common shareholders (note 5)
Basic	0.44	0.27		0.92		1.10
Diluted	0.43	0.24		0.90		1.01
Cash dividends	0.06	0.05		0.11		0.0925

See accompanying notes.

Consolidated Balance Sheets

(unaudited)

($ millions)	June 30 2004	December 31 2003
ASSETS
Current assets
Cash and cash equivalents	37	388
Accounts receivable	724	505
Inventories (note 13)	474	371
Future income taxes	63	28
Total current assets	1 298	1 292
Property, plant and equipment, net (note 2)	9 391	8 936
Deferred charges and other	338	286
Future income taxes (note 2)	232	234
Total assets	11 259	10 748
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	37	31
Accounts payable and accrued liabilities	1 224	970
Income taxes payable	—	9
Taxes other than income taxes	51	49
Future income taxes	9	14
Total current liabilities	1 321	1 073
Long-term debt (note 10)	2 521	2 448
Accrued liabilities and other (note 2)	677	616
Future income taxes (note 2)	2 458	2 256
Shareholders’ equity (see below)	4 282	4 355
Total liabilities and shareholders’ equity	11 259	10 748

SHAREHOLDERS’ EQUITY

	Number			Number
	(thousands)			(thousands)
Preferred securities (note 11)	—	—		17 540	476
Share capital	452 929	628		451 184	604
Contributed surplus		16			7
Cumulative foreign currency translation		(15	)		(26	)
Retained earnings (note 2)		3 653			3 294
		4 282			4 355

See accompanying notes.

Consolidated Statements of Cash Flows

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2004		2003		2004		2003
OPERATING ACTIVITIES
Cash flow from operations	490		358		912		971
Decrease (increase) in operating working capital
Accounts receivable	(87	)	149		(219	)	35
Inventories	(70	)	(1	)	(103	)	(33	)
Accounts payable and accrued liabilities	143		(42	)	254		90
Taxes payable	(11	)	(10	)	(3	)	(10	)
Cash flow from operating activities	465		454		841		1 053
CASH USED IN INVESTING ACTIVITIES	(347	)	(353	)	(696	)	(654	)
NET CASH SURPLUS BEFORE FINANCING ACTIVITIES	118		101		145		399
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	(1	)	(3	)	6		1
Net increase (decrease) in other long-term debt	(116	)	(75	)	25		(359	)
Redemption of preferred securities (note 11)	—		—		(493	)	—
Issuance of common shares under stock option plan	3		2		20		6
Dividends paid on preferred securities	—		(11	)	(9	)	(23	)
Dividends paid on common shares	(24	)	(21	)	(45	)	(39	)
Cash (used in) financing activities	(138	)	(108	)	(496	)	(414	)
(DECREASE) IN CASH AND CASH EQUIVALENTS	(20	)	(7	)	(351	)	(15	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	57		7		388		15
CASH AND CASH EQUIVALENTS AT END OF PERIOD	37		—		37		—

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	—		—	—	—		482
Dividends paid on preferred securities, net of tax	—		—	—	—		(13	)
Dividends paid on common shares	—		—	—	—		(39	)
Issued for cash under stock option plan	—		6	—	—		—
Issued under dividend reinvestment plan	—		1	—	—		(1	)
Stock-based compensation expense	—		—	3	—		—
Revaluation of US$ preferred securities	(37	)	—	—	—		29
At June 30, 2003	486		585	3	—		2 754

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	—		—	—	—		430
Dividends paid on preferred securities, net of tax	—		—	—	—		(6	)
Dividends paid on common shares	—		—	—	—		(45	)
Issued for cash under stock option plan	—		20	—	—		—
Issued under dividend reinvestment plan	—		4	—	—		(4	)
Stock-based compensation expense	—		—	9	—		—
Foreign currency translation adjustment	—		—	—	11		—
Revaluation of US$ preferred securities	7		—	—	—		(6	)
Reclassification of issue costs for preferred securities	10		—	—	—		(10	)
Redemption of preferred securities (note 11)	(493	)	—	—	—		—
At June 30, 2004	—		628	16	(15	)	3 653

See accompanying notes.

