6-K

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.   20549

Report of Foreign Private Issuer

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

For the month of: July, 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 page 13 of Exhibit 99.2.

B.Changes in Internal Control Over Financial Reporting

See page 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.
Date:	July 27, 2005	By:	“JANICE B. ODEGAARD”
			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 second fiscal quarter ended June 30, 2005
99.3	Interim Unaudited Financial Statements of Suncor Energy Inc. for the second fiscal quarter ended June 30, 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

second quarter 2005

Report to shareholders for the period ended June 30, 2005

Suncor Energy financial results for second quarter reflect reduced production

long-term growth outlook positive as company makes significant progress on oil sands fire rebuild and expansion projects

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 second quarter management’s discussion and analysis on page 14 and 15. 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 second quarter 2005 net earnings of $112 million ($0.24 per common share), compared to $202 million ($0.44 per common share) in the second quarter of 2004. Excluding the effects of unrealized foreign exchange losses on the company’s U.S. dollar denominated long-term debt, 2005 second quarter net earnings were $125 million ($0.27 per common share), compared to $227 million ($0.50 per common share) in 2004 second quarter. Cash flow from operations was $305 million in the quarter, compared to $490 million in the second quarter of 2004.

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The decrease in earnings and cash flow was primarily due to lower production rates at Suncor’s oil sands facility, which was damaged by fire last January. This decrease was partially offset by higher commodity prices, higher refining margins and sales volumes in Suncor’s U.S. downstream operations, fire insurance proceeds and lower net financing expenses.

Net earnings for the first six months of 2005 were $210 million ($0.46 per common share), compared to $418 million ($0.92 per common share) for the same period in 2004. Cash flow from operations for the first six months of 2005 was $599 million, compared to $904 million in 2004.

Company-wide, Suncor’s total upstream production averaged 160,600 barrels of oil equivalent (boe) per day during the second quarter, compared to 264,000 boe per day in the second quarter of 2004. Oil sands production during the quarter averaged 128,200 barrels per day (bpd), including 8,700 bpd of in-situ bitumen production. This compares to the second quarter of 2004 when production averaged 225,900 bpd, including 15,100 bpd of in-situ bitumen production. Natural gas production in the second quarter of 2005 was 175 million cubic feet (mmcf) per day, compared to second quarter 2004 production of 209 mmcf per day.

During the quarter, Suncor made significant progress in rebuilding portions of the oil sands plant damaged by the January fire and expects to return to full production capacity of 225,000 bpd in the third quarter. Major repairs are complete and the remainder of the reconstruction effort is now focused on replacing piping and electrical systems to support operations. Planned maintenance, which had been originally scheduled for September, was brought ahead and is near completion.

“We’re looking forward to putting this short-term production setback behind us and we’re on target to have recovery work completed in September,” said Rick George, president and chief executive officer.

Following completion of the fire rebuild, Suncor expects to commission new expansion projects at the oil sands plant and increase production capacity to 260,000 bpd by year end. Additional work to increase Suncor’s oil sands production to 350,000 bpd in 2008 remains on schedule and on budget.

“Suncor’s oil sands team has done an exceptional job to put us back on track to meet our expansion goals,” said George. “We expect a strong finish to the year and reliable, strong production during 2006.”

Downstream plans to support future growth in oil sands were also advanced in the second quarter with the acquisition of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero Energy Corporation. The acquisition increased Suncor’s U.S. refining capacity to approximately 90,000 bpd. During the second quarter, Suncor’s U.S. downstream business generated refining margins of 9.5 cents per litre (cpl), compared to 9.0 cpl during the second quarter of 2004. Retail margins averaged 4.3 cpl in the second quarter of 2005, compared to 6.2 cpl the year before.

In the company’s Canadian downstream operations, Suncor generated refining margins of 7.3 cpl in the second quarter of 2005, compared to 7.4 cpl during the second quarter of 2004. Retail margins were 3.8 cpl during the second quarter of 2005, compared to 4.3 cpl the year before. Also during the quarter, Suncor received regulatory approval to construct an estimated $120 million ethanol facility near its Sarnia, Ontario refinery. The facility is expected to produce 200 million litres of ethanol annually when completed in 2006.

