EXHIBIT 1

Interim Unaudited Financial Statements of Suncor Energy Inc. for the second fiscal quarter ended June 30, 2003

CONSOLIDATED STATEMENTS OF EARNINGS

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2003		2002		2003		2002
REVENUES (note 7)	1 292		1 289		2 968		2 366

EXPENSES
Purchases of crude oil and products	293		392		704		670
Energy marketing and trading activities	42		21		68		37
Transportation and other costs (note 7)	36		30		70		57
Operating, selling and general (note 5)	341		307		707		650
Depreciation, depletion and amortization	143		137		298		270
Exploration	16		3		33		8
Royalties	38		26		80		46
Taxes other than income taxes	91		93		180		181
(Gain) on disposal of assets	(1	)	(1	)	(2	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		(37	)	—		(37	)
Project start-up costs	3		—		5		—
Financing expenses (note 3)	(31	)	(3	)	(53	)	28
	971		968		2 090		1 909
EARNINGS BEFORE INCOME TAXES	321		321		878		457
Provision for income taxes (note 8)
Current	21		9		42		20
Future	179		83		347		118
	200		92		389		138
NET EARNINGS	121		229		489		319
Dividends on preferred securities, net of tax	(6	)	(7	)	(13	)	(14	)
Revaluation of US$preferred securities, net of tax	15		9		29		9
Net earnings attributable to common shareholders	130		231		505		314

PER COMMON SHARE (dollars)

Net earnings attributable to common shareholders (note 4)

See accompanying notes.

CONSOLIDATED BALANCE SHEETS

(unaudited)

($ millions)		June 30 2003		December 31 2002

ASSETS
Current assets
Cash and cash equivalents		—		15
Accounts receivable		368		403
Inventories		299		266
Future income taxes		33		38
Total current assets		700		722
Property, plant and equipment, net		7 981		7 641
Deferred charges and other		267		185
Future income taxes		143		135
Total assets		9 091		8 683
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		1		—
Accounts payable and accrued liabilities		806		716
Income taxes payable		31		34
Taxes other than income taxes		20		37
Future income taxes		10		10
Total current liabilities		868		797
Long-term debt		2 186		2 686
Accrued liabilities and other		267		226
Future income taxes (note 8)		1 874		1 516
Shareholders’ equity (see below)		3 896		3 458
Total liabilities and shareholders’ equity		9 091		8 683

SHAREHOLDERS’ EQUITY
	Number		Number
Preferred securities	17 540 000	486	17 540 000	523
Share capital	449 646 400	585	448 971 543	578
Contributed surplus (note 5)		3		—
Retained earnings		2 822		2 357
		3 896		3 458

See accompanying notes.

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2003		2002		2003		2002
OPERATING ACTIVITIES

Cash flow from operations	358		352		971		533
Decrease (increase) in operating working capital
Accounts receivable	149		22		35		(67	)
Inventories	(1	)	31		(33	)	37
Accounts payable and accrued liabilities	(42	)	(153	)	90		(135	)
Taxes payable	(10	)	1		(10	)	11
Cash flow from operating activities	454		253		1 053		379
CASH USED IN INVESTING ACTIVITIES	(353	)	(140	)	(654	)	(361	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	101		113		399		18
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	(3	)	(4	)	1		(26	)
Proceeds from issuance of long-term debt	—		—		—		797
Net (decrease) in other long-term debt	(75	)	(83	)	(359	)	(734	)
Issuance of common shares under stock option plan	2		6		6		11
Dividends paid on preferred securities	(11	)	(12	)	(23	)	(24	)
Dividends paid on common shares	(21	)	(18	)	(39	)	(36	)
Cash from (used in) financing activities	(108	)	(111	)	(414	)	(12	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(7	)	2		(15	)	6
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	7		5		15		1
CASH AND CASH EQUIVALENTS AT END OF PERIOD	—		7		—		7

See accompanying notes.