Schedules of Segmented Data

(unaudited)

Second quarter

	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	815		553		132		120		764		624		372		—	1		1		2 084		1 298
Energy marketing and trading activities	—		—		—		—		117		86		—		—	—		—		117		86
Intersegment revenues	93		81		16		5		—		—		—		—	(109	)	(86	)	—		—
Interest	—		—		—		—		—		—		—		—	—		1		—		1
	908		634		148		125		881		710		372		—	(108	)	(84	)	2 201		1 385
Expenses
Purchases of crude oil and products	30		2		—		—		573		419		282		—	(108	)	(80	)	777		341
Operating, selling and general	250		209		19		18		96		82		38		—	42		26		445		335
Energy marketing and trading activities	—		—		—		—		110		87		—		—	—		—		110		87
Transportation and other costs	19		30		6		6		—		—		4		—	—		—		29		36
Depreciation, depletion and amortization	126		108		29		21		16		14		4		—	2		1		177		144
Accretion of asset retirement obligations	5		5		1		1		1		—		—		—	—		—		7		6
Exploration	2		—		3		16		—		—		—		—	—		—		5		16
Royalties	105		5		32		33		—		—		—		—	—		—		137		38
Taxes other than income taxes	7		6		2		1		87		84		27		—	—		—		123		91
(Gain) loss on disposal of assets	3		—		(2	)	—		—		(1	)	—		—	—		—		1		(1	)
Project start-up costs	—		3		—		—		—		—		—		—	—		—		—		3
Financing expenses (income)	—		—		—		—		—		—		—		—	53		(31	)	53		(31	)
	547		368		90		96		883		685		355		—	(11	)	(84	)	1 864		1 065
Earnings (loss) before income taxes	361		266		58		29		(2	)	25		17		—	(97	)	—		337		320
Income taxes	(129	)	(196	)	(23	)	(1	)	(1	)	(8	)	(5	)	—	24		1		(134	)	(204	)
Net earnings (loss)	232		70		35		28		(3	)	17		12		—	(73	)	1		203		116

	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)	232		70		35		28		(3	)	17		12		—	(73	)	1		203		116
Exploration expenses
Cash	—		—		3		1		—		—		—		—	—		—		3		1
Dry hole costs	—		—		—		15		—		—		—		—	—		—		—		15
Non-cash items included in earnings
Depreciation, depletion and amortization	126		108		29		21		16		14		4		—	2		1		177		144
Future income taxes	126		192		19		1		4		(4	)	7		—	(26	)	(6	)	130		183
Current income tax provision allocated to Corporate	3		4		4		—		(3	)	12		(2	)	—	(2	)	(16	)	—		—
(Gain) loss on disposal of assets	3		—		(2	)	—		—		(1	)	—		—	—		—		1		(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	5		3		5		3
Other	3		(1	)	4		1		1		3		(1	)	—	31		(55	)	38		(52	)
Overburden removal outlays	(58	)	(53	)	—		—		—		—		—		—	—		—		(58	)	(53	)
Increase (decrease) in deferred credits and other	(14	)	1		(2	)	(1	)	8		—		1		—	(2	)	2		(9	)	2
Total cash flow from (used in) operations	421		321		90		66		23		41		21		—	(65	)	(70	)	490		358
Decrease (increase) in operating working capital	(3	)	66		(24	)	12		(23	)	(14	)	(20	)	—	45		32		(25	)	96
Total cash flow from (used in) operating activities	418		387		66		78		—		27		1		—	(20	)	(38	)	465		454
Cash from (used in) investing activities:
Capital and exploration expenditures	(246	)	(188	)	(37	)	(37	)	(40	)	(25	)	(27	)	—	(11	)	(8	)	(361	)	(258	)
Deferred maintenance shutdown expenditures	—		(83	)	—		—		(24	)	(2	)	(6	)	—	—		—		(30	)	(85	)
Deferred outlays and other investments	(1	)	(9	)	—		—		(8	)	(1	)	—		—	8		(1	)	(1	)	(11	)
Proceeds from disposals	40		—		3		—		2		1		—		—	—		—		45		1
Total cash (used in) investing activities	(207	)	(280	)	(34	)	(37	)	(70	)	(27	)	(33	)	—	(3	)	(9	)	(347	)	(353	)
Net cash surplus (deficiency) before financing activities	211		107		32		41		(70	)	—		(32	)	—	(23	)	(47	)	118		101

