consolidated statements of earnings

(unaudited)

	Three months ended March 31
($ millions)	2005	2004
Revenues (note 10)	2 061	1 795
Expenses
Purchases of crude oil and products	816	531
Operating, selling and general (note 6)	468	400
Energy marketing and trading activities (note 3)	134	67
Transportation and other costs	34	27
Depreciation, depletion and amortization (note 2)	165	175
Accretion of asset retirement obligations	8	6
Exploration	17	33
Royalties (note 9)	115	91
Taxes other than income taxes	120	119
Gain on disposal of assets	—	(1	)
Project start-up costs	3	22
Financing expenses (notes 2 and 4)	7	59
	1 887	1 529
Earnings Before Income Taxes	174	266
Provision for Income Taxes (note 2)
Current	29	20
Future	47	30
	76	50
Net Earnings	98	216

Per Common Share (dollars), (note 5)
Basic	0.22	0.48
Diluted	0.21	0.46
Cash dividends	0.06	0.05

See accompanying notes.

consolidated balance sheets

(unaudited)

	March 31	December 31
($ millions)	2005	2004
Assets
Current assets
Cash and cash equivalents	39	88
Accounts receivable	929	627
Inventories	434	423
Future income taxes	78	57
Total current assets	1 480	1 195
Property, plant and equipment, net (note 2)	10 738	10 326
Deferred charges and other	373	320
Total assets	12 591	11 841
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	8	30
Accounts payable and accrued liabilities (note 9)	1 520	1 306
Income taxes payable	27	32
Taxes other than income taxes	23	41
Total current liabilities	1 578	1 409
Long-term debt	2 555	2 217
Accrued liabilities and other	815	749
Future income taxes (note 2)	2 613	2 545
Shareholders’ equity (see below)	5 030	4 921
Total liabilities and shareholders’ equity	12 591	11 841

Shareholders’ Equity

	Number (thousands)			Number (thousands)
Share capital	455 810	684		454 241	651
Contributed surplus		36			32
Cumulative foreign currency translation		(54	)		(55	)
Retained earnings (note 2)		4 364			4 293
		5 030			4 921

See accompanying notes.

consolidated statements of changes in shareholders’ equity

(unaudited)

			Cumulative
			Foreign
	Share	Contributed	Currency		Retained
($ millions)	Capital	Surplus	Translation		Earnings
At December 31, 2003, as previously reported	604	7	(26	)	3 294
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—	—	—		14
At December 31, 2003, as restated	604	7	(26	)	3 308
Net earnings	—	—	—		216
Dividends paid on common shares	—	—	—		(21	)
Issued for cash under stock option plan	17	—	—		—
Issued under dividend reinvestment plan	2	—	—		(2	)
Stock-based compensation expense	—	4	—		—
Foreign currency translation adjustment	—	—	4		—
At March 31, 2004	623	11	(22	)	3 501
At December 31, 2004, as previously reported	651	32	(55	)	4 269
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—	—	—		24
At December 31, 2004, as restated	651	32	(55	)	4 293
Net earnings	—	—	—		98
Dividends paid on common shares	—	—	—		(25	)
Issued for cash under stock option plan	31	—	—		—
Issued under dividend reinvestment plan	2	—	—		(2	)
Stock-based compensation expense	—	4	—		—
Foreign currency translation adjustment	—	—	1		—
At March 31, 2005	684	36	(54	)	4 364

See accompanying notes.

schedules of segmented data

(unaudited)