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(unaudited)

($ millions)	Preferred Securities		Share Capital	Contributed Surplus	Retained Earnings

At December 31, 2001	525		555	—	1 700
Net earnings	—		—	—	319
Dividends paid on preferred securities, net of tax	—		—	—	(14	)
Dividends paid on common shares	—		—	—	(36	)
Issued for cash under stock option plan	—		11	—	—
Issued under dividend reinvestment plan	—		2	—	(2	)
Revaluation of US$ preferred securities	(12	)	—	—	9
At June 30, 2002	513		568	—	1 976
At December 31, 2002	523		578	—	2 357
Net earnings	—		—	—	489
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	2 822

See accompanying notes.

SCHEDULES OF SEGMENTED DATA

(unaudited)

Second quarter

	Oil Sands				Natural Gas			Energy Marketing and Refining				Corporate and Eliminations				Total
($ millions)	2003		2002		2003	2002		2003		2002		2003		2002		2003		2002

EARNINGS
Revenues
Operating revenues	553		577		120	80		576		608		1		1		1 250		1 266
Energy marketing and trading activities	—		—		—	—		41		23		—		—		41		23
Intersegment revenues	81		43		5	7		—		—		(86	)	(50	)	—		—
Interest	—		—		—	—		—		—		1		—		1		—
	634		620		125	87		617		631		(84	)	(49	)	1 292		1 289
Expenses
Purchases of crude oil and products	2		—		—	7		371		441		(80	)	(56	)	293		392
Energy marketing and trading activities	—		—		—	—		42		21		—		—		42		21
Transportation and other costs	30		24		6	6		—		—		—		—		36		30
Operating, selling and general	214		190		19	16		82		84		26		17		341		307
Depreciation, depletion and amortization	107		105		21	19		14		13		1		—		143		137
Exploration	—		—		16	3		—		—		—		—		16		3
Royalties	5		9		33	17		—		—		—		—		38		26
Taxes other than income taxes	6		5		1	—		84		88		—		—		91		93
(Gain) on disposal of assets	—		—		—	(1	)	(1	)	—		—		—		(1	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—	—		—		(37	)	—		—		—		(37	)
Project start-up costs	3		—		—	—		—		—		—		—		3		—
Financing expenses	—		—		—	—		—		—		(31	)	(3	)	(31	)	(3	)
	367		333		96	67		592		610		(84	)	(42	)	971		968
Earnings (loss) before income taxes	267		287		29	20		25		21		—		(7	)	321		321
Income taxes	(200	)	(86	)	8	(8	)	(9	)	6		1		(4	)	(200	)	(92	)
Net earnings (loss)	67		201		37	12		16		27		1		(11	)	121		229

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

Second quarter

	Oil Sands				Natural Gas				Energy Marketing and Refining				Corporate and Eliminations				Total
($ millions)	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)	67		201		37		12		16		27		1		(11	)	121		229
Exploration expenses
Cash	—		—		1		1		—		—		—		—		1		1
Dry hole costs	—		—		15		2		—		—		—		—		15		2
Non-cash items included in earnings
Depreciation, depletion and amortization	107		105		21		19		14		13		1		—		143		137
Future income taxes	196		87		(8	)	7		(3	)	(8	)	(6	)	(3	)	179		83
Current income tax provision allocated to Corporate	4		—		—		—		12		3		(16	)	(3	)	—		—
(Gain) on disposal of assets	—		—		—		(1	)	(1	)	—		—		—		(1	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		(37	)	—		—		—		(37	)
Stock-based compensation expense	—		—		—		—		—		—		3		—		3		—
Other	(1	)	4		1		1		3		3		(55	)	(35	)	(52	)	(27	)
Overburden removal outlays	(53	)	(32	)	—		—		—		—		—		—		(53	)	(32	)
Increase (decrease) in deferred credits and other	1		1		(1	)	—		—		(1	)	2		(3	)	2		(3	)
Total cash flow from (used in) operations	321		366		66		41		41		—		(70	)	(55	)	358		352
Decrease (increase) in operating working capital	66		(92	)	12		25		(14	)	(11	)	32		(21	)	96		(99	)
Total cash flow from (used in) operating activities	387		274		78		66		27		(11	)	(38	)	(76	)	454		253
Cash from (used in) investing activities:
Capital and exploration expenditures	(188	)	(114	)	(37	)	(40	)	(25	)	(9	)	(8	)	(2	)	(258	)	(165	)
Deferred maintenance shutdown expenditures	(83	)	(3	)	—		—		(2	)	(15	)	—		—		(85	)	(18	)
Deferred outlays and other investments	(9	)	(3	)	—		—		(1	)	(17	)	(1	)	1		(11	)	(19	)
Proceeds from disposals	—		—		—		1		1		61		—		—		1		62
Total cash (used in) investing activities	(280	)	(120	)	(37	)	(39	)	(27	)	20		(9	)	(1	)	(353	)	(140	)
Net cash surplus (deficiency) before financing activities	107		154		41		27		—		9		(47	)	(77	)	101		113