Schedules of Segmented Data

(unaudited)

Six months ended June 30

	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	1 481		1 310		223		256		1 442		1 382		661		—	1		1		3 808		2 949
Energy marketing and trading activities	—		—		—		—		195		135		—		—	(8	)	—		187		135
Intersegment revenues	192		189		58		12		—		—		—		—	(250	)	(201	)	—		—
Interest	—		—		—		—		—		—		—		—	1		1		1		1
	1 673		1 499		281		268		1 637		1 517		661		—	(256	)	(199	)	3 996		3 085
Expenses
Purchases of crude oil and products	42		4		—		—		1 011		946		506		—	(251	)	(198	)	1 308		752
Operating, selling and general	464		434		39		37		192		182		71		—	79		43		845		696
Energy marketing and trading activities	—		—		—		—		185		137		—		—	(8	)	—		177		137
Transportation and other costs	36		58		11		12		1		—		8		—	—		—		56		70
Depreciation, depletion and amortization	250		228		57		42		33		29		7		—	4		2		351		301
Accretion of asset retirement obligations	10		10		2		2		1		—		—		—	—		—		13		12
Exploration	15		9		23		24		—		—		—		—	—		—		38		33
Royalties	167		15		61		65		—		—		—		—	—		—		228		80
Taxes other than income taxes	14		12		2		1		170		167		56		—	—		—		242		180
(Gain) loss on disposal of assets	3		—		(3	)	—		—		(2	)	—		—	—		—		—		(2	)
Project start-up costs	22		5		—		—		—		—		—		—	—		—		22		5
Financing expenses (income)	—		—		—		—		—		—		—		—	97		(53	)	97		(53	)
	1 023		775		192		183		1 593		1 459		648		—	(79	)	(206	)	3 377		2 211
Earnings (loss) before income taxes	650		724		89		85		44		58		13		—	(177	)	7		619		874
Income taxes	(180	)	(349	)	(32	)	(30	)	(17	)	(20	)	(4	)	—	44		7		(189	)	(392	)
Net earnings (loss)	470		375		57		55		27		38		9		—	(133	)	14		430		482

As at June 30
TOTAL ASSETS	8 608		7 582		847		770		1 217		1 002		504		—	83		64		11 259		9 418
CAPITAL EMPLOYED (1)	4 525		4 160		421		394		587		488		345		—	166		157		6 044		5 199

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

	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)	470		375		57		55		27		38		9		—	(133	)	14		430		482
Exploration expenses
Cash	—		—		11		5		—		—		—		—	—		—		11		5
Dry hole costs	—		—		12		19		—		—		—		—	—		—		12		19
Non-cash items included in earnings
Depreciation, depletion and amortization	250		228		57		42		33		29		7		—	4		2		351		301
Future income taxes	173		342		28		29		—		(7	)	6		—	(42	)	(14	)	165		350
Current income tax provision allocated to Corporate	7		7		4		1		17		27		(2	)	—	(26	)	(35	)	—		—
(Gain) loss on disposal of assets	3		—		(3	)	—		—		(2	)	—		—	—		—		—		(2	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	9		3		9		3
Other	(8	)	3		8		3		(7	)	5		(8	)	—	44		(108	)	29		(97	)
Overburden removal outlays	(112	)	(97	)	—		—		—		—		—		—	—		—		(112	)	(97	)
Increase (decrease) in deferred credits and other	3		4		(1	)	—		9		—		3		—	3		3		17		7
Total cash flow from (used in) operations	786		862		173		154		79		90		15		—	(141	)	(135	)	912		971
Decrease (increase) in operating working capital	7		91		(37	)	3		9		4		(44	)	—	(6	)	(16	)	(71	)	82
Total cash flow from (used in) operating activities	793		953		136		157		88		94		(29	)	—	(147	)	(151	)	841		1 053
Cash from (used in) investing activities:
Capital and exploration expenditures	(473	)	(429	)	(107	)	(76	)	(65	)	(38	)	(45	)	—	(17	)	(10	)	(707	)	(553	)
Deferred maintenance shutdown expenditures	—		(92	)	—		—		(25	)	(2	)	(6	)	—	—		—		(31	)	(94	)
Deferred outlays and other investments	(3	)	(9	)	—		—		(12	)	(1	)	—		—	8		(1	)	(7	)	(11	)
Proceeds from disposals	40		—		7		2		2		2		—		—	—		—		49		4
Total cash (used in) investing activities	(436	)	(530	)	(100	)	(74	)	(100	)	(39	)	(51	)	—	(9	)	(11	)	(696	)	(654	)
Net cash surplus (deficiency) before financing activities	357		423		36		83		(12	)	55		(80	)	—	(156	)	(162	)	145		399