	Three months ended March 31
									Energy Marketing				Refining and
									and Refining -				Marketing -				Corporate and
	Oil Sands				Natural Gas				Canada				U.S.A.				Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
EARNINGS
Revenues
Operating revenues	553		666		131		91		765		678		411		289		1		—		1 861		1 724
Energy marketing and trading activities	—		—		—		—		137		78		—		—		—		(8	)	137		70
Net insurance proceeds (note 10)	63		—		—		—		—		—		—		—		—		—		63		—
Intersegment revenues	77		99		6		42		—		—		—		—		(83	)	(141	)	—		—
Interest	—		—		—		—		—		—		—		—		—		1		—		1
	693		765		137		133		902		756		411		289		(82	)	(148	)	2 061		1 795
Expenses
Purchases of crude oil and products	9		12		—		—		561		438		329		224		(83	)	(143	)	816		531
Operating, selling and general	242		214		21		20		108		96		32		33		65		37		468		400
Energy marketing and trading activities	—		—		—		—		134		75		—		—		—		(8	)	134		67
Transportation and other costs	24		17		5		5		1		1		4		4		—		—		34		27
Depreciation, depletion and amortization	107		124		31		28		18		17		6		3		3		3		165		175
Accretion of asset retirement obligations	6		5		2		1		—		—		—		—		—		—		8		6
Exploration	10		13		7		20		—		—		—		—		—		—		17		33
Royalties	87		62		28		29		—		—		—		—		—		—		115		91
Taxes other than income taxes	7		7		—		—		83		83		30		29		—		—		120		119
Gain on disposal of assets	—		—		—		(1	)	—		—		—		—		—		—		—		(1	)
Project start-up costs	3		22		—		—		—		—		—		—		—		—		3		22
Financing expenses	—		—		—		—		—		—		—		—		7		59		7		59
	495		476		94		102		905		710		401		293		(8	)	(52	)	1 887		1 529
Earnings (loss) before income taxes	198		289		43		31		(3	)	46		10		(4	)	(74	)	(96	)	174		266
Income taxes	(81	)	(50	)	(17	)	(9	)	—		(16	)	(4	)	1		26		24		(76	)	(50	)
Net earnings (loss)	117		239		26		22		(3	)	30		6		(3	)	(48	)	(72	)	98		216

As at March 31
TOTAL ASSETS	9 577		8 282		1 005		809		1 460		1 144		725		410		(176	)	(27	)	12 591		10 618

	Three months ended March 31
									Energy Marketing				Refining and
									and Refining -				Marketing -				Corporate and
	Oil Sands				Natural Gas				Canada				U.S.A.				Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	117		239		26		22		(3	)	30		6		(3	)	(48	)	(72	)	98		216
Exploration expenses	—		—		7		20		—		—		—		—		—		—		7		20
Non-cash items included in earnings
Depreciation, depletion and amortization	107		124		31		28		18		17		6		3		3		3		165		175
Income taxes	81		50		17		9		—		16		4		(1	)	(55	)	(44	)	47		30
Gain on disposal of assets	—		—		—		(1	)	—		—		—		—		—		—		—		(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		4		4		4		4
Other	25		(11	)	2		4		7		(8	)	2		(7	)	(12	)	20		24		(2	)
Overburden removal outlays	(75	)	(54	)	—		—		—		—		—		—		—		—		(75	)	(54	)
Increase (decrease) in deferred credits and other	(3	)	17		—		1		—		1		—		2		27		5		24		26
Total cash flow from (used in) operations	252		365		83		83		22		56		18		(6	)	(81	)	(84	)	294		414
Decrease (increase) in operating working capital	(5	)	11		(16	)	(13	)	(53	)	32		(73	)	(24	)	108		(52	)	(39	)	(46	)
Total cash flow from (used in) operating activities	247		376		67		70		(31	)	88		(55	)	(30	)	27		(136	)	255		368
Cash from (used in) investing activities:
Capital and exploration expenditures	(370	)	(228	)	(82	)	(70	)	(78	)	(25	)	(67	)	(18	)	(12	)	(6	)	(609	)	(347	)
Deferred maintenance shutdown expenditures	(25	)	—		—		—		—		(1	)	—		—		—		—		(25	)	(1	)
Deferred outlays and other investments	(1	)	(2	)	—		—		(1	)	(4	)	—		—		—		—		(2	)	(6	)
Proceeds from disposals	21		—		—		4		—		—		—		—		—		—		21		4
Total cash (used in) investing activities	(375	)	(230	)	(82	)	(66	)	(79	)	(30	)	(67	)	(18	)	(12	)	(6	)	(615	)	(350	)
Net cash surplus (deficiency) before financing activities	(128	)	146		(15	)	4		(110	)	58		(122	)	(48	)	15		(142	)	(360	)	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 changes as described in note 2, Changes in Accounting Policies.