SCHEDULES OF SEGMENTED DATA

(unaudited)

Six months ended June 30

	Oil Sands				Natural Gas				Energy Marketing and Refining				Corporate and Eliminations				Total
($ millions)	2003		2002		2003		2002		2003		2002		2003		2002		2003		2002

EARNINGS
Revenues
Operating revenues	1 310		1 024		256		144		1 334		1 157		1		1		2 901		2 326
Energy marketing and trading activities	—		—		—		—		66		39		—		—		66		39
Intersegment revenues	189		115		12		18		—		—		(201	)	(133	)	—		—
Interest	—		—		—		—		—		—		1		1		1		1
	1 499		1 139		268		162		1 400		1 196		(199	)	(131	)	2 968		2 366
Expenses
Purchases of crude oil and products	4		—		—		14		898		797		(198	)	(141	)	704		670
Energy marketing and trading activities	—		—		—		—		68		37		—		—		68		37
Transportation and other costs	58		45		12		12		—		—		—		—		70		57
Operating, selling and general	444		408		38		33		182		169		43		40		707		650
Depreciation, depletion and amortization	225		204		42		37		29		28		2		1		298		270
Exploration	9		—		24		8		—		—		—		—		33		8
Royalties	15		17		65		29		—		—		—		—		80		46
Taxes other than income taxes	12		11		1		1		167		169		—		—		180		181
(Gain) on disposal of assets	—		—		—		(1	)	(2	)	—		—		—		(2	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		(37	)	—		—		—		(37	)
Project start-up costs	5		—		—		—		—		—		—		—		5		—
Financing expenses	—		—		—		—		—		—		(53	)	28		(53	)	28
	772		685		182		133		1 342		1 163		(206	)	(72	)	2 090		1 909
Earnings (loss) before income taxes	727		454		86		29		58		33		7		(59	)	878		457
Income taxes	(354	)	(142	)	(21	)	(12	)	(21	)	1		7		15		(389	)	(138	)
Net earnings (loss)	373		312		65		17		37		34		14		(44	)	489		319

As at June 30
TOTAL ASSETS	7 285		6 578		751		732		991		893		64		155		9 091		8 358
CAPITAL EMPLOYED (1)	4 186		4 833		431		473		493		524		157		82		5 267		5 912

