EXHIBIT 3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the third fiscal

quarter ended September 30, 2003

EXHIBIT 3

CONSOLIDATED STATEMENTS OF EARNINGS

(unaudited)

	Third quarter				Nine months ended Sept 30
($ millions)	2003		2002		2003		2002

REVENUES (note 8)	1 700		1 257		4 668		3 623
EXPENSES
Purchases of crude oil and products	484		238		1 188		908
Energy marketing and trading activities	49		39		117		76
Transportation and other costs (note 8)	27		34		97		91
Operating, selling and general (note 6)	347		307		1 054		957
Depreciation, depletion and amortization	154		153		452		423
Exploration	8		7		41		15
Royalties	32		24		112		70
Taxes other than income taxes	124		94		304		275
(Gain) on disposal of assets	(2	)	—		(4	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		(37	)
Project start-up costs	7		2		12		2
Financing expenses (note 4)	7		68		(46	)	96
	1 237		966		3 327		2 875
EARNINGS BEFORE INCOME TAXES	463		291		1 341		748
PROVISION FOR INCOME TAXES (note 9)
Current	—		15		42		35
Future	168		92		515		210
	168		107		557		245
NET EARNINGS	295		184		784		503
Dividends on preferred securities, net of tax	(7	)	(7	)	(20	)	(21	)
Revaluation of US$ preferred securities, net of tax	1		(8	)	30		1
Net earnings attributable to common shareholders	289		169		794		483

PER COMMON SHARE (dollars)

Net earnings attributable to common shareholders (note 5)

See accompanying notes.

CONSOLIDATED BALANCE SHEETS

(unaudited)

($ millions)	September 30 2003	December 31 2002

ASSETS
Current assets
Cash and cash equivalents	62	15
Accounts receivable	492	403
Inventories	355	266
Future income taxes	30	38
Total current assets	939	722
Property, plant and equipment, net	8 391	7 641
Deferred charges and other	283	185
Future income taxes	147	135
Total assets	9 760	8 683
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	7	—
Accounts payable and accrued liabilities	795	716
Income taxes payable	23	34
Taxes other than income taxes	56	37
Future income taxes	9	10
Total current liabilities	890	797
Long-term debt (note 11)	2 358	2 686
Accrued liabilities and other	311	226
Future income taxes (note 9)	2 044	1 516
Shareholders’ equity (see below)	4 157	3 458
Total liabilities and shareholders’ equity	9 760	8 683

SHAREHOLDERS’ EQUITY

	Number			Number
Preferred securities	17 540 000	485		17 540 000	523
Share capital	449 972 694	592		448 971 543	578
Contributed surplus (note 6)		5			—
Cumulative foreign currency translation (note 2)		(12	)		—
Retained earnings		3 087			2 357
		4 157			3 458

See accompanying notes.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Third quarter				Nine months ended Sept 30
($ millions)	2003		2002		2003		2002

OPERATING ACTIVITIES
Cash flow from operations	584		447		1 555		980
Decrease (increase) in operating working capital (net of effects of Denver refinery and related assets)
Accounts receivable	(123	)	13		(88	)	(54	)
Inventories	31		(45	)	(2	)	(8	)
Accounts payable and accrued liabilities	(14	)	(5	)	76		(140	)
Taxes payable	32		32		22		43
Cash flow from operating activities	510		442		1 563		821
CASH USED IN INVESTING ACTIVITIES	(583	)	(202	)	(1 237	)	(563	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	(73	)	240		326		258
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	6		(5	)	7		(31	)
Proceeds from issuance of long-term debt	—		—		—		797
Net increase (decrease) in other long-term debt	159		(216	)	(200	)	(950	)
Issuance of common shares under stock option plan	4		5		10		16
Dividends paid on preferred securities	(11	)	(12	)	(34	)	(36	)
Dividends paid on common shares	(21	)	(18	)	(60	)	(54	)
Cash from (used in) financing activities	137		(246	)	(277	)	(258	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	64		(6	)	49		—
EFFECT OF FOREIGN EXCHANGE ON CASH AND CASH EQUIVALENTS	(2	)	—		(2	)	—
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	—		7		15		1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	62		1		62		1

