Exhibit 1

FOR IMMEDIATE RELEASE

Suncor Energy delivers solid financial results in 2004, advances growth strategy

All financial figures are unaudited and in Canadian dollars unless noted otherwise. Certain prior period amounts have been restated to conform to the current year’s presentation. Certain financial measures referred to in this release are not prescribed by generally accepted accounting principles (GAAP). For a description of these measures, see “Non-GAAP Financial Measures” in Suncor’s 2003 annual report to shareholders. This document makes reference to barrels of oil equivalent (boe). A boe conversion ratio of six thousand cubic feet of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Accordingly, boe measures may be misleading, particularly if used in isolation. Base operations refer to oil sands mining and upgrading operations.

Calgary, Alberta (January 27, 2004) – Suncor Energy Inc. today announced 2004 earnings of $1.1 billion ($2.40 per common share), up slightly from $1.075 billion ($2.41 per common share) in 2003. Excluding the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt, 2004 net earnings were $1.026 billion compared to $938 million in 2003. Cash flow from operations in 2004 was $2.021 billion compared to $2.079 billion in 2003.

Net earnings in 2004 compared to 2003 reflect higher benchmark crude oil prices, increased production, and non-cash reductions in income tax expense due to year-over-year changes in tax rates and resource allowance deductions. These positive impacts were largely offset by higher Oil Sands Alberta Crown Royalties, higher crude oil hedging losses and the impact of a stronger Canadian dollar. The decrease in cash flow from operations in 2004 compared to 2003 was due to the same factors that impacted net earnings.

“Strong oil and gas production and high commodity prices continued to benefit Suncor in 2004,” said Rick George, president and chief executive officer. “At the same time, our efforts in the past year provide a firm foundation for Suncor’s long term growth strategy.”

Key highlights in 2004 include:

•Suncor’s common shares closed at $42.40 at the end of 2004, an increase of 30% over 2003. Suncor shares outperformed both the S&P/TSX Composite Index and the S&P 500 during the year.

•Total production increased to 263,300 barrels of oil equivalent per day (boe/d), from 251,500 boe/d in 2003.

•Production at Suncor’s oil sands facility averaged 226,500 barrels per day (bpd), comprising 215,600 bpd from base operations and 10,900 bpd of bitumen from the company’s in-situ operations. Production in 2003 averaged 216,600 bpd; there was a 30-day planned maintenance shutdown and no in-situ production that year.

•Cash operating costs from oil sands base operations averaged $11.95 per barrel during 2004, at an average natural gas price of US$6.20 per thousand cubic feet.

•Natural gas production increased to 200 million cubic feet per day (mmcf/d) in 2004, compared to 187 mmcf/d in 2003.

•Refining margins averaged 8.0 cents per litre (cpl) for Canadian operations and 6.7 cpl for U.S. operations. This compares to 6.5 cpl for Canadian operations and 5.9 cpl for U.S. operations during 2003. Retail gasoline margins averaged 4.4 cpl for Canadian operations and 5.4 cpl for U.S. operations compared to 6.6 cpl for Canadian operations and 5.6 cpl for U.S. operations the year before. Also in 2004, expansion and upgrades of the company’s Sarnia and Denver refineries were launched.

•During 2004 work to expand Suncor’s oil sands production capacity to 260,000 bpd continued on schedule and on budget. Suncor also began preliminary site work and vessel construction for projects planned to increase production capacity to 350,000 bpd in 2008.

•While Suncor invested $1.8 billion in capital spending primarily to expand operations, maintaining a strong balance sheet remained a priority. At December 31, 2004, Suncor’s net debt (including cash and cash equivalents) was $2.16 billion.

•Suncor achieved a company wide Return on Capital Employed of 19.1% (excluding major projects in progress).

Fourth Quarter, 2004

Suncor’s net earnings for the fourth quarter of 2004 were $333 million ($0.73 per common share) compared to $302 million ($0.67 per common share) in the fourth quarter of 2003. Excluding the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt and preferred securities, fourth quarter net earnings were $283 million ($0.62 per common share) compared to $263 million ($0.57 per common share) during the fourth quarter, 2003. Cash flow from operations for the fourth quarter of 2004 was $524 million, unchanged from the same period in 2003.

Net earnings increased in the fourth quarter of 2004 compared to 2003 due to higher benchmark crude oil prices, largely offset by higher Oil Sands Alberta Crown Royalties, higher crude oil hedging losses, lower production and the impact of a stronger Canadian dollar.

Suncor’s combined oil sands and natural gas production for the fourth quarter was 258,600 boe/d, compared to 270,900 boe/d in the same period of 2003.

Oil sands production in the fourth quarter averaged 222,500 bpd, comprising 206,900 bpd from base operations and 15,600 bpd of bitumen from the company’s in-situ operations. Unplanned maintenance during the quarter impacted production and cash operating costs, which averaged $13.20 per barrel for base operations. In 2003, fourth quarter production averaged 235,200 bpd; there was no in-situ production that year.

Natural gas production averaged 193 mmcf/d in the fourth quarter of 2004, compared to 194 mmcf/d in the fourth quarter of 2003.

In the downstream, fourth quarter refining margins averaged 7.9 cpl for Canadian operations and 7.7 cpl for U.S. operations. This compares to 7.0 cpl for Canadian operations and 4.6 cpl for U.S. operations during the fourth quarter of 2003. Retail gasoline margins averaged 4.5 cpl for

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Canadian operations and 6.0 cpl for U.S. operations. This compares to 6.3 cpl for Canadian operations and 4.8 cpl for U.S. operations in the fourth quarter of 2003.

Firebag Oil and Gas Reserves

As a result of using year-end commodity pricing in the determination of proved reserves as required by U.S. Securities and Exchange Commission (SEC) regulations, 420 million barrels of Suncor’s net in-situ bitumen reserves (345 million barrels on a synthetic crude oil equivalent basis) were considered to be uneconomic at December 31, 2004, due to the effect of unusually wide light/heavy crude oil differentials.

Accordingly, Suncor has reclassified all 420 million barrels of its opening net in-situ bitumen reserves, as adjusted for 2004 production, to probable from proved to reflect the decrease in year-end prices. The reserves reclassification does not impact the company’s reported results of operations or financial position at December 31, 2004.

Suncor is subject to Canadian disclosure rules in connection with the reporting of its reserves. However, Suncor has received exemptive relief from Canadian securities administrators permitting it to report its proved reserves in accordance with U.S. disclosure practices and accordingly, the corresponding information prepared in accordance with National Instrument 51-101 standards may differ. For additional information about Suncor’s exemptive relief see “Reliance on Exemptive Relief” in Suncor’s annual information form dated February 26, 2004 available on www.sedar.com.

Outlook for 2005

Suncor’s Outlook provides management’s targets for 2005 in certain key areas of the company’s business. Outlook numbers are subject to change.

As a result of a fire in early January at the company’s oil sands facility, production has been reduced to about 110,000 bpd plus bitumen production from in-situ operations. Based on a preliminary assessment of the damage, Suncor estimates production should return to full rates of approximately 225,000 bpd sometime during the third quarter.

