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: April 2005 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 12 and 13 of Exhibit 99.2.

B.            Changes in Internal Control Over Financial Reporting

See pages 12 and 13 of Exhibit 99.2.

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.
	By:
Date:
		“JANICE B. ODEGAARD”
April 28, 2005
		JANICE B. ODEGAARD
		Vice President, Associate
		General Counsel and
		Corporate Secretary

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EXHIBIT INDEX

Exhibit	Description of Exhibit
99.1	Press Release Including 2005 Outlook
99.2	Interim Management’s Discussion and Analysis for the first fiscal quarter ended March 31, 2005
99.3	Interim Unaudited Financial Statements of Suncor Energy Inc. for the first fiscal quarter ended March 31, 2005
99.4	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
99.5	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
99.6	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
99.7	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-99.1

Exhibit 99.1

Press Release Including 2005 Outlook

first quarter 2005

Report to shareholders for the period ended March 31, 2005

energy for the future
expanding beyond

Suncor earnings and cash flow lower on reduced production

recovery and expansion work on schedule as company plans for strong finish to year

All financial figures are unaudited and in Canadian dollars unless noted otherwise. Certain prior period amounts have been restated to conform to the current year’s presentation.  Certain financial measures referred to in this release are not prescribed by generally accepted accounting principles (GAAP). For a description of these measures, see “Non GAAP Financial Measures” in Suncor’s 2005 first 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 measures may be misleading, particularly if used in isolation. Base operations refer to oil sands mining and upgrading operations.

Suncor Energy Inc. reported its first quarter 2005 net earnings of $98 million ($0.22 per common share), compared to $216 million ($0.48 per common share) in the first quarter of 2004. Excluding the effects of unrealized foreign exchange losses on the company’s U.S. dollar denominated long-term debt, 2005 first quarter net earnings were $103 million ($0.23 per common share). Cash flow from operations was $294 million in the quarter, compared to $414 million in the first quarter of 2004.

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The decrease in earnings and cash flow primarily reflects reduced production. Suncor averaged 175,600 barrels of oil equivalent (boe) per day in the first quarter of 2005, compared to 255,700 boe per day in the first quarter of 2004. Most of the production decline was due to a January 4 fire at Suncor’s oil sands facility. Oil sands production during the first quarter of 2005 averaged 139,900 barrels per day (bpd), including 18,700 bpd of in-situ bitumen production. This compares to production of 219,800 bpd, including 5,900 bpd of in-situ bitumen production in the first quarter of 2004. Suncor’s natural gas production during the first quarter of 2005 was also down slightly to 191 million cubic feet (mmcf) per day, compared to first quarter 2004 production of 197 mmcf per day.

Earnings and cash flow were also negatively impacted by lower refining margins in Suncor’s Canadian downstream operations, primarily as a result of higher synthetic crude feedstock prices, due in part to the fire at Oil Sands. Refining margins were 4.8 cents per litre (cpl) in the first quarter of 2005, compared to 7.8 cpl in the first quarter of 2004.

These factors were partly offset by higher commodity prices and accrued interim insurance proceeds of $73 million (US$60 million) from the company’s business interruption policy. In April, Suncor also received $12 million (US$10 million) towards property damage. The company continues to work with its insurers on a schedule of future payments under its policies.

“We’re disappointed with the quarter, but not surprised,” says Rick George, president and chief executive officer. “We know that from a financial perspective, the first nine months of the year will not deliver to our normal expectations. However, we’re focused on safely returning production to full capacity and recovery is going very well.”

Equipment damaged in the fire has been dismantled and removed, and reconstruction is well under way. In order to return to full production capacity once the rebuild is complete, a maintenance shutdown originally scheduled for the third quarter of 2005 is now in progress.

Suncor is targeting all recovery work, commissioning and start up of the repaired facilities to be completed in September. Suncor will then focus on commissioning newly expanded components of the plant that are expected to bring the company’s oil sands production capacity to 260,000 bpd by year end.

“Work to restore production, bring forward planned maintenance and increase production capacity, all remain on schedule,” said George. “The near-term set back of the fire does not detract from the solid operational and financial foundation that underlies our long-term growth plans.”

Growth projects beyond 2005 are proceeding according to plan. Expansion work to increase production capacity to 350,000 bpd in 2008 is well under way and in March, Suncor filed a regulatory application to construct a third upgrader as part of its Voyageur strategy which targets production capacity of 550,000 bpd in 2012.

“The next phases of expansion are expected to increase production capacity by 50% in the next three years and more than double production in the next seven years,” said George. “That’s a growth plan few companies of our size can match.”

In April, Suncor’s Canadian downstream operations received regulatory approval to build and operate a new facility to supply ethanol for blending in gasoline. The $120 million facility is expected to produce 200 million litres of ethanol per year when completed in 2006. The Federal government will contribute $22 million to the project through Natural Resources Canada’s Ethanol Expansion Program.

As Suncor invests for future growth, prudent debt management remains a priority. At the end of the first quarter, the company’s net debt was $2.5 billion. This is expected to increase as Suncor continues to fund growth during a period of reduced cash flow, primarily as a result of the January fire at oil sands. Suncor expects insurance proceeds will substantially mitigate impacts to the company’s balance sheet and, as insurance settlements are reached, the majority of proceeds are planned to be used to reduce debt.

Remembrance

On February 26, Nabors Drilling employee Bryan Gaudet, 31, died following injuries sustained while working on a Suncor well site in northeastern British Columbia. “This is a tragic reminder of the importance of safety on our work sites – for both Suncor employees and our contractors,” said Rick George.

Suncor has completed its investigation into the accident and is working with our contractors to strengthen procedures and the provision of training to prevent any similar tragedy in the future. A report and recommendations have been submitted to the British Columbia Workers’ Compensation Board.

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“The next phases of expansion are expected to increase production capacity by 50% in the next three years and more than double production in the next seven years. That’s a growth plan few companies of our size can match.” Rick George president and chief executive officer

outlook for 2005

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

Oil Sands

As a result of the January fire at the company’s oil sands facility, production capacity is expected to average about 110,000 bpd plus bitumen production from in-situ operations. Suncor expects to return to production capacity of approximately 225,000 bpd in September and increase production capacity to 260,000 bpd by year end.

Because Suncor is still working on fire recovery, specific targets for oil sands production, sales mix and cash operating costs are not currently available.

Natural Gas

Suncor’s Natural Gas business continues to focus on increasing production by 3% to 5% per year to provide a financial hedge against natural gas use at the company’s oil sands and refining operations. In 2005, this business is targeting natural gas production of 205 to 210 mmcf/d and crude oil and natural gas liquids production of 3,300 bpd.

Factors that could potentially impact Suncor’s financial performance during 2005 include:

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

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

• A scheduled 42-day maintenance shutdown at the Denver refinery during the fourth quarter.