In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature necessary to present fairly Suncor Energy Inc.’s (Suncor) financial position at March 31, 2005 and the results of its operations and cash flows for the three month periods ended March 31, 2005 and 2004.

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

2. CHANGES IN ACCOUNTING POLICIES

(a) Preferred Securities

On January 1, 2005 the company retroactively adopted the Canadian accounting standard related to disclosure and presentation of financial instruments. Accordingly, the company’s preferred securities, which were redeemed in March, 2004, have been reclassified as long-term debt. The company has also restated its property, plant and equipment and depreciation, depletion and amortization to reflect the capitalized interest that would have been incurred and amortized had the preferred securities been classified as debt during the period in which they were outstanding. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

	As at March 31
($ millions, increase)	2005	2004
Property, plant and equipment	37	39
Total assets	37	39

Future income tax liabilities	13	14
Retained earnings	24	25
Total liabilities and shareholders’ equity	37	39

Change in Consolidated Statements of Earnings

	Three months ended March 31
($ millions, increase/(decrease))	2005	2004
Depreciation, depletion and amortization	—	1
Financing expenses	—	15
Future income taxes	—	(5	)
Net earnings	—	(11	)
Per common share – basic (dollars)	—	—
Per common share – diluted (dollars)	—	—

(b) Consolidation of Variable Interest Entities

On January 1, 2005 the company adopted Canadian Accounting Guideline 15 “Consolidation of Variable Interest Entities (VIEs)” without restatement of prior periods. Accordingly, the company has consolidated the VIE related to the sale of equipment as described in note 11(c) of the company’s 2004 Annual Report. The impact of adopting this standard was an increase to property, plant and equipment of $14 million, an increase to materials and supplies inventory of $8 million and an increase to long-term debt of $22 million.

3. ENERGY MARKETING AND TRADING ACTIVITIES

The company uses physical and financial energy contracts, including swaps, forwards and options to gain market information and earn trading and marketing revenues. The results of these activates are reported as revenue and as energy trading and marketing activities in the Consolidated Statement of Earnings.

Physical energy marketing contracts involve activities intended to generate revenues. For the quarter ended March 31, 2005 these activities resulted in a net pretax gain of $2 million (2004 – pretax gain $1 million).

In addition to the financial derivatives used for hedging activities, the company also enters into various financial energy contracts for trading activities. The following information presents all positions for the financial instruments only. These energy trading activities are accounted for using the mark-to-market method and as such all financial instruments are recorded at fair value at each balance sheet date. For the quarter ended March 31, 2005, a net pretax gain of $2 million (2004 – pretax gain $2 million) from the settlement and revaluation of the financial contracts. The above amounts do not include the impact of related general and administrative costs.

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

	March 31	December 31
($ millions)	2005	2004
Energy trading assets	35	26
Energy trading liabilities	24	9

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

4. FINANCING EXPENSES

	Three months ended March 31
($ millions)	2005		2004
Interest on debt	33		49
Capitalized interest	(26	)	(11	)
Net interest expense	7		38
Foreign exchange loss on long-term debt	6		25
Other foreign exchange gain	(6	)	(4	)
Total financing expenses	7		59

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Three months ended March 31
($ millions)	2005	2004
Net earnings	98	216
Interest on subordinated debentures, net of tax	—	—	(a)
Revaluation of US $subordinated debentures, net of tax	—	—	(a)
Adjusted net earnings	98	216

(millions of common shares)
Weighted-average number of common shares	455	452
Dilutive securities:
Options issued under stock-based compensation plans	8	13
Redemption of subordinated debentures by the issuance of common shares	—	—	(a)
Weighted-average number of diluted common shares	463	465

(dollars per common share)
Basic earnings per share (b)	0.22	0.48
Diluted earnings per share (c)	0.21	0.46	(a)

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

(a) For the three months ended March 31, 2004, diluted earnings per share is net earnings divided by the weighted-average number of diluted common shares. Interest on subordinated debentures, the revaluation of US$ subordinated debentures and the redemption of subordinated debentures 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 net earnings divided by the weighted-average number of common shares.