• 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 June 30, 2004 and the results of its operations and cash flows for the three and six month periods ended June 30, 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 June 30
($ millions, increase/(decrease))	2004		2003
Property, plant and equipment	207		215
Future income tax assets	104		112
Total assets	311		327

Accrued liabilities and other	310		321
Future income tax liabilities	70		74
Retained earnings	(69	)	(68	)
Total liabilities and shareholders’ equity	311		327

CHANGE IN CONSOLIDATED STATEMENTS OF EARNINGS

	Second quarter				Six months ended June 30
($ millions, increase/(decrease))	2004		2003		2004		2003
Depreciation, depletion and amortization	2		1		4		3
Accretion of asset retirement obligations	7		6		13		12
Operating, selling and general expenses	(11	)	(6	)	(21	)	(11	)
Future income taxes	2		4		3		3
Net earnings	—		(5	)	1		(7	)
Per common share – basic (dollars)	—		(0.02	)	—		(0.02	)
Per common share – diluted (dollars)	—		(0.02	)	—		(0.02	)

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 June 30
($ millions)	2004		2003
Asset retirement obligations, beginning of year	401		400
Liabilities incurred	—		—
Liabilities settled	(11	)	(11	)
Accretion of asset retirement obligations	13		12
Asset retirement obligations, end of period	403		401

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.

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.

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 quarter ended June 30, 2004, a net pretax gain of $4 million (2003 – pretax loss of $1 million) from the settlement and revaluation of financial contracts was reported as energy marketing and trading activities in the Consolidated Statements of Earnings. In the second quarter the settlement of physical trading activities also resulted in a net pretax gain of $4 million (2003 – pretax gain of $1 million). For the six month period ended June 30, 2004, a pretax gain of $6 million was recorded on financial contracts (2003 – pretax loss of $3 million). Year-to-date settlement of physical trading activities resulted in a net pretax gain of $5 million (2003 – pretax gain of $2 million). The fair value of unsettled (unrealized) energy trading assets and liabilities are as follows:

	June 30	December 31
($ millions)	2004	2003
Energy trading assets	14	5
Energy trading liabilities	5	5

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

4. FINANCING EXPENSES (INCOME)

	Second quarter				Six months ended June 30
($ millions)	2004		2003		2004		2003
Interest on debt	36		32		76		68
Capitalized interest	(12	)	(13	)	(22	)	(23	)
Net interest expense	24		19		54		45
Foreign exchange (gain) loss on long-term debt	30		(57	)	48		(112	)
Other foreign exchange (gain) loss	(1	)	7		(5	)	14
Total financing expenses (income)	53		(31	)	97		(53	)

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Second quarter				Six months ended June 30
($ millions)	2004		2003		2004		2003
Net earnings attributable to common shareholders	203		125		418		498
Dividends on preferred securities, net of tax	—	(a)	6		—	(a)	13
Revaluation of US$ preferred securities, net of tax	—	(a)	(15	)	—	(a)	(29	)
Adjusted net earnings attributable to common shareholders	203		116		418		482