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, 2001	525		555	—	—		1 700
Net earnings	—		—	—	—		503
Dividends paid on preferred securities, net of tax	—		—	—	—		(21	)
Dividends paid on common shares	—		—	—	—		(54	)
Issued for cash under stock option plan	—		16	—	—		—
Issued under dividend reinvestment plan	—		4	—	—		(4	)
Revaluation of US$ preferred securities	(1	)	—	—	—		1
At September 30, 2002	524		575	—	—		2 125
At December 31, 2002	523		578	—	—		2 357
Net earnings	—		—	—	—		784
Dividends paid on preferred securities, net of tax	—		—	—	—		(20	)
Dividends paid on common shares	—		—	—	—		(60	)
Issued for cash under stock option plan	—		10	—	—		—
Issued under dividend reinvestment plan	—		4	—	—		(4	)
Stock-based compensation expense	—		—	5	—		—
Foreign currency translation adjustment	—		—	—	(12	)	—
Revaluation of US$ preferred securities	(38	)	—	—	—		30
At September 30, 2003	485		592	5	(12	)	3 087

See accompanying notes.

SCHEDULES OF SEGMENTED DATA

(unaudited)


																Third quarter
	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2003		2002		2003		2002		2003		2002		2003		2002	2003		2002		2003		2002

EARNINGS
Revenues
Operating revenues	681		571		127		68		613		578		228		—	1		—		1 650		1 217
Energy marketing and trading activities	—		—		—		—		50		40		—		—	—		—		50		40
Intersegment revenues	75		132		2		10		—		—		—		—	(77	)	(142	)	—		—
	756		703		129		78		663		618		228		—	(76	)	(142	)	1 700		1 257
Expenses
Purchases of crude oil and products	8		—		—		2		404		376		152		—	(80	)	(140	)	484		238
Energy marketing and trading activities	—		—		—		—		49		39		—		—	—		—		49		39
Transportation and other costs	19		28		7		6		1		—		—		—	—		—		27		34
Operating, selling and general	192		187		18		19		92		84		20		—	25		17		347		307
Depreciation, depletion and amortization	111		119		25		18		15		16		2		—	1		—		154		153
Exploration	1		—		7		7		—		—		—		—	—		—		8		7
Royalties	9		8		23		16		—		—		—		—	—		—		32		24
Taxes other than income taxes	6		6		1		—		90		87		27		—	—		1		124		94
(Gain) on disposal of assets	—		—		—		—		(2	)	—		—		—	—		—		(2	)	—
Project start-up costs	3		2		—		—		—		—		4		—	—		—		7		2
Financing expenses	—		—		—		—		—		—		—		—	7		68		7		68
	349		350		81		68		649		602		205		—	(47	)	(54	)	1 237		966
Earnings (loss) before income taxes	407		353		48		10		14		16		23		—	(29	)	(88	)	463		291
Income taxes	(146	)	(120	)	(21	)	(9	)	(4	)	(6	)	(9	)	—	12		28		(168	)	(107	)
Net earnings (loss)	261		233		27		1		10		10		14		—	(17	)	(60	)	295		184

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

																Third quarter
									Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations
	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2003		2002		2003		2002		2003		2002		2003		2002	2003		2002		2003		2002

CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	261		233		27		1		10		10		14		—	(17	)	(60	)	295		184
Exploration expenses
Cash	—		—		2		2		—		—		—		—	—		—		2		2
Dry hole costs	—		—		5		5		—		—		—		—	—		—		5		5
Non-cash items included in earnings
Depreciation, depletion and amortization	111		119		25		18		15		16		2		—	1		—		154		153
Future income taxes	144		115		20		8		11		(1	)	5		—	(12	)	(30	)	168		92
Current income tax provision allocated to Corporate	2		4		1		1		(7	)	6		4		—	—		(11	)	—		—
(Gain) on disposal of assets	—		—		—		—		(2	)	—		—		—	—		—		(2	)	—
Stock-based compensation expense	—		—		—		—		—		—		—		—	2		—		2		—
Other	3		6		—		1		1		3		—		—	(9	)	37		(5	)	47
Overburden removal outlays	(35	)	(33	)	—		—		—		—		—		—	—		—		(35	)	(33	)
Increase (decrease) in deferred credits and other	2		(1	)	—		—		(1	)	1		—		—	(1	)	(3	)	—		(3	)
Total cash flow from (used in) operations	488		443		80		36		27		35		25		—	(36	)	(67	)	584		447
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets)	(87	)	(29	)	15		2		(2	)	3		44		—	(44	)	19		(74	)	(5	)
Total cash flow from (used in) operating activities	401		414		95		38		25		38		69		—	(80	)	(48	)	510		442
Cash from (used in) investing activities:
Capital and exploration expenditures	(212	)	(150	)	(49	)	(32	)	(31	)	(15	)	(8	)	—	(5	)	(2	)	(305	)	(199	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		(272	)	—	—		—		(272	)	—
Deferred maintenance shutdown expenditures	(8	)	—		—		—		(3	)	(2	)	—		—	—		—		(11	)	(2	)
Deferred outlays and other investments	—		(1	)	—		—		1		2		—		—	(1	)	(2	)	—		(1	)
Proceeds from disposals	—		—		3		—		2		—		—		—	—		—		5		—
Total cash (used in) investing activities	(220	)	(151	)	(46	)	(32	)	(31	)	(15	)	(280	)	—	(6	)	(4	)	(583	)	(202	)
Net cash surplus (deficiency) before financing activities	181		263		49		6		(6	)	23		(211	)	—	(86	)	(52	)	(73	)	240

SCHEDULES OF SEGMENTED DATA

(unaudited)

																Nine months ended September 30
									Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.
	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2003		2002		2003		2002		2003		2002		2003		2002	2003		2002		2003		2002

EARNINGS
Revenues
Operating revenues	1 991		1 595		383		212		1 947		1 735		228		—	2		1		4 551		3 543
Energy marketing and trading activities	—		—		—		—		116		79		—		—	—		—		116		79
Intersegment revenues	264		247		14		28		—		—		—		—	(278	)	(275	)	—		—
Interest	—		—		—		—		—		—		—		—	1		1		1		1
	2 255		1 842		397		240		2 063		1 814		228		—	(275	)	(273	)	4 668		3 623
Expenses
Purchases of crude oil and products	12		—		—		16		1 302		1 173		152		—	(278	)	(281	)	1 188		908
Energy marketing and trading activities	—		—		—		—		117		76		—		—	—		—		117		76
Transportation and other costs	77		73		19		18		1		—		—		—	—		—		97		91
Operating, selling and general	636		595		56		52		274		253		20		—	68		57		1 054		957
Depreciation, depletion and amortization	336		323		67		55		44		44		2		—	3		1		452		423
Exploration	10		—		31		15		—		—		—		—	—		—		41		15
Royalties	24		25		88		45		—		—		—		—	—		—		112		70
Taxes other than income taxes	18		17		2		1		257		256		27		—	—		1		304		275
(Gain) on disposal of assets	—		—		—		(1	)	(4	)	—		—		—	—		—		(4	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		(37	)	—		—	—		—		—		(37	)
Project start-up costs	8		2		—		—		—		—		4		—	—		—		12		2
Financing expenses	—		—		—		—		—		—		—		—	(46	)	96		(46	)	96
	1 121		1 035		263		201		1 991		1 765		205		—	(253	)	(126	)	3 327		2 875
Earnings (loss) before income taxes	1 134		807		134		39		72		49		23		—	(22	)	(147	)	1 341		748
Income taxes	(500	)	(262	)	(42	)	(21	)	(25	)	(5	)	(9	)	—	19		43		(557	)	(245	)
Net earnings (loss)	634		545		92		18		47		44		14		—	(3	)	(104	)	784		503