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

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

Six months ended June 30

	Oil Sands				Natural Gas				Energy Marketing and Refining				Corporate and Eliminations				Total
($ millions)	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)	373		312		65		17		37		34		14		(44	)	489		319
Exploration expenses
Cash	—		—		5		2		—		—		—		—		5		2
Dry hole costs	—		—		19		6		—		—		—		—		19		6
Non-cash items included in earnings
Depreciation, depletion and amortization	225		204		42		37		29		28		2		1		298		270
Future income taxes	347		141		20		11		(6	)	(8	)	(14	)	(26	)	347		118
Current income tax provision allocated to Corporate	7		2		1		1		27		8		(35	)	(11	)	—		—
(Gain) on disposal of assets	—		—		—		(1	)	(2	)	—		—		—		(2	)	(1	)
(Gain) on sale of retail natural gas marketing business	—		—		—		—		—		(37	)	—		—		—		(37	)
Stock-based compensation expense	—		—		—		—		—		—		3		—		3		—
Other	3		9		2		2		5		4		(108	)	(36	)	(98	)	(21	)
Overburden removal outlays	(97	)	(85	)	—		—		—		—		—		—		(97	)	(85	)
Increase (decrease) in deferred credits and other	4		(4	)	—		—		—		(1	)	3		(33	)	7		(38	)
Total cash flow from (used in) operations	862		579		154		75		90		28		(135	)	(149	)	971		533
Decrease (increase) in operating working capital	91		(148	)	3		6		4		(36	)	(16	)	24		82		(154	)
Total cash flow from (used in) operating activities	953		431		157		81		94		(8	)	(151	)	(125	)	1 053		379
Cash from (used in) investing activities:
Capital and exploration expenditures	(429	)	(266	)	(76	)	(97	)	(38	)	(14	)	(10	)	(4	)	(553	)	(381	)
Deferred maintenance shutdown expenditures	(92	)	(5	)	—		—		(2	)	(16	)	—		—		(94	)	(21	)
Deferred outlays and other investments	(9	)	(3	)	—		—		(1	)	(19	)	(1	)	1		(11	)	(21	)
Proceeds from disposals	—		—		2		1		2		61		—		—		4		62
Total cash (used in) investing activities	(530	)	(274	)	(74	)	(96	)	(39	)	12		(11	)	(3	)	(654	)	(361	)
Net cash surplus (deficiency) before financing activities	423		157		83		(15	)	55		4		(162	)	(128	)	399		18

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 5, 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 June 30, 2003 and the results of its operations and cash flows for the three and six month periods ended June 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. 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 quarter ended June 30, 2003 a net pretax loss of $1 million ($3 million for the six month period ended June 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)	June 30 2003	December 31 2002

Energy trading assets	4	2
Energy trading liabilities	3	2

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

3. Financing Expenses

	Second quarter				Six months ended June 30
($ millions)	2003		2002		2003		2002

Interest on debt	32		40		68		78
Capitalized interest	(13	)	(5	)	(23	)	(9	)
Net interest expense	19		35		45		69
Unrealized foreign exchange (gain) on long-term debt	(57	)	(38	)	(112	)	(41	)
Other foreign exchange	7		—		14		—
Total financing expenses	(31	)	(3	)	(53	)	28

4. Reconciliation of Basic and Diluted Earnings Per Common Share

	Second quarter				Six months ended June 30
($ millions)	2003		2002		2003		2002

Net earnings attributable to common shareholders	130		231		505		314
Dividends on preferred securities, net of tax	6		7		13		14
Revaluation of US$ preferred securities, net of tax	(15	)	(9	)	(29	)	(9	)
Adjusted net earnings attributable to common shareholders	121		229		489		319

(millions of common shares)
Weighted-average number of common shares	449		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		18		22		20

Weighted-average number of diluted common shares	474		472		476		473

(dollars per common share)
Basic earnings per share (a)	0.29		0.52		1.12		0.70
Diluted earnings per share (b)	0.26		0.49		1.03		0.67

Note: An option will have a dilutive effect under the treasury stock method only when the average market price of the common stock during the period exceeds the exercise price of the option.

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

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

5. 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 options are granted.

Under the SunShare long-term incentive plan, the company granted 343,067 options to new employees in the second quarter of 2003 for a total of 596,405 options granted in the six months ended June 30, 2003 (8,334,240 options granted during the second quarter and the six months ended June 30, 2002).