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

6. STOCK-BASED COMPENSATION

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

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

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 264,000 options to new employees in the first quarter of 2005 (810,000 options granted during the first quarter of 2004).

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, 2,062,000 SunShare options vested. These options represented approximately 25% of the then outstanding unvested options under the SunShare plan.

Under the company’s other plans, 1,291,000 options were granted in the first quarter of 2005 (1,226,000 options granted during the first quarter of 2004).

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 and the weighted-average assumptions used in their determination are as noted below:

	Three months ended March 31
	2005			2004
Quarterly dividend per share	$	0.06		$	0.05
Risk-free interest rate	3.77		%	3.72		%
Expected life	6 years			6 years
Expected volatility	28		%	29		%
Weighted-average fair value per option	$	13.88		$	11.76

Stock-based compensation expense recognized in the first quarter of 2005 related to stock options plans was $4 million (2004 – $4 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:

	Three months ended March 31
($ millions, except per share amounts)	2005	2004
Net earnings – as reported	98	216
Less: compensation cost under the fair value method for pre-2003 options	2	15
Pro forma net earnings	96	201
Basic earnings per share
As reported	0.22	0.48
Pro forma	0.21	0.45
Diluted earnings per share
As reported	0.21	0.46
Pro forma	0.20	0.43

(b) Performance Share Units (PSUs)

In the first quarter of 2005 the company issued 436,000 (2004 – 351, 000) PSUs. Expense recognized in the first quarter of 2005 was $3 million (2004 – $1 million).

7. EMPLOYEE FUTURE BENEFITS

The company’s pension plans and other post-retirement benefits programs are described in note 9 of the company’s 2004 Annual Report. The following is the status of the net periodic benefit cost for the three months ended March 31.

	Pension Benefits				Other Post-retirement Benefits
	2005		2004		2005	2004
Current service costs	8		6		2	1
Interest costs	10		8		2	2
Expected return on plan assets	(7	)	(6	)	—	—
Amortization of net actuarial loss	5		5		—	—
Net periodic benefit cost	16		13		4	3

8. SUPPLEMENTAL INFORMATION

	Three months ended March 31
($ millions)	2005	2004
Interest paid	46	64
Income taxes paid	34	20

Strategic Crude Oil Hedges at March 31, 2005

		Quantity (bbl/day)		Average Price (US$/bbl) (a)		Revenue Hedged (Cdn$ millions) (b)		Hedge Period (c)
Swaps		36 000		22.77		273		2005

Margin Hedges at March 31, 2005

		Quantity (bbl/day)		Average Margin (US$/bbl)		Margin Hedged (Cdn$ millions (b)		Hedge Period (d)
Refined product and crude swaps		11 700		7.29		28		2005

Natural Gas Hedges at March 31, 2005

	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period (c)
Costless collars	20 000	6.83 - 7.98	29 - 34	2005	(e)
Swaps	4 000	6.99	8	2005
Swaps	4 000	6.58	10	2006
Swaps	4 000	6.11	9	2007

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

(b) The revenue and margin hedged is translated to Cdn$ at the March 31, 2005 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(d) For the period April to December 2005, inclusive.

(e) For the period April to October 2005, inclusive.

highlights

(unaudited)

	2005	2004
Cash Flow from Operations
(dollars per common share)
For the three months ended March 31
Cash flow from operations (1)	0.65	0.92

Ratios
For the twelve months ended March 31
Return on capital employed (%) (2)	15.7	15.9
Return on capital employed (%) (3)	13.1	14.4
Net debt to cash flow from operations (times) (4)	1.3	1.4
Interest coverage on long-term debt (times)
Net earnings (5)	11.3	8.5
Cash flow from operations (6)	14.5	10.5

