6-K

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.   20549

Report of Foreign Private Issuer
Pursuant to Rule 13a - 16 or 15d - 16 of
the Securities Exchange Act of 1934

For the month of:  July 2004 Commission File Number:  1-12384

SUNCOR ENERGY INC.

(Name of registrant)

112 Fourth Avenue S.W.

P.O. Box 38

Calgary, Alberta

Canada, T2P 2V5

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F o Form 40-F ý

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the SEC pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

Yes o No ý

If “Yes” is marked, indicate the number assigned to the registrant in connection with Rule 12g3-2(b):

N/A

CONTROLS AND PROCEDURES

A.Disclosure Controls and Procedures

See pages 9 and 10 of Exhibit 2.

B.Changes in Internal Control Over Financial Reporting

See pages 9 and 10 of Exhibit 2.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SUNCOR ENERGY INC.
Date:	By:
July 28, 2004		/s/ “JANICE B. ODEGAARD”
		JANICE B. ODEGAARD Vice President, Associate General Counsel and Corporate Secretary

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EXHIBIT INDEX

Exhibit	Description of Exhibit
1	Press Release Including 2004 Outlook
2	Interim Management’s Discussion and Analysis for the second fiscal quarter ended June 30, 2004
3	Interim Unaudited Financial Statements of Suncor Energy Inc. for the second fiscal quarter ended June 30, 2004
4	Certificate of the President and Chief Executive Officer Pursuant to Exchange Act Rule 13a-14 or Rule 15d-14, as Enacted Pursuant to Section 302 of Sarbanes-Oxley Act of 2002
5	Certificate of the Senior Vice President and Chief Financial Officer Pursuant to Exchange Act Rule 13a-14 or Rule 15d-14, as Enacted Pursuant to Section 302 of Sarbanes-Oxley Act of 2002
6	Certificate of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002
7	Certificate of the Senior Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

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EX-1

EXHIBIT 1

Press Release Including 2004 Outlook

second quarter 2004

REPORT TO SHAREHOLDERS FOR THE PERIOD ENDED JUNE 30, 2004

Higher production and strong commodity prices deliver increased second quarter earnings and cash flow for Suncor Energy

All financial figures are unaudited and in Canadian dollars unless noted otherwise. Certain prior period comparative 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 second quarter Management’s Discussion and Analysis. 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’s may be misleading, particularly if used in isolation. Base operations refer to oil sands mining and upgrading operations.

Suncor Energy Inc. reported second quarter net earnings of $203 million ($0.44 per common share), compared to $116 million ($0.27 per common share) in the second quarter of 2003. Excluding the effects of unrealized foreign exchange losses on the company’s U.S. dollar denominated long-term debt, 2004 second quarter net earnings were $228 million ($0.50 per common share). Cash flow from operations was $490 million in the second quarter, compared to $358 million in the second quarter of 2003.

The improved financial results were primarily due to higher crude oil and natural gas production, higher benchmark commodity prices and lower income taxes. These positive impacts were partially offset by higher oil sands royalties and hedging losses, the impact of scheduled and unscheduled maintenance shutdowns, a stronger Canadian dollar, and foreign exchange losses on U.S. dollar denominated long-term debt.

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“Very good oil sands production in May and strong natural gas volumes throughout the quarter have kept Suncor’s production curve moving in the right direction. We’re looking to maintain that momentum in the second half when we expect to see further production increases from our Firebag operations.”  Rick George  president and chief executive officer

“Operational excellence will continue to be the focus for the second half of 2004, as we diligently work on the aspects of our business we can control. Delivering steady, reliable production and controlling costs are key to strengthening our financial results and generating improved value for shareholders,” says Rick George, president and chief executive officer.

Net earnings for the first six months of 2004 were $430 million ($0.92 per common share), compared to $482 million ($1.10 per common share) in the first six months of 2003. Year-to-date cash flow from operations was $912 million, compared to $971 million during the first half of 2003.

Oil sands production during the second quarter averaged 225,900 barrels per day (bpd), comprising 210,800 bpd from base operations and 15,100 bpd of bitumen from the company’s Firebag in-situ operations. Production was lower than expected due to unscheduled maintenance in June. These figures compare to production of 188,200 bpd in the second quarter of 2003, when operations were impacted by a 30-day planned maintenance shutdown. Production in 2003 does not include volumes from Firebag, which began producing bitumen in early 2004.

Second quarter cash operating costs from oil sands base operations averaged $12.10 per barrel.

Natural gas production for the second quarter of 2004 increased 19% to an average 209 million cubic feet (mmcf) per day from 175 mmcf per day in the same period of 2003. As a result of strong production in the second quarter, Suncor has increased annual natural gas production targets to 195 to 200 mmcf per day from 190 to 195 mmcf per day.

Suncor’s combined oil sands and natural gas production increased to 264,000 barrels of oil equivalent (boe) in the second quarter of 2004, compared to 221,000 boe in the same period of 2003.

“Very good oil sands production in May and strong natural gas volumes throughout the quarter have kept Suncor’s production curve moving in the right direction,” said George. “We’re looking to maintain that momentum in the second half when we expect to see further production increases from our Firebag operations.”

In Suncor’s downstream operations, portions of the company’s Sarnia, Ontario refinery were shut down for both scheduled and unscheduled maintenance between April 7 and June 1. Planned maintenance was also completed at the company’s Denver refinery in April. To fulfill customer contracts during the maintenance period, Suncor increased purchases of gasoline from third-party suppliers at market prices, which were above historical averages.

Growth Update

Suncor’s next major growth stage targets oil sands production capacity of 260,000 bpd in 2005. Construction of a second vacuum unit, a key component to reaching that milestone, is 65% complete. Construction of Firebag Stage 2, which is planned to provide bitumen supplies to future upgrader expansions, is 25% complete with steaming planned to start in late 2005. Both projects are on schedule and on budget.

Preliminary planning for construction of a proposed third upgrader near the company’s existing oil sands facilities is now under way. As part of the regulatory process, Suncor is preparing an Environmental Impact Assessment (EIA) to identify potential environmental impacts and mitigation strategies related to the proposed expansion. The proposed upgrader is central to Suncor’s plan to increase production capacity to 500,000 to 550,000 bpd in 2010 to 2012.

As Suncor plans for future growth, prudent debt management remains a priority. In the second quarter, net debt was reduced to approximately $2.5 billion from $2.6 billion at March 31, 2004.

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•Outlook for 2004

Suncor’s Outlook provides management’s targets for 2004 in certain key areas of the company’s business.

	Year to Date Actual		2004 Full Year Outlook
Oil Sands Base Operations
Production (bpd) (1)	212,400		220,000
Production mix
Light sweet	52	%	57	%
Diesel	13	%	13	%
Light sour/bitumen	35	%	30	%
Realization on crude sales basket	WTI (2) @ Cushing less		WTI @ Cushing less
	Cdn$3.40 per barrel		Cdn$3.00 to $4.00 per barrel
Cash operating costs (3)	$12.15 per barrel		$12.00 to $12.50 per barrel
Oil Sands Firebag In-situ
Bitumen production (bpd) (4)	10,500		15,000
Natural Gas
Natural gas production (5)	203 mmcf/d		195 to 200 mmcf/d
Crude oil and natural gas liquids	3,200 bpd		3,300 bpd

(1)As a result of lower than anticipated production during the second quarter, Suncor revised its annual oil sands production targets on July 7, 2004. The original target for base operations was 225,000 to 230,000 bpd. Targeted annual production from base operations does not reflect bitumen production from Firebag in-situ operations.

(2)WTI – West Texas Intermediate

(3)As a result of higher natural gas prices and the effects of unplanned maintenance and lower than expected production, Suncor revised its annual cash operating cost targets for base operations. The original target was $10.75 to $11.75 per barrel at an assumed natural gas price of US$5.50 per mcf at Henry Hub. The revised cash operating cost outlook assumes a natural gas price of US$6.30/mcf of natural gas at Henry Hub. During the second quarter natural gas at Henry Hub averaged US$5.95/mcf.

Cash operating costs per barrel are a non-GAAP financial measure. Suncor includes cash operating costs per barrel data because investors may use this information to analyze operating performance and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Readers are directed to the Management’s Discussion and Analysis for further details on the calculation of cash operating costs per barrel.

(4)In-situ production is expected to increase throughout 2004 with annual average production for the year targeted at approximately 15,000 bpd. This assumes average production in the second half of approximately 20,000 bpd.

(5)As a result of higher than anticipated production in the second quarter, Suncor increased targeted annual natural gas production. The original target was 190 to 195 mmcf/d.

Factors that could potentially impact Suncor’s financial performance and targets over the remainder of the year include:

•Ongoing volatility in Canadian/U.S. currency exchange rates.

•Ongoing volatility in global crude oil markets and North American natural gas and synthetic crude oil markets. The impact of additional synthetic crude oil supply periodically introduced to North American markets may also impact Suncor’s realization on its crude oil sales basket.