(millions of common shares)
Weighted-average number of common shares	453		449		452		449
Dilutive securities:
Options issued under stock-based compensation plans	7		5		10		5
Redemption of preferred securities by the issuance of common shares	—	(a)	20		—	(a)	22
Weighted-average number of diluted common shares	460		474		462		476

(dollars per common share)
Basic earnings per share (b)	0.44		0.27		0.92		1.10
Diluted earnings per share (c)	0.43		0.24		0.90		1.01

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 six months ended June 30, 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. The company redeemed its preferred securities in the first quarter of 2004 and accordingly, no revaluations or dividends were recorded in the second quarter of 2004.

(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 and directors that hold options must earn the right to exercise them. This is done by the employee or director fulfilling a time requirement for service to the company, and with respect to certain options, is subject to accelerated vesting should the company meet predetermined performance criteria. Once this right has been earned, these options are considered vested.

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

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

(a) Stock Option Plans

Under the SunShare long-term incentive plan, the company granted 386,000 options in the second quarter of 2004, for a total of 1,196,000 options granted in the six months ended June 30, 2004 (343,000 options granted during the second quarter of 2003; 596,000 granted in the six months ended June 30, 2003).

Under the company’s other plans, 58,000 options were granted in the second quarter of 2004, for a total of 1,284,000 options granted in the six months ended June 30, 2004 (122,000 options granted during the second quarter of 2003; 1,843,000 granted in the six months ended June 30, 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:

	Second quarter						Six months ended June 30
	2004			2003			2004			2003
Quarterly dividend per share	$	0.06		$	0.05		$	0.06	*	$	0.05	*
Risk-free interest rate	3.73		%	4.58		%	3.73		%	4.41		%
Expected life	6 years			7 years			6 years			6 years
Expected volatility	29		%	33		%	29		%	33		%
Weighted-average fair value per option	$	11.82		$	9.86		$	11.77		$	10.05

* In 2004, quarterly dividends of $0.05 and $0.06 per share were paid in the first and second quarter, respectively. In 2003, quarterly dividends of $0.0425 and $0.05 per common share were declared and paid in the first and second quarter, respectively.

Stock-based compensation expense recognized in the second quarter of 2004 related to stock option plans was $5 million (2003 – $3 million). For the six months ended June 30, 2004 stock-based compensation expense recognized was $9 million (2003 – $3 million).

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

	Second quarter		Six months ended June 30
($ millions, except per share amounts)	2004	2003	2004	2003
Net earnings attributable to common shareholders – as reported	203	125	418	498
Less: compensation cost under the fair value method for pre-2003 options	6	5	21	19
Pro forma net earnings attributable to common shareholders for pre-2003 options	197	120	397	479
Basic earnings per share
As reported	0.44	0.27	0.92	1.10
Pro forma	0.43	0.26	0.88	1.06
Diluted earnings per share
As reported	0.43	0.24	0.90	1.01
Pro forma	0.42	0.23	0.86	0.97

(b) Performance Share Units (PSUs)

As a means of providing better alignment between employee incentive plans and shareholder interests, in the second quarter of 2004 the company issued 2,000 PSUs under a new employee incentive compensation plan (353,000 PSUs issued for the six months ended June 30, 2004). 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. Pretax expense recognized for PSUs in the second quarter of 2004 was $1 million ($2 million for the six months ended June 30, 2004).

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 six months ended June 30.