As at March 31
Debt to debt plus shareholders’ equity (%)(7)	33.8	39.1

Common Share Information
As at March 31
Share price at end of trading
Toronto Stock Exchange – Cdn$	48.73	35.97
New York Stock Exchange – US$	40.21	27.35
Common share options outstanding (thousands)	20 307	21 524

For the three months ended March 31
Average number outstanding, weighted monthly (thousands)	454 911	452 123

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) Net earnings (2005 – $970 million; 2004 – $929 million) adjusted for after-tax financing expenses (2005 – income of $36 million; 2004 – income of $8 million) for the twelve month period ended; divided by average capital employed (2005 – $5,958 million; 2004 – $5,802 million). Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, at the beginning and end of the year, divided by two, less capitalized costs related to major projects in progress (as applicable). 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 51 of Suncor’s 2004 Annual Report to Shareholders.

(3) If capital employed were to include capitalized costs related to major projects in progress (average capital employed including major projects in progress: 2005 – $7,116 million; 2004 – $6,395 million), the return on capital employed would be as stated on this line.

(4) 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.

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

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

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

quarterly operating summary

(unaudited)

	For the quarter ended					Total year
	Mar 31 2005	Dec 31 2004	Sept 30 2004	June 30 2004	Mar 31 2004	Dec 31 2004
OIL SANDS
Production (a)
Base operations	121.2	206.9	230.2	210.8	213.9	215.6
Firebag	18.7	15.6	7.3	15.1	5.9	10.9
Total production	139.9	222.5	237.5	225.9	219.8	226.5
Sales (a)
Light sweet crude oil	75.3	115.3	113.5	118.7	112.2	114.9
Diesel	11.8	25.5	28.7	29.7	27.5	27.9
Light sour crude oil	38.5	80.9	76.3	68.9	74.3	75.1
Bitumen	18.4	11.0	7.9	14.5	—	8.4
Total sales	144.0	232.7	226.4	231.8	214.0	226.3
Average sales price (1),(b)
Light sweet crude oil	45.41	50.55	46.03	45.70	40.26	45.60
Other (diesel, light sour crude oil and bitumen)	47.31	39.62	42.29	38.28	35.85	39.13
Total	46.44	44.68	44.08	41.88	38.16	42.28
Total *	54.80	54.40	52.72	48.18	43.28	49.78

CASH OPERATING COSTS AND TOTAL OPERATING COSTS – BASE OPERATIONS

Cash costs	15.10	10.90	9.00	9.75	9.65	9.80
Natural gas	4.70	2.20	1.40	2.30	2.10	2.00
Imported bitumen	0.10	0.10	0.10	0.05	0.40	0.15
Cash operating costs (2),(c)	19.90	13.20	10.50	12.10	12.15	11.95
Firebag start-up costs	—	—	—	—	1.20	0.30
Total cash operating costs (3),(c)	19.90	13.20	10.50	12.10	13.35	12.25
Depreciation, depletion and amortization	9.05	6.25	5.70	6.15	6.20	6.10
Total operating costs (4),(c)	28.95	19.45	16.20	18.25	19.55	18.35

CASH OPERATING COSTS AND TOTAL OPERATING COSTS – FIREBAG

Cash costs	8.90	7.00	14.90	6.55	—	8.30
Natural gas	10.10	10.45	11.90	11.65	—	11.20
Cash operating costs (5),(c)	19.00	17.45	26.80	18.20	—	19.50
Depreciation, depletion and amortization	4.75	5.55	7.45	5.80	—	6.00
Total operating costs (6),(c)	23.75	23.00	34.25	24.00	—	25.50

(for the period ended)
Capital employed (i)	4 231	4 169	4 182	4 525	4 725

(for the twelve months ended)
Return on capital employed (j)	19.6	22.9	22.8	22.6	18.1
Return on capital employed (j)********	15.9	18.8	19.0	19.2	16.0