“We are completely focused on returning to full rates of production as quickly as possible,” said George. “And while operations and maintenance crews tackle the challenge of returning to reliable production, our growth teams are diligently implementing our long term growth strategy – increasing oil sands production capacity and expanding refining capacity in the downstream. We will recover from the short term production challenges and will keep Suncor’s strategy for delivering long-term shareholder value on track.”

Oil Sands

Construction of a vacuum unit, planned to increase production capacity to 260,000 bpd by the end of 2005, is approximately 85% complete and on budget. Work to bring production capacity to 350,000 bpd in 2008 is also expected to reach several milestones with fabrication and transport of major vessels planned to be completed in 2005. Construction of the second stage of in-situ development, planned to provide bitumen feed for the expanded upgrader, is targeted for completion in 2005.

In planning for expansion beyond 2008, Suncor expects this year to file regulatory applications to construct a third upgrader, a key step in increasing production capacity to 500,000 to 550,000 bpd in the 2010 to 2012 timeframe.

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Since Suncor is still in the early stages of recovering from the fire, specific targets for oil sands production, sales mix and cash operating costs are not currently available. Suncor will provide specifics as soon as possible.

Natural Gas

Suncor’s Natural Gas business continues to focus on increasing production by 3% to 5% per year to provide a financial hedge against natural gas use at the company’s oil sands and refining operations.

In 2005, this business is targeting natural gas production of 205 to 210 mmcf/d and crude oil and natural gas liquids production of 3,300 bpd.

Downstream Operations

In the downstream, expansion work at Suncor’s Sarnia and Denver refineries is progressing on schedule and on budget. When completed, modifications are planned to allow both facilities to process oil sands sour crude.

Other Factors

Factors that could potentially impact Suncor’s financial performance and the 2005 Outlook targets include:

•Final timing of the settlement and payment of insurance proceeds related to the fire damage and interruption of business at oil sands.

•Additional maintenance or updated maintenance schedules related to returning oil sands to full production as well as delay or extension of work to tie-in major vessels required to meet Suncor’s plans to expand operations.

•The Denver refinery is scheduled to have a 42-day maintenance shutdown during the fourth quarter. To meet customer requirements during the outage, purchases from third parties will occur.

•Ongoing volatility in global crude oil markets and North American natural gas and synthetic crude oil markets. Variability in crude oil supply may also impact Suncor’s realization on its crude oil sales basket. In the downstream, the pricing and availability of synthetic crude could also impact refining margins and profitability.

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Net Earnings Components

This table sets forth some of the factors impacting Suncor’s net earnings. For comparability purposes readers should rely on the reported net earnings that are presented in the company’s consolidated financial statements and notes in accordance with Canadian GAAP. The company’s fourth quarter financial statements (unaudited) can be obtained at www.suncor.com or by calling 1-800-558-9071.

	3 months ended		3 months ended		Year ended		Year ended
($ millions after tax)	Dec 31, 2004		Dec 31, 2003		Dec 31, 2004		Dec 31, 2003
Net earnings before the following items	358		270		1,248		1,048
Firebag in-situ start up costs	—		—		(14	)	—
Oil Sands Alberta Crown Royalties	(75	)	(5	)	(261	)	(21	)
Impact of income tax rate reductions on opening net future income tax liabilities	—		(2	)	53		(89	)
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	50		39		74		137
Net earnings as reported	333		302		1,100		1,075
Net earnings attributable to common shareholders as reported	333		302		1,088		1,085

Non GAAP Financial Measures

Suncor includes cash and total operating costs per barrel data, Return on Capital Employed (ROCE) and cash flow from operations data because investors may use this information to analyze operating performance, leverage and liquidity. The additional information may not be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with generally accepted accounting principles. Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the schedules of segmented data, which are an integral part of the company’s fourth quarter financial statements.

A summarized narrative reconciliation of ROCE for 2004 is provided in the highlights table of the company’s fourth quarter financial statements.

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The following table outlines the reconciliation of oil sands cash and total operating costs to expenses included in the schedules of segmented data in the company’s financial statements.  Amounts for base operations and Firebag in-situ reconcile to the schedules of segmented data when combined.

Oil Sands Operating Costs - Base Operations		Quarter ended Dec 31						Year ended Dec 31 (1)
		2004			2003			2004			2003
		$			$			$			$
		millions		$/barrel	millions		$/barrel	millions		$/barrel	millions		$/barrel
Operating, selling and general expenses		257			245			871			865
Less: natural gas costs and inventory changes		(62	)		(55	)		(142	)		(176	)
Accretion of asset retirement obligations		6			5			21			21
Taxes other than income taxes		7			6			28			24
Cash costs		208		10.90	201		9.25	778		9.80	734		9.25
Natural gas		41		2.20	34		1.60	158		2.00	169		2.15
Imported bitumen (net of other reported product purchases)		2		0.10	—		—	13		0.15	4		0.05
Cash operating costs	A	251		13.20	235		10.85	949		11.95	907		11.45
Start-up costs		3			2			26			10
Add: in-situ inventory changes		—			—			2			—
Less: pre-start-up commissioning costs		(3	)		(2	)		(4	)		(10	)
In-situ (Firebag) start-up costs	B	—		—	—		—	24		0.30	—		—
Total cash operating costs	A+B	251		13.20	235		10.85	973		12.25	907		11.45
Depreciation, depletion and amortization		119		6.25	117		5.40	482		6.10	458		5.80
Total operating costs		370		19.45	352		16.25	1,455		18.35	1,365		17.25
Production (thousands of barrels per day)		206.9			235.2			217.0			216.6

Oil Sands Operating Costs - Firebag In-situ Bitumen Production	Quarter ended Dec 31					Year ended Dec 31 (1)
	2004			2003		2004			2003
	$			$		$			$
	millions		$/barrel	millions	$/barrel	millions		$/barrel	millions	$/barrel
Operating, selling and general expenses	25			—		68			—
Less: natural gas costs and inventory changes	(15	)		—		(39	)		—
Accretion of asset retirement obligations	—			—		—			—
Taxes other than income taxes	—			—		—			—
Cash costs	10		7.00	—	—	29		8.30	—	—
Natural gas	15		10.45	—	—	39		11.20	—	—
Cash operating costs	25		17.45	—	—	68		19.50	—	—
Depreciation, depletion and amortization	8		5.55	—	—	21		6.00	—
Total operating costs	33		23.00	—	—	89		25.50	—	—
Production (thousands of barrels per day)	15.6					12.7

(1) Production in the base operations for the year ended December 31, 2004 includes Firebag in-situ volumes of 5,900 bpd produced in the first quarter of 2004 during the Firebag start-up period.