•Ongoing variability in refining and retail margins.

•Unscheduled maintenance shutdowns of upgrading, processing and refining operations, which can increase costs and impact production and sales.

•Oil sands Crown royalty payments. Crown royalties are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates, and total capital and operating costs for each Project. Readers are directed to Management’s Discussion and Analysis, “Analysis of Segmented Earnings and Cash Flow – Oil Sands” on page 6.

•Suncor’s ability to complete future projects both on schedule and on budget. This could be impacted by competition from other projects for skilled labour, increased demands on the Fort McMurray infrastructure (housing, roads, schools, etc.) or higher prices for the products and services required to maintain or expand operations. Suncor continues to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing oil sands expansion to reduce unit costs, seeking strategic alliances with service providers and maintaining a strong focus on engineering, procurement and construction management.

•Extreme cold weather in the fourth quarter may negatively impact oil sands production, natural gas consumption and transportation of products.

The foregoing summary contains forward-looking statements. Readers are directed to the Management’s Discussion and Analysis, “Legal Notice – Forward-looking Information” on page 12, which also applies to the forward-looking statements in the summary.

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EX-2

EXHIBIT 2

Interim Management’s Discussion and Analysis for the second fiscal quarter ended June 30, 2004

management’s discussion and analysis

July 26, 2004

This Management’s Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 12 for additional information.

This MD&A should be read in conjunction with Suncor’s June 30, 2004 unaudited interim consolidated financial statements and notes. Readers should also refer to Suncor’s 2003 Annual Information Form and Management’s Discussion and Analysis on pages 16 to 51 of Suncor’s 2003 Annual Report. All financial information is reported in Canadian dollars and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash operating costs, referred to in this MD&A, are not prescribed by GAAP and are outlined and reconciled in “Non-GAAP Financial Measures” on page 10.

Certain amounts in prior years have been reclassified to enable comparison with the current year’s presentation.

Base operations refers to Oil Sands mining and upgrading operations.

Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) 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.

References to “Suncor” or “the company” mean Suncor Energy Inc., its subsidiaries and joint venture investments, unless the context otherwise requires.

The tables and charts in this document form an integral part of this MD&A.

Additional information about Suncor filed with Canadian securities commissions and the United States Securities and Exchange Commission, including quarterly and annual reports and the Annual Information Form (AIF/40-F) is available on-line at www.sedar.com and www.sec.gov.

INDUSTRY INDICATORS

	3 months ended June 30		6 months ended June 30
(average for the period)	2004	2003	2004	2003
West Texas Intermediate (WTI) crude oil US$/barrel @ Cushing	38.30	28.90	36.75	31.40
Canadian 0.3% par crude oil Cdn$/barrel @ Edmonton	51.00	41.60	48.50	46.50
Light/heavy crude oil differential US$/barrel – WTI @ Cushing less Bow River @ Hardisty	11.00	6.55	10.05	7.05
Natural gas US$/mcf @ Henry Hub	5.95	5.50	5.85	6.05
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.80	7.00	6.70	7.45
New York Harbour 3-2-1 crack (1) US$/barrel	8.90	3.55	7.90	4.95
Exchange rate: Cdn$:US$	0.74	0.72	0.75	0.69

(1)New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking two times the New York Harbour gasoline margin plus one times the New York Harbour distillate margin and dividing by three.

SELECTED FINANCIAL INFORMATION

Outstanding Share Data(as at June 30, 2004)
Common shares	452 928 675
Common share options	21 638 518
Common share options – exercisable	8 233 599

Summary of Quarterly Results

	2004 Quarter ended		2003 Quarter ended				2002 Quarter ended
($ millions, except per share data)	June 30	Mar. 31	Dec. 31	Sep. 30	June 30	Mar. 31	Dec. 31	Sep. 30
Revenues	2 201	1 795	1 698	1 788	1 385	1 700	1 409	1 257
Net earnings	203	227	302	291	116	366	256	183
Net earnings attributable to common shareholders per share
Basic	0.44	0.48	0.67	0.63	0.27	0.84	0.55	0.38
Diluted	0.43	0.46	0.61	0.62	0.24	0.77	0.54	0.37

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ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the second quarter of 2004 were $203 million, compared to $116 million for the second quarter of 2003. The increase in net earnings in 2004 was primarily due to higher crude oil and natural gas production, as well as higher benchmark commodity prices. This was partially offset by higher Oil Sands royalties, higher hedging losses, the effects of maintenance shutdowns in both of the company’s downstream operations, foreign exchange losses on U.S. dollar denominated long-term debt, and a 3% strengthening in the Canadian dollar that decreased operating revenues. Earnings in the second quarter of 2003 were impacted by a planned maintenance shutdown in Oil Sands as well as a one-time non-cash income tax adjustment related to changes in federal and provincial tax policies and rates.

Cash flow from operations in the second quarter was $490 million, compared to $358 million in the same period of 2003. The increase was primarily due to the same factors that impacted earnings, excluding the impact of the non-cash income tax adjustment in 2003.

Net earnings for the first half of 2004 were $430 million, compared to $482 million in the same period of 2003. The decrease was primarily due to higher Oil Sands royalty expenses, higher hedging losses, foreign exchange losses on U.S. dollar denominated long-term debt and the effects of an 8% strengthening in the Canadian dollar in the first six months of 2004 compared to 2003 that decreased operating revenues. These negative impacts were partly offset by higher crude oil and natural gas production, higher benchmark commodity prices and year-over-year non-cash federal and provincial income tax adjustments.

Cash flow from operations for the first six months of 2004 was $912 million, compared to $971 million in the first half of 2003. This decrease was primarily due to the same factors that impacted earnings, excluding the impacts of the non-cash income tax adjustments.

NET EARNINGS COMPONENTS

This table explains some of the factors impacting Suncor’s net earnings on an after-tax basis. For comparability purposes readers should rely on the reported net earnings that are presented in the company’s unaudited interim consolidated financial statements and notes in accordance with Canadian GAAP.

	3 months ended June 30				6 months ended June 30
($ millions, after-tax)	2004		2003		2004		2003
Net earnings before the following items	296		160		539		489
Firebag in-situ start-up costs	—		—		(14	)	—
Oil Sands Crown royalties	(68	)	(3	)	(108	)	(10	)
Impact of income tax changes and rate reductions on opening future income tax liabilities	—		(86	)	53		(86	)
Unrealized foreign exchange gains (losses) on U.S. dollar denominated long-term debt	(25	)	45		(40	)	89
Net earnings as reported	203		116		430		482
Net earnings attributable to common shareholders as reported	203		125		418		498

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ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2004 second quarter net earnings of $232 million, compared with $70 million in the second quarter of 2003. The increase was primarily due to higher benchmark crude oil prices and higher crude oil production. In addition, 2003 net earnings were reduced by a one-time non-cash income tax adjustment related to changes in federal and provincial tax policies and rates. These positive factors were offset by higher Crown royalties, an increase in hedging losses, higher natural gas costs, higher depreciation, depletion and amortization expenses, costs related to unscheduled upgrader maintenance, and a 3% strengthening of the Canadian dollar against the U.S. dollar that reduced operating revenues in the second quarter of 2004.

Cash flow from operations for the quarter was $421 million, compared to $321 million in the second quarter of 2003. The increase was primarily due to the same factors that impacted net earnings, excluding the impact of 2003 non-cash income tax adjustments.

Net earnings for the first six months were $470 million, compared to $375 million in the first six months of 2003. In addition to the impact of favourable 2004 first quarter tax adjustments due to a decrease in the provincial income tax rate, the increase in net earnings was primarily due to the same factors that impacted earnings in the second quarter.

Cash flow from operations for the first six months of 2004 decreased to $786 million from $862 million in the first six months of 2003, primarily due to the same factors that impacted net earnings, excluding the impact of non-cash income tax adjustments in 2004 and 2003.

Oil sands production during the second quarter averaged 225,900 barrels of oil per day (bpd), comprised of 210,800 bpd of upgraded crude oil from the base operations and 15,100 bpd of bitumen production from the company’s Firebag in-situ operations. This compares to production of 188,200 bpd of upgraded crude oil in the second quarter of 2003, when operations were impacted by a 30-day planned maintenance shutdown.

Oil Sands production volumes in the second quarter of 2004 were lower than expected due to the extension of scheduled coker and furnace maintenance in April, as well as unscheduled maintenance in June as a result of wear caused by higher mineral content in the bitumen sourced from the Millennium mine pit. Oil Sands is currently evaluating various capital and/or operating alternatives to address this issue on a long-term basis. As a result of lower than anticipated production during the second quarter, Suncor revised its 2004 annual production target from its base operations to 220,000 bpd from the original target of 225,000 to 230,000 bpd.

Sales during the second quarter averaged 231,800 bpd, compared with 184,400 bpd during the second quarter of 2003. The increase in sales was directly related to the higher production levels in 2004 compared to 2003. The sales mix of higher value products increased to 64% compared to 59% in 2003.