	Pension Benefits
	Second quarter				Six months ended June 30
	2004		2003		2004		2003
Current service costs	6		4		12		9
Interest costs	9		8		17		16
Expected return on plan assets	(6	)	(5	)	(12	)	(10	)
Amortization of net actuarial loss	4		6		9		11
Net periodic benefit cost	13		13		26		26

	Other Post-retirement Benefits
	Second quarter		Six months ended June 30
	2004	2003	2004	2003
Current service costs	2	—	3	1
Interest costs	1	1	3	3
Amortization of net actuarial loss	1	1	1	1
Net periodic benefit cost	4	2	7	5

8. SUPPLEMENTAL INFORMATION

	Second quarter		Six months ended June 30
($ millions)	2004	2003	2004	2003
Interest paid	23	9	78	71
Income taxes paid	12	10	32	35

STRATEGIC CRUDE OIL HEDGES AT JUNE 30, 2004

	Quantity	Average Price		Revenue Hedged		Hedge
	(bbl/day)	(US$/bbl)	(a)	(Cdn$ millions)	(b)	Period	(c)
Swaps	68 000	23.93		401		2004
Costless collars	11 000	21.00 – 23.65		57 – 64		2004
Swaps	36 000	22.77		401		2005

MARGIN HEDGES AT JUNE 30, 2004

	Quantity	Average Margin	Margin Hedged		Hedge
	(bbl/day)	(US$/bbl)	(Cdn$ millions)	(b)	Period
Refined product and crude swaps	14 000	6.92	24		2004	(d)

NATURAL GAS HEDGES AT JUNE 30, 2004

	Quantity	Average Price	Revenue Hedged	Hedge
	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period
Swaps	30 000	5.95	22	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 June 30, 2004 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

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

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

9. INCOME TAXES

During the first quarter of 2004 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. ROYALTY ESTIMATE MEASUREMENT UNCERTAINTY

Crown royalties in effect for each Oil Sands Project are based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of capital expenditures (the 25% R-C royalty) for each project, subject to a minimum payment of 1% of R. Firebag is being treated by the government of Alberta as a separate Project from the rest of the Oil Sands operations for royalty purposes. The 2004 calendar year is a transitional year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million would be claimed before the 25% R-C royalty applies to current year results.

Absolute royalties that may be payable in 2004 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates and total capital and operating costs for each Project. Oil Sands pretax Crown royalty estimate was $167 million ($108 million after-tax) for the first six months of 2004. The annualized estimate of $310 million ($202 million after-tax) was based on six months of actual results, together with 2004 forward crude oil pricing as at June 30, 2004, current forecasts of capital and operating costs for the remainder of 2004, and a US/Canadian foreign exchange rate of $0.75. Accordingly, actual results will differ, and these differences may be material.

13. 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 accounts receivable securitization program, as currently structured, does not meet the AcG 15 criteria for consolidation by Suncor.

The VIE involving the sale of crude oil inventory terminated on June 25, 2004, prior to the effective date of AcG 15. The crude oil inventory was purchased by the company at its fair value of $107 million, resulting in a permanent increase in inventory volumes of 2.1 million barrels.

Highlights

(unaudited)

	2004	2003
CASH FLOW FROM OPERATIONS (dollars per common share)

For the three months ended June 30
Cash flow from operations (1)	1.08	0.80
Dividends paid on preferred securities (pretax) (2)	—	0.03
Cash flow from operations after deducting dividends paid on preferred securities (3)	1.08	0.77

For the six months ended June 30
Cash flow from operations (1)	2.02	2.16
Dividends paid on preferred securities (pretax) (2)	0.02	0.05
Cash flow from operations after deducting dividends paid on preferred securities (3)	2.00	2.11

RATIOS

For the twelve months ended June 30
Return on capital employed (%) (4)	19.1	16.9
Return on capital employed (%) (5)	16.8	15.3

Net debt to cash flow from operations (times) (6)	1.2	1.2
Interest coverage on long-term debt (times)
Net earnings (7)	11.1	11.4
Cash flow from operations (8)	14.4	14.2

As at June 30
Debt to debt plus shareholders’ equity (%) (9)	37.6	36.4

COMMON SHARE INFORMATION

As at June 30
Share price at end of trading
Toronto Stock Exchange – Cdn$	34.01	25.34
New York Stock Exchange – US$	25.61	18.75
Common share options outstanding (thousands)	21 639	21 950

For the six months ended June 30
Average number outstanding, weighted monthly (thousands)	452 283	449 326