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Reconciliation of cash flow from operations on a per share basis

		3 months ended Dec 31		Year ended Dec 31
		2004	2003	2004	2003
Cash flow from operations ($ millions)	A	524	524	2,021	2,079
Dividends paid on Preferred Securities ($ millions, pretax)	B	—	11	9	45
Weighted average number of common shares outstanding (millions of shares)	C	454	451	453	450
Cash flow from operations (per share)	A/C	1.15	1.16	4.46	4.62
Dividends paid on Preferred Securities (pretax, per share)	B/C	—	0.03	0.02	0.10
Cash flow from operations after deducting dividends paid on Preferred Securities (per share)	(A- B)/C	1.15	1.13	4.44	4.52

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. Suncor’s oil sands business, located near Fort McMurray, Alberta, extracts and upgrades oil sands and markets refinery feedstock and diesel fuel, while operations throughout western Canada produce natural gas. Suncor operates a refining and marketing business in Ontario with retail distribution under the Sunoco brand. U.S.A. downstream assets include pipeline and refining operations in Colorado and Wyoming and retail sales in the Denver area under the Phillips 66 brand. Suncor’s common shares (symbol: SU) are listed on the Toronto and New York stock exchanges.

Sunoco in Canada is separate and unrelated to Sunoco in the United States, which is owned by Sunoco, Inc. of Philadelphia.

Legal Notice – Forward-looking Information

This news release contains certain forward-looking statements that are based on Suncor’s current expectations, estimates, projections and assumptions made in light of its experience and its perception of historical trends. All statements that address expectations or projections about the future, including statements about Suncor’s strategy for growth, expected and future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and the impact of future commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like “targets”, “targeted”, “expects”, “expected,” “plan”, “planned”, “planning”, “strategy”, “outlook”, “future growth”, “focused”, “could” and similar expressions. These statements are not guarantees of future performance as they are based on current facts and assumptions and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in the general economic, market and business conditions; fluctuations in supply and demand for our products, commodity prices and currency exchange rates; Suncor’s ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example the Firebag in-situ development project) and regulatory projects (for example, the clean fuels refinery modifications projects in our downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or preliminary stage of projects and prior to commencement or completion of detailed engineering needed to reduce the margin of error; the integrity and reliability of our capital assets; the cumulative impact of other resource development, future environmental laws; the accuracy of our reserve, resource and future production estimates and our success at exploration and development drilling and related activities; maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies,

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including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from the January 2005 fire at the oil sands facility and other uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations; the ability and willingness of parties with whom we have material relationships to perform their obligations to us, and the occurrence of unexpected events, such as the recent fire, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us. These important factors are not exhaustive. Many of these risk factors are discussed in further detail in other documents that we file from time to time with securities regulatory authorities.

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Media & Investor Inquiries:
John Rogers, vice president, Investor Relations
(403) 269-8670

Suncor’s fourth quarter financial statements and notes (unaudited) can be obtained at www.suncor.com/financialreporting or by calling 1-800-558-9071 toll-free in North America.

To listen to the conference call discussing Suncor’s 2004 results, visit http://www.suncor.com/webcasts

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Suncor Energy Inc.

Consolidated Statements of Earnings

(unaudited)

	Fourth quarter				Years ended Dec 31
($ millions)	2004		2003		2004		2003
REVENUES	2 310		1 698		8 621		6 571
EXPENSES
Purchases of crude oil and products	753		404		2 867		1 686
Operating, selling and general (notes 2 and 6)	528		441		1 769		1 478
Energy marketing and trading activities (note 3)	78		53		373		279
Transportation and other costs	36		36		132		135
Depreciation, depletion and amortization (note 2)	183		161		717		618
Accretion of asset retirement obligations (note 2)	7		5		26		25
Exploration	7		10		55		51
Royalties (note 12)	150		27		531		139
Taxes other than income taxes	125		122		496		426
(Gain) loss on disposal of assets	(19	)	(13	)	(16	)	(17	)
Project start-up costs	3		4		26		16
Financing expenses (income) (note 4)	(41	)	(20	)	9		(66	)
	1 810		1 230		6 985		4 770
EARNINGS BEFORE INCOME TAXES	500		468		1 636		1 801
PROVISION FOR INCOME TAXES (notes 2 and 9)
Current	26		(4	)	69		38
Future	141		170		467		688
	167		166		536		726
NET EARNINGS	333		302		1,100		1,075
Dividends on preferred securities, net of tax (note 11)	—		(7	)	(6	)	(27	)
Revaluation of US$ preferred securities, net of tax (note 11)	—		7		(6	)	37
Net earnings attributable to common shareholders	333		302		1 088		1 085
PER COMMON SHARE (dollars)
Net earnings attributable to common shareholders (note 5)
- basic	0.73		0.67		2.40		2.41
- diluted	0.72		0.62		2.36		2.24
Cash dividends	0.06		0.05		0.23		0.1925

See accompanying notes.

Suncor Energy Inc.

Consolidated Balance Sheets

(unaudited)

	December 31	December 31
($ millions)	2004	2003
ASSETS
Current assets
Cash and cash equivalents	88	388
Accounts receivable	627	505
Inventories	423	371
Future income taxes	57	15
Total current assets	1 195	1 279
Property, plant and equipment, net (note 2)	10 289	8 936
Deferred charges and other	320	286
Total assets	11 804	10 501
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	30	31
Accounts payable and accrued liabilities (note 12)	1 306	970
Income taxes payable	32	9
Taxes other than income taxes	41	49
Future income taxes	—	1
Total current liabilities	1 409	1 060
Long-term debt (note 10)	2 217	2 448
Accrued liabilities and other (note 2)	749	616
Future income taxes (note 2)	2 532	2 022
Shareholders’ equity (see below)	4 897	4 355
Total liabilities and shareholders’ equity	11 804	10 501

SHAREHOLDERS’ EQUITY
	Number			Number
	(thousands)			(thousands)
Preferred securities (note 11)	—	—		17 540	476
Share capital	454 241	651		451 184	604
Contributed surplus		32			7
Cumulative foreign currency translation		(55	)		(26	)
Retained earnings (note 2)		4 269			3 294
		4 897			4 355

See accompanying notes.

Suncor Energy Inc.

Consolidated Statements of Cash Flows

(unaudited)

	Fourth quarter				Years ended Dec 31
($ millions)	2004		2003		2004		2003
OPERATING ACTIVITIES
Cash flow from operations	524		524		2 021		2 079
Decrease (increase) in operating working capital
Accounts receivable	55		(17	)	(121	)	(105	)
Inventories	15		(17	)	(51	)	(19	)
Accounts payable and accrued liabilities	36		182		337		258
Taxes payable	10		(17	)	16		5
Cash flow from operating activities	640		655		2 202		2 218
CASH USED IN INVESTING ACTIVITIES	(650	)	(465	)	(1 824	)	(1 702	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	(10	)	190		378		516
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	18		24		(1	)	31
Proceeds from issuance of long-term debt	—		651		—		651
Net decrease in other long-term debt	(58	)	(516	)	(142	)	(716	)
Redemption of preferred securities (note 11)	—		—		(493	)	—
Issuance of common shares understock option plan	14		10		41		20
Dividends paid on preferred securities	—		(11	)	(9	)	(45	)
Dividends paid on common shares	(25	)	(21	)	(97	)	(81	)
Deferred revenue	15		—		26		—
Cash provided by (used in) financing activities	(36	)	137		(675	)	(140	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(46	)	327		(297	)	376
EFFECT OF FOREIGN EXCHANGE ON CASH AND CASH EQUIVALENTS	(1	)	(1	)	(3	)	(3	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	135		62		388		15
CASH AND CASH EQUIVALENTS AT END OF PERIOD	88		388		88		388

See accompanying notes.