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

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EX-99.2

Exhibit 99.2

Interim Management's Discussion and Analysis for the first fiscal quarter ended March 31, 2005

management’s discussion and analysis

April 27, 2005

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 15 for additional information.

This MD&A should be read in conjunction with our March 31, 2005 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 14 to 52 of our 2004 Annual Report and to our 2004 Annual Information Form. 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 and total operating costs per barrel, referred to in this MD&A, are not prescribed by GAAP and are outlined and reconciled in “Non GAAP Financial Measures” on page 13.

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

Base operations refer 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 “we,” “our,” “us,” “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.

selected financial information

Industry Indicators

	3 months ended March 31
(average for the period)	2005	2004
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	49.85	35.15
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	61.95	46.00
Light/heavy crude oil differential US$/barrel – WTI at Cushing less Lloyd Blend at Hardisty	19.25	10.10
Natural gas US$/mcf at Henry Hub	6.30	5.70
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.70	6.60
New York Harbour 3-2-1 crack(1) US$/barrel	6.00	6.95
Exchange rate: Cdn$:US$	0.82	0.76

(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.

Outstanding Share Data (as at March 31, 2005)
Common shares	455 810 483
Common share options – total	20 306 629
Common share options – exercisable	11 045 834

Summary of Quarterly Results

	2005 Quarter ended	2004 Quarter ended				2003 Quarter ended
($ millions, except per share data)	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30
Revenues	2 061	2 310	2 315	2 201	1 795	1 698	1 788	1 385
Net earnings	98	333	337	202	216	301	285	125
Net earnings attributable to common shareholders per share
Basic	0.22	0.73	0.74	0.44	0.48	0.67	0.63	0.27
Diluted	0.21	0.72	0.73	0.43	0.46	0.62	0.61	0.24

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ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the first quarter of 2005 were $98 million, compared to $216 million for the first quarter of 2004. The decrease in net earnings was primarily due to:

•a decrease in Oil Sands crude oil production as a result of a fire that occurred on January 4, 2005 (see below), which resulted in reduced sales volumes and revenues;

•     lower refining margins in our Canadian downstream operations primarily due to higher feedstock prices; and

•     a first quarter 2004 reduction in the Alberta corporate income tax rate of 1%, which resulted in a $53 million one time reduction in non-cash income taxes compared to no reduction in the first quarter of 2005.

These negative impacts were partially offset by:

•     an increase in the average price realization for Oil Sands crude oil to $46.44 per barrel in the first quarter of 2005 from $38.16 per barrel during the first quarter of 2004. The price increase was due mainly to an increase in the average benchmark WTI crude oil price, partially offset by a lower percentage of high value products in Oil Sands sales mix due to reduced production capacity as a result of the fire. The noted price increase was also partially offset by an 8% strengthening of the Canadian dollar compared to the U.S. dollar. Because crude oil is sold based on U.S. dollar benchmark prices, the stronger Canadian dollar reduces the realized value of Suncor’s products.

•     improved refining margins and sales volumes at our U.S. downstream operations.

•     accrued fire insurance proceeds, net of the write-off of damaged assets and related expenses which increased net earnings by $41 million (see below).

•     lower financing expenses reflecting a $16 million after-tax decrease in non-cash foreign exchange losses on U.S. dollar denominated debt, and a reduction in interest expense due to lower effective interest rates, lower average levels of outstanding long term borrowings and higher capitalized interest.

Cash flow from operations in the first quarter was $294 million, compared to $414 million in the same period of 2004. Excluding the effects of unrealized foreign exchange losses, non-cash stock based compensation expense and non-cash income tax adjustments, cash flow from operations was lower quarter over quarter primarily due to the same factors affecting earnings.

Our effective tax rate for the first quarter of 2005 was 44%, compared to 19% in the first quarter of 2004. The lower effective tax rate in the first quarter of 2004 was due to the revaluation of future taxes for the substantial enactment of the Alberta tax rate reduction. The increase in the 2005 effective tax rate was due to the proportionately lower Oil Sands earnings relative to consolidated earnings. As a result, earnings subject to a higher effective tax rate (our Natural Gas business unit), and the large corporations tax (which is a capital tax insensitive to earnings), have a greater impact on the overall effective tax rate. The effective tax rate for 2005 is expected to be closer to 37% as additional business interruption insurance proceeds are received and Oil Sands production capacity is restored to pre-fire levels.

Oil Sands Fire

On January 4, 2005, a fire at our Oil Sands operations damaged Upgrader 2. Despite average base operations production in the first quarter of 121,200 bpd, we continue to target oil sands base operations production of 110,000 bpd over the full recovery period due to the potential impacts of production interruptions related to maintenance. The damaged equipment has been dismantled and removed, and reconstruction is well under way. The rebuild is expected to take several months and we expect to return to full production capacity of 225,000 bpd in September 2005. In order to return to full production capacity once the rebuild is complete, a maintenance shutdown originally scheduled for the third quarter of 2005 is now in progress.

Suncor carries property loss and business interruption insurance policies with a combined coverage limit of up to US$1.15 billion, net of deductible amounts, which is expected to substantially mitigate, upon receipt of these funds, the financial impact of the fire. The primary property loss policy of US$250 million has a deductible per incident of US$10 million and the primary business interruption policy of US$200 million has a deductible per incident of the greater of US$50 million gross earnings lost (as defined in the insurance policy) or 30 days from the date of the fire. In addition to these primary coverage insurance policies, we have additional coverage of US$700 million that can be used for either property loss or business interruption. For business interruption purposes, this additional coverage begins on the later of full utilization of the primary business interruption coverage or 90 days from the date of the fire.

During the first quarter of 2005, we accrued $63 million ($41 million after-tax) of insurance proceeds (from both the business interruption and the property loss policies), net of the write-off of the net book value of the damaged assets and the expenses incurred to fight the fire, safe the site, and investigate the cause and extent of the damage. Business interruption proceeds are treated in the same manner for royalty purposes as the revenues they replace and accordingly attract Alberta Crown royalties (see page 8).

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On April 21, 2005 we received a $73 million interim payment under our business interruption insurance policy. These proceeds related to business activity in the first quarter of 2005 and have accordingly been recorded as “net insurance proceeds” in the first quarter. Additional business interruption insurance proceeds will be recorded at the time of unconditional receipt. In April we also received an initial $12 million as partial payment against accrued property loss insurance proceeds.