		For the quarter ended					Total year
		Mar 31 2005	Dec 31 2004	Sept 30 2004	Jun 30 2004	Mar 31 2004	Dec 31 2004
NATURAL GAS
Gross production **
Natural gas (d)		191	193	201	209	197	200
Natural gas liquids (a)		3.0	2.9	2.6	2.2	2.2	2.5
Crude oil (a)		0.9	1.0	1.0	1.1	0.9	1.0
Total gross production (e)		35.7	36.1	37.1	38.1	35.9	36.8
Average sales price (1)
Natural gas (f)		6.81	7.02	6.49	6.77	6.54	6.70
Natural gas (f)*		6.74	6.98	6.53	6.84	6.59	6.73
Natural gas liquids (b)		38.32	46.46	42.06	43.53	38.13	42.82
Crude oil – Conventional (b)		61.40	55.26	55.43	47.08	44.14	50.41
Net wells drilled
Conventional	– Exploratory ***	5	—	3	3	4	10
	– Development	5	5	3	—	8	16
		10	5	6	3	12	26

(for the period ended)
Capital employed (i)		490	448	410	421	418

(for the twelve months ended)
Return on capital employed (j)		26.2	27.1	30.4	29.9	27.7

ENERGY MARKETING AND REFINING – CANADA

Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.6	4.8	4.6	4.5	4.2	4.6
Other	4.0	4.1	4.3	4.1	4.0	4.1
Jet fuel	0.9	1.0	1.0	0.7	1.0	0.9
Diesel	2.7	3.3	3.0	3.1	2.9	3.1
Total transportation fuel sales	12.2	13.2	12.9	12.4	12.1	12.7
Petrochemicals	0.8	0.8	0.7	0.6	0.9	0.8
Heating oils	0.8	0.5	0.2	0.3	0.8	0.4
Heavy fuel oils	1.0	0.8	0.5	0.7	0.8	0.7
Other	0.3	0.3	1.0	1.5	0.6	0.8
Total refined product sales	15.1	15.6	15.3	15.5	15.2	15.4

Margins (h)
Refining (7)	4.8	7.9	8.8	7.4	7.8	8.0
Refining (7)*	4.8	7.8	8.8	8.0	7.8	8.1
Retail (8)	4.7	4.5	3.7	4.3	5.0	4.4

Crude oil supply and refining
Processed at Sarnia refinery (g)	10.1	11.3	11.6	9.5	12.0	11.1
Utilization of refining capacity (j)	91	101	104	85	108	100

(for the period ended)
Capital employed (i)	525	512	528	587	567

(for the twelve months ended)
Return on capital employed (j)	8.4	14.6	11.2	7.8	11.8
Return on capital employed (j)****	7.3	13.6	10.8	7.8	11.8

	For the quarter ended					Total year
	Mar 31 2005	Dec 31 2004	Sept 30 2004	Jun 30 2004	Mar 31 2004	Dec 31 2004
REFINING AND MARKETING – U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.6	0.7	0.7
Other	3.8	3.9	4.3	3.6	3.4	3.8
Jet fuel	0.7	0.6	0.7	0.5	0.4	0.5
Diesel	2.6	2.5	2.5	1.9	2.2	2.2
Total transportation fuel sales	7.8	7.7	8.2	6.6	6.7	7.2
Asphalt	1.6	1.1	1.9	1.8	1.2	1.5
Other	0.7	0.7	0.8	0.5	0.2	0.6
Total refined product sales	10.1	9.5	10.9	8.9	8.1	9.3

Margins (h)
Refining (7)	6.3	7.7	5.1	9.0	5.0	6.7
Refining (7)*	6.3	7.7	5.3	9.3	5.0	6.8
Retail (8)	3.3	6.0	4.2	6.2	5.0	5.4

Crude oil supply and refining
Processed at Denver refinery (g)	9.2	9.5	9.5	8.2	8.1	8.8
Utilization of refining capacity (j)	96	100	99	86	85	92

(for the period ended)
Capital employed (i)	262	232	241

(for the twelve months ended)
Return on capital employed (j)	14.5	12.2	10.0
Return on capital employed (j)****	12.2	11.0	9.6

*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 mining 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 – Base operations 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 – Base operations 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 – Firebag 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, as applicable, and other adjustments, less refining gasoline transfer price.