As Suncor invests for future growth, prudent debt management remains a priority. At the end of the second quarter, the company’s net debt was $2.9 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.

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“Suncor’s oil sands team has done an exceptional job to put us back on track to meet our expansion goals. We expect a strong finish to the year and reliable, strong production during 2006.”

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 forecasts 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

Due to unplanned maintenance and weather related delays in drilling, Suncor has revised its annual Outlook to 195 to 200 mmcf per day from the original target of 205 to 210 mmcf per day. The revised Outlook is still expected to exceed the company’s projected purchases for internal consumption of natural gas. The circumstances affecting this revision are anticipated to only affect 2005. In subsequent years, Suncor’s Natural Gas business will continue to focus on annually increasing production by 3% to 5% in order to provide a financial hedge against natural gas use at the company’s oil sands and refining operations.

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. There is no specific schedule for payments and Suncor expects insurance recoveries will extend beyond 2005.

•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 to portions of the Denver refinery during the fourth quarter has been rescheduled to the first quarter of 2006.

•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 second fiscal quarter ended June 30, 2005

management’s discussion and analysis July 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 June 30, 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 14.

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 June 30		6 months ended June 30
(average for the period)	2005	2004	2005	2004
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	53.15	38.30	51.50	36.75
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	66.45	51.00	64.20	48.50
Light/heavy crude oil differential US$/barrel – WTI at Cushing less Lloyd Light Blend at Hardisty	21.30	11.80	20.30	10.95
Natural gas US$/mcf at Henry Hub	6.80	5.95	6.55	5.85
Natural gas (Alberta spot) Cdn$/mcf at AECO	7.35	6.80	7.05	6.70
New York Harbour 3-2-1 crack(1) US$/barrel	8.40	8.90	7.20	7.90
Exchange rate: Cdn$:US$	0.80	0.74	0.81	0.75

(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 June 30, 2005)
Common shares	456 760 467
Common share options – total	19 629 554
Common share options – exercisable	10 173 806

Summary of Quarterly Results

	2005 Quarter ended			2004 Quarter ended			2003 Quarter ended
($ millions, except per share data)	June 30	Mar. 31	Dec. 31	Sep. 30	June 30	Mar. 31	Dec. 31	Sep. 30
Revenues	2 380	2 061	2 310	2 315	2 201	1 795	1 698	1 788
Net earnings	112	98	333	337	202	216	301	285
Net earnings attributable to common shareholders per share
Basic	0.24	0.22	0.73	0.74	0.44	0.48	0.67	0.63
Diluted	0.24	0.21	0.72	0.73	0.43	0.46	0.62	0.61

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ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the second quarter of 2005 were $112 million, compared to $202 million for the second quarter of 2004. The decrease in net earnings was primarily due to a decrease in Oil Sands crude oil production as a result of the fire that occurred in the first quarter of 2005 (see page 7), which resulted in reduced sales volumes and revenues. These negative impacts were partially offset by:

•an increase in the average price realization for Oil Sands crude oil to $45.98 per barrel in the second quarter of 2005 from $41.88 per barrel during the second quarter of 2004. The price increase was due mainly to an increase in the average benchmark WTI crude oil price, partially offset by widening light/heavy differentials and a lower percentage of high value products in Oil Sands sales mix due to reduced upgrading capacity as a result of the fire.  The 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.

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

•fire insurance proceeds net of the write off of damaged assets and related expenses that increased net earnings by $72 million (see page 7).

•lower net financing expenses primarily due to higher levels of capitalized interest and lower unrealized foreign exchange losses on U.S. dollar denominated long-term debt.

Cash flow from operations in the second quarter was $305 million, compared to $490 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.

Net earnings for the first half of 2005 were $210 million compared to $418 million in the same period of 2004. In addition to the factors listed above, the decrease in net earnings was also due to lower refining margins in our Canadian downstream operations in the first quarter of 2005 compared to the first quarter of 2004, as well as a first quarter 2004 reduction in the Alberta corporate income tax rate of 1%. This tax rate adjustment resulted in a $53 million one time reduction in non-cash income taxes compared to no reduction in the first quarter of 2005.