NET EARNINGS COMPONENTS

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

	3 months ended March 31
($ millions, after tax)	2005		2004
Net earnings before the following items	62		198
Firebag in-situ start-up costs	—		(14	)
Oil Sands fire accrued insurance proceeds (net), excluding incremental Alberta Crown royalties	41		—
Impact of income tax rate reductions on opening future income tax liabilities	—		53
Unrealized foreign exchange losses on U.S. dollar denominated long-term debt	(5	)	(21	)
Net earnings as reported	98		216

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2005 first quarter net earnings of $117 million, compared with $239 million in the first quarter of 2004. The decrease in net earnings was primarily due to decreased revenues as a result of the fire. The fire resulted in lower production and sales volumes, and a less favourable sales mix of sweet crude oil and diesel fuel compared to sour crude and bitumen, due to reduced upgrading capacity. Partially offsetting these negative factors were net insurance proceeds related to the fire that increased net earnings by $41 million (excluding Alberta Crown royalties). An increase in the average realization

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for our oil sands crude oil products, reflecting a 42% increase in average benchmark WTI crude oil prices partially offset by the lower percentage of high value products in our sales mix and an 8% strengthening of the Canadian dollar compared to the U.S. dollar.

Despite reduced production volumes, Oil Sands operating costs remained relatively stable in the first quarter of 2005 compared to 2004. Operating expenses have increased to $242 million before tax in the first quarter of 2005 from $214 million before tax in the first quarter of 2004. The increase is due primarily to increased in-situ operating costs. In the first quarter of 2004 in-situ operations were in startup and the related costs were not included in operating expenses. These higher expenses were partially offset by higher deferral of costs related to overburden removal. Due to reduced oil sands ore mining activities as a result of the fire, we have redeployed some of our mining resources to overburden removal. The decrease in oil sands production has also lead to lower amortization of deferred overburden. As a result, depreciation, depletion and amortization expense decreased to $107 million before tax in 2005 from $124 million before tax in the first quarter of 2004.

Despite lower production and earnings, Alberta Crown royalty expense was $87 million before tax in the first quarter of 2005 compared to $62 million before tax in the first quarter of 2004. See page 8 for a discussion of Alberta Oil Sands Crown royalties.

Cash flow from operations for the quarter was $252 million, compared to $365 million in the first quarter of 2004. Excluding the impact of non-cash income taxes, and depreciation, depletion and amortization, the decrease was primarily due to the same factors that impacted net earnings.

Oil sands production during the first quarter averaged 139,900 bpd, comprising 121,200 bpd of upgraded crude oil from base operations and 18,700 bpd of bitumen production from in-situ operations. This compares to production of 219,800 bpd during the first quarter of 2004 comprising 213,900 bpd of upgraded crude oil from base operations and 5,900 bpd of bitumen production from in-situ operations.

Sales during the first quarter averaged 144,000 bpd, compared with 214,000 bpd during the first quarter of 2004. The sales mix of higher value sweet products decreased to 60% in the first quarter of 2005, compared to 65% in the first quarter of 2004. Sales prices averaged $46.44 per barrel during the first quarter of 2005 compared to $38.16 per barrel in the first quarter of 2004.

During the first quarter, cash operating costs for base operations averaged $19.90 per barrel, compared to $12.15 per barrel during the first quarter of 2004. Cash operating costs per barrel increased due to total cash operating costs being applied to fewer barrels of base operations production as a result of the fire. For further details on cash operating costs as a non GAAP financial measure, including the calculation and reconciliation to GAAP measures (see page 13).

We are targeting completion of the rebuild and commissioning and start up of Upgrader 2 in September 2005. In the fourth quarter, we will focus on commissioning newly expanded components of the base plant that are expected to bring production capacity to 260,000 bpd. Construction of a second vacuum unit, a key component to reaching that milestone, is 90% complete. Construction of the Firebag Stage 2 in-situ operation is 70% complete with steaming scheduled to start in late 2005. In addition, Suncor is continuing to progress plans to expand capacity to 350,000 bpd in 2008. See page 11 for an update on our significant growth projects currently in progress.

On March 14, 2005, we filed an application with Alberta regulators to construct and operate a third oil sands upgrader, designed to increase production capacity to more than half a million barrels of oil per day. The new facility is planned to include cokers, hydrotreaters, utilities support and a 50 kilometre hot bitumen pipeline to connect the upgrader with Suncor’s in-situ operations. A decision by regulators on this application is expected to take approximately two years, and construction is not expected to begin until 2007. Production from the new facility is currently expected to be brought on line in phases starting in 2010 with full production capacity of approximately 550,000 bpd targeted in 2012. Preliminary estimates place the cost of the upgrader at $5.9 billion. Final cost estimates for the project must be approved by our Board of Directors before construction can proceed. We expect to submit separate applications that will outline plans to provide bitumen feed to the proposed upgrader.

Also, on March 14, 2005, a second application was filed with Alberta regulators requesting permission to proceed with the Steepbank Mine extension at an estimated cost of $350 million.

The estimated capital cost of these projects is at a very preliminary stage and is still subject to a high level of uncertainty. The project scope and engineering detail will continue to evolve and will influence the estimated capital cost. All cost estimates are by their nature uncertain, and can be subject to wide variances as engineering is developed and even as construction progresses. Estimates are subject to revisions which may be material, particularly when given at very early stages of project development.

A summary of both applications is available on www.suncor.com.

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Oil Sands Crown Royalties and Cash Income Taxes

Crown royalties in effect for Oil Sands operations 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) for each project, subject to a minimum payment of 1% of R. In April 2004, the Alberta government confirmed it would modify our royalty treatment because it does not recognize our Firebag in-situ facility as an expansion to our existing Oil Sands project. Accordingly, for Alberta Crown royalty purposes, our oil sands operations are considered two separate projects: base oil sands mining and associated upgrading operations with royalties based on upgraded product values and the current Firebag in-situ project with royalties based on bitumen values. Alberta Oil Sands Crown royalties may be subject to change as policies arising from the Government’s position are finalized and audits of 2004 and prior years are completed. Changes to the estimated amounts previously recorded will be reflected in our financial statements on a prospective basis and may be significant.

Oil Sands first quarter pretax Alberta Crown royalty estimate of $87 million ($53 million after tax) was based on:

•average 2005 crude oil pricing of approximately US$54.95 WTI per barrel (based on a average price of US$49.85 WTI per barrel for the first three months of 2005, as well as 2005 forward crude oil pricing at March 31, 2005 of US$56.65 per barrel for the remainder of the year).

•     current forecasts of capital and operating costs for the remainder of 2005.

•     an average annual Cdn$/US$ exchange rate of $0.82.

•     the receipt of $73 million of business interruption insurance proceeds on April 22, 2005. Business interruption proceeds are considered to be R for the purposes of the calculation of Alberta Crown royalties. However, they are only included in the estimate when unconditionally settled.

Using these assumptions, we estimate 2005 annualized pretax royalties to be approximately $450 million ($280 million after tax), compared to $407 million ($260 million after tax) in 2004.

Alberta Crown royalties payable in 2005 and subsequent years continue to be 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 was a transition year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed in 2004 to reduce our 2004 Alberta Crown royalty obligation. No such carry forward of allowed costs exists for 2005 and subsequent years.