Under the company’s other plans, 122,700 options were granted in the second quarter of 2003 for a total of 1,843,480 granted in the six months ended June 30, 2003 (128,880 options granted during the second quarter of 2002 and 1,787,900 options granted for the six months ended June 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:

	Second quarter						Six months ended June 30
	2003			2002			2003			2002

Quarterly dividend per share (a)	$	0.05		$	0.0425		$	0.05		$	0.0425
Risk-free interest rate	4.58		%	5.46		%	4.41		%	5.42		%
Expected life	7 years			8 years			6 years			8 years
Expected volatility	33		%	31		%	33		%	31		%
Weighted-average fair value per option	$	9.86		$	12.65		$	10.05		$	12.05

(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 and $0.05 per common share were declared and paid in the first and second quarter, respectively.

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 proforma 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 $3 million in the second quarter and for the six month period ended June 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:

	Second quarter		Six months ended June 30
($ millions, except per share amounts)	2003	2002	2003	2002
Net earnings attributable to common shareholders – as reported	130	231	505	314
Less: compensation cost under the fair value method for pre-2003 options	5	11	19	21
Pro forma net earnings attributable to common shareholders for pre-2003 options	125	220	486	293
Basic earnings per share
As reported	0.29	0.52	1.12	0.70
Pro forma	0.28	0.50	1.08	0.65
Diluted earnings per share
As reported	0.26	0.49	1.03	0.67
Pro forma	0.25	0.46	0.99	0.63

6. Supplemental Information

	Second quarter		Six months ended June 30
($ millions)	2003	2002	2003	2002

Interest paid	9	13	71	58
Income taxes paid	10	4	35	13

Crude oil hedges at June 30, 2003

	Quantity (bbl/day)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (d)
Swaps	22 000	27.45	151	2003	(c)
Swaps	15 000	24.46	91	2003
Costless collars	60 000	21.27 – 25.56	318 – 382	2003

Swaps	38 000	23.58	444	2004
Costless collars	11 000	21.00 – 23.65	115 – 129	2004
Swap/call (e)	30 000	24.36	363	2004

Swaps	36 000	22.77	406	2005

Margin hedges at June 30, 2003

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

	9 000	5.08	11	2003
	6 600	5.25	3	2004	(f)

Natural gas hedges at June 30, 2003

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

Swaps	10 000	6.43	8	2003
Costless collars	15 000	5.85 – 7.01	11 – 13	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 June 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 July to October 2003, inclusive.

7. 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.

8. 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.

9. Acquisition of Refinery and Related Assets

On April 14, 2003, the company entered into an agreement to acquire a Denver refinery and related assets for cash and other consideration of US$150 million. In addition, the company will purchase current crude oil and product inventories. The agreement is subject to a number of closing conditions including approval of the U.S. Federal Trade Commission and other regulatory authorities. The closing is currently expected to occur in August 2003.

10. Recently Issued Accounting Guideline

In June 2003 the Canadian Institute of Chartered Accountants issued Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities (VIEs)”. VIEs, commonly referred to as Special Purpose Entities or SPEs, are entities in which the equity investors do not have a controlling financial interest or do not have sufficient equity at risk to absorb future losses. 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. Suncor has not completed its evaluation of the two VIEs involving the sale of crude oil inventory and the sale of equipment as described in note 9(c) on page 63 of the company’s 2002 Annual Report. It is reasonably possible the company will be required to consolidate these VIEs. The company does not expect a significant impact on net income if it is required to consolidate. The impact on the balance sheet would be an increase to inventories, an increase to property, plant and equipment and an increase to long-term debt. AcG 15 would be adopted without restatement of prior periods.