Suncor Energy Inc.

Consolidated Statements of Changes in Shareholders’ Equity

(unaudited)

					Cumulative
					Foreign
	Preferred		Share	Contributed	Currency		Retained
($ millions)	Securities		Capital	Surplus	Translation		Earnings
At December 31, 2002, as previously reported	523		578	—	—		2 357
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—		—	—	—		(61	)
At December 31, 2002, as restated	523		578	—	—		2 296
Net earnings	—		—	—	—		1 075
Dividends paid on preferred securities, net of tax	—		—	—	—		(27	)
Dividends paid on common shares	—		—	—	—		(81	)
Issued for cash under stock option plan	—		20	—	—		—
Issued under dividend reinvestment plan	—		6	—	—		(6	)
Stock-based compensation expense	—		—	7	—		—
Foreign currency translation adjustment	—		—	—	(26	)	—
Revaluation of US$ preferred securities	(47	)	—	—	—		37
At December 31, 2003, as restated	476		604	7	(26	)	3 294
Net earnings	—		—	—	—		1 100
Dividends paid on preferred securities, net of tax	—		—	—	—		(6	)
Dividends paid on common shares	—		—	—	—		(97	)
Issued for cash under stock option plan	—		41	—	—		—
Issued under dividend reinvestment plan	—		6	—	—		(6	)
Stock-based compensation expense	—		—	25	—		—
Foreign currency translation adjustment	—		—	—	(29	)	—
Revaluation of US$ preferred securities	7		—	—	—		(6	)
Reclassification of issue costs for preferred securities	10		—	—	—		(10	)
Redemption of preferred securities (note 11)	(493	)	—	—	—		—
At December 31, 2004	—		651	32	(55	)	4 269

See accompanying notes.

Suncor Energy Inc.

Schedules of Segmented Data

(unaudited)

Fourth quarter

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003		2004		2003		2004		2003
EARNINGS
Revenues
Operating revenues	854		685		141		53		833		617		396		287		1		—		2 225		1 642
Energy marketing and trading activities	—		—		—		—		84		51		—		—		—		—		84		51
Intersegment revenues	123		121		5		62		—		—		—		—		(128	)	(183	)	—		—
Interest	—		—		—		—		—		—		—		—		1		5		1		5
	977		806		146		115		917		668		396		287		(126	)	(178	)	2 310		1 698
Expenses
Purchases of crude oil and products	—		—		—		—		571		399		312		190		(130	)	(185	)	753		404
Operating, selling and general	282		245		39		18		121		85		30		48		56		45		528		441
Energy marketing and trading activities	—		—		—		—		78		53		—		—		—		—		78		53
Transportation and other costs	25		24		5		5		1		2		5		5		—		—		36		36
Depreciation, depletion and amortization	127		117		29		24		18		15		6		4		3		1		183		161
Accretion of asset retirement obligations	6		5		1		—		—		—		—		—		—		—		7		5
Exploration	2		1		5		9		—		—		—		—		—		—		7		10
Royalties	118		9		32		18		—		—		—		—		—		—		150		27
Taxes other than income taxes	7		6		—		1		92		85		26		30		—		—		125		122
(Gain) loss on disposal of assets	(3	)	(1	)	(16	)	(12	)	(1	)	—		1		—		—		—		(19	)	(13	)
Project start-up costs	3		2		—		—		—		—		—		2		—		—		3		4
Financing expenses (income)	—		—		—		—		—		—		—		—		(41	)	(20	)	(41	)	(20	)
	567		408		95		63		880		639		380		279		(112	)	(159	)	1 810		1 230
Earnings (loss) before income taxes	410		398		51		52		37		29		16		8		(14	)	(19	)	500		468
Income taxes	(148	)	(144	)	(16	)	(13	)	(13	)	(23	)	(6	)	(4	)	16		18		(167	)	(166	)
Net earnings (loss)	262		254		35		39		24		6		10		4		2		(1	)	333		302

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003		2004		2003		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	262		254		35		39		24		6		10		4		2		(1	)	333		302
Exploration expenses	—		—		5		9		—		—		—		—		—		—		5		9
Non-cash items included in earnings
Depreciation, depletion and amortization	127		117		29		24		18		15		6		4		3		1		183		161
Income taxes	148		144		16		13		13		23		6		4		(42	)	(14	)	141		170
(Gain) loss on disposal of assets	(3	)	(1	)	(16	)	(12	)	(1	)	—		1		—		—		—		(19	)	(13	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		6		2		6		2
Other	(16	)	(2	)	(2	)	(9	)	2		3		1		(2	)	(52	)	(46	)	(67	)	(56	)
Overburden removal outlays	(59	)	(43	)	—		—		—		—		—		—		—		—		(59	)	(43	)
Increase (decrease) in deferred credits and other	(2	)	(16	)	(1	)	—		1		—		(1	)	(1	)	4		9		1		(8	)
Total cash flow from (used in) operations	457		453		66		64		57		47		23		9		(79	)	(49	)	524		524
Decrease (increase) in operating working capital	46		47		10		(7	)	50		(2	)	30		2		(20	)	91		116		131
Total cash flow from (used in) operating activities	503		500		76		57		107		45		53		11		(99	)	42		640		655
Cash from (used in) investing activities:
Capital and exploration expenditures	(340	)	(307	)	(119	)	(58	)	(96	)	(53	)	(93	)	(23	)	(6	)	(17	)	(654	)	(458	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		—		—		—		—		—		—
Deferred maintenance shutdown expenditures	(3	)	—		(1	)	—		1		(12	)	—		—		—		—		(3	)	(12	)
Deferred outlays and other investments	(6	)	(1	)	—		—		(2	)	(2	)	(1	)	3		(7	)	(12	)	(16	)	(12	)
Proceeds from disposals	3		3		19		12		1		2		—		—		—		—		23		17
Total cash (used in) investing activities	(346	)	(305	)	(101	)	(46	)	(96	)	(65	)	(94	)	(20	)	(13	)	(29	)	(650	)	(465	)
Net cash surplus (deficiency) before financing activities	157		195		(25	)	11		11		(20	)	(41	)	(9	)	(112	)	13		(10	)	190

Suncor Energy Inc.