Assuming anticipated levels of operating expenses and capital expenditures for each project remain relatively constant, variability in expected Oil Sands Crown royalty expense is primarily a function of changes in expected annual Oil Sands revenue. Absent the impact of the January 4, 2005 fire, we expect that Alberta Oil Sands Crown royalty expense for the period 2005 to 2007 would range from approximately 12% to 14% of total Oil Sands Revenue based on WTI prices of US$40 per barrel to US$50 per barrel respectively. For subsequent years, this percentage range may decline as anticipated new in-situ production attracts royalties based on bitumen values. This royalty percentage range is based on the following assumptions: a natural gas price of US$6.25 per thousand cubic feet (mcf) at Henry Hub; a light/heavy oil differential to the U.S. Gulf Coast of US$9 per barrel, and a Cdn$/US$ exchange rate of $0.80.

Alberta Oil Sands Crown royalty expense in 2005 and 2006 may be significantly impacted by the amount and timing of the recognition of the business interruption insurance proceeds. Accordingly, the range of annualized royalty expense as a percentage of revenues may differ from that stated above, and these differences may be material.

Based on our current long-term planning assumptions, the 25% R-C royalty would continue to apply to our existing Oil Sands base operations in future years and the 1% minimum royalty would apply to our Firebag Project until the next decade. We continue to discuss the terms of our option to transition to the generic bitumen-based royalty regime in 2009. After 2009, the royalty would be based on bitumen value if we exercise our option to transition to the Province of Alberta’s generic regime for oil sands royalties. In the event that we exercise this option, future upgrading operations would not be included for Oil Sands Crown royalty purposes.

The timing of when the Oil Sands operations will be fully cash taxable is highly dependent on crude oil commodity prices and capital invested. At WTI prices between US$34 per barrel and US$50 per barrel, an average annual Cdn$/US$ foreign exchange rate of $0.80, future investment plans and certain other assumptions, we do not believe we will be fully cash taxable until the next

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decade. However, in any particular year, our Oil Sands and Natural Gas operations may be subject to some cash income tax due to the sensitivity to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for tax purposes. At sustained forward prices, based on the assumptions stated above, we anticipate that Oil Sands and Natural Gas operations will be partially cash taxable commencing in 2009 at WTI prices of US$34 per barrel, and in 2007 at WTI prices of US$40 per barrel to US$50 per barrel, until the next decade, at which point they are expected to become fully cash taxable.

The information in the preceding paragraphs under “Oil Sands Crown Royalties and Cash Income Taxes” incorporates operating and capital cost assumptions included in our current budget and long-range plan, and is not an estimate, forecast or prediction of actual future events or circumstances.

Natural Gas

Natural Gas recorded 2005 first quarter net earnings of $26 million, compared with $22 million during the first quarter of 2004. Higher natural gas prices and lower exploration expenses were partially offset by lower production volumes and increased depletion, depreciation and amortization expense. Realized natural gas prices in the first quarter of 2005 were $6.81 per mcf compared to $6.54 per mcf in the first quarter of 2004 reflecting higher benchmark commodity prices offset by a stronger Canadian dollar.

Cash flow from operations for the first quarter of 2005 was $83 million consistent with the first quarter of 2004, as higher natural gas prices and lower exploration expenses were offset by lower production volumes.

Our strategy calls for natural gas production to exceed natural gas purchases for internal consumption, retaining our position as a net seller into the North American market. Natural gas production in the first quarter was 191 million cubic feet (mmcf) per day, compared to 197 mmcf per day in the first quarter of 2004. The 2005 production outlook targets an average of 205 to 210 mmcf per day for the year, exceeding Suncor’s projected purchases.

Energy Marketing & Refining – Canada

Energy Marketing and Refining – Canada (EM&R) has historically reported its segmented results on a Rack Back/Rack Forward divisional basis. The Rack Back division included Ontario refining operations, as well as sales and distribution to the Sarnia refinery’s largest industrial and reseller customers and the Sun Petrochemicals Company (SPC) joint venture. Rack Forward included retail operations, cardlock and industrial/commercial sales as well as the UPI and Pioneer joint ventures.

EM&R’s Rack Back and Rack Forward organizational structures have now been consolidated into one unit for the purposes of external segmented reporting. Prior year amounts have been reclassified to conform to this presentation. EM&R’s external results continue to be measured and analyzed on a margin basis.

EM&R recorded 2005 first quarter net losses of $3 million, compared to net earnings of $30 million in the first quarter of 2004. The decrease was primarily due to higher feedstock and product purchase prices reflecting higher overall commodity price levels that resulted in lower refining margins. Also contributing to the decrease in earnings were lower refining volumes and lower mark-to-market gains on inventory related derivatives.

Refining margins on Suncor’s proprietary refined products were 4.8 cents per litre (cpl) in the first quarter of 2005, significantly lower than the 7.8 cpl realized in the first quarter of 2004. The decrease was primarily due to record high synthetic crude oil prices resulting in increased feedstock prices. Refining utilization decreased to 91% in the first quarter of 2005 from 108% in the first quarter of 2004, as a result of synthetic crude oil supply issues, due in part to the fire at Oil Sands which reduced synthetic crude oil production.

Retail margins were 4.7 cpl in the first quarter of 2005 compared to 5.0 cpl in the first quarter of 2004. The decrease was due to continuing competitive pressures in the Ontario market, combined with higher crude input costs.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $2 million in the first quarter of 2005, unchanged from the first quarter of 2004.

9

Cash flow from operations for the first quarter decreased to $22 million in the first quarter of 2005 from $56 million in the first quarter of 2004. The decrease was primarily due to the same factors that decreased net earnings.

Suncor’s diesel desulphurization project at the Sarnia refinery is on schedule and on budget. When complete, modifications to the refinery will allow Suncor to meet federal regulations for on-road ultra-low sulphur diesel fuel as well as permitting the processing of Oil Sands sour crude oil. See page 11 for an update on our significant projects in progress.

On March 17, 2005, portions of the Sarnia refinery were shutdown to perform planned maintenance. The work was completed on schedule.

Refining & Marketing – U.S.A.

Refining & Marketing – U.S.A. (R&M) recorded net earnings of $6 million in the first quarter of 2005 compared to losses of $3 million during the first quarter of 2004. Net earnings in 2005 were positively impacted by higher refinery utilizations resulting in increased sales volumes and higher refining margins, partially offset by higher feedstock costs and lower retail margins.

Cash flow from operations for the first quarter was $18 million compared to cash used in operations of $6 million in the first quarter of 2004. Cash flow from operations increased due to the same factors that increased net earnings.

Refining margins in the first quarter of 2005 averaged 6.3 cpl, compared to 5.0 cpl in the first quarter of 2004, reflecting record high prices for light oil products. Refinery utilization at the Denver refinery averaged 96% in the first quarter of 2005 compared to 85% in the first quarter of 2004. The lower utilization during the first quarter of 2004 was a result of operating difficulties with several of the refinery’s major units.