As at September 30
TOTAL ASSETS	7 471		6 780		755		733		1 019		905		480		—	35		14		9 760		8 432
CAPITAL EMPLOYED (1)	4 191		4 720		411		467		529		503		290		—	149		118		5 570		5 808

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

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

																Nine months ended September 30
									Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.
	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2003		2002		2003		2002		2003		2002		2003		2002	2003		2002		2003		2002

CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	634		545		92		18		47		44		14		—	(3	)	(104	)	784		503
Exploration expenses
Cash	—		—		7		4		—		—		—		—	—		—		7		4
Dry hole costs	—		—		24		11		—		—		—		—	—		—		24		11
Non-cash items included in earnings
Depreciation, depletion and amortization	336		323		67		55		44		44		2		—	3		1		452		423
Future income taxes	491		256		40		19		5		(9	)	5		—	(26	)	(56	)	515		210
Current income tax provision allocated to Corporate	9		6		2		2		20		14		4		—	(35	)	(22	)	—		—
(Gain) on disposal of assets	—		—		—		(1	)	(4	)	—		—		—	—		—		(4	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		(37	)	—		—	—		—		—		(37	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	5		—		5		—
Other	6		15		2		3		6		7		—		—	(117	)	1		(103	)	26
Overburden removal outlays	(132	)	(118	)	—		—		—		—		—		—	—		—		(132	)	(118	)
Increase (decrease) in deferred credits and other	6		(5	)	—		—		(1	)	—		—		—	2		(36	)	7		(41	)
Total cash flow from (used in) operations	1 350		1 022		234		111		117		63		25		—	(171	)	(216	)	1 555		980
Decrease (increase) in operating working capital (net of effects of acquisition of Denver refinery and related assets)	4		(177	)	18		8		2		(33	)	44		—	(60	)	43		8		(159	)
Total cash flow from (used in) operating activities	1 354		845		252		119		119		30		69		—	(231	)	(173	)	1 563		821
Cash from (used in) investing activities:
Capital and exploration expenditures	(641	)	(416	)	(125	)	(129	)	(69	)	(29	)	(8	)	—	(15	)	(6	)	(858	)	(580	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		(272	)	—	—		—		(272	)	—
Deferred maintenance shutdown expenditures	(100	)	(5	)	—		—		(5	)	(18	)	—		—	—		—		(105	)	(23	)
Deferred outlays and other investments	(9	)	(4	)	—		—		—		(17	)	—		—	(2	)	(1	)	(11	)	(22	)
Proceeds from disposals	—		—		5		1		4		61		—		—	—		—		9		62
Total cash (used in) investing activities	(750	)	(425	)	(120	)	(128	)	(70	)	(3	)	(280	)	—	(17	)	(7	)	(1 237	)	(563	)
Net cash surplus (deficiency) before financing activities	604		420		132		(9	)	49		27		(211	)	—	(248	)	(180	)	326		258

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 6, Stock-based Compensation.

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 September 30, 2003 and the results of its operations and cash flows for the three and nine month periods ended September 30, 2003 and 2002. The results of operations and cash flows are not necessarily indicative of the results of operations or cash flows to be expected for the year ending December 31, 2003.

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 and other 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 and the estimated 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 preliminary costs of environmental clean-up work currently underway. 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 ten 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 ten-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.

The company’s Denver-based 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 Statement of Shareholders’ Equity.

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. 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 nine month period ended September 30, 2003 a net pretax loss of $3 million (nil for the quarter ended September 30, 2003) from the settlement and revaluation of these contracts was reported as energy trading and marketing activities in the Statement of Earnings.