H I G H L I G H T S

(unaudited)

	2003	2002

CASH FLOW FROM OPERATIONS (3)
(dollars per common share)

For the quarters ended June 30
Cash flow from operations	0.80	0.79
Dividends paid on preferred securities (pretax)	0.03	0.03
Cash flow from operations after deducting dividends paid on preferred securities	0.77	0.76

For the six months ended June 30
Cash flow from operations	2.16	1.19
Dividends paid on preferred securities (pretax)	0.05	0.05
Cash flow from operations after deducting dividends paid on preferred securities	2.11	1.14

RATIOS

For the twelve months ended June 30
Return on capital employed (%) (1)	17.1	10.7
Return on capital employed (%) (2)	15.6	7.6

Net debt to cash flow from operations (times)	1.2	3.7
Interest coverage on long-term debt (times)
Net earnings	11.4	4.5
Cash flow from operations	14.2	6.2

As at June 30
Debt to debt plus shareholders’ equity (%)	35.9	50.8

COMMON SHARE INFORMATION (3)

As at June 30
Share price at end of trading
Toronto Stock Exchange – Cdn$	25.34	26.60
New York Stock Exchange – US$	18.75	17.86

Common share options outstanding (thousands)	21 950	20 840

For the six months ended June 30
Average number outstanding, weighted monthly (thousands)	449 326	447 026

(1) Return on capital employed – net earnings adjusted for after-tax financing expenses, divided by average capital employed. Average capital employed is the total 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 period, divided by two.

(2) 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.

(3) Comparative figures reflect a two-for-one share split in May 2002.

QUARTERLY OPERATING SUMMARY

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30 2003	Mar 31 2003	Dec 31 2002	Sept 30 2002	June 30 2002	June 30 2003	June 30 2002	Dec 31 2002

OIL SANDS
Production (a)	188.2	211.1	227.6	207.9	207.6	199.6	193.6	205.8
Sales (a)
Light sweet crude oil	86.4	120.7	116.7	114.1	90.8	103.5	93.8	104.7
Diesel	22.9	30.1	25.6	22.4	23.8	26.5	22.0	23.0
Light sour crude oil	73.9	60.4	73.9	54.8	73.8	67.1	72.3	68.3
Bitumen	1.2	—	12.2	15.4	8.9	0.6	4.6	9.3
Total sales	184.4	211.2	228.4	206.7	197.3	197.7	192.7	205.3
Average sales price (b)
Light sweet crude oil	39.87	46.69	39.02	39.80	37.07	43.83	35.26	37.56
Other (diesel, light sour crude oil and bitumen)	32.94	40.62	31.04	30.86	30.33	36.60	28.13	29.58
Total	36.19	44.09	35.12	35.79	33.43	40.38	31.60	33.65
Total ^*	38.14	48.77	39.11	40.40	36.68	43.79	33.74	36.94

Cash operating costs and total operating costs
New definition:
Cash costs	10.70	9.20	8.30	9.35	9.50	9.95	10.30	9.50
Natural gas	2.40	3.10	1.75	1.05	1.40	2.75	1.80	1.55
Imported bitumen	0.10	0.10	0.15	—	—	0.10	—	0.05
Cash operating costs (1),(c)	13.20	12.40	10.20	10.40	10.90	12.80	12.10	11.10
Depreciation, depletion and amortization	6.25	6.20	6.05	6.25	5.50	6.20	5.80	6.00
Total operating costs (2),(c)	19.45	18.60	16.25	16.65	16.40	19.00	17.90	17.10

As previously defined:
Cash costs	10.70	9.35	8.70	9.15	9.40	9.95	10.20	9.45
Natural gas	2.50	3.10	1.75	1.05	1.45	2.80	1.80	1.60
Cash overburden spending	3.20	2.30	2.00	1.75	1.75	2.75	2.45	2.10
Imported bitumen	0.10	0.10	—	—	—	0.10	—	0.05
Project start-up costs	0.15	0.10	0.05	0.10	—	0.10	—	0.05
Cash operating costs (3),(c)	16.65	14.95	12.50	12.05	12.60	15.70	14.45	13.25
Depreciation, depletion and amortization
(net of cash overburden spending)	3.25	3.90	4.05	4.50	4.05	3.55	3.40	3.90
Total operating costs (4),(c)	19.90	18.85	16.55	16.55	16.65	19.25	17.85	17.15