Cash flow from operations for the first six months of 2005 was $599 million, compared to $904 million in the first half of 2004. The decrease was primarily due to the same factors that impacted second quarter 2005 cash flow from operations.

Our effective tax rate for the first half of 2005 was 42%, compared to 31% in the first half of 2004. 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 in the first half of 2004 was also impacted by a revaluation of future taxes for the substantial enactment of the Alberta tax rate reduction. The effective tax rate for 2005 is expected to be approximately 37% assuming Oil Sands production capacity is restored to pre-fire levels in September.

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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 June 30				6 months ended June 30
($ millions, after tax)	2005		2004		2005		2004
Net earnings before the following items	53		227		115		425
Firebag in-situ start-up costs (1)	—		—		—		(14	)
Oil Sands fire accrued insurance proceeds (1)	72		—		113		—
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	(13	)	(25	)	(18	)	(46	)
Net earnings as reported	112		202		210		418

(1)Before deduction of Alberta Crown Royalties.

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2005 second quarter net earnings of $117 million, compared with $231 million in the second quarter of 2004. The decrease in net earnings was primarily due to decreased revenues as a result of the January 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 $72 million (see page 7), an increase in the average realization for oil sands crude products, primarily reflecting a 39% increase in average benchmark WTI crude oil prices.

Purchases of crude oil were $12 million before tax in the second quarter of 2005 compared to $30 million before tax in the second quarter of 2004. Purchases of crude oil were higher in the second quarter of 2004 due to the repurchase of crude oil originally sold to a variable interest entity. Operating expenses decreased to $210 million before tax in the second quarter of 2005 from $250 million before tax in the second quarter of 2004. The decrease is due primarily to higher deferral of costs related to overburden removal, lower energy consumption costs at our base operations as a result of lower upgrading activities due to the fire, and an inventory build due to sales volumes being lower than production. As a result of the fire, we continue to redeploy some of our mining resources to overburden removal. The decrease in oilsands production has led to lower amortization of deferred overburden. As a result, depreciation, depletion and amortization expense decreased to $110 million before tax in the second quarter of 2005 from $127 million before tax during the same period in 2004.

Alberta Crown royalty expense was $94 million before tax in the second quarter of 2005 compared to $105 million before tax in the second quarter of 2004. The decrease was due to lower production as a result of the fire, partially offset by higher commodity prices. See page 7 for a discussion of Alberta Oil Sands Crown royalties.

Cash flow from operations for the quarter was $215 million, compared to $421 million in the second quarter of 2004. Excluding the impact of depreciation, depletion and amortization, the decrease was primarily due to the same factors that impacted net earnings.

Net earnings for the first six months of 2005 were $234 million, compared to $470 million in the first six months of 2004. The decrease is due primarily to reduced sales volumes as a result of the fire, partially offset by higher benchmark WTI crude oil prices and the receipt of fire insurance proceeds.

Cash flow from operations for the first six months of 2005 decreased to $467 million from $786 million in the first six months of 2004, primarily due to the same factors that impacted net earnings, excluding the impact of non-cash income tax adjustments in 2005 and 2004.

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Oil Sands production during the second quarter of 2005 averaged 128,200 bpd, comprising 119,500 bpd of upgraded crude oil from base operations and 8,700 bpd of bitumen production from in-situ operations. This compares to production of 225,900 bpd during the second quarter of 2004 comprising 210,800 bpd of upgraded crude oil from base operations and 15,100 bpd of bitumen production from in-situ operations. Production from in-situ operations was negatively affected by planned and unplanned maintenance during the second quarter of 2005.

Sales during the second quarter averaged 121,100 bpd, compared with 231,800 bpd during the second quarter of 2004. The sales mix of higher value diesel fuel and sweet crude products decreased to 47% in the second quarter of 2005, compared to 64% in the second quarter of 2004 reflecting the negative impact of the fire. A build up in inventory levels also resulted in lower sales volumes in the second quarter of 2005 compared to the second quarter of 2004. The sales mix was further affected by an unplanned hydrotreater outage during the second quarter of 2005. Sales prices averaged $45.98 per barrel during the second quarter of 2005 compared to $41.88 per barrel in the second quarter of 2004.