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

($ millions)	September 30 2003	December 31 2002

Energy trading assets	3	2
Energy trading liabilities	3	2

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

4. Financing Expenses

	Third quarter				Nine months ended Sept 30
($ millions)	2003		2002		2003		2002

Interest on debt	35		40		103		118
Capitalized interest	(15	)	(6	)	(38	)	(15	)
Net interest expense	20		34		65		103
Unrealized foreign exchange (gain) loss on long-term debt	(11	)	34		(123	)	(7	)
Other foreign exchange (gain) loss	(2	)	—		12		—
Total financing expenses	7		68		(46	)	96

5. Reconciliation of Basic and Diluted Earnings Per Common Share

	Third quarter				Nine months ended Sept 30
($ millions)	2003		2002		2003		2002

Net earnings attributable to common shareholders	289		169		794		483
Dividends on preferred securities, net of tax	7		—	(a)	20		21
Revaluation of US$ preferred securities, net of tax	(1	)	—	(a)	(30	)	(1	)
Adjusted net earnings attributable to common shareholders	295		169		784		503

(millions of common shares)
Weighted-average number of common shares	450		448		449		447
Dilutive securities:
Options issued under stock-based compensation plans	5		6		5		6
Redemption of preferred securities by the issuance of common shares	20		—	(a)	22		20

Weighted-average number of diluted common shares	475		454		476		473

(dollars per common share)
Basic earnings per share (b)	0.64		0.38		1.76		1.08
Diluted earnings per share	0.62	(c)	0.37	(a)	1.65	(c)	1.07	(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 third quarter of 2002, 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 stock 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 rights 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.

Under the SunShare long-term incentive plan, the company granted 490,375 options to new employees in the third quarter of 2003 for a total of 1,086,780 options granted in the nine months ended September 30, 2003 (276,890 options granted during the third quarter of 2002 and 8,675,730 granted for the nine months ended September 30, 2002).

Under the company’s other plans, 54,165 options were granted in the third quarter of 2003 for a total of 1,897,645 granted in the nine months ended September 30, 2003 (14,100 options granted during the third quarter of 2002 and 1,802,000 options granted for the nine months ended September 30, 2002).

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:

	Third quarter						Nine months ended Sept 30
	2003			2002			2003			2002

Quarterly dividend per share (a)	$	0.05		$	0.0425		$	0.05		$	0.0425
Risk-free interest rate	4.40		%	4.90		%	4.41		%	5.40		%
Expected life	8 years			8 years			7 years			8 years
Expected volatility	29		%	32		%	32		%	31		%
Weighted-average fair value per option	$	9.65		$	12.41		$	9.98		$	12.07

(a) In 2002, four quarterly dividends totalling $0.17 per common share ($0.0425 quarterly) were declared and paid. In 2003, quarterly dividends of $0.0425 per common share were declared and paid in the first quarter, and $0.05 in the second and third quarters.

Change in accounting policy

During the second quarter, the company adopted a new accounting policy for stock-based compensation related to common share options. Pursuant to new transitional rules recently approved by the Canadian Institute of Chartered Accountants, the company recorded stock-based compensation expense in the company’s Statement 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 Statement of Shareholders’ Equity. Compensation expense for options granted during 2003 is determined based on the fair values at the time of grant, the cost of which is recognized in the Statement of Earnings over the estimated vesting periods of the respective options. For common share options granted prior to January 1, 2003 (“pre-2003 options”), the company continues to disclose the pro forma earnings impact of related stock-based compensation expense. Pro forma compensation-related earnings impacts of pre-2003 options are determined in the same manner as 2003 options.

This change in accounting policy has increased operating, selling and general expenses by $2 million in the third quarter and $5 million for the nine months ended September 30, 2003. The disclosures relating to pro forma earnings impacts for these periods have been adjusted by a corresponding amount.