Schedules of Segmented Data

(unaudited)

Years ended December 31

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003		2004		2003		2004		2003
EARNINGS
Revenues
Operating revenues	3 171		2 676		499		436		3 060		2 660		1 494		515		2		2		8 226		6 289
Energy marketing and trading activities	—		—		—		—		400		276		—		—		(8	)	—		392		276
Intersegment revenues	425		385		68		76		—		—		—		—		(493	)	(461	)	—		—
Interest	—		—		—		—		—		—		1		—		2		6		3		6
	3 596		3 061		567		512		3 460		2 936		1 495		515		(497	)	(453	)	8 621		6 571
Expenses
Purchases of crude oil and products	75		12		—		—		2 115		1 797		1 171		340		(494	)	(463	)	2 867		1 686
Operating, selling and general	939		865		100		73		418		359		124		68		188		113		1 769		1 478
Energy marketing and trading activities	—		—		—		—		381		279		—		—		(8	)	—		373		279
Transportation and other costs	88		101		21		24		3		3		20		7		—		—		132		135
Depreciation, depletion and amortization	503		458		115		91		69		59		22		6		8		4		717		618
Accretion of asset retirement obligations	21		21		4		3		1		1		—		—		—		—		26		25
Exploration	17		11		38		40		—		—		—		—		—		—		55		51
Royalties	407		33		124		106		—		—		—		—		—		—		531		139
Taxes other than income taxes	28		24		2		3		352		342		114		57		—		—		496		426
(Gain) loss on disposal of assets	4		(1	)	(19	)	(12	)	(2	)	(4	)	1		—		—		—		(16	)	(17	)
Project start-up costs	26		10		—		—		—		—		—		6		—		—		26		16
Financing expenses (income)	—		—		—		—		—		—		—		—		9		(66	)	9		(66	)
	2 108		1 534		385		328		3 337		2 836		1 452		484		(297	)	(412	)	6 985		4 770
Earnings (loss) before income taxes	1 488		1 527		182		184		123		100		43		31		(200	)	(41	)	1 636		1 801
Income taxes	(493	)	(639	)	(67	)	(64	)	(43	)	(47	)	(9	)	(13	)	76		37		(536	)	(726	)
Net earnings (loss)	995		888		115		120		80		53		34		18		(124	)	(4	)	1 100		1 075
As at December 31
TOTAL ASSETS	9 032		7 934		965		763		1 321		1 080		518		442		(32	)	282		11 804		10 501
CAPITAL EMPLOYED (1)	4 169		4 050		448		400		512		551		232		270		228		52		5 589		5 323

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

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003		2004		2003		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	995		888		115		120		80		53		34		18		(124	)	(4	)	1 100		1075
Exploration expenses	—		—		38		40		—		—		—		—		—		—		38		40
Non-cash items included in earnings
Depreciation, depletion and amortization	503		458		115		91		69		59		22		6		8		4		717		618
Income taxes	493		639		67		64		43		47		9		13		(145	)	(75	)	467		688
(Gain) loss on disposal of assets	4		(1	)	(19	)	(12	)	(2	)	(4	)	1		—		—		—		(16	)	(17	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		25		7		25		7
Other	(29	)	4		4		(5	)	(3	)	10		(8	)	(2	)	(78	)	(163	)	(114	)	(156	)
Overburden removal outlays	(222	)	(175	)	—		—		—		—		—		—		—		—		(222	)	(175	)
Increase (decrease) in deferred credits and other	8		(10	)	(1	)	—		1		(1	)	1		(1	)	17		11		26		(1	)
Total cash flow from (used in) operations	1 752		1 803		319		298		188		164		59		34		(297	)	(220	)	2 021		2 079
Decrease (increase) in operating working capital	71		51		(1	)	11		50		—		68		46		(7	)	31		181		139
Total cash flow from (used in) operating activities	1 823		1,854		318		309		238		164		127		80		(304	)	(189	)	2 202		2 218
Cash from (used in) investing activities:
Capital and exploration expenditures	(1 118	)	(948	)	(279	)	(183	)	(228	)	(122	)	(190	)	(31	)	(31	)	(32	)	(1,846	)	(1 316	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		—		(272	)	—		—		—		(272	)
Deferred maintenance shutdown expenditures	(4	)	(100	)	(1	)	—		(20	)	(17	)	(7	)	—		—		—		(32	)	(117	)
Deferred outlays and other investments	(9	)	(10	)	—		—		(14	)	(2	)	(1	)	3		1		(14	)	(23	)	(23	)
Proceeds from disposals	45		3		29		17		3		6		—		—		—		—		77		26
Total cash (used in) investing activities	(1 086	)	(1 055	)	(251	)	(166	)	(259	)	(135	)	(198	)	(300	)	(30	)	(46	)	(1,824	)	(1 702	)
Net cash surplus (deficiency) before financing activities	737		799		67		143		(21	)	29		(71	)	(220	)	(334	)	(235	)	378		516

NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

(unaudited)

1.Accounting Policies

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

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

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

2.Asset Retirement Obligations

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

Change in Consolidated Balance Sheets

	As at December 31
($ millions, increase/(decrease))	2004		2003
Property, plant and equipment	284		211
Future income tax assets	33		37
Total assets	317		248
Accounts payable and accrued liabilities	—		(2	)
Accrued liabilities and other	382		320
Retained earnings	(65	)	(70	)
Total liabilities and shareholders’ equity	317		248

Change in Consolidated Statements of Earnings

	Fourth Quarter				Years ended December 31
($ millions, increase/(decrease))	2004		2003		2004		2003
Depreciation, depletion and amortization	2		2		9		7
Accretion of asset retirement obligations	7		5		26		25
Operating, selling and general expenses	(11	)	(12	)	(43	)	(29	)
Future income taxes	—		3		3		6
Net earnings	2		2		5		(9	)
Per common share – basic (dollars)	—		—		0.01		(0.02	)
Per common share – diluted (dollars)	—		—		0.01		(0.02	)

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

	As at December 31
($ millions)	2004		2003
Asset retirement obligations, beginning of year	401		400
Liabilities incurred	82		—
Liabilities settled	(33	)	(24	)
Accretion of asset retirement obligations	26		25
Asset retirement obligations, end of period	476		401

The total undiscounted amount of estimated cash flows required to settle the obligation at December 31, 2004 is approximately $1.1 billion (2003 - $1.0 billion), and has been discounted using a credit-adjusted risk free rate of 6%. Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

A significant portion of the company’s assets have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life.  The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.

3.Energy Marketing and Trading Activities

In addition to those financial derivatives used for hedging activities, the company also uses energy derivatives, including physical and financial swaps, forwards and options to gain market information and earn trading revenues.  These energy trading activities are accounted for using the mark-to-market method and as such physical and financial energy contracts are recorded at fair value at each balance sheet date.   For the quarter ended December 31, 2004, a net pretax gain of $2 million (2003 – $nil) from the settlement and revaluation of financial contracts was

reported as energy marketing and trading activities in the Consolidated Statements of Earnings.  In the fourth quarter the settlement of physical trading activities also resulted in a net pretax gain of $5 million (2003 – pretax loss of $2 million).  For the year ended December 31, 2004 a pretax gain of $11 million was recorded on financial contracts (2003 – pretax loss of $3 million).  Year to date settlement of physical trading activities resulted in a net pretax gain of $12 million (2003 - pretax gain of $2 million).  The above amounts do not include the impact of related general and administrative costs.