During the second quarter, cash operating costs for the base operations averaged $12.10 per barrel, reflecting higher than forecasted natural gas prices, unplanned maintenance and lower than anticipated production. Suncor has revised its 2004 annual cash operating cost target for the base operations to $12.00 to $12.50 per barrel, compared to the original target of $10.75 to $11.75 per barrel, based on actual costs incurred to date and updated natural gas pricing forecasts for the remainder of the year of US$6.30/mcf at Henry Hub. For further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures see page 11.

Included in cash from investing activities in the Oil Sands schedules of segmented data, are the proceeds from the sale of certain proprietary technology.

Suncor’s next major growth stage targets oil sands production capacity of 260,000 bpd in 2005. Construction of a second vacuum unit, a key component to reaching that milestone, is 65% complete. Construction of Firebag Stage 2, which is planned to provide bitumen supplies to future upgrader expansions, is 25% complete with steaming planned to start in late 2005. Both projects are on schedule and on budget.

Preliminary planning for construction of a proposed third upgrader near the company’s existing Oil Sands facilities is now under way. As part of the regulatory process, Suncor is preparing an Environmental Impact Assessment (EIA) to identify potential environmental impacts and mitigation strategies related to the proposed expansion. The proposed upgrader is a key component of Suncor’s plan to increase production to 500,000 to 550,000 bpd in 2010 to 2012.

Oil Sands Crown Royalties

Crown royalties in effect for each Oil Sands Project require payments to the Government of Alberta, based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. In April, the Alberta government confirmed it would modify Suncor’s royalty treatment because it does not recognize the company’s Firebag in-situ facility as an expansion to the company’s existing Oil Sands Project. Accordingly, for Alberta Crown royalty purposes, Suncor’s oil sands operations are considered as two separate projects: Suncor’s base oil sands mining and associated upgrading operations and Suncor’s current Firebag in-situ oil sands project. On this basis, Suncor has provided for estimated additional Crown royalty obligations in 2004. Royalties payable in 2004 or any subsequent year, are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates, and total capital and operating costs for each Project. In addition, 2004

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is a transition 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 the current year’s results.

Oil Sand’s second quarter pretax Crown royalty estimate of $105 million ($68 million after-tax) was based on:

•average 2004 crude oil pricing of approximately US$37 WTI per barrel (based on US$37 WTI per barrel for both actual average pricing for the first six months of 2004, as well as 2004 forward crude oil pricing at June 30 for the remainder of the year).

•current forecasts of capital and operating costs for the remainder of 2004.

•a Canadian/U.S foreign exchange rate of $0.75.

Using these assumptions, Suncor revised its estimate of 2004 annualized pretax royalties to approximately $310 million ($202 million after tax).

Suncor estimates that for every US$1 per barrel change in the average WTI price for calendar 2004, Suncor’s 2004 royalty obligation would change by approximately $25 million.

Further, based on the company’s current long-term planning assumptions, the 25% R-C royalty would continue to apply to the existing Oil Sands Project in future years and the 1% minimum royalty would apply to the Firebag Project until the next decade. The company continues to discuss the terms of Suncor’s option to transition to the generic bitumen-based royalty regime in 2009. After 2009 the royalty would be based on bitumen value if Suncor exercised its option to transition to the Province of Alberta’s generic regime for oil sands royalties. In the event that Suncor exercises this option, upgrading would not be included in the Oil Sands Project for royalty purposes.

This sensitivity analysis incorporates operating and capital cost assumptions included in the company’s current budget and long-range plan, and is not an estimate, forecast or prediction of actual future events or circumstances.

Suncor’s time horizon for cash income taxes for its oil sands operations to be fully cash taxable is not expected until the next decade, based on US$34 per barrel WTI, prior years’ investment levels, future investment plans and certain other assumptions stated above. However, in any particular year, the company’s upstream oil sands and natural gas operations may be subject to some cash income tax due to natural gas price volatility or the timing of recognition of capital expenditures for tax purposes.

Natural Gas

Natural Gas recorded 2004 second quarter net earnings of $35 million, compared with $28 million during the second quarter of 2003. Excluding the impact of a $5 million non-cash future income tax adjustment, earnings for the second quarter of 2003 were $23 million. The increase in 2004 was primarily due to higher production volumes, higher realized natural gas prices and lower exploration costs. These factors were partly offset by higher depletion, depreciation and amortization expenses.

Cash flow from operations for the second quarter of 2004 was $90 million, compared to $66 million in the second quarter of 2003. The increase was primarily due to higher production and higher gas prices.

Year-to-date net earnings were $57 million, compared to $55 million in the first six months of 2003. Excluding the effect of the $5 million non-cash future income tax adjustment described above, earnings for the first six months of 2003 were $50 million. The increase in year-to-date earnings resulted from higher production volumes and lower royalty expenses, partially offset by higher depreciation, depletion and amortization expenses.

Cash flow from operations for the first six months of the year was $173 million, compared to $154 million reported in the same period in 2003, reflecting the same factors that affected net earnings, excluding the impact of the non-cash income tax adjustments in 2003.

Suncor’s strategy calls for natural gas production to exceed natural gas purchases for internal consumption, retaining the company’s position as a net seller into the North American market. Natural gas production in the second quarter of 2004 increased by 19% to 209 mmcf per day, compared to 175 mmcf per day in the second quarter of 2003. The 2004 revised production outlook targets an average of 195 to 200 mmcf per day for the year, exceeding Suncor’s projected 2004 purchases of about 120 to 130 mmcf per day.

Energy Marketing & Refining – Canada

Energy Marketing and Refining – Canada (EM&R) recorded a 2004 second quarter net loss of $3 million, compared to net earnings of $17 million in the second quarter of 2003. The decrease was primarily due to reduced earnings from refining activities as a result of scheduled and unscheduled maintenance to portions of Suncor’s Sarnia, Ontario refinery between April 7 and June 1. Earnings were also affected by weaker retail gasoline margins. These negative impacts were partially offset by mark-to-market gains on inventory-related derivatives and increased earnings from energy marketing and trading activities.

Cash flow from operations for the second quarter decreased to $23 million from $41 million in the second quarter of 2003 due to the same factors that decreased earnings.

Rack Forward, the retail and commercial customer division of EM&R, recorded a second quarter 2004 net loss of $4 million, compared to earnings of $6 million in the second quarter of 2003. Retail margins decreased to an average of 4.3 cents per litre (cpl) from 6.2 cpl in the second quarter of 2003 due to competitive pressures

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in the Ontario market. Sales volumes were relatively flat quarter over quarter.

Rack Back, the refining and large industrial customer division of EM&R, recorded a net loss of $3 million in the second quarter, compared to net earnings of $12 million in the second quarter of 2003. The decrease was primarily due to a loss of refining margins during the shutdown, as well as higher natural gas prices. During the shutdown, EM&R purchased refined product from third parties at prices above historical averages to fulfill customer commitments. These negative earnings factors were partially offset by mark-to-market gains on inventory related derivatives that increased by $6 million quarter over quarter.

During the second quarter, crude utilization decreased to 85% from 100% in 2003 due primarily to the maintenance shutdown. Refining margins on Suncor’s proprietary refined products averaged 7.4 cpl, compared to 4.7 cpl in 2003.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $4 million in the second quarter of 2004, compared to a loss of $1 million in the same period of 2003.

EM&R recorded year-to-date net earnings of $27 million, compared to $38 million in the same period of 2003. The decrease in net earnings reflects lower rack forward earnings due to retail competition and lower refinery utilization related to the second quarter maintenance shutdown, offset by higher mark-to-market gains on inventory related derivatives, as well as higher energy marketing and trading income.

Cash flow from operations for the first six months of 2004 was $79 million compared to $90 million in the first six months of 2003, primarily due to the same factors that affected net earnings.

Progress continues on the planned construction of a new ethanol plant, as the company finalizes both the $22 million contribution agreement with the federal government and its purchase of the land for the plant site.

Refining & Marketing – U.S.A.

Refining & Marketing – U.S.A. (R&M) recorded net earnings of $12 million in the second quarter of 2004, primarily as a result of strong refining margins, partially offset by lower than capacity refinery production due to a scheduled maintenance shutdown on certain refinery units, which was completed on April 19. Cash flow from operations for the second quarter was $21 million. There are no comparative earnings or cash flow data for the second quarter of 2003 as the R&M operations were acquired on August 1, 2003.

Refining margins in the second quarter averaged 9.0 cpl, compared to 5.0 cpl in the first quarter of 2004. Crude utilization at the Denver refinery averaged 86%, reflecting the effects of the planned April shutdown. In order to meet customer demands during the shutdown, R&M purchased refined products from third-party suppliers at market prices.

Retail margins averaged 6.2 cpl in the second quarter of 2004, compared to 5.0 cpl in the first quarter of 2004. Retail sales volumes in the second quarter were lower than the first quarter of 2004 primarily due to increasing competitive pressures from discount gasoline merchants as well as record high gasoline prices during the quarter.