Pro forma disclosure

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:

	Third quarter		Nine months ended Sept 30
($ millions, except per share amounts)	2003	2002	2003	2002

Net earnings attributable to common shareholders – as reported	289	169	794	483
Less: compensation cost under the fair value method for pre-2003 options	5	5	24	26
Pro forma net earnings attributable to common shareholders for pre-2003 options	284	164	770	457
Basic earnings per share
As reported	0.64	0.38	1.76	1.08
Pro forma	0.63	0.37	1.71	1.02
Diluted earnings per share
As reported	0.62	0.37	1.65	1.07
Pro forma	0.61	0.36	1.60	1.01

7. Supplemental Information

	Third quarter			Nine months ended Sept 30
($ millions)	2003	2002		2003	2002

Interest paid	59	65		130	123
Income taxes paid (refunded)	4	(17	)	39	(4	)

Crude oil hedges at September 30, 2003

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

Swaps	22 000	27.45	75	2003	(c)
Swaps	15 000	24.46	46	2003
Costless collars	60 000	21.27 – 25.56	159 – 191	2003

Swaps	38 000	23.58	443	2004
Costless collars	11 000	21.00 – 23.65	114 – 129	2004
Swap/call (e)	30 000	24.36	361	2004

Swaps	36 000	22.77	404	2005

Margin hedges at September 30, 2003

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

	7 100	5.41	5	2003
	6 600	5.25	3	2004	(f)

Natural gas hedges at September 30, 2003

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

Swaps	10 000	6.43	2	2003
Costless collars	15 000	5.85 – 7.01	2 – 3	2003

(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 September 30, 2003 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(d) Original hedge term is for the full year unless otherwise noted.

(e) These hedging instruments provide for a minimum price of US$24.36 per barrel with the company realizing additional revenue when prices exceed US$29.67 per barrel.

(f) For the period January and February 2004, inclusive.

(g) For the period October 2003.

8. 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 Statement 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.

9. Income Taxes

During the second quarter, the Canadian government substantively enacted changes to federal taxation policies relating to the resource sector. The changes, to be phased in over the next five years, include a 7% reduction of the federal tax rate, deductibility of provincial Crown royalties and the elimination of the federal resource allowance deduction.

The province of Alberta has also substantively enacted a 0.5% reduction to its provincial corporate tax rates.

Accordingly, the company revalued its federal and provincial income tax liabilities and recognized an increase in future income tax expense totalling $86 million of which $78 million related to the revaluation of the opening future income tax balance.

10. Consolidation of Variable Interest Entities

In June 2003 the Canadian Institute of Chartered Accountants issued Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities (VIEs)”, commonly referred to as Special Purpose Entities or SPEs. 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. AcG 15 will be adopted without restatement of prior periods. The company will be required to consolidate the VIE related to the sale of equipment as described in note 9(c) on page 63 of the company’s 2002 Annual Report. The company does not expect a significant impact on net income upon consolidation of the VIE related to the sale of equipment. The impact on the balance sheet will be an increase to property, plant and equipment and an increase to long-term debt. 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.

11. Long-term Debt

During the third quarter, the company replaced its available credit and term loan facilities. At September 30, 2003 the company had available facilities 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

HIGHLIGHTS

(unaudited)

	2003	2002
CASH FLOW FROM OPERATIONS
(dollars per common share)
For the quarters ended September 30
Cash flow from operations (1)	1.30	1.00
Dividends paid on preferred securities (pretax) (2)	0.03	0.03
Cash flow from operations after deducting dividends paid on preferred securities (3)	1.27	0.97

For the nine months ended September 30
Cash flow from operations (1)	3.46	2.19
Dividends paid on preferred securities (pretax) (2)	0.08	0.08
Cash flow from operations after deducting dividends paid on preferred securities (3)	3.38	2.11

RATIOS

For the twelve months ended September 30
Return on capital employed (%) (4)	18.1	11.8
Return on capital employed (%) (5)	16.2	9.9

Net debt to cash flow from operations (times) (6)	1.1	2.7
Interest coverage on long-term debt (times)
Net earnings (7)	12.9	5.7
Cash flow from operations (8)	15.4	8.1

As at September 30
Debt to debt plus shareholders’ equity (%) (9)	34.5	47.9

COMMON SHARE INFORMATION

As at September 30
Share price at end of trading
Toronto Stock Exchange – Cdn$	24.93	27.31
New York Stock Exchange – US$	18.55	16.95

Common share options outstanding (thousands)	22 129	20 502

For the nine months ended September 30
Average number outstanding, weighted monthly (thousands)	449 474	447 465

(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 adjusted for after tax financing expenses for the twelve month period ended; divided by average capital employed. Average capital employed is the sum of shareholders’ equity and short-term and long-term debt, less capitalized costs related to major projects in progress (as applicable), at the beginning and end of the twelve month period ended, divided by two.