As a result of competitive pressures and high fuel costs, retail margins averaged 3.3 cpl in the first quarter of 2005, compared to 5.0 cpl in the same period of 2004.

Construction at the Denver refinery to meet clean fuels regulations and to modify the refinery to handle higher volumes of Oil Sands sour crude oil blends is well under way. See page 11 for an update on our significant projects.

Corporate

Corporate recorded a net loss in the first quarter of 2005 of $48 million, compared to a net loss of $72 million during the first quarter of 2004. Corporate expenses were lower in the first quarter of 2005 primarily due to the impact of lower net financing expenses. After-tax unrealized foreign exchange losses on U.S. dollar denominated long-term debt were $5 million in the first quarter of 2005 compared to $21 million in 2004. After-tax interest expense was $5 million during the first quarter of 2005 compared to $25 million in the first quarter of 2004. Total interest expense was lower in the first quarter of 2005 due mainly to refinancing debt with shorter duration, lower floating rate instruments. As a result, the effective interest rate on our long-term debt was 5.8% in the first quarter of 2005 compared to 6.4% in the first quarter of 2004. In addition to lower effective interest rates, average debt outstanding in the first quarter of 2005 was $2.4 billion compared to $3.0 billion in 2004. Capitalized interest in the first quarter of 2005 was $17 million after tax compared to $7 million after tax in the first quarter of 2004, due mainly to higher levels of construction in progress in 2005.

Partially offsetting the impact of lower financing costs, corporate net earnings were negatively impacted by higher stock-based compensation expense and higher insurance related costs.

Cash flow used in operations in the first quarter was $81 million, compared to $84 million used in the first quarter of 2004. The decreased use of cash was primarily due to the earnings factors described above, excluding the impact of the unrealized foreign exchange losses on U.S. dollar denominated debt and non-cash stock-based compensation expenses.

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, 2,062,000 SunShare options vested, representing approximately 25% of the then outstanding unvested options under the SunShare Plan. As we had been accruing the costs of these options throughout the vesting period, there was no incremental cost related to stock based compensation expense during the first quarter.

10

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 $207 million at the end of the first quarter, compared to a deficiency of $329 million at the end of the first quarter, of 2004. The decrease in our working capital deficiency is due primarily to higher accounts receivable balances as a result of higher commodity prices and accrued insurance proceeds, partially offset by increased accounts payable balances as a result of increased construction activity and the purchase of feedstock and refined products at higher commodity prices.

During the first quarter of 2005, net debt increased to approximately $2.5 billion from $2.2 billion at December 31, 2004. The increase in debt levels was a result of reduced cash flow from operations as a result of the fire. While we expect the financial impact of the fire will be substantially mitigated by insurance proceeds, debt is expected to grow during the recovery period as the timing of insurance proceeds is uncertain. At March 31, 2005 our undrawn lines of credit were approximately $1.2 billion. Notwithstanding the impact of the fire at Oil Sands on cash flow from operations and the cost to repair damaged facilities, we believe we have the capital resources from our undrawn lines of credit, cash flow from operations and, if necessary, additional sources of financing to fund our anticipated $2.5 billion in 2005 capital spending and to meet our current working capital requirements. If additional capital is required, we believe adequate additional financing is available at commercial terms and rates.

We spent $609 million towards capital investing activities in the first quarter of 2005. A summary of the progress on our significant projects under construction is provided below.

SIGNIFICANT CAPITAL PROJECT UPDATE

Description	Board of Directors’ Approval	Cost Estimate (1) ($ millions)			Spent 2005 Year to Date ($ millions)			Total Spent to Date ($ millions)			Status
Oil Sands
Millennium vacuum unit	Yes	$	425		$	18		$	411		Project is on schedule.
											Commissioning and start up planned for Q4 2005.
Firebag stage 2	Yes	$	515		$	36		$	435		Project is on schedule.
											Initial steaming planned for late 2005.
Coker unit (2)	Yes	$	2 100		$	102		$	501		Project is on schedule for completion in 2008.
EM&R
Clean fuels and	Yes	$	800		$	73		$	251		Project is on schedule
Oil Sands integration											for completion in 2006.
R&M
Clean fuels and	Yes	$	360		$	59		$	195		Project is on schedule
Oil Sands integration		(US$300		)	(US$49		)	(US$153		)	for completion in 2006.

(1)Estimating and budgeting for major capital projects is a process that involves uncertainties and that evolves in stages, each with progressively more refined data and a correspondingly narrower range of uncertainty. At very early stages, when broad engineering design specifications are developed, the level of uncertainty can result in price ranges with -25%/+50% (or similar) levels of uncertainty. As project engineering progresses, vendor bids are studied, goods and materials ordered and we move closer to the build stage, the level of uncertainty narrows. Generally, when projects receive final approval from our Board of Directors, our cost estimates have a range of uncertainty that has narrowed to the - -10%/+10% or similar range. These ranges establish an expected high and low capital cost estimate for a project. When we say that a project is “on budget”, we mean that we still expect the final project capital cost to fall within the current range of uncertainty for the project. Even at this stage, the uncertainties in the estimating process and the impact of future events, can and will cause actual results to differ, in some cases materially, from our estimates.

(2)Excludes costs associated with bitumen feed.

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Derivative Financial Instruments

In the first quarter of 2004 we suspended our strategic hedging program and have not entered into any new strategic crude oil hedges. Our strategic hedging program permitted us to fix a price or range of prices for a percentage of our total production of crude oil for specified periods of time.

We continue to be party to crude oil hedges, covering 36,000 bpd of production placed prior to the suspension of the program. 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 first quarter of 2005, strategic crude oil hedging decreased our after-tax net earnings by $65 million, the same amount as the first quarter of 2004.

The fair value of strategic 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 March 31:

($ millions)	2005		2004
Revenue hedge swaps and options	(407	)	(416	)
Margin hedge swaps	(16	)	4
Interest rate and cross-currency interest rate swaps	28		42
	(395	)	(370	)

We also use derivative instruments to hedge risks specific to individual transactions. The estimated fair value of these instruments was $14 million at March 31, 2005 compared to $9 million at December 31, 2004.

Energy Marketing and Trading Activities

For the quarter ended March 31, 2005, we recorded a net pretax gain of $2 million equal to the $2 million recorded during the first quarter of 2004, related to the settlement and revaluation of financial energy trading contracts. In the first quarter, the settlement of physical trading activities also resulted in a net pretax gain of $2 million compared to a $1 million pretax gain in the first quarter of 2004. These gains were included as energy marketing and trading activities in the Consolidated Statement of Earnings. The above amounts do not include the impact of related general and administrative costs. Total after tax energy marketing and trading activities resulted in a gain of $2 million for the quarter ended March 31, 2005 equivalent to the gain in the first quarter of 2004. The fair value of unsettled financial energy trading assets and liabilities at March 31, 2005 and December 31, 2004 were as follows:

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

Control Environment

Based on their evaluation as of March 31, 2005, our chief executive officer and chief financial officer concluded that our 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 (the Exchange Act)) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, other than as described below, as of March 31, 2005, there were no changes in our internal controls over financial reporting that occurred during the three month period ended March 31, 2005 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal controls over financial reporting and will make any modifications from time to time as deemed necessary.