R&M recorded year-to-date net earnings of $9 million and cash flow from operations of $15 million.

Corporate

Corporate recorded a net loss in the second quarter of 2004 of $73 million, compared to net earnings of $1 million during the second quarter of 2003. Results in 2004 included a $25 million after-tax unrealized foreign exchange loss on the company’s U.S. dollar denominated long-term debt, compared to a $45 million after-tax gain in the second quarter of 2003. Corporate expenses were also higher in 2004 due to the implementation of the company’s Enterprise Resource Planning (ERP) system, and higher stock-based compensation expense, attributable to expensing options and deferred share units, as initiated in the second quarter of 2003.

Cash flow used in operations in the quarter was $65 million, compared to the $70 million used in the second quarter of 2003. The slight decrease was primarily due to the earnings factors described above, excluding the impact of the unrealized foreign exchange losses on the U.S. dollar denominated debt, as well as a decrease in current income tax allocations.

Corporate recorded a net loss of $133 million in the first six months of 2004, compared to earnings of $14 million in the same period of 2003. Year-to-date, after-tax unrealized foreign exchange losses on Suncor’s U.S. dollar denominated debt were $40 million, compared to gains of $89 million in 2003. Excluding the impacts of the foreign exchange and consistent with the second quarter, the net loss for the first six months of 2004 was higher primarily due to costs related to the implementation of the ERP system and higher stock-based compensation costs. The net cash deficiency in the first half of 2004 of $141 million was comparable to the prior year net cash deficiency of $135 million.

Analysis of Financial Condition and Liquidity

Excluding cash and cash equivalents, short-term borrowings and future income taxes, Suncor had an operating working capital deficiency of $77 million at the end of the second quarter, compared to a deficiency of $152 million at the end of second quarter 2003. The decrease primarily reflects higher trade receivables and inventory due to higher commodity prices and inventory levels. This decrease was partially offset by higher trade payables due to higher commodity prices and higher Oil Sands Crown royalty accruals.

8

In the second quarter, net debt decreased to approximately $2.5 billion from $2.6 billion at March 31, 2004. Suncor’s undrawn lines of credit at June 30, 2004 were approximately $1.5 billion. Suncor believes it has the capital resources from its undrawn lines of credit and cash flow from operations to fund the balance of its 2004 capital spending program and to meet its current working capital requirements. The 2004 capital spending forecast has not changed significantly from that reported in the company’s 2003 annual MD&A.

On June 25, the company repurchased approximately 2.1 million barrels of crude oil originally sold to a Variable Interest Entity (VIE) in 1999, for net consideration of $49 million. As the company economically hedged the repurchase of the inventory, the net consideration paid was equal to the original proceeds Suncor received in 1999 when it sold the inventory to the VIE. During the third quarter, Suncor will recognize a final $11 million after-tax reduction in margins on subsequent resale of a portion of this inventory. This amount will partially offset mark-to-market gains recorded in previous periods on the economic hedges.

Derivative Financial Instruments

The company’s strategic hedging program permits the company to fix a price or range of prices for crude oil for specified periods of time for a percentage of Suncor’s total production. For accounting purposes, amounts received or paid on settlement of hedge contracts are recorded as part of the related hedged sales or purchase transactions in the consolidated statements of earnings. In the second quarter of 2004, strategic crude oil hedging decreased Suncor’s net earnings by $86 million after-tax compared to an after-tax decrease of $21 million in the second quarter of 2003.

In accordance with the Board of Director’s decision to suspend the hedging program in the first quarter, the company did not enter into any new strategic crude oil arrangements in the second quarter of 2004.

The fair value of derivative hedging instruments is the estimated amount, based on brokers’ quotes and/or internal valuation models, the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss), on the contracts, were as follows at June 30:

($ millions)	2004		2003
Revenue hedge swaps and options	(466	)	(175	)
Margin hedge swaps	(2	)	4
Interest rate swaps	25		36
	(443	)	(135	)

Energy Marketing and Trading Activities

For the quarter ended June 30, 2004 Suncor recorded a net pretax gain of $4 million compared to a $1 million pretax loss during the second quarter of 2003, related to the settlement and revaluation of financial energy trading contracts. In the second quarter the settlement of physical trading activities also resulted in a net pretax gain of $4 million compared to a $1 million pretax gain in the second quarter of 2003. These gains were included as energy trading and marketing activities in the consolidated statement of earnings. The fair value of unsettled energy trading assets and liabilities at June 30, 2004 and December 31, 2003 were as follows:

($ millions)	June 302004	December 31 2003
Energy trading assets	14	5
Energy trading liabilities	5	5

Control Environment

Based on their evaluation as of the end of the three month period ended June 30, 2004, Suncor’s Chief Executive Officer and Chief Financial Officer concluded that Suncor’s disclosure controls and procedures (as defined in Rules 13(a) – 15(e) and 15(d) – 15(e) under the United States Securities and Exchange Act of 1934) are effective to ensure that information required to be disclosed by Suncor in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

As at June 30, 2004, there were no changes in Suncor’s internal controls over financial reporting that occurred during the three month period ended June 30, 2004 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting, other than the new software applications implemented in both Suncor’s crude oil marketing and major projects groups. In connection with these system conversions, internal controls have been modified to reflect the new system environment. Suncor has reviewed the effectiveness of the design of the new internal controls and processes and believes them to be adequate.

9

Suncor continues to identify the need to implement a more robust control environment to support the R&M business unit’s financial reporting and disclosure processes. At June 30, 2004, certain of the compensating controls and processes that were initially put in place at the time of the acquisition have been enhanced.

Suncor will continue to periodically evaluate its disclosure controls and procedures and internal controls over financial reporting and intends to make modifications from time to time as deemed necessary. Suncor is also continuing its previously disclosed review of internal controls, including a comprehensive review of its existing internal controls over financial reporting. Further development of, and enhancements to, control processes and computerized systems are expected to be completed from 2004 to 2006 in connection with the implementation of Suncor’s current ERP installation.

Non-GAAP Financial Measures

Certain financial measures referred to in this MD&A, namely cash flow from operations, return on capital employed (ROCE) and Oil Sands cash and total operating costs per barrel, are not prescribed by GAAP. These non-GAAP financial measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. Suncor includes these non-GAAP financial measures 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.

Suncor provides a detailed numerical reconciliation of ROCE on an annual basis in the company’s annual MD&A, which is to be read in conjunction with the company’s annual consolidated financial statements. For a summarized narrative reconciliation of ROCE calculated on a June 30, 2004 interim basis, please refer to page 26 of the Quarterly Operating Summary included in the company’s Quarterly Shareholders’ Report.

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 Suncor’s June 30, 2004 unaudited interim consolidated financial statements.

A reconciliation of cash flow from operations on a per common share basis is presented in the following table:

			3 months ended June 30		6 months ended June 30
			2004	2003	2004	2003
Cash flow from operations ($ millions)	A		490	358	912	971
Dividends paid on preferred securities ($ millions pretax)	B		—	11	9	23
Weighted average number of common shares outstanding (millions of shares)	C		453	449	452	449
Cash flow from operations (per share)	(A / C	)	1.08	0.80	2.02	2.16
Dividends paid on preferred securities (pretax, per share)	(B / C	)	—	0.03	0.02	0.05
Cash flow from operations after deducting dividends paid on preferred securities (per share)	[(A-B) / C]		1.08	0.77	2.00	2.11

10

The following tables outline 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 included in the tables below for base operations and Firebag in-situ reconcile to the schedules of segmented data when combined.

OIL SANDS OPERATING COSTS – BASE OPERATIONS

		3 months ended June 30						6 months ended June 30
		2004			2003			2004			2003
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		226			209			440			434
Less: natural gas costs and inventory changes		(51	)		(37	)		(84	)		(98	)
Accretion of asset retirement obligations		5			5			10			10
Taxes other than income taxes		7			6			14			12
Cash costs		187		9.75	183		10.70	380		9.70	358		9.95
Natural gas		44		2.30	42		2.45	87		2.20	100		2.75
Imported bitumen (net of other reported product purchases)		1		0.05	2		0.10	9		0.25	4		0.10
Cash operating costs	A	232		12.10	227		13.25	476		12.15	462		12.80
Start-up costs		—			3			22			5
Add: in-situ inventory changes		—			—			2			—
Less: pre-start-up commissioning costs		—			(3	)		—			(5	)
Firebag in-situ start-up costs	B	—		—	—		—	24		0.60	—		—
Total cash operating costs	A+B	232		12.10	227		13.25	500		12.75	462		12.80
Depreciation, depletion and amortization		118		6.15	108		6.30	242		6.20	228		6.30
Total operating costs		350		18.25	335		19.55	742		18.95	690		19.10
Production (thousands of barrels per day)		210.8			188.2			215.3(1)			199.6

(1)Production in the base operations for the six months ended June 30, 2004 includes upgraded Firebag in-situ volumes of 5,900 bpd produced in the first quarter of 2004 during the Firebag start-up period.