During the second quarter, cash operating costs for base operations averaged $18.95 per barrel, compared to $12.10 per barrel during the second quarter of 2004. Despite lower costs, cash operating costs per barrel increased due to applying the total dollars 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 refer to page 14.

Oil Sands Fire

On January 4, 2005, a fire damaged Upgrader 2. We continue to target base operations production of 110,000 bpd plus bitumen production from in-situ operations over the remaining recovery period. The fire rebuild is expected to be complete in September 2005, at which time we expect to return to full production capacity of 225,000 bpd. Major repairs are complete and the remaining stages of the reconstruction effort are now focused on replacing damaged piping and electrical systems. A substantial portion of a maintenance shutdown originally scheduled for the third quarter of 2005 was brought forward to take place during the rebuild and is near completion.

We carry property loss and business interruption (BI) 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 BI policy of US$200 million has a deductible of 30 days from the date of the fire. Coverage of US$700 million can be used for either property loss or BI. For BI purposes, this coverage has a deductible of 90 days from the date of the fire.

Total property loss insurance proceeds received during the six month period ended June 30, 2005 were $55 million. To date, BI insurance proceeds received were $197 million ($73 million in the first quarter of 2005, $63 million in the second quarter of 2005 and $61 million on July 8, 2005 and recorded in the second quarter of 2005). BI proceeds are treated in the same manner for royalty purposes as the revenues they replace and accordingly attract Alberta Crown royalties (see page 8).

During the second quarter of 2005, we accrued $113 million before tax ($176 million before tax for the six months ended June 30, 2005) of insurance proceeds, 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.

During the fourth quarter, we intend to 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 nearing completion. Firebag Stage Two is scheduled to begin steaming in the third quarter of 2005. In addition, Suncor is continuing to progress plans to expand capacity to 350,000 bpd in 2008. See page 12 for an update on our significant growth projects currently in progress.

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 the 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.

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Changes to the estimated amounts previously recorded will be reflected in our financial statements on a prospective basis and may be significant.

Oil Sands second quarter pretax Alberta Crown royalty estimate of $94 million ($57 million after tax) was based on:

•average 2005 crude oil pricing of approximately US$55.00 WTI per barrel (based on an average price of US$51.50 WTI per barrel for the first six months of 2005, as well as 2005 forward crude oil pricing at June 30, 2005 of US$58.50 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 $0.81;

•business interruption insurance proceeds of $124 million recorded in the second quarter and $197 million for the first half of the year, which are considered to be R for the purposes of the calculation of Alberta Crown royalties.

Using these assumptions, we estimate 2005 annualized pretax royalties to be approximately $500 million ($305 million after tax), compared to $407 million ($260 million after tax) in 2004. The increase from our $450 million estimate in the first quarter is due mainly to higher commodity price assumptions and the receipt of additional BI insurance proceeds.

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 allowable 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 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 with the government the terms of our option to transition our base operations to the generic bitumen-based royalty regime in 2009. After 2009, the royalty on our base operations 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 decade. 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. 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.

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.

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Natural Gas

Natural Gas recorded 2005 second quarter net earnings of $27 million, compared with $35 million during the second quarter of 2004. The decrease was due primarily to lower production volumes, partially offset by higher natural gas prices. Realized natural gas prices in the second quarter of 2005 were $7.29 per thousand cubic feet (mcf) compared to $6.77 per mcf in the second quarter of 2004 reflecting higher benchmark commodity prices.

Cash flow from operations for the second quarter of 2005 was $81 million compared with $90 million from the second quarter of 2004. The decrease is due primarily to the same factors that impacted net earnings.

Year-to-date net earnings were $53 million, compared to $57 million in the first six months of 2004. The decrease in year-to-date earnings resulted from lower production volumes, increased operating, selling and general expenses, and increased depletion, depreciation and amortization expense, partially offset by higher natural gas prices and lower exploration expenses.