(5) 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.

(6) Long-term debt plus short-term debt less cash and short-term investments; divided by cash flow from operations for the twelve month period then ended.

(7) Net income 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) Long-term debt plus short-term debt; divided by the sum of long-term debt, short-term debt and shareholders’ equity.

QUARTERLY OPERATING SUMMARY

(unaudited)

	For the quarter ended					Nine months ended		Total year
	Sept 30 2003	Jun 30 2003	Mar 31 2003	Dec 31 2002	Sept 30 2002	Sept 30 2003	Sept 30 2002	Dec 31 2002
OIL SANDS
Production (a)	231.5	188.2	211.1	227.6	207.9	210.3	198.4	205.8
Sales (a)
Light sweet crude oil	109.0	86.4	120.7	116.7	114.1	105.3	100.6	104.7
Diesel	24.8	22.9	30.1	25.6	22.4	25.9	22.1	23.0
Light sour crude oil	77.5	73.9	60.4	73.9	54.8	70.7	66.4	68.3
Bitumen	16.1	1.2	—	12.2	15.4	5.8	8.3	9.3
Total sales	227.4	184.4	211.2	228.4	206.7	207.7	197.4	205.3
Average sales price (1) (b)
Light sweet crude oil	37.96	39.87	46.69	39.02	39.80	41.78	37.00	37.56
Other (diesel, light sour crude oil and bitumen)	32.92	32.94	40.62	31.04	30.86	35.17	29.01	29.58
Total	35.34	36.19	44.09	35.12	35.79	38.52	33.08	33.65
Total *	38.05	38.14	48.77	39.11	40.40	41.67	36.09	36.94

Cash operating costs and total operating costs
New definition:
Cash costs	8.20	10.70	9.20	8.30	9.35	9.30	10.00	9.50
Natural gas	1.65	2.40	3.10	1.75	1.05	2.35	1.50	1.55
Imported bitumen	—	0.10	0.10	0.15	—	0.05	—	0.05
Cash operating costs (2), (c)	9.85	13.20	12.40	10.20	10.40	11.70	11.50	11.10
Depreciation, depletion and amortization	5.20	6.25	6.20	6.05	6.25	5.85	5.95	6.00
Total operating costs (3), (c)	15.05	19.45	18.60	16.25	16.65	17.55	17.45	17.10

As previously defined:
Cash costs	8.10	10.70	9.35	8.55	9.15	9.30	9.85	9.45
Natural gas	1.65	2.50	3.10	1.75	1.05	2.35	1.50	1.60
Cash overburden spending	1.70	3.20	2.30	2.00	1.75	2.35	2.20	2.10
Imported bitumen	—	0.10	0.10	0.15	—	0.05	—	0.05
Project start-up costs	0.15	0.15	0.10	0.05	0.10	0.15	0.05	0.05
Cash operating costs (4), (c)	11.60	16.65	14.95	12.50	12.05	14.20	13.60	13.25
Depreciation, depletion and amortization (net of cash overburden spending)	3.65	3.25	3.90	4.05	4.50	3.60	3.80	3.90
Total operating costs (5), (c)	15.25	19.90	18.85	16.55	16.55	17.80	17.40	17.15

(for the period ended)
Capital employed (i)	4 191	4 186	4 395	4 540	4 720

(for the twelve months ended)
Return on capital employed (j)	19.8	18.9	21.2	16.8	14.6
Return on capital employed (j) ****	17.2	16.8	19.3	15.6	11.8

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

		For the quarter ended					Nine months ended		Total year
		Sept 30 2003	Jun 30 2003	Mar 31 2003	Dec 31 2002	Sept 30 2002	Sept 30 2003	Sept 30 2002	Dec 31 2002