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

	3 months ended June 30
	2004			2003
	$ millions		$/barrel	$ millions	$/barrel
Operating, selling and general expenses	24			—
Less: natural gas costs and inventory changes	(15	)		—
Accretion of asset retirement obligations	—			—
Taxes other than income taxes	—			—
Cash costs	9		6.55	—	—
Natural gas	16		11.65	—	—
Cash operating costs	25		18.20	—	—
Depreciation, depletion and amortization	8		5.80	—	—
Total operating costs	33		24.00	—	—
Production (thousands of barrels per day)	15.1			—

11

Legal Notice – Forward-looking Information

This Management’s Discussion and Analysis contains certain forward-looking statements that are based on Suncor’s current expectations, estimates, projections and assumptions that were made by the company 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 expected impact of future commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “plans,” “intends,” “believes,” “projects,” “indicates,” “could,” “vision,” “goal,” “target,” “objective” 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 Suncor’s 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 and Voyageur) and regulatory projects (for example, the clean fuels refinery modifications projects in Suncor’s downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error or level of accuracy, the integrity and reliability of Suncor’s capital assets, the cumulative impact of other resource development, future environmental laws, the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities, the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the 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 Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian Securities Commissions and the SEC. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

12

EX-3

EXHIBIT 3

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

Consolidated Statements of Earnings

(unaudited)

	Second quarter			Six months ended June 30
($ millions)	2004	2003		2004		2003
REVENUES	2 201	1 385		3 996		3 085
EXPENSES
Purchases of crude oil and products	777	341		1 308		752
Operating, selling and general (notes 2 and 6)	445	335		845		696
Energy marketing and trading activities (note 3)	110	87		177		137
Transportation and other costs	29	36		56		70
Depreciation, depletion and amortization (note 2)	177	144		351		301
Accretion of asset retirement obligations (note 2)	7	6		13		12
Exploration	5	16		38		33
Royalties (note 12)	137	38		228		80
Taxes other than income taxes	123	91		242		180
(Gain) loss on disposal of assets	1	(1	)	—		(2	)
Project start-up costs	—	3		22		5
Financing expenses (income) (note 4)	53	(31	)	97		(53	)
	1 864	1 065		3 377		2 211
EARNINGS BEFORE INCOME TAXES	337	320		619		874
PROVISION FOR INCOME TAXES (notes 2 and 9)
Current	4	21		24		42
Future	130	183		165		350
	134	204		189		392
NET EARNINGS	203	116		430		482
Dividends on preferred securities, net of tax (note 11)	—	(6	)	(6	)	(13	)
Revaluation of US$ preferred securities, net of tax (note 11)	—	15		(6	)	29
Net earnings attributable to common shareholders	203	125		418		498
PER COMMON SHARE (dollars)
Net earnings attributable to common shareholders (note 5)
Basic	0.44	0.27		0.92		1.10
Diluted	0.43	0.24		0.90		1.01
Cash dividends	0.06	0.05		0.11		0.0925

See accompanying notes.

13

Consolidated Balance Sheets

(unaudited)

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

SHAREHOLDERS’ EQUITY

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

See accompanying notes.

14

Consolidated Statements of Cash Flows

(unaudited)

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

See accompanying notes.

15

Consolidated Statements of Changes in Shareholders’ Equity

(unaudited)

($ millions)	Preferred Securities		Share Capital	Contributed Surplus	Cumulative Foreign Currency Translation		Retained Earnings
At December 31, 2002, as previously reported	523		578	—	—		2 357
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—		—	—	—		(61	)
At December 31, 2002, as restated	523		578	—	—		2 296
Net earnings	—		—	—	—		482
Dividends paid on preferred securities, net of tax	—		—	—	—		(13	)
Dividends paid on common shares	—		—	—	—		(39	)
Issued for cash under stock option plan	—		6	—	—		—
Issued under dividend reinvestment plan	—		1	—	—		(1	)
Stock-based compensation expense	—		—	3	—		—
Revaluation of US$ preferred securities	(37	)	—	—	—		29
At June 30, 2003	486		585	3	—		2 754
At December 31, 2003, as previously reported	476		604	7	(26	)	3 364
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—		—	—	—		(70	)
At December 31, 2003, as restated	476		604	7	(26	)	3 294
Net earnings	—		—	—	—		430
Dividends paid on preferred securities, net of tax	—		—	—	—		(6	)
Dividends paid on common shares	—		—	—	—		(45	)
Issued for cash under stock option plan	—		20	—	—		—
Issued under dividend reinvestment plan	—		4	—	—		(4	)
Stock-based compensation expense	—		—	9	—		—
Foreign currency translation adjustment	—		—	—	11		—
Revaluation of US$ preferred securities	7		—	—	—		(6	)
Reclassification of issue costs for preferred securities	10		—	—	—		(10	)
Redemption of preferred securities (note 11)	(493	)	—	—	—		—
At June 30, 2004	—		628	16	(15	)	3 653

See accompanying notes.

16

Schedules of Segmented Data

(unaudited)

Second quarter

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
EARNINGS
Revenues
Operating revenues	815		553		132		120		764		624		372		—	1		1		2 084		1 298
Energy marketing and trading activities	—		—		—		—		117		86		—		—	—		—		117		86
Intersegment revenues	93		81		16		5		—		—		—		—	(109	)	(86	)	—		—
Interest	—		—		—		—		—		—		—		—	—		1		—		1
	908		634		148		125		881		710		372		—	(108	)	(84	)	2 201		1 385
Expenses
Purchases of crude oil and products	30		2		—		—		573		419		282		—	(108	)	(80	)	777		341
Operating, selling and general	250		209		19		18		96		82		38		—	42		26		445		335
Energy marketing and trading activities	—		—		—		—		110		87		—		—	—		—		110		87
Transportation and other costs	19		30		6		6		—		—		4		—	—		—		29		36
Depreciation, depletion and amortization	126		108		29		21		16		14		4		—	2		1		177		144
Accretion of asset retirement obligations	5		5		1		1		1		—		—		—	—		—		7		6
Exploration	2		—		3		16		—		—		—		—	—		—		5		16
Royalties	105		5		32		33		—		—		—		—	—		—		137		38
Taxes other than income taxes	7		6		2		1		87		84		27		—	—		—		123		91
(Gain) loss on disposal of assets	3		—		(2	)	—		—		(1	)	—		—	—		—		1		(1	)
Project start-up costs	—		3		—		—		—		—		—		—	—		—		—		3
Financing expenses (income)	—		—		—		—		—		—		—		—	53		(31	)	53		(31	)
	547		368		90		96		883		685		355		—	(11	)	(84	)	1 864		1 065
Earnings (loss) before income taxes	361		266		58		29		(2	)	25		17		—	(97	)	—		337		320
Income taxes	(129	)	(196	)	(23	)	(1	)	(1	)	(8	)	(5	)	—	24		1		(134	)	(204	)
Net earnings (loss)	232		70		35		28		(3	)	17		12		—	(73	)	1		203		116

17

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	232		70		35		28		(3	)	17		12		—	(73	)	1		203		116
Exploration expenses
Cash	—		—		3		1		—		—		—		—	—		—		3		1
Dry hole costs	—		—		—		15		—		—		—		—	—		—		—		15
Non-cash items included in earnings
Depreciation, depletion and amortization	126		108		29		21		16		14		4		—	2		1		177		144
Future income taxes	126		192		19		1		4		(4	)	7		—	(26	)	(6	)	130		183
Current income tax provision allocated to Corporate	3		4		4		—		(3	)	12		(2	)	—	(2	)	(16	)	—		—
(Gain) loss on disposal of assets	3		—		(2	)	—		—		(1	)	—		—	—		—		1		(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	5		3		5		3
Other	3		(1	)	4		1		1		3		(1	)	—	31		(55	)	38		(52	)
Overburden removal outlays	(58	)	(53	)	—		—		—		—		—		—	—		—		(58	)	(53	)
Increase (decrease) in deferred credits and other	(14	)	1		(2	)	(1	)	8		—		1		—	(2	)	2		(9	)	2
Total cash flow from (used in) operations	421		321		90		66		23		41		21		—	(65	)	(70	)	490		358
Decrease (increase) in operating working capital	(3	)	66		(24	)	12		(23	)	(14	)	(20	)	—	45		32		(25	)	96
Total cash flow from (used in) operating activities	418		387		66		78		—		27		1		—	(20	)	(38	)	465		454
Cash from (used in) investing activities:
Capital and exploration expenditures	(246	)	(188	)	(37	)	(37	)	(40	)	(25	)	(27	)	—	(11	)	(8	)	(361	)	(258	)
Deferred maintenance shutdown expenditures	—		(83	)	—		—		(24	)	(2	)	(6	)	—	—		—		(30	)	(85	)
Deferred outlays and other investments	(1	)	(9	)	—		—		(8	)	(1	)	—		—	8		(1	)	(1	)	(11	)
Proceeds from disposals	40		—		3		—		2		1		—		—	—		—		45		1
Total cash (used in) investing activities	(207	)	(280	)	(34	)	(37	)	(70	)	(27	)	(33	)	—	(3	)	(9	)	(347	)	(353	)
Net cash surplus (deficiency) before financing activities	211		107		32		41		(70	)	—		(32	)	—	(23	)	(47	)	118		101