We are currently in the process of implementing an enterprise resource planning (ERP) system in all of our businesses to support our growth plan. The phased implementation is currently planned to be complete by 2006. Implementing an ERP system on a widespread basis involves significant changes in business processes and extensive training. We believe a phased-in approach reduces the risks associated with making these changes. We believe

12

we are taking the necessary steps to monitor and maintain appropriate internal controls during this transition period. These steps include deploying resources to mitigate internal control risks and performing additional verifications and testing to ensure data integrity.

We have evaluated the effectiveness of our internal control over financial reporting as part of the reporting, certification and attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of 2002. We have concluded that our disclosure controls and procedures have operated effectively and free of any material weaknesses for the quarter ended March 31, 2005. In connection with the continued implementation of our ERP system, we expect there will be a significant redesign of processes during 2006, some of which relate to internal controls over financial reporting and disclosure controls and procedures.

Change in Accounting Policies

Effective January 1, 2005, we retroactively adopted the Canadian Accounting Standards Board amendment to Handbook Section 3860 “Financial Instruments – Disclosure and Presentation”. The amendment requires that certain obligations that must or could be settled with an entity’s own equity investments, be presented as liabilities. Accordingly, we have reclassified our preferred securities from equity to long-term debt, resulting in an increase to property, plant and equipment of $37 million, an increase in future tax liabilities of $13 million and an increase in retained earnings of $24 million.

Also on January 1, 2005 we adopted Canadian Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities (VIEs)” without restatement of prior periods. The guideline requires consolidation of a VIE where the company will absorb a majority of a VIE’s losses, receive a majority of its returns, or both. Accordingly, we consolidated a VIE related to an equipment sale and leaseback arrangement with a third party which was entered into in 1999. The third party’s sole asset is the equipment sold to it and leased back by us. The impact of adopting this guideline was an increase to property, plant and equipment of $14 million, an increase to materials and supplies inventory of $8 million and an increase to long-term debt of $22 million.

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 March 31, 2005 interim basis, please refer to page 27 of the Quarterly Operating Summary included in our 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 March 31, 2005 unaudited interim consolidated financial statements.

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

For the three months ended March 31			2005	2004
Cash flow from operations ($ millions)	A		294	414
Weighted average number of common shares outstanding (millions of shares)	B		454.9	452.1
Cash flow from operations (per share)	(A / B	)	0.65	0.92

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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

		Quarter ended March 31
		2005			2004 (1)
		$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		210			214
Less: natural gas costs and inventory changes		(58	)		(33	)
Accretion of asset retirement obligations		6			5
Taxes other than income taxes		7			7
Cash costs		165		15.10	193		9.65
Natural gas		51		4.70	42		2.10
Imported bitumen (net of other reported product purchases)		1		0.10	8		0.40
Cash operating costs	A	217		19.90	243		12.15
Start-up costs		—			22
Add: in-situ inventory changes		—			2
Less: pre-start-up commissioning costs		—			—
In-situ (Firebag) start-up costs	B	—		—	24		1.20
Total cash operating costs	A+B	217		19.90	267		13.35
Depreciation, depletion and amortization		99		9.05	124		6.20
Total operating costs		316		28.95	391		19.55
Production (thousands of barrels per day)		121.2			219.8

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

	Quarter ended March 31
	2005			2004 (1)
	$ millions		$/barrel	$ millions	$/barrel
Operating, selling and general expenses	32			—
Less: natural gas costs and inventory changes	(17	)		—
Accretion of asset retirement obligations	—			—
Taxes other than income taxes	—			—
Cash costs	15		8.90	—	—
Natural gas	17		10.10	—	—
Cash operating costs	32		19.00	—	—
Depreciation, depletion and amortization	8		4.75	—	—
Total operating costs	40		23.75	—	—
Production (thousands of barrels per day)	18.7

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

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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,” “estimates,” “plans,” “intends,” “believes,” “projects,” “indicates,” “could,” “focus,” “vision,” “goal,” “proposed,” “target,” “objective,” and similar expressions. These statements are not guarantees of future performance 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 and increase the 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 the January 2005 fire at the Oil Sands facility and other uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as the January 2005 fire, 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 at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. 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.

15

EX-99.3

Exhibit 99.3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the first fiscal quarter ended March 31, 2005

consolidated statements of earnings

(unaudited)

	Three months ended March 31
($ millions)	2005	2004
Revenues (note 10)	2 061	1 795
Expenses
Purchases of crude oil and products	816	531
Operating, selling and general (note 6)	468	400
Energy marketing and trading activities (note 3)	134	67
Transportation and other costs	34	27
Depreciation, depletion and amortization (note 2)	165	175
Accretion of asset retirement obligations	8	6
Exploration	17	33
Royalties (note 9)	115	91
Taxes other than income taxes	120	119
Gain on disposal of assets	—	(1	)
Project start-up costs	3	22
Financing expenses (notes 2 and 4)	7	59
	1 887	1 529
Earnings Before Income Taxes	174	266
Provision for Income Taxes (note 2)
Current	29	20
Future	47	30
	76	50
Net Earnings	98	216
Per Common Share (dollars), (note 5)
Basic	0.22	0.48
Diluted	0.21	0.46
Cash dividends	0.06	0.05

See accompanying notes.

16

consolidated balance sheets

(unaudited)

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

Shareholders’ Equity

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

See accompanying notes.

17

consolidated statements of cash flows

(unaudited)

	Three months ended March 31
($ millions)	2005		2004
Operating Activities
Cash flow from operations	294		414
Decrease (increase) in operating working capital
Accounts receivable	(226	)	(132	)
Inventories	(4	)	(33	)
Accounts payable and accrued liabilities	214		111
Taxes payable	(23	)	8
Cash flow from operating activities	255		368
Cash Used in Investing Activities	(615	)	(350	)
Net Cash Surplus (Deficiency) Before Financing Activities	(360	)	18
Financing Activities
Increase (decrease) in short-term debt	(22	)	7
Net increase (decrease) in other long-term debt	311		(352	)
Issuance of common shares under stock option plan	31		17
Dividends paid on common shares	(25	)	(21	)
Deferred revenue	16		—
Cash provided by (used in) financing activities	311		(349	)
Decrease in Cash and Cash Equivalents	(49	)	(331	)
Cash and Cash Equivalents at Beginning of Period	88		388
Cash and Cash Equivalents at End of Period	39		57

See accompanying notes.