Cash flow from operations for the first six months of the year was $164 million, compared to $173 million reported in the same period in 2004, reflecting the same factors that affected net earnings, excluding the impact of the non-cash expenses.

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 second quarter was 175 million cubic feet (mmcf) per day, compared to 209 mmcf per day in the second quarter of 2004. Lower production volumes were due to planned and unplanned plant maintenance shutdowns during the second quarter of 2005 as well as a shortened winter drilling season due to the mild weather, and wet weather during the second quarter that further hampered our drilling program. As a result of these factors, we have revised our annual Outlook to 195 to 200 mmcf per day from the original target of 205 to 210 mmcf per day. The revised Outlook is still expected to exceed our projected internal consumption.

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 second quarter net earnings of $5 million, compared to a net loss of $3 million in the second quarter of 2004. The increase in net earnings was primarily due to higher refinery utilization. Second quarter 2005 utilization was 100%, compared to 85% in the second quarter of 2004 when utilization was negatively impacted by planned and unplanned maintenance. The increase in second quarter earnings was partially offset by lower retail margins, lower mark-to-market gains on inventory related derivatives, and higher energy costs. EM&R’s results continue to be negatively impacted by historically high prices for synthetic crude oil, due in part to the fire at oil sands that reduced synthetic crude oil production.

Refining margins on Suncor’s proprietary refined products were 7.3 cents per litre (cpl) in the second quarter of 2005, compared to 7.4 cpl in the second quarter of 2004.

Retail margins were 3.8 cpl in the second quarter of 2005 compared to 4.3 cpl in the second quarter of 2004. The decrease was due to continuing competitive pressures in the Toronto, Ontario market.

9

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $3 million in the second quarter of 2005, compared to $4 million in the second quarter of 2004.

Cash flow from operations increased to $26 million in the second quarter of 2005 from $23 million in the second quarter of 2004. The increase was primarily due to the same factors that affected net earnings.

EM&R recorded net earnings of $2 million for the first half of 2005 compared to $27 million during the first half of 2004. The net earnings decrease reflects lower refinery utilization and margins, lower mark-to-market gains on inventory related derivatives, higher energy costs and high prices for synthetic crude oil during the first half of 2005.

Cash flow from operations for the first six months of 2005 was $48 million, compared to $79 million in the first six months of 2004, primarily due to the same factors that affected net earnings.

Suncor’s diesel desulphurization project at the Sarnia refinery is on budget and on schedule for completion in April 2006. During the second quarter of 2005, construction began on the planned ethanol production facility. In June 2005, we received a $19 million contribution from the Government of Canada related to the facility. An additional $3 million contribution is expected to be received in 2006. See page 12 for an update on our significant projects in progress.

Refining & Marketing – U.S.A.

Refining & Marketing – U.S.A. (R&M) recorded net earnings of $31 million in the second quarter of 2005 compared to earnings of $12 million during the second quarter of 2004. Net earnings in 2005 were positively impacted by higher refinery utilizations, increased sales volumes and higher refining margins, partially offset by higher feedstock costs and lower retail margins.

Cash flow from operations for the second quarter was $52 million compared to cash flow from operations of $21 million in the second quarter of 2004. Cash flow from operations increased due to the same factors that increased net earnings.

Refining margins in the second quarter of 2005 averaged 9.5 cpl, compared to 9.0 cpl in the second quarter of 2004, reflecting historically high prices for light oil products. Refinery utilization at the Denver refinery averaged 102% in the second quarter of 2005 compared to 86% in the second quarter of 2004 reflecting the effects of a planned maintenance shutdown. As a result of competitive pressures, retail margins averaged 4.3 cpl in the second quarter of 2005, compared to 6.2 cpl in the same period of 2004.

R&M recorded year-to-date net earnings of $37 million, compared to net earnings of $9 million in the same period in 2004. Cash flow from operations was $70 million for the six months ended June 30, 2005, compared to $15 million during the same period in 2004. The increases in net earnings and cash flow from operations were due to the same factors that impacted net earnings and cash flow from operations in the second quarter.