The fair values of unsettled (unrealized) energy trading assets and liabilities as at December 31 are as follows:

($ millions)	2004	2003
Energy trading assets	26	5
Energy trading liabilities	9	5

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

4.Financing Expenses (Income)

	Fourth quarter				Years ended December 31
($ millions)	2004		2003		2004		2003
Interest on debt	36		37		148		140
Capitalized interest	(22	)	(19	)	(61	)	(57	)
Net interest expense	14		18		87		83
Foreign exchange (gain) on long-term debt	(60	)	(43	)	(89	)	(166	)
Other foreign exchange loss	5		5		11		17
Total financing expenses (income)	(41	)	(20	)	9		(66	)

5.Reconciliation of Basic and Diluted Earnings Per Common Share

	Fourth quarter				Years ended December 31
($ millions)	2004		2003		2004		2003
Net earnings attributable to common shareholders	333		302		1 088		1 085
Dividends on preferred securities, net of tax	—	(a)	7		—	(a)	27
Revaluation of US$ preferred securities, net of tax	—	(a)	(7	)	—	(a)	(37	)
Adjusted net earnings attributable to common shareholders	333		302		1 088		1 075
(millions of common shares)
Weighted-average number of common shares	454		451		453		450
Dilutive securities:
Options issued under stock-based compensation plans	8		16		9		8
Redemption of preferred securities by the issuance of common shares	—	(a)	20		—	(a)	22
Weighted-average number of diluted common shares	462		487		462		480
(dollars per common share)
Basic earnings per share (b)	0.73		0.67		2.40		2.41
Diluted earnings per share (c)	0.72		0.62		2.36		2.24

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 year ended December 31, 2004, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares.  Dividends on preferred securities, the revaluation of US$ preferred securities and the redemption of preferred securities by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share.  The company redeemed its preferred securities in the first quarter of 2004 and accordingly, no revaluations or dividends were recorded in the fourth quarter of 2004.

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

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

6.Stock-based Compensation

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

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

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

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

(a)Stock option plans:

Under the SunShare long-term incentive plan, the company granted 290,000 options in the fourth quarter of 2004, for a total of 1,742,000 options granted in the year ended December 31, 2004 (218,000 options granted during the fourth quarter of 2003;  1,305,000 granted in the year ended December 31, 2003).

In October 2004, the company met the predetermined performance criteria for the accelerated vesting of 2,097,000 common share options granted to executive and non-executive employees.  The vested options represented approximately 20% of the then outstanding common share options granted under the Sunshare plan.  An additional 2,062,000 options, representing approximately 20% of outstanding Sunshare options, will vest on January 31, 2005  in connection with the achievement of the second predetermined performance criterion.  The remaining 60% of outstanding Sunshare options may vest on April 30, 2008. All unvested Sunshare options, which have not previously expired or been cancelled, will automatically vest on January 1, 2012.

Under the company’s other plans, 61,000 options were granted in the fourth quarter of 2004, for a total of 1,346,000 options granted during the year ended December 31, 2004 (4,000 options granted during the fourth quarter of 2003;  1,902,000 granted in the year ended December 31, 2003).

In November 2004, the Board of Directors gave final approval to the establishment of the new Key Contributor stock option plan, under which 5,200,000 options were made available for grant to senior managers and key employees. The Board of Directors also approved an additional 3,000,000 options available for grant under the Sunshare plan.

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:

	Fourth quarter						Years ended December 31
	2004			2003			2004			2003
Quarterly dividend per share	$	0.06		$	0.05		$	0.06	*	$	0.05	*
Risk-free interest rate	4.02		%	4.15		%	3.79		%	4.39		%
Expected life	6 years			8 years			6 years			7 years
Expected volatility	28		%	29		%	29		%	32		%
Weighted-average fair value per option	$	13.70		$	9.36		$	12.02		$	9.94

* In 2004, a quarterly dividend of $0.05 per share was paid in the first quarter, and quarterly dividends of $0.06 were paid in the second, third and fourth quarters. In 2003, a quarterly dividend of $0.0425 per share was paid in the first quarter, and quarterly dividends of $0.05 were paid in the second, third and fourth quarters.

Stock-based compensation expense recognized in the fourth quarter of 2004 related to stock option plans was $6 million (2003 - $2 million).  For the year ended December 31, 2004 stock-based compensation expense recognized related to stock option plans was $25 million (2003 - $7 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:

	Fourth quarter		Years ended December 31
($ millions, except per share amounts)	2004	2003	2004	2003
Net earnings attributable to common shareholders—as reported	333	302	1 088	1 085
Less: compensation cost under the fair value method for pre- 2003 options	6	6	47	30
Pro forma net earnings attributable to common shareholders for pre-2003 options	327	296	1 041	1 055
Basic earnings per share
As reported	0.73	0.67	2.40	2.41
Pro forma	0.72	0.66	2.30	2.35
Diluted earnings per share
As reported	0.72	0.62	2.36	2.24
Pro forma	0.71	0.61	2.26	2.18

(b) Performance share units (PSUs)

In the fourth quarter of 2004 the company issued 1,000 PSUs under its employee incentive compensation plan (354,000 PSUs issued for the year ended December 31, 2004).  PSUs granted replace the remuneration value of reduced grants under the company’s stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor’s performance. Performance is measured by reference to the Company’s total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the probability of vesting.  This expense is recognized on a straight-line basis over the term of the grant.  Pretax expense recognized for PSUs in the fourth quarter of 2004 was $2 million ($5 million for the year ended December 31, 2004).

7.Employee Future Benefits Liability

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

	Fourth quarter				Pension Benefits Years ended December 31
	2004		2003		2004		2003
Current service costs	7		4		25		18
Interest costs	9		8		34		32
Expected return on plan assets	(7	)	(5	)	(25	)	(20	)
Amortization of net actuarial loss	5		6		19		22
Net periodic benefit cost	14		13		53		52

	Fourth quarter		Other Post-retirement Benefits Years ended December 31
	2004	2003	2004	2003
Current service costs	1	1	5	3
Interest costs	2	1	7	6
Amortization of net actuarial loss	—	—	1	1
Net periodic benefit cost	3	2	13	10

8.Supplemental Information

	Fourth quarter		Years ended December 31
($ millions)	2004	2003	2004	2003
Interest paid	18	9	143	139
Income taxes paid	12	6	50	45

Strategic crude oil hedges at December 31, 2004

	Quantity (bbl/day)	Average Price (US$ /bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Swaps	36 000	22.77	360	2005

Margin hedges at December 31, 2004

	Quantity (bbl/day)	Average Margin (US$ /bbl)	Margin Hedged (Cdn$ millions) (b)	Hedge Period
Refined product and crude swaps	6 300	7.48	16	2005	(d)

Natural gas hedges at December 31, 2004

	Quantity (GJ/day)	Average Price (Cdn$ /GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period
Costless Collars	10 000	7.50 - 9.04	7 - 8	2005	(e)
Swaps	4 000	6.99	10	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 December 31, 2004 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

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

(d)For the period January to September 2005 inclusive.

(e)For the period January to March 2005 inclusive.