18

consolidated statements of changes in shareholders’ equity

(unaudited)

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

See accompanying notes.

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schedules of segmented data

(unaudited)

	Three months ended March 31
									Energy Marketing				Refining and
									and Refining -				Marketing -				Corporate and
	Oil Sands				Natural Gas				Canada				U.S.A.				Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
EARNINGS
Revenues
Operating revenues	553		666		131		91		765		678		411		289		1		—		1 861		1 724
Energy marketing and trading activities	—		—		—		—		137		78		—		—		—		(8	)	137		70
Net insurance proceeds (note 10)	63		—		—		—		—		—		—		—		—		—		63		—
Intersegment revenues	77		99		6		42		—		—		—		—		(83	)	(141	)	—		—
Interest	—		—		—		—		—		—		—		—		—		1		—		1
	693		765		137		133		902		756		411		289		(82	)	(148	)	2 061		1 795
Expenses
Purchases of crude oil and products	9		12		—		—		561		438		329		224		(83	)	(143	)	816		531
Operating, selling and general	242		214		21		20		108		96		32		33		65		37		468		400
Energy marketing and trading activities	—		—		—		—		134		75		—		—		—		(8	)	134		67
Transportation and other costs	24		17		5		5		1		1		4		4		—		—		34		27
Depreciation, depletion and amortization	107		124		31		28		18		17		6		3		3		3		165		175
Accretion of asset retirement obligations	6		5		2		1		—		—		—		—		—		—		8		6
Exploration	10		13		7		20		—		—		—		—		—		—		17		33
Royalties	87		62		28		29		—		—		—		—		—		—		115		91
Taxes other than income taxes	7		7		—		—		83		83		30		29		—		—		120		119
Gain on disposal of assets	—		—		—		(1	)	—		—		—		—		—		—		—		(1	)
Project start-up costs	3		22		—		—		—		—		—		—		—		—		3		22
Financing expenses	—		—		—		—		—		—		—		—		7		59		7		59
	495		476		94		102		905		710		401		293		(8	)	(52	)	1 887		1 529
Earnings (loss) before income taxes	198		289		43		31		(3	)	46		10		(4	)	(74	)	(96	)	174		266
Income taxes	(81	)	(50	)	(17	)	(9	)	—		(16	)	(4	)	1		26		24		(76	)	(50	)
Net earnings (loss)	117		239		26		22		(3	)	30		6		(3	)	(48	)	(72	)	98		216
As at March 31
TOTAL ASSETS	9 577		8 282		1 005		809		1 460		1 144		725		410		(176	)	(27	)	12 591		10 618

20

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

21

notes to the consolidated financial statements

(unaudited)

1. ACCOUNTING POLICIES

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

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

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

2. CHANGES IN ACCOUNTING POLICIES

(a) Preferred Securities

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

Change in Consolidated Balance Sheets

	As at March 31
($ millions, increase)	2005	2004
Property, plant and equipment	37	39
Total assets	37	39
Future income tax liabilities	13	14
Retained earnings	24	25
Total liabilities and shareholders’ equity	37	39

Change in Consolidated Statements of Earnings

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

(b) Consolidation of Variable Interest Entities

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

22

3. ENERGY MARKETING AND TRADING ACTIVITIES

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

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

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

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

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

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

4. FINANCING EXPENSES

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

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

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

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

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

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

(a)For the three months ended March 31, 2004, diluted earnings per share is net earnings divided by the weighted-average number of diluted common shares. Interest on subordinated debentures, the revaluation of US$ subordinated debentures and the redemption of subordinated debentures by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share.

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

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

23

6. STOCK-BASED COMPENSATION

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

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

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

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

(a) Stock Option Plans

Under the SunShare long-term incentive plan, the company granted 264,000 options to new employees in the first quarter of 2005 (810,000 options granted during the first quarter of 2004).

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

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

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

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

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

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

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

(b) Performance Share Units (PSUs)

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

24

7. EMPLOYEE FUTURE BENEFITS

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

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

8. SUPPLEMENTAL INFORMATION

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

Strategic Crude Oil Hedges at March 31, 2005

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

Margin Hedges at March 31, 2005

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

Natural Gas Hedges at March 31, 2005

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

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

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

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

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

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

25

9. ROYALTY ESTIMATE MEASUREMENT UNCERTAINTY

Alberta 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. The Firebag project 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 was a transitional year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed before the 25% R-C royalty applied to 2004 results.

Absolute royalties that may be payable in 2005 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, timing of the receipt of business interruption insurance proceeds, foreign exchange rates and total capital and operating costs for each project. Oil Sands pretax Crown royalty estimate was $87 million ($53 million after-tax) for the first three months of 2005 ($40 million after-tax in 2004). The annualized estimate of $450 million ($280 million after-tax) was based on three months of actual results, together with 2005 forward crude oil pricing as at March 31, 2005, current forecasts of capital and operating costs for the remainder of 2005, a Canadian/US foreign exchange rate of $0.82, and no receipts of business interruption insurance proceeds other than those recorded to date (see note 10). Accordingly, actual results will differ, and these differences may be material.

10. OIL SANDS FIRE, INSURANCE AND SUBSEQUENT EVENT

During the first quarter of 2005, accrued insurance proceeds from both the property loss and the business interruption policies, net of the write-off of the net book value of the damaged assets and the expenses incurred to fight the fire, safe the site, and investigate the cause and extent of the damage, was $63 million.

In April, 2005 the company received an initial $12 million in property loss insurance proceeds and $73 million in proceeds related to its business interruption insurance coverage. The business interruption insurance proceeds related to business activity in the first quarter of 2005 and have accordingly been recognized as revenue in the first quarter. Additional business interruption insurance proceeds will be recorded at the time of unconditional receipt.

26

highlights

(unaudited)

	2005	2004
Cash Flow from Operations
(dollars per common share)
For the three months ended March 31
Cash flow from operations (1)	0.65	0.92
Ratios
For the twelve months ended March 31
Return on capital employed (%) (2)	15.7	15.9
Return on capital employed (%) (3)	13.1	14.4
Net debt to cash flow from operations (times) (4)	1.3	1.4
Interest coverage on long-term debt (times)
Net earnings (5)	11.3	8.5
Cash flow from operations (6)	14.5	10.5
As at March 31
Debt to debt plus shareholders’ equity (%)(7)	33.8	39.1
Common Share Information
As at March 31
Share price at end of trading
Toronto Stock Exchange – Cdn$	48.73	35.97
New York Stock Exchange – US$	40.21	27.35
Common share options outstanding (thousands)	20 307	21 524
For the three months ended March 31
Average number outstanding, weighted monthly (thousands)	454 911	452 123

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

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

(2)Net earnings (2005 – $970 million; 2004 – $929 million) adjusted for after-tax financing expenses (2005 – income of $36 million; 2004 – income of $8 million) for the twelve month period ended; divided by average capital employed (2005 – $5,958 million; 2004 – $5,802 million). Average capital employed is the sum of shareholders’ equity and short-term debt plus long-term debt less cash and cash equivalents, at the beginning and end of the year, divided by two, less capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments as presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed reconciliation of ROCE prepared on an annual basis, see page 51 of Suncor’s 2004 Annual Report to Shareholders.