Suncor’s diesel desulphurization project at the Denver refinery is on schedule for completion in April 2006. See page 12 for an update on our significant projects in progress. A refinery shutdown originally scheduled for the third quarter of 2005 has been rescheduled to the first quarter of 2006. During the second quarter of 2005, we signed a three year extension to the existing collective agreement with the United Steel Workers. The new agreement expires in 2009.

On May 31, 2005, we acquired all of the issued shares of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero Energy Corporation for total cash consideration of $62 million, including the cost for purchased crude oil, product inventories and other closing adjustments. The acquired company’s assets include a 30,000 barrel per day Denver refinery located adjacent to our existing refinery, as well as a products terminal located in Grand Junction, Colorado.

10

Corporate

Corporate recorded a net loss in the second quarter of 2005 of $68 million, compared to a net loss of $73 million during the second quarter of 2004. Corporate expenses were lower in the second quarter of 2005 primarily due to the impact of lower net financing expenses, partially offset by higher stock based compensation expense and higher insurance related costs. Unrealized foreign exchange losses on U.S. dollar denominated long-term debt were $13 million after-tax in the second quarter of 2005 compared to $25 million after-tax in the second quarter of 2004. Excluding unrealized foreign exchange losses on U.S. dollar denominated long term debt, financing expenses were $3 million after-tax in the second quarter of 2005 compared to $14 million after-tax in the second quarter of 2004. The decrease in financing expenses is primarily due to increased capitalized interest related to higher levels of capital projects in progress during 2005 compared to the same period in 2004. We expect higher levels of capitalized interest to continue for the remainder of 2005.

Cash used in operations in the second quarter increased due to the same factors impacting net earnings, excluding the impact of unrealized foreign exchange losses on U.S. dollar denominated debt, non-cash stock based compensation expense and insurance related costs.

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. On June 30, 2005, we met an additional predetermined performance criterion under the SunShare plan, resulting inthe vesting of 50% of the remaining outstanding, unvested SunShare options on April 30, 2008. As we have been accruing the costs of these options, the impact on net earnings for the second quarter and the six months ended June 30, 2005 was not significant.

Corporate recorded a net loss of $116 million in the first six months of 2005, compared to a loss of $145 million in the same period of 2004. For 2005 year-to-date, after-tax unrealized foreign exchange losses on our U.S. dollar denominated debt were $18 million, compared to after tax losses of $46 million in 2004. Excluding the impact of the foreign exchange, the net loss for the first six months of 2004 was higher primarily due to higher stock based compensation and insurance related costs partially offset by lower cash financing costs.

Cash flow used in operations was $150 million in the first half of 2005 compared to $149 million in the first half of 2004. Despite lower net losses, cash used in operations for the first half of 2005 was unchanged from the first half of 2004 primarily due to the same factors impacting cash flow from operations for the second quarter of 2005.

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 $426 million at the end of the second quarter, compared to a deficiency of $77 million at the end of the second quarter of 2004. The increase in our working capital deficiency is due primarily to increased accounts payable balances as a result of increased construction activity and the purchase of higher volumes of feedstock and refined products at higher commodity prices. This was partially offset by higher accounts receivable balances as a result of higher commodity prices and accrued insurance proceeds.

During the second quarter of 2005, net debt increased to approximately $2.9 billion from $2.2 billion at December 31, 2004. The increase in debt levels was primarily a result of reduced cash flow from operations as a result of the fire and increased capital spending activities. While we expect the financial impact of the fire will be substantially mitigated by insurance proceeds, we expect debt to continue to increase during the recovery period as the timing of insurance proceeds is uncertain. At June 30, 2005 our undrawn lines of credit were approximately $1.4 billion. During the second quarter of 2005, we entered into a new $600 million dollar credit facility agreement. The new facility is fully revolving for 364 days and expires in 2006. As a result of the acquisition of the Colorado Refining Company, additional planned drilling in our Natural Gas business as well as some additional maintenance capital at Oil Sands, we have increased our budgeted 2005 capital spending plan from $2.5 billion to $2.7 billion (excluding the fire rebuild). We believe we have the capital resources from our undrawn lines of credit and cash flow from operations to fund our 2005 capital spending and to meet our current working capital requirements.