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 – $1,023 million; 2003 – $919 million) adjusted for after-tax financing expenses (2004 – expense of $53 million; 2003 – expense of $13 million) for the twelve month period ended; divided by average capital employed (2004 – $5,621 million; 2003 – $5,524 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 (capital employed including major projects in progress: 2004 – $760 million; 2003 – $815 million; 2002 – $298 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					Six months ended		Total year
	June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	June 30	Dec 31
	2004	2004	2003	2003	2003	2004	2003	2003
OIL SANDS
Production (a)
Base operations	210.8	213.9	235.2	231.5	188.2	212.4	199.6	216.6
Firebag	15.1	5.9	—	—	—	10.5	—	—
Total production	225.9	219.8	235.2	231.5	188.2	222.9	199.6	216.6
Sales (a)
Light sweet crude oil	118.7	112.2	132.7	109.0	86.4	115.4	103.5	112.3
Diesel	29.7	27.5	27.2	24.8	22.9	28.6	26.5	26.3
Light sour crude oil	68.9	74.3	81.3	77.5	73.9	71.6	67.1	73.3
Bitumen	14.5	—	8.3	16.1	1.2	7.3	0.6	6.4
Total sales	231.8	214.0	249.5	227.4	184.4	222.9	197.7	218.3
Average sales price (1), (b)
Light sweet crude oil	45.70	40.26	36.67	37.96	39.87	42.98	43.83	40.26
Other (diesel, light sour crude oil and bitumen)	38.28	35.85	30.72	32.92	32.94	37.16	36.60	33.93
Total	41.88	38.16	33.89	35.34	36.19	40.09	40.38	37.19
Total *	48.18	43.28	36.63	38.05	38.14	45.83	43.79	40.22

CASH OPERATING COSTS AND TOTAL OPERATING COSTS - BASE OPERATIONS
Cash costs	9.75	9.65	9.25	8.20	10.70	9.70	9.95	9.25
Natural gas	2.30	2.10	1.60	1.65	2.45	2.20	2.75	2.15
Imported bitumen	0.05	0.40	—	—	0.10	0.25	0.10	0.05
Cash operating costs (2),(c)	12.10	12.15	10.85	9.85	13.25	12.15	12.80	11.45
Firebag start-up costs	—	1.20	—	—	—	0.60	—	—
Total cash operating costs (3),(c)	12.10	13.35	10.85	9.85	13.25	12.75	12.80	11.45
Depreciation, depletion and amortization	6.15	6.20	5.40	5.30	6.30	6.20	6.30	5.80
Total operating costs (4),(c)	18.25	19.55	16.25	15.15	19.55	18.95	19.10	17.25

CASH OPERATING COSTS AND TOTAL OPERATING COSTS - FIREBAG
Cash costs	6.55
Natural gas	11.65
Cash operating costs (5),(c)	18.20
Depreciation, depletion and amortization	5.80
Total operating costs (6),(c)	24.00

(for the period ended)
Capital employed (i)	4 525	4 725	4 050	4 163	4 160

(for the twelve months ended)
Return on capital employed (j)	22.6	18.1	20.8	19.8	19.0
Return on capital employed (j) ****	19.2	16.0	17.4	17.2	16.9

		For the quarter ended					Six months ended		Total year
		June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	June 30	Dec 31
		2004	2004	2003	2003	2003	2004	2003	2003
NATURAL GAS
Gross production **
Natural gas (d)		209	197	194	194	175	203	180	187
Natural gas liquids (a)		2.2	2.2	2.4	2.5	2.1	2.2	2.3	2.3
Crude oil (a)		1.1	0.9	1.0	1.6	1.6	1.0	1.5	1.4
Total gross production (e)		38.1	35.9	35.7	36.4	32.8	37.0	33.8	34.9
Average sales price (1)
Natural gas (f)		6.77	6.54	5.53	6.07	6.63	6.66	7.09	6.42
Natural gas (f) *		6.84	6.59	5.51	6.04	6.65	6.72	7.13	6.42
Natural gas liquids (b)		43.53	38.13	35.45	33.50	33.45	40.85	37.85	36.08
Crude oil – Conventional (b)		47.08	44.14	36.91	38.31	37.82	45.71	42.45	40.29
Net wells drilled
Conventional	– Exploratory ***	3	4	5	1	24	7	27	33
	– Development	—	8	6	9	1	8	6	21
		3	12	11	10	25	15	33	54