9.Income Taxes

During the first quarter of 2004 the province of Alberta substantively enacted a 1% reduction to its provincial corporate tax rates.  Accordingly, the company recognized a reduction in future income tax expense of $53 million related to the revaluation of its opening future income tax balances.

10.Long-term Debt

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

During the third quarter, the company renewed its available credit and term loan facilities.  At December 31, 2004 the company had available facilities as follows:

($ millions)
Facility that is fully revolving for a period of three years and expires in 2007	1 500
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2006	200
Facilities that can be terminated at any time at the option of the lenders	30
Total available credit facilities	1 730

11.Preferred Securities

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

12.Alberta Crown Royalties

Alberta Crown royalties in effect for each Oil Sands Project are based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of capital expenditures (the 25% R-C royalty) for each project, subject to a minimum payment of 1% of R.  Firebag is being treated by the government of Alberta as a separate Project from the rest of the Oil Sands operations for royalty purposes.  The 2004 calendar year is a transitional year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million would be claimed before the 25% R-C royalty applies to current year results. In 2003, the company was subject to the minimum payment of 1% of R.

Crown royalty expense for the company’s Oil Sands operation for the fourth quarter was $118 million (2003 - $9 million).  For the year ended December 31, 2004 Crown royalty expense was $407 million (2003 - $33 million).

13.Subsequent Event

On January 4, 2005 a fire occurred at the company’s Oil Sands operations.  The fire was confined to one of the Upgraders, primarily affecting a coker fractionator.  Production capacity at the Oil Sands facility will be reduced from about 225,000 barrels per day to approximately 110,000 barrels per day during the investigation and repair of the fire-related damage.

The company carries property loss and business interruption insurance policies with a combined coverage limit of up to US$1.15 billion, net of deductible amounts, that will mitigate a portion of the financial impact of this incident.  The primary property loss policy of US$250 million has a deductible of US$10 million per incident and the primary business interruption policy of US$200 million has a deductible per incident of the greater of US$50 million gross earnings lost (as defined in the insurance policy) or 30 days from the incident.  In addition to these primary coverage insurance policies, Suncor has excess coverage of US$ 700 million that can be used

for either property loss or business interruption coverage.  For business interruption purposes this excess coverage begins the later of full utilization of the primary business interruption coverage or 90 days from the date of the incident.

As the company is still evaluating the effect of the fire on its operations, the financial impact of this incident is currently not determinable.

14.Consolidation of Variable Interest Entities

In 2003 Canadian Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities” (VIEs) was issued.  Effective January 1, 2005 AcG 15 requires consolidation of a VIE where the company will absorb a majority of a VIE’s losses, receive a majority of its returns, or both.  The company will be required to consolidate the VIE related to the sale of equipment as described in note 10(c) on page 78 of the company’s 2003 Annual Report.  The company does not expect a significant impact on net income upon consolidation of the equipment VIE.  The impact on the balance sheet upon adoption in 2005 will be an increase to property, plant and equipment and an increase to liabilities of approximately $20 million. The accounts receivable securitization program, as currently structured, does not meet the AcG 15 criteria for consolidation by Suncor.

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

The company is currently evaluating the impact of AcG 15 on other arrangements.

Suncor Energy Inc.

Highlights

(unaudited)

		2004	2003
CASH FLOW FROM OPERATIONS
(dollars per common share)
For the quarters ended December 31
Cash flow from operations (1)		1.15	1.16
Dividends paid on preferred securities (pretax) (2)		—	0.03
Cash flow from operations after deducting dividends paid on preferred securities (3)		1.15	1.13
For the years ended December 31
Cash flow from operations (1)		4.46	4.62
Dividends paid on preferred securities (pretax) (2)		0.02	0.10
Cash flow from operations after deducting dividends paid on preferred securities (3)		4.44	4.52
RATIOS
For the years ended December 31
Return on capital employed (%) (4)		19.1	18.4
Return on capital employed (%) (5)		16.2	16.0
Net debt to cash flow from operations (times) (6)		1.1	1.0
Interest coverage on long-term debt (times)
Net earnings (7)		11.6	13.5
Cash flow from operations (8)		14.7	15.7
As at December 31
Debt to debt plus shareholders’ equity (%) (9)		31.4	36.3
COMMON SHARE INFORMATION
As at December 31
Share price at end of trading
Toronto Stock Exchange	- Cdn$	42.40	32.50
New York Stock Exchange	- US$	35.40	25.06
Common share options outstanding (thousands)		20 687	21 016
For the years ended December 31
Average number outstanding, weighted monthly (thousands)		452 910	449 753
Refer to the Quarterly Operating Summary for a discussion of financial measures not prepared in accordance with generally accepted accounting principles (GAAP).
(1) Cash flow from operations for the period; divided by the weighted average number of common shares outstanding during the period.
(2) Dividends paid on preferred securities for the period, before income taxes; divided by the weighted-average number of common shares outstanding during the period.
(3) Cash flow from operations minus pretax dividends paid on preferred securities, for the period; divided by the weighted-average number of common shares outstanding for the period.
(4) Net earnings (2004 - $1,100 million; 2003 - $1,075 million) adjusted for after-tax financing expenses (2004 - income of $10 million; 2003 - income of $75 million) for the twelve month period ended; divided by average capital employed (2004 - $5,696 million; 2003 - $5,441 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 average 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 example of the reconciliation of ROCE prepared on an annual basis, see page 50 of Suncor’s 2003 Annual Report to Shareholders.
(5) If capital employed were to include capitalized costs related to major projects in progress (average capital employed including major projects in progress: 2004 - $6,720 million; 2003 - $6,258 million), the return on capital employed would be as stated on this line.
(6) Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations for the twelve month period then ended.
(7) Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.
(8) Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(9) Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders’ equity.

Suncor Energy Inc.

Quarterly Operating Summary

(unaudited)