(for the period ended)
Capital employed (i)	4 186	4 395	4 540	4 720	4 833

(for the twelve months ended)

Return on capital employed (j)	18.9	21.2	16.8	14.6	13.4

Return on capital employed (j) ****	16.8	19.3	15.6	11.8	8.7

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30 2003	Mar 31 2003	Dec 31 2002	Sept 30 2002	June 30 2002	June 30 2003	June 30 2002	Dec 31 2002

NATURAL GAS
Gross production **
Natural gas (d)	175	184	182	181	179	180	177	179
Natural gas liquids (a)	2.1	2.4	2.4	2.3	2.5	2.3	2.5	2.4
Crude oil (a)	1.6	1.4	1.5	1.3	1.7	1.5	1.5	1.5
Total gross production (e)	32.8	34.5	34.2	33.8	34.0	33.8	33.5	33.7
Average sales price
Natural gas (f)	6.63	7.54	4.91	3.56	3.92	7.09	3.57	3.91
Natural gas (f) *	6.65	7.59	4.91	3.56	3.92	7.13	3.57	3.91
Natural gas liquids (b)	33.45	41.65	35.14	31.66	28.25	37.85	25.38	29.35
Crude oil – conventional (b)	37.82	47.75	33.20	33.57	30.99	42.45	30.16	31.72
Net wells drilled
Conventional – exploratory ***	24	3	4	3	—	27	14	21
– development	1	5	6	2	5	6	14	22
	25	8	10	5	5	33	28	43

(for the period ended)
Capital employed (i)	431	434	449	467	473

(for the twelve months ended)
Return on capital employed (j)	18.6	14.6	9.2	7.7	10.4

ENERGY MARKETING AND REFINING
Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.5	4.4	4.5	4.6	4.5	4.4	4.4	4.5
Other	4.1	4.2	5.0	4.3	4.2	4.1	4.1	4.4
Jet fuel	0.7	0.7	0.5	0.4	0.4	0.7	0.3	0.4
Diesel	3.0	3.0	3.2	2.8	3.1	3.0	2.8	2.9
Total transportation fuel sales	12.3	12.3	13.2	12.1	12.2	12.2	11.6	12.2
Petrochemicals	0.9	1.0	0.7	0.6	0.8	0.9	0.7	0.6
Heating oils	0.3	0.8	0.6	0.1	0.4	0.6	0.5	0.4
Heavy fuel oils	0.6	0.7	0.7	0.5	0.6	0.7	0.6	0.6
Other	0.8	0.9	0.6	0.8	0.9	0.9	0.8	0.7
Total refined product sales	14.9	15.7	15.8	14.1	14.9	15.3	14.2	14.5

Margins (h)
Refining (5)	4.7	7.5	6.6	4.4	3.8	6.2	3.9	4.8
Refining (5)*	4.2	7.8	6.6	4.4	3.8	6.1	3.9	4.8
Retail (6)	6.2	7.0	6.5	6.9	6.8	6.6	6.4	6.6

Crude oil supply and refining
Processed at Suncor refinery (g)	11.1	11.5	12.0	11.1	7.8	11.3	9.6	10.6
Utilization of refining capacity (j)	100	103	108	100	70	101	86	95

(for the period ended)
Capital employed (i)	493	470	491	503	524

(for the twelve months ended)
Return on capital employed (j)	13.0	15.5	12.5	8.3	8.6

QUARTERLY OPERATING SUMMARY (continued)

*Definitions*

(1) 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.

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

(3) 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.

(4) Total operating costs (as previously defined)		– Included cash operating costs as defined in (3) above and non-cash operating costs. Per barrel amounts were based on sales volumes.

(5) Refining margin		– Average wholesale unit price from all products less average unit cost of crude oil.

(6) Retail margin		– Average street price of Sunoco branded retail gasoline net of federal excise tax and other adjustments, less refining gasoline 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.

(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