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

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

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

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

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

27

quarterly operating summary

(unaudited)

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

CASH OPERATING COSTS AND TOTAL OPERATING COSTS – BASE OPERATIONS

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

CASH OPERATING COSTS AND TOTAL OPERATING COSTS – FIREBAG

Cash costs	8.90	7.00	14.90	6.55	—	8.30
Natural gas	10.10	10.45	11.90	11.65	—	11.20
Cash operating costs (5),(c)	19.00	17.45	26.80	18.20	—	19.50
Depreciation, depletion and amortization	4.75	5.55	7.45	5.80	—	6.00
Total operating costs (6),(c)	23.75	23.00	34.25	24.00	—	25.50
(for the period ended)
Capital employed (i)	4 231	4 169	4 182	4 525	4 725
(for the twelve months ended)
Return on capital employed (j)	19.6	22.9	22.8	22.6	18.1
Return on capital employed (j)****	15.9	18.8	19.0	19.2	16.0

28

		For the quarter ended					Total year
		Mar 31 2005	Dec 31 2004	Sept 30 2004	Jun 30 2004	Mar 31 2004	Dec 31 2004
NATURAL GAS
Gross production **
Natural gas (d)		191	193	201	209	197	200
Natural gas liquids (a)		3.0	2.9	2.6	2.2	2.2	2.5
Crude oil (a)		0.9	1.0	1.0	1.1	0.9	1.0
Total gross production (e)		35.7	36.1	37.1	38.1	35.9	36.8
Average sales price (1)
Natural gas (f)		6.81	7.02	6.49	6.77	6.54	6.70
Natural gas (f)  *		6.74	6.98	6.53	6.84	6.59	6.73
Natural gas liquids (b)		38.32	46.46	42.06	43.53	38.13	42.82
Crude oil – Conventional (b)		61.40	55.26	55.43	47.08	44.14	50.41
Net wells drilled
Conventional	– Exploratory ***	5	—	3	3	4	10
	– Development	5	5	3	—	8	16
		10	5	6	3	12	26
(for the period ended)
Capital employed (i)		490	448	410	421	418
(for the twelve months ended)
Return on capital employed (j)		26.2	27.1	30.4	29.9	27.7

ENERGY MARKETING AND REFINING – CANADA

Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.6	4.8	4.6	4.5	4.2	4.6
Other	4.0	4.1	4.3	4.1	4.0	4.1
Jet fuel	0.9	1.0	1.0	0.7	1.0	0.9
Diesel	2.7	3.3	3.0	3.1	2.9	3.1
Total transportation fuel sales	12.2	13.2	12.9	12.4	12.1	12.7
Petrochemicals	0.8	0.8	0.7	0.6	0.9	0.8
Heating oils	0.8	0.5	0.2	0.3	0.8	0.4
Heavy fuel oils	1.0	0.8	0.5	0.7	0.8	0.7
Other	0.3	0.3	1.0	1.5	0.6	0.8
Total refined product sales	15.1	15.6	15.3	15.5	15.2	15.4
Margins (h)
Refining (7)	4.8	7.9	8.8	7.4	7.8	8.0
Refining (7)*	4.8	7.8	8.8	8.0	7.8	8.1
Retail (8)	4.7	4.5	3.7	4.3	5.0	4.4
Crude oil supply and refining
Processed at Sarnia refinery (g)	10.1	11.3	11.6	9.5	12.0	11.1
Utilization of refining capacity (j)	91	101	104	85	108	100
(for the period ended)
Capital employed (i)	525	512	528	587	567
(for the twelve months ended)
Return on capital employed (j)	8.4	14.6	11.2	7.8	11.8
Return on capital employed (j)  ****	7.3	13.6	10.8	7.8	11.8

29

	For the quarter ended					Total year
	Mar 31 2005	Dec 31 2004	Sept 30 2004	Jun 30 2004	Mar 31 2004	Dec 31 2004
REFINING AND MARKETING – U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.6	0.7	0.7
Other	3.8	3.9	4.3	3.6	3.4	3.8
Jet fuel	0.7	0.6	0.7	0.5	0.4	0.5
Diesel	2.6	2.5	2.5	1.9	2.2	2.2
Total transportation fuel sales	7.8	7.7	8.2	6.6	6.7	7.2
Asphalt	1.6	1.1	1.9	1.8	1.2	1.5
Other	0.7	0.7	0.8	0.5	0.2	0.6
Total refined product sales	10.1	9.5	10.9	8.9	8.1	9.3
Margins (h)
Refining (7)	6.3	7.7	5.1	9.0	5.0	6.7
Refining (7)*	6.3	7.7	5.3	9.3	5.0	6.8
Retail (8)	3.3	6.0	4.2	6.2	5.0	5.4
Crude oil supply and refining
Processed at Denver refinery (g)	9.2	9.5	9.5	8.2	8.1	8.8
Utilization of refining capacity (j)	96	100	99	86	85	92
(for the period ended)
Capital employed (i)	262	232	241
(for the twelve months ended)
Return on capital employed (j)	14.5	12.2	10.0
Return on capital employed (j)  ****	12.2	11.0	9.6

30

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 and total operating costs per barrel data because investors may use this information to analyze operating performance, leverage and liquidity.  The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

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

Explanatory Notes

*Excludes the impact of hedging activities.

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

***Excludes exploratory wells in progress.

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

(a) thousands of barrels per day

(b) dollars per barrel

(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. 1m(3)(cubic metre) = approx. 6.29 barrels

31

EX-99.4

EXHIBIT 99.4

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 13a-15(e) and 15d-15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a — 15(f) and 15d — 15(f)) 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)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           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

(d)           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:	April 28, 2005	PER:	“RICHARD L. GEORGE”
			RICHARD L. GEORGE
			President and Chief Executive
			Officer

EX-99.5

EXHIBIT 99.5

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 RULES 13a-14

AS ADOPTED 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 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 13a-15(e) and 15d-15(e) and internal control over financial reporting (as defined in Exchange Act Rules 13a — 15(f) and 15d — 15(f)) 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)           designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

(c)           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

(d)           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:	April 28, 2005	PER:	“J. KENNETH ALLEY”
			J. KENNETH ALLEY
			Senior Vice President and Chief
			Financial Officer

EX-99.6

EXHIBIT 99.6

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 first fiscal quarter ended March 31, 2005 (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:	April 28, 2005

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-99.7

EXHIBIT 99.7

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 first fiscal quarter ended March 31, 2005 (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:	April 28, 2005

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.