18

Schedules of Segmented Data

(unaudited)

Six months ended June 30

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
EARNINGS
Revenues
Operating revenues	1 481		1 310		223		256		1 442		1 382		661		—	1		1		3 808		2 949
Energy marketing and trading activities	—		—		—		—		195		135		—		—	(8	)	—		187		135
Intersegment revenues	192		189		58		12		—		—		—		—	(250	)	(201	)	—		—
Interest	—		—		—		—		—		—		—		—	1		1		1		1
	1 673		1 499		281		268		1 637		1 517		661		—	(256	)	(199	)	3 996		3 085
Expenses
Purchases of crude oil and products	42		4		—		—		1 011		946		506		—	(251	)	(198	)	1 308		752
Operating, selling and general	464		434		39		37		192		182		71		—	79		43		845		696
Energy marketing and trading activities	—		—		—		—		185		137		—		—	(8	)	—		177		137
Transportation and other costs	36		58		11		12		1		—		8		—	—		—		56		70
Depreciation, depletion and amortization	250		228		57		42		33		29		7		—	4		2		351		301
Accretion of asset retirement obligations	10		10		2		2		1		—		—		—	—		—		13		12
Exploration	15		9		23		24		—		—		—		—	—		—		38		33
Royalties	167		15		61		65		—		—		—		—	—		—		228		80
Taxes other than income taxes	14		12		2		1		170		167		56		—	—		—		242		180
(Gain) loss on disposal of assets	3		—		(3	)	—		—		(2	)	—		—	—		—		—		(2	)
Project start-up costs	22		5		—		—		—		—		—		—	—		—		22		5
Financing expenses (income)	—		—		—		—		—		—		—		—	97		(53	)	97		(53	)
	1 023		775		192		183		1 593		1 459		648		—	(79	)	(206	)	3 377		2 211
Earnings (loss) before income taxes	650		724		89		85		44		58		13		—	(177	)	7		619		874
Income taxes	(180	)	(349	)	(32	)	(30	)	(17	)	(20	)	(4	)	—	44		7		(189	)	(392	)
Net earnings (loss)	470		375		57		55		27		38		9		—	(133	)	14		430		482
As at June 30
TOTAL ASSETS	8 608		7 582		847		770		1 217		1 002		504		—	83		64		11 259		9 418
CAPITAL EMPLOYED (1)	4 525		4 160		421		394		587		488		345		—	166		157		6 044		5 199

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

19

	Oil Sands				Natural Gas				Energy Marketing and Refining – Canada				Refining and Marketing – U.S.A.			Corporate and Eliminations				Total
($ millions)	2004		2003		2004		2003		2004		2003		2004		2003	2004		2003		2004		2003
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	470		375		57		55		27		38		9		—	(133	)	14		430		482
Exploration expenses
Cash	—		—		11		5		—		—		—		—	—		—		11		5
Dry hole costs	—		—		12		19		—		—		—		—	—		—		12		19
Non-cash items included in earnings
Depreciation, depletion and amortization	250		228		57		42		33		29		7		—	4		2		351		301
Future income taxes	173		342		28		29		—		(7	)	6		—	(42	)	(14	)	165		350
Current income tax provision allocated to Corporate	7		7		4		1		17		27		(2	)	—	(26	)	(35	)	—		—
(Gain) loss on disposal of assets	3		—		(3	)	—		—		(2	)	—		—	—		—		—		(2	)
Stock-based compensation expense	—		—		—		—		—		—		—		—	9		3		9		3
Other	(8	)	3		8		3		(7	)	5		(8	)	—	44		(108	)	29		(97	)
Overburden removal outlays	(112	)	(97	)	—		—		—		—		—		—	—		—		(112	)	(97	)
Increase (decrease) in deferred credits and other	3		4		(1	)	—		9		—		3		—	3		3		17		7
Total cash flow from (used in) operations	786		862		173		154		79		90		15		—	(141	)	(135	)	912		971
Decrease (increase) in operating working capital	7		91		(37	)	3		9		4		(44	)	—	(6	)	(16	)	(71	)	82
Total cash flow from (used in) operating activities	793		953		136		157		88		94		(29	)	—	(147	)	(151	)	841		1 053
Cash from (used in) investing activities:
Capital and exploration expenditures	(473	)	(429	)	(107	)	(76	)	(65	)	(38	)	(45	)	—	(17	)	(10	)	(707	)	(553	)
Deferred maintenance shutdown expenditures	—		(92	)	—		—		(25	)	(2	)	(6	)	—	—		—		(31	)	(94	)
Deferred outlays and other investments	(3	)	(9	)	—		—		(12	)	(1	)	—		—	8		(1	)	(7	)	(11	)
Proceeds from disposals	40		—		7		2		2		2		—		—	—		—		49		4
Total cash (used in) investing activities	(436	)	(530	)	(100	)	(74	)	(100	)	(39	)	(51	)	—	(9	)	(11	)	(696	)	(654	)
Net cash surplus (deficiency) before financing activities	357		423		36		83		(12	)	55		(80	)	—	(156	)	(162	)	145		399

20

•  Notes to the Consolidated Financial Statements

(unaudited)

1. ACCOUNTING POLICIES

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

In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature necessary to present fairly Suncor Energy Inc.’s (Suncor) financial position at June 30, 2004 and the results of its operations and cash flows for the three and six month periods ended June 30, 2004 and 2003.

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

2. ASSET RETIREMENT OBLIGATIONS

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

CHANGE IN CONSOLIDATED BALANCE SHEETS

			As at June 30
($ millions, increase/(decrease))	2004		2003
Property, plant and equipment	207		215
Future income tax assets	104		112
Total assets	311		327
Accrued liabilities and other	310		321
Future income tax liabilities	70		74
Retained earnings	(69	)	(68	)
Total liabilities and shareholders’ equity	311		327

CHANGE IN CONSOLIDATED STATEMENTS OF EARNINGS

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

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the obligations

associated with the retirement of property, plant and equipment.

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

21

The total undiscounted amount of estimated cash flows required to settle the obligations is approximately $1 billion for each of 2003 and 2004, and has been discounted using a credit-adjusted risk free rate of 6%. Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

The Company owns interests in several assets for which the fair value of the asset retirement obligation cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.

3. ENERGY MARKETING AND TRADING ACTIVITIES

In addition to those financial derivatives used for hedging activities, the company also uses energy derivatives, including physical and financial swaps, forwards and options to gain market information and earn trading revenues. These energy trading activities are accounted for using the mark-to-market method and as such physical and financial energy contracts are recorded at fair value at each balance sheet date. For the quarter ended June 30, 2004, a net pretax gain of $4 million (2003 – pretax loss of $1 million) from the settlement and revaluation of financial contracts was reported as energy marketing and trading activities in the Consolidated Statements of Earnings. In the second quarter the settlement of physical trading activities also resulted in a net pretax gain of $4 million (2003 – pretax gain of $1 million). For the six month period ended June 30, 2004, a pretax gain of $6 million was recorded on financial contracts (2003 – pretax loss of $3 million). Year-to-date settlement of physical trading activities resulted in a net pretax gain of $5 million (2003 – pretax gain of $2 million). The fair value of unsettled (unrealized) energy trading assets and liabilities are as follows:

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

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

4. FINANCING EXPENSES (INCOME)

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

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Second quarter				Six months ended June 30
($ millions)	2004		2003		2004		2003
Net earnings attributable to common shareholders	203		125		418		498
Dividends on preferred securities, net of tax	—	(a)	6		—	(a)	13
Revaluation of US$ preferred securities, net of tax	—	(a)	(15	)	—	(a)	(29	)
Adjusted net earnings attributable to common shareholders	203		116		418		482
(millions of common shares)
Weighted-average number of common shares	453		449		452		449
Dilutive securities:
Options issued under stock-based compensation plans	7		5		10		5
Redemption of preferred securities by the issuance of common shares	—	(a)	20		—	(a)	22
Weighted-average number of diluted common shares	460		474		462		476
(dollars per common share)
Basic earnings per share (b)	0.44		0.27		0.92		1.10
Diluted earnings per share (c)	0.43		0.24		0.90		1.01

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

(a)For the six months ended June 30, 2004, diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares. Dividends on preferred securities, the revaluation of US$ preferred securities and the redemption of preferred securities by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share. The company redeemed its preferred securities in the first quarter of 2004 and accordingly, no revaluations or dividends were recorded in the second quarter of 2004.