NATURAL GAS
Gross production **
Natural gas (d)		194	175	184	182	181	184	178	179
Natural gas liquids (a)		2.5	2.1	2.4	2.4	2.3	2.3	2.4	2.4
Crude oil (a)		1.6	1.6	1.4	1.5	1.3	1.5	1.5	1.5
Total gross production (e)		36.4	32.8	34.5	34.2	33.8	34.5	33.6	33.7
Average sales price (1)
Natural gas (f)		6.07	6.63	7.54	4.91	3.56	6.73	3.57	3.91
Natural gas (f) *		6.04	6.65	7.59	4.91	3.56	6.74	3.57	3.91
Natural gas liquids (b)		33.50	33.45	41.65	35.14	31.66	36.29	27.42	29.35
Crude oil – conventional (b)		38.31	37.82	47.75	33.20	33.57	41.02	31.22	31.72
Net wells drilled
Conventional	– exploratory ***	1	24	3	4	3	28	17	21
	– development	9	1	5	6	2	15	16	22
		10	25	8	10	5	43	33	43

(for the period ended)
Capital employed (i)		411	431	434	449	467

(for the twelve months ended)
Return on capital employed (j)		25.1	18.6	14.6	9.2	7.7

ENERGY MARKETING AND REFINING – CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail		4.3	4.5	4.4	4.5	4.6	4.4	4.5	4.5
Other		3.4	4.1	4.2	5.0	4.3	3.9	4.2	4.4
Jet fuel		0.7	0.7	0.7	0.5	0.4	0.7	0.3	0.4
Diesel		2.1	3.0	3.0	3.2	2.8	2.7	2.8	2.9
Total transportation fuel sales		10.5	12.3	12.3	13.2	12.1	11.7	11.8	12.2
Petrochemicals		0.6	0.9	1.0	0.7	0.6	0.8	0.6	0.6
Heating oils		0.1	0.3	0.8	0.6	0.1	0.4	0.4	0.4
Heavy fuel oils		1.3	0.6	0.7	0.7	0.5	0.9	0.6	0.6
Other		0.6	0.8	0.9	0.6	0.8	0.8	0.8	0.7
Total refined product sales		13.1	14.9	15.7	15.8	14.1	14.6	14.2	14.5

Margins (h)
Refining (6)		6.5	4.7	7.5	6.6	4.4	6.3	4.2	4.8
Refining (6) *		6.4	4.2	7.8	6.6	4.4	6.2	4.2	4.8
Retail (7)		7.0	6.2	7.0	6.5	6.9	6.7	6.6	6.6

Crude oil supply and refining
Processed at Sarnia refinery (g)		10.1	11.1	11.5	12.0	11.1	10.9	10.1	10.6
Utilization of refining capacity (j)		91	100	103	108	100	98	91	95

(for the period ended)
Capital employed (i)		529	493	470	491	503

(for the twelve months ended)
Return on capital employed (j)		12.8	13.0	15.5	12.5	8.3

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

		For the quarter ended Sept 30 2003 *****
REFINING AND MARKETING – U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail		0.7
Other		3.5
Jet fuel		0.6
Diesel		2.3
Total transportation fuel sales		7.1
Asphalt		2.1
Other		0.6
Total refined product sales		9.8

Margins (h)
Refining (6)		7.9
Refining (6) *		7.9
Retail (7)		6.4

Crude oil supply and refining
Processed at Denver refinery (g)		9.6
Utilization of refining capacity (j)		101

QUARTERLY OPERATING SUMMARY (continued)

Definitions

(1) Average sales price	–	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.

(3) Total operating costs	–	Include cash operating costs as defined 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	–	Average wholesale unit price from all products less average unit cost of crude oil.

(7) Retail margin	–	Average street price of Sunoco and Phillips 66 branded 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.

*****		For the third quarter, Refining and Marketing – U.S.A. reflects the results of two months of operations since acquisition from August 1 to September 30, 2003.

(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