(for the period ended)
Capital employed (i)		421	418	400	373	394

(for the twelve months ended)
Return on capital employed (j)		29.9	27.7	29.2	24.4	17.3

ENERGY MARKETING AND REFINING – CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail		4.5	4.2	4.4	4.3	4.5	4.4	4.4	4.4
Other		4.1	4.0	3.9	4.5	4.1	4.0	4.1	4.2
Jet fuel		0.7	1.0	0.7	0.8	0.7	0.9	0.7	0.7
Diesel		3.1	2.9	3.1	2.8	3.0	3.0	3.0	3.0
Total transportation fuel sales		12.4	12.1	12.1	12.4	12.3	12.3	12.2	12.3
Petrochemicals		0.6	0.9	0.7	0.6	0.9	0.7	0.9	0.8
Heating oils		0.3	0.8	0.5	0.2	0.3	0.5	0.6	0.5
Heavy fuel oils		0.7	0.8	0.5	1.4	0.6	0.8	0.7	0.8
Other		1.5	0.6	0.4	0.6	0.8	1.1	0.9	0.6
Total refined product sales		15.5	15.2	14.2	15.2	14.9	15.4	15.3	15.0

Margins (h)
Refining (7)		7.4	7.8	7.0	6.5	4.7	7.7	6.2	6.5
Refining (7) *		8.0	7.8	6.9	6.4	4.2	8.0	6.1	6.4
Retail (8)		4.3	5.0	6.3	7.0	6.2	4.6	6.6	6.6

Crude oil supply and refining
Processed at Sarnia refinery (g)		9.5	12.0	9.6	10.1	11.1	10.7	11.3	10.5
Utilization of refining capacity (j)		85	108	86	91	100	97	101	95

(for the period ended)
Capital employed (i)		587	567	551	523	488

(for the twelve months ended)
Return on capital employed (j)		7.8	11.8	10.3	11.0	13.1

	For the quarter ended				Six months ended		Total year
	June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	Dec 31
	2004	2004	2003	2003	2004	2003	2003
REFINING AND MARKETING – U.S.A. *****
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.6	0.7	0.7	0.7	0.7	—	0.7
Other	3.6	3.4	3.4	3.5	3.5	—	3.5
Jet fuel	0.5	0.4	0.5	0.6	0.4	—	0.5
Diesel	1.9	2.2	2.3	2.3	2.0	—	2.3
Total transportation fuel sales	6.6	6.7	6.9	7.1	6.6	—	7.0
Asphalt	1.8	1.2	1.4	2.1	1.5	—	1.7
Other	0.5	0.2	0.3	0.6	0.4	—	0.4
Total refined product sales	8.9	8.1	8.6	9.8	8.5	—	9.1

Margins (h)
Refining (7)	9.0	5.0	4.6	7.9	7.1	—	5.9
Refining (7) *	9.3	5.0	4.6	7.9	7.3	—	5.9
Retail (8)	6.2	5.0	4.8	6.4	5.6	—	5.6

Crude oil supply and refining
Processed at Denver refinery (g)	8.2	8.1	9.2	9.6	8.1	—	9.4
Utilization of refining capacity (j)	86	85	96	101	85	—	98

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

(3) Total cash operating costs – Base operations	–	Include cash operating costs – mining as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on mining production volumes.

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

(5) Cash operating costs – Firebag	–	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes.

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

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

(8) 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

(b) dollars per barrel

(d) millions of cubic feet per day

(e) thousands of barrels of oil equivalent per day

(f) dollars per thousand cubic feet

(g) thousands of cubic metres per day

(h) cents per litre

(i) $ millions

(j) percentage

Metric conversion

Crude oil, refined products, etc.

1m³(cubic metre) = approx. 6.29 barrels