	For the quarter ended					Years ended
	Dec 31	Sept 30	June 30	Mar 31	Dec 31	Dec 31	Dec 31
	2004	2004	2004	2004	2003	2004	2003
OIL SANDS
Production (a)
Base operations	206.9	230.2	210.8	213.9	235.2	215.6	216.6
Firebag	15.6	7.3	15.1	5.9	—	10.9	—
Total production	222.5	237.5	225.9	219.8	235.2	226.5	216.6
Sales (a)
Light sweet crude oil	115.3	113.5	118.7	112.2	132.7	114.9	112.3
Diesel	25.5	28.7	29.7	27.5	27.2	27.9	26.3
Light sour crude oil	80.9	76.3	68.9	74.3	81.3	75.1	73.3
Bitumen	11.0	7.9	14.5	—	8.3	8.4	6.4
Total sales	232.7	226.4	231.8	214.0	249.5	226.3	218.3
Average sales price (1), (b)
Light sweet crude oil	50.55	46.03	45.70	40.26	36.67	45.60	40.26
Other (diesel, light sour crude oil and bitumen)	39.62	42.29	38.28	35.85	30.72	39.13	33.93
Total	44.68	44.08	41.88	38.16	33.89	42.28	37.19
Total *	54.40	52.72	48.18	43.28	36.63	49.78	40.22
Cash operating costs and Total operating costs - Base operations
Cash costs	10.90	9.00	9.75	9.65	9.25	9.80	9.25
Natural gas	2.20	1.40	2.30	2.10	1.60	2.00	2.15
Imported bitumen	0.10	0.10	0.05	0.40	—	0.15	0.05
Cash operating costs (2),(c)	13.20	10.50	12.10	12.15	10.85	11.95	11.45
Firebag start-up costs	—	—	—	1.20	—	0.30	—
Total cash operating costs (3),(c)	13.20	10.50	12.10	13.35	10.85	12.25	11.45
Depreciation, depletion and amortization	6.25	5.70	6.15	6.20	5.40	6.10	5.80
Total operating costs (4),(c)	19.45	16.20	18.25	19.55	16.25	18.35	17.25
Cash operating costs and Total operating costs - Firebag
Cash costs	7.00	14.90	6.55	—	—	8.30	—
Natural gas	10.45	11.90	11.65	—	—	11.20	—
Cash operating costs (5),(c)	17.45	26.80	18.20	—	—	19.50	—
Depreciation, depletion and amortization	5.55	7.45	5.80	—	—	6.00	—
Total operating costs (6),(c)	23.00	34.25	24.00	—	—	25.50	—
(for the period ended)
Capital employed (i)	4 169	4 182	4 525	4 725	4 050
(for the twelve months ended)
Return on capital employed (j)	22.9	22.8	22.6	18.1	20.8
Return on capital employed (j) ****	18.8	19.0	19.2	16.0	17.4

	For the quarter ended					Years ended
	Dec 31	Sept 30	Jun 30	Mar 31	Dec 31	Dec 31	Dec 31
	2004	2004	2004	2004	2003	2004	2003
NATURAL GAS
Gross production **
Natural gas (d)	193	201	209	197	194	200	187
Natural gas liquids (a)	2.9	2.6	2.2	2.2	2.4	2.5	2.3
Crude oil (a)	1.0	1.0	1.1	0.9	1.0	1.0	1.4
Total gross production (e)	36.1	37.1	38.1	35.9	35.7	36.8	34.9
Average sales price (1)
Natural gas (f)	7.02	6.49	6.77	6.54	5.53	6.70	6.42
Natural gas (f) *	6.98	6.53	6.84	6.59	5.51	6.73	6.42
Natural gas liquids (b)	46.46	42.06	43.53	38.13	35.45	42.82	36.08
Crude oil - conventional(b)	55.26	55.43	47.08	44.14	36.91	50.41	40.29
Net wells drilled
Conventional - exploratory ***	—	3	3	4	5	10	33
- development	5	3	—	8	6	16	21
	5	6	3	12	11	26	54
(for the period ended)
Capital employed (i)	448	410	421	418	400
(for the twelve months ended)
Return on capital employed (j)	27.1	30.4	29.9	27.7	29.2
ENERGY MARKETING AND REFINING—CANADA
Refined product sales (g)
Transportation fuels
Gasoline - retail	4.8	4.6	4.5	4.2	4.4	4.6	4.4
- other	4.1	4.3	4.1	4.0	3.9	4.1	4.2
Jet fuel	1.0	1.0	0.7	1.0	0.7	0.9	0.7
Diesel	3.3	3.0	3.1	2.9	3.1	3.1	3.0
Total transportation fuel sales	13.2	12.9	12.4	12.1	12.1	12.7	12.3
Petrochemicals	0.8	0.7	0.6	0.9	0.7	0.8	0.8
Heating oils	0.5	0.2	0.3	0.8	0.5	0.4	0.5
Heavy fuel oils	0.8	0.5	0.7	0.8	0.5	0.7	0.8
Other	0.3	1.0	1.5	0.6	0.4	0.8	0.6
Total refined product sales	15.6	15.3	15.5	15.2	14.2	15.4	15.0
Margins (h)
Refining (7)	7.9	8.8	7.4	7.8	7.0	8.0	6.5
Refining (7) *	7.8	8.8	8.0	7.8	6.9	8.1	6.4
Retail (8)	4.5	3.7	4.3	5.0	6.3	4.4	6.6
Crude oil supply and refining
Processed at Sarnia refinery (g)	11.3	11.6	9.5	12.0	9.6	11.1	10.5
Utilization of refining capacity (j)	101	104	85	108	86	100	95
(for the period ended)
Capital employed (i)	512	528	587	567	551
(for the twelve months ended)
Return on capital employed (j)	14.6	11.2	7.8	11.8	10.3
Return on capital employed (j) ****	13.6	10.8	7.8	11.8	10.3

	For the quarter ended					Years ended
	Dec 31	Sept 30	Jun 30	Mar 31	Dec 31	Dec 31	Dec 31
	2004	2004	2004	2004	2003	2004	2003
REFINING AND MARKETING—U.S.A. *****
Refined product sales (g)
Transportation fuels
Gasoline - retail	0.7	0.7	0.6	0.7	0.7	0.7	0.7
- other	3.9	4.3	3.6	3.4	3.4	3.8	3.5
Jet fuel	0.6	0.7	0.5	0.4	0.5	0.5	0.5
Diesel	2.5	2.5	1.9	2.2	2.3	2.2	2.3
Total transportation fuel sales	7.7	8.2	6.6	6.7	6.9	7.2	7.0
Asphalt	1.1	1.9	1.8	1.2	1.4	1.5	1.7
Other	0.7	0.8	0.5	0.2	0.3	0.6	0.4
Total refined product sales	9.5	10.9	8.9	8.1	8.6	9.3	9.1
Margins (h)
Refining (7)	7.7	5.1	9.0	5.0	4.6	6.7	5.9
Refining (7) *	7.7	5.3	9.3	5.0	4.6	6.8	5.9
Retail (8)	6.0	4.2	6.2	5.0	4.8	5.4	5.6
Crude oil supply and refining
Processed at Denver refinery (g)	9.5	9.5	8.2	8.1	9.2	8.8	9.4
Utilization of refining capacity (j)	100	99	86	85	96	92	98
(for the period ended)
Capital employed (i)	232	241
(for the twelve months ended)
Return on capital employed (j)	12.2	10.0
Return on capital employed (j) ****	11.0	9.6

Non GAAP Financial Measures

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

Definitions

(1) Average sales price	• This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(2) Cash operating costs - Base operations	• Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on production volumes. For a reconciliation of this non GAAP financial measure see the fourth quarter 2004 earnings release available at www.sedar.com.
(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 and other adjustments, less refining gasoline transfer price.

Explanatory Notes
*	Excludes the impact of hedging activities.
**	Currently all Natural Gas production is located in the Western Canada Sedimentary Basin.
***	Excludes exploratory wells in progress.
****	If capital employed were to include capitalized costs related to major projects in progress, the return on capital
	employed would be as stated on this line.
*****	Refining and Marketing-U.S.A. reflects the results of operations since acquisition on August 1, 2003.

(a)   thousands of barrels per day

(b)  dollars per barrel

(c)   dollars per barrel rounded to the nearest $0.05

(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