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

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

22

6. STOCK-BASED COMPENSATION

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

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

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

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

(a) Stock Option Plans

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

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

The fair values of all common share options granted during the period are estimated as at the grant date using the Black-Scholes option-pricing model. The weighted-average fair values of the options granted during the various periods and the weighted-average assumptions used in their determination are as noted below:

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

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

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

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

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

(b) Performance Share Units (PSUs)

As a means of providing better alignment between employee incentive plans and shareholder interests, in the second quarter of 2004 the company issued 2,000 PSUs under a new employee incentive compensation plan (353,000 PSUs issued for the six months ended June 30, 2004). PSUs granted replace the remuneration value of reduced grants under the company’s stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%)

23

contingent upon Suncor’s performance. Performance is measured by reference to the Company’s total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the probability of vesting. This expense is recognized on a straight-line basis over the term of the grant. Pretax expense recognized for PSUs in the second quarter of 2004 was $1 million ($2 million for the six months ended June 30, 2004).

7. EMPLOYEE FUTURE BENEFITS LIABILITY

The company’s pension plans are described in the notes to the 2003 Consolidated Financial Statements. The following is the status of the net periodic benefit cost for the six months ended June 30.

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

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

8. SUPPLEMENTAL INFORMATION

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

STRATEGIC CRUDE OIL HEDGES AT JUNE 30, 2004

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

MARGIN HEDGES AT JUNE 30, 2004

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

NATURAL GAS HEDGES AT JUNE 30, 2004

	Quantity	Average Price	Revenue Hedged	Hedge
	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period
Swaps	30 000	5.95	22	2004	(e)

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

(b)The revenue and margin hedged is translated to Cdn$ at the June 30, 2004 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

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

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

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

24

9. INCOME TAXES

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

10. LONG-TERM DEBT

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

11. PREFERRED SECURITIES

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

12. ROYALTY ESTIMATE MEASUREMENT UNCERTAINTY

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

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

13. CONSOLIDATION OF VARIABLE INTEREST ENTITIES

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

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

25

Highlights

(unaudited)

	2004	2003
CASH FLOW FROM OPERATIONS (dollars per common share)
For the three months ended June 30
Cash flow from operations (1)	1.08	0.80
Dividends paid on preferred securities (pretax) (2)	—	0.03
Cash flow from operations after deducting dividends paid on preferred securities (3)	1.08	0.77
For the six months ended June 30
Cash flow from operations (1)	2.02	2.16
Dividends paid on preferred securities (pretax) (2)	0.02	0.05
Cash flow from operations after deducting dividends paid on preferred securities (3)	2.00	2.11
RATIOS
For the twelve months ended June 30
Return on capital employed (%) (4)	19.1	16.9
Return on capital employed (%) (5)	16.8	15.3
Net debt to cash flow from operations (times) (6)	1.2	1.2
Interest coverage on long-term debt (times)
Net earnings (7)	11.1	11.4
Cash flow from operations (8)	14.4	14.2
As at June 30
Debt to debt plus shareholders’ equity (%) (9)	37.6	36.4
COMMON SHARE INFORMATION
As at June 30
Share price at end of trading
Toronto Stock Exchange – Cdn$	34.01	25.34
New York Stock Exchange – US$	25.61	18.75
Common share options outstanding (thousands)	21 639	21 950
For the six months ended June 30
Average number outstanding, weighted monthly (thousands)	452 283	449 326

Refer to the Quarterly Operating Summary for a discussion of financial measures not prepared in accordance with generally accepted accounting principles (GAAP).

(1)Cash flow from operations for the period; divided by the weighted average number of common shares outstanding during the period.

(2)Dividends paid on preferred securities for the period, before income taxes; divided by the weighted-average number of common shares outstanding during the period.

(3)Cash flow from operations minus pretax dividends paid on preferred securities, for the period; divided by the weighted-average number of common shares outstanding for the period.

(4)Net earnings (2004 – $1,023 million; 2003 – $919 million) adjusted for after-tax financing expenses (2004 – expense of $53 million; 2003 – expense of $13 million) for the twelve month period ended; divided by average capital employed (2004 – $5,621 million; 2003 – $5,524 million). Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable), at the beginning and end of the year, divided by two. Return on capital employed (ROCE) for Suncor operating segments as presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed reconciliation of ROCE prepared on an annual basis, see page 50 of Suncor’s 2003 Annual Report to Shareholders.

(5)If capital employed were to include capitalized costs related to major projects in progress (capital employed including major projects in progress: 2004 – $760 million; 2003 – $815 million; 2002 – $298 million), the return on capital employed would be as stated on this line.

(6)Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations for the twelve month period then ended.

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

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

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

26

Quarterly Operating Summary

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	June 30	Dec 31
	2004	2004	2003	2003	2003	2004	2003	2003
OIL SANDS
Production (a)
Base operations	210.8	213.9	235.2	231.5	188.2	212.4	199.6	216.6
Firebag	15.1	5.9	—	—	—	10.5	—	—
Total production	225.9	219.8	235.2	231.5	188.2	222.9	199.6	216.6
Sales (a)
Light sweet crude oil	118.7	112.2	132.7	109.0	86.4	115.4	103.5	112.3
Diesel	29.7	27.5	27.2	24.8	22.9	28.6	26.5	26.3
Light sour crude oil	68.9	74.3	81.3	77.5	73.9	71.6	67.1	73.3
Bitumen	14.5	—	8.3	16.1	1.2	7.3	0.6	6.4
Total sales	231.8	214.0	249.5	227.4	184.4	222.9	197.7	218.3
Average sales price (1), (b)
Light sweet crude oil	45.70	40.26	36.67	37.96	39.87	42.98	43.83	40.26
Other (diesel, light sour crude oil and bitumen)	38.28	35.85	30.72	32.92	32.94	37.16	36.60	33.93
Total	41.88	38.16	33.89	35.34	36.19	40.09	40.38	37.19
Total *	48.18	43.28	36.63	38.05	38.14	45.83	43.79	40.22
CASH OPERATING COSTS AND TOTAL OPERATING COSTS - BASE OPERATIONS
Cash costs	9.75	9.65	9.25	8.20	10.70	9.70	9.95	9.25
Natural gas	2.30	2.10	1.60	1.65	2.45	2.20	2.75	2.15
Imported bitumen	0.05	0.40	—	—	0.10	0.25	0.10	0.05
Cash operating costs (2),(c)	12.10	12.15	10.85	9.85	13.25	12.15	12.80	11.45
Firebag start-up costs	—	1.20	—	—	—	0.60	—	—
Total cash operating costs (3),(c)	12.10	13.35	10.85	9.85	13.25	12.75	12.80	11.45
Depreciation, depletion and amortization	6.15	6.20	5.40	5.30	6.30	6.20	6.30	5.80
Total operating costs (4),(c)	18.25	19.55	16.25	15.15	19.55	18.95	19.10	17.25
CASH OPERATING COSTS AND TOTAL OPERATING COSTS - FIREBAG
Cash costs	6.55
Natural gas	11.65
Cash operating costs (5),(c)	18.20
Depreciation, depletion and amortization	5.80
Total operating costs (6),(c)	24.00
(for the period ended)
Capital employed (i)	4 525	4 725	4 050	4 163	4 160
(for the twelve months ended)
Return on capital employed (j)	22.6	18.1	20.8	19.8	19.0
Return on capital employed (j) ****	19.2	16.0	17.4	17.2	16.9

27

		For the quarter ended					Six months ended		Total year
		June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	June 30	Dec 31
		2004	2004	2003	2003	2003	2004	2003	2003
NATURAL GAS
Gross production **
Natural gas (d)		209	197	194	194	175	203	180	187
Natural gas liquids (a)		2.2	2.2	2.4	2.5	2.1	2.2	2.3	2.3
Crude oil (a)		1.1	0.9	1.0	1.6	1.6	1.0	1.5	1.4
Total gross production (e)		38.1	35.9	35.7	36.4	32.8	37.0	33.8	34.9
Average sales price (1)
Natural gas (f)		6.77	6.54	5.53	6.07	6.63	6.66	7.09	6.42
Natural gas (f) *		6.84	6.59	5.51	6.04	6.65	6.72	7.13	6.42
Natural gas liquids (b)		43.53	38.13	35.45	33.50	33.45	40.85	37.85	36.08
Crude oil – Conventional (b)		47.08	44.14	36.91	38.31	37.82	45.71	42.45	40.29
Net wells drilled
Conventional	– Exploratory ***	3	4	5	1	24	7	27	33
	– Development	—	8	6	9	1	8	6	21
		3	12	11	10	25	15	33	54
(for the period ended)
Capital employed (i)		421	418	400	373	394
(for the twelve months ended)
Return on capital employed (j)		29.9	27.7	29.2	24.4	17.3
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail		4.5	4.2	4.4	4.3	4.5	4.4	4.4	4.4
Other		4.1	4.0	3.9	4.5	4.1	4.0	4.1	4.2
Jet fuel		0.7	1.0	0.7	0.8	0.7	0.9	0.7	0.7
Diesel		3.1	2.9	3.1	2.8	3.0	3.0	3.0	3.0
Total transportation fuel sales		12.4	12.1	12.1	12.4	12.3	12.3	12.2	12.3
Petrochemicals		0.6	0.9	0.7	0.6	0.9	0.7	0.9	0.8
Heating oils		0.3	0.8	0.5	0.2	0.3	0.5	0.6	0.5
Heavy fuel oils		0.7	0.8	0.5	1.4	0.6	0.8	0.7	0.8
Other		1.5	0.6	0.4	0.6	0.8	1.1	0.9	0.6
Total refined product sales		15.5	15.2	14.2	15.2	14.9	15.4	15.3	15.0
Margins (h)
Refining (7)		7.4	7.8	7.0	6.5	4.7	7.7	6.2	6.5
Refining (7) *		8.0	7.8	6.9	6.4	4.2	8.0	6.1	6.4
Retail (8)		4.3	5.0	6.3	7.0	6.2	4.6	6.6	6.6
Crude oil supply and refining
Processed at Sarnia refinery (g)		9.5	12.0	9.6	10.1	11.1	10.7	11.3	10.5
Utilization of refining capacity (j)		85	108	86	91	100	97	101	95
(for the period ended)
Capital employed (i)		587	567	551	523	488
(for the twelve months ended)
Return on capital employed (j)		7.8	11.8	10.3	11.0	13.1

28

	For the quarter ended				Six months ended		Total year
	June 30	Mar 31	Dec 31	Sept 30	June 30	June 30	Dec 31
	2004	2004	2003	2003	2004	2003	2003
REFINING AND MARKETING – U.S.A. *****
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.6	0.7	0.7	0.7	0.7	—	0.7
Other	3.6	3.4	3.4	3.5	3.5	—	3.5
Jet fuel	0.5	0.4	0.5	0.6	0.4	—	0.5
Diesel	1.9	2.2	2.3	2.3	2.0	—	2.3
Total transportation fuel sales	6.6	6.7	6.9	7.1	6.6	—	7.0
Asphalt	1.8	1.2	1.4	2.1	1.5	—	1.7
Other	0.5	0.2	0.3	0.6	0.4	—	0.4
Total refined product sales	8.9	8.1	8.6	9.8	8.5	—	9.1
Margins (h)
Refining (7)	9.0	5.0	4.6	7.9	7.1	—	5.9
Refining (7) *	9.3	5.0	4.6	7.9	7.3	—	5.9
Retail (8)	6.2	5.0	4.8	6.4	5.6	—	5.6
Crude oil supply and refining
Processed at Denver refinery (g)	8.2	8.1	9.2	9.6	8.1	—	9.4
Utilization of refining capacity (j)	86	85	96	101	85	—	98

29

Non-GAAP Financial Measures

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

Definitions

(1) Average sales price	–	This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(2) Cash operating costs – Base operations	–	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on production volumes. For a reconciliation of this non-GAAP financial measure see Management’s Discussion and Analysis.
(3) Total cash operating costs – Base operations	–	Include cash operating costs – mining as defined above and cash start-up costs for in-situ operations.  Per barrel amounts are based on mining production volumes.
(4) Total operating costs – Base operations	–	Include total cash operating costs – mining as defined above and non-cash operating costs. Per barrel amounts are based on mining production volumes.
(5) Cash operating costs – Firebag	–	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes.
(6) Total operating costs – Firebag	–	Include cash operating costs – in-situ as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes.
(7) Refining margin	–	This operating statistic is calculated as the average wholesale unit price from all products less average unit cost of crude oil.
(8) Retail margin	–	This operating statistic is calculated as the average street price of Sunoco (Energy, Marketing and Refining – Canada) and Phillips 66-branded (Refining and Marketing – U.S.A.) retail gasoline net of federal excise tax and other adjustments, less refining gasoline transfer price.

Explanatory Notes

*Excludes the impact of hedging activities.

**Currently all Natural Gas production is located in the Western Canada Sedimentary Basin.

***Excludes exploratory wells in progress.

****If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

*****Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003. Return on capital employed will not be calculated for this segment until there is twelve months of information available on which to base the calculation.

(a) thousands of barrels per day

(b) dollars per barrel

(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

30

EX-4

EXHIBIT 4

Certificate of the President and Chief Executive Officer Pursuant to Exchange Act
Rule 13a-14 or Rule 15d-14, as Enacted Pursuant to Section 302 of the
Sarbanes-Oxley Act of 2002

CERTIFICATION PURSUANT TO EXCHANGE ACT RULES 13a-14
AS ADOPTED PURSUANT TO
SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, RICHARD L. GEORGE, President and Chief Executive Officer of Suncor Energy Inc., certify that:

1.I have reviewed this quarterlyreport on Form 6-K of Suncor Energy Inc.;

2.Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this interim report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the issuer as of, and for, the periods presented in this report;

4.The issuer’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 15(e) and 15d-15(e) for the issuer and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the issuer, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

(b)evaluated the effectiveness of the issuer’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;  and

(c)disclosed in this report any change in the issuer’s internal control over financial reporting that occurred during the period covered by the annual report that has materially affected, or is reasonably likely to materially affect, the issuer’s internal control over financial reporting.

5.The issuer’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of issuer’s board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the issuer’s ability to record, process, summarize and report financial information;  and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

		SUNCOR ENERGY INC.
DATE:	July 28, 2004		PER:	“RICHARD L. GEORGE”
				RICHARD L. GEORGE
				President and Chief Executive  Officer

EX-5

EXHIBIT 5

Certificate of the Senior Vice President and Chief Financial Officer Pursuant to
Exchange Act Rule 13a-14 or Rule 15d-14, as Enacted Pursuant to Section 302 of
the Sarbanes-Oxley Act of 2002

CERTIFICATION PURSUANT TO EXCHANGE ACT RULE 13a-14 OR RULE 15d-14,

AS ENACTED PURSUANT TO

SECTION 302 OF THE SARBANES-OXLEY ACT OF 2002

I, J. KENNETH ALLEY, Senior Vice President and Chief Financial Officer of Suncor Energy Inc., certify that:

1.I have reviewed this quarterlyreport on Form 6-K of Suncor Energy Inc.;

2.Based on my knowledge, this quarterly report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3.Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4.The registrant’s other certifying officers and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) for the registrant and have:

(a)designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this quarterly report is being prepared;

(b)evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation;  and

(c)disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during registrant’s most recent fiscal quarter that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting.

5.The registrant’s other certifying officers and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the issuer’s auditors and the audit committee of registrant’s board of directors (or persons performing the equivalent functions):

(a)all significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information;  and

(b)any fraud, whether or not material, that involves management or other employees who have a significant role in the issuer’s internal control over financial reporting.

		SUNCOR ENERGY INC.
DATE:	July 28, 2004		PER:	“J. KENNETH ALLEY”
				J. KENNETH ALLEY
				Senior Vice President and Chief  Financial Officer

EX-6

EXHIBIT 6

Certificate of the President and Chief Executive Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Suncor Energy Inc. (the “Registrant”), is filing its interim report on Form 6-K for the second fiscal quarter ended June 30, 2004 (the “Report”) with the Securities and Exchange Commission.

I, RICHARD L. GEORGE, President and Chief Executive Officer of the Registrant, certify, pursuant to 18 U.S.C. section 1350, as enacted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(i)the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934;  and

(ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of the operations of the Registrant.

”RICHARD L. GEORGE”
RICHARD L. GEORGE
President and Chief Executive Officer
Suncor Energy Inc.
DATE:	July 28, 2004

A signed version of this written statement required by Section 906 has been provided to Suncor Energy Inc. and will be retained by Suncor Energy Inc. and furnished to the Securities and Exchange Commission or its staff upon request.

EX-7

EXHIBIT 7

Certificate of the Senior Vice President and Chief Financial Officer Pursuant to 18 U.S.C. Section 1350, as Enacted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

CERTIFICATION PURSUANT TO 18 U.S.C. SECTION 1350,

AS ENACTED PURSUANT TO

SECTION 906 OF THE SARBANES-OXLEY ACT OF 2002

Suncor Energy Inc. (the “Registrant”), is filing its interim report on Form 6-K for the second fiscal quarter ended June 30, 2004 (the “Report”) with the Securities and Exchange Commission.

I, J. KENNETH ALLEY, Senior Vice President and Chief Financial Officer of the Registrant, certify, pursuant to 18 U.S.C. section 1350, as enacted pursuant to section 906 of the Sarbanes-Oxley Act of 2002, that, to the best of my knowledge:

(i)the Report fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934;  and

(ii)the information contained in the Report fairly presents, in all material respects, the financial condition and results of the operations of the Registrant.

”J. KENNETH ALLEY”
J. KENNETH ALLEY
Senior Vice President and Chief Financial
Officer
Suncor Energy Inc.
DATE:	July 28, 2004

A signed version of this written statement required by Section 906 has been provided to Suncor Energy Inc. and will be retained by Suncor Energy Inc. and furnished to the Securities and Exchange Commission or its staff upon request.