11

Suncor spent $804 million towards capital investing activities in the second quarter of 2005 compared to $361 million in the second quarter of 2004. A summary of the progress on our significant projects under construction is provided below.

SIGNIFICANT CAPITAL PROJECT UPDATE

					Spent 2005			Total Spent
	Board of	Cost Estimate (1)			Year to Date			to Date
Description	Directors’ Approval	($ millions)			($ millions)			($ millions)			Status
Oil Sands
Millennium vacuum unit	Yes	$	425		$	37		$	430	(1)	Project is on schedule.
											Commissioning and start up
											planned for Q4 2005.
Firebag Stage Two	Yes	$	515		$	78		$	477		Project is on schedule.
											Initial steaming planned for Q3 2005.
Coker Unit (2)	Yes	$	2 100		$	239		$	638		Project is on schedule for
											completion in 2008.
EM&R
Clean fuels and Oil Sands integration	Yes	$	800		$	158		$	336		Project components are on
											schedule for completion in 2006 and 2007.
R&M
Clean fuels and	Yes	$	360		$	153		$	289		Project is on schedule for
Oil Sands integration		(US$300		)	(US$123		)	(US$229		)	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. When we say that a project is “on schedule” we mean that we still expect completion of the project to fall within the current range of uncertainty for the project schedule. 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.

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 second quarter of 2005, strategic crude oil hedging decreased our after-tax net earnings by $78 million, compared with $86 million in the second 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 June 30:

($ millions)	2005		2004
Revenue hedge swaps and options	(292	)	(466	)
Margin hedge swaps	(12	)	(2	)
Interest rate and cross-currency interest rate swaps	40		25
	(264	)	(443	)

12

We also use derivative instruments to hedge risks specific to individual transactions. The estimated fair value of these instruments was $11 million at June 30, 2005 compared to $9 million at December 31, 2004.

Energy Marketing and Trading Activities

For the quarter ended June 30, 2005, we recorded a net pretax loss of $1 million compared to the $4 million gain recorded during the second quarter of 2004, related to the settlement and revaluation of financial energy trading contracts. In the second quarter, the settlement of physical trading activities resulted in a net pretax gain of $7 million compared to a $4 million pretax gain in the second 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 $3 million for the quarter ended June 30, 2005 compared to a gain of $4 million in the second quarter of 2004. The fair value of unsettled financial energy trading assets and liabilities at June 30, 2005 and December 31, 2004 were as follows:

($ millions)	2005	2004
Energy trading assets	34	26
Energy trading liabilities	21	9

Control Environment

Based on their evaluation as of June 30, 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 June 30, 2005, there were no changes in our internal controls over financial reporting that occurred during the six month period ended June 30, 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 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 concluded that our disclosure controls and procedures have operated effectively and free of any material weaknesses for the quarter ended June 30, 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.

As a result of our acquisition of the Colorado Refining Company, we are working to integrate the new assets and operations into the existing R&M U.S.A. internal control system. In the interim, we have implemented compensating controls and procedures to monitor and maintain appropriate internal controls during this transition period.

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 $36 million, an increase in future tax liabilities of $13 million and an increase in retained earnings of $23 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.

13

Non GAAP Financial Measures

Certain financial measures referred to in this MD&A, namely cash flow from operations, return on capital employed (ROCE) and Oil Sands cash and total operating costs per barrel, are not prescribed by GAAP. These non GAAP financial measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. Suncor includes these non GAAP financial measures because investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP.

Suncor provides a detailed numerical reconciliation of ROCE on an annual basis in the company’s annual MD&A, which is to be read in conjunction with the company’s annual consolidated financial statements. For a summarized narrative reconciliation of ROCE calculated on a June 30, 2005 interim basis, please refer to page 29 of the Quarterly Shareholders’ Report.

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of Suncor’s June 30, 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:

			3 months ended June 30		6 months ended June 30
			2005	2004	2005	2004
Cash flow from operations ($ millions)	A		305	490	599	904
Weighted average number of common shares outstanding (millions of shares)	B		456.1	452.8	455.5	452.5
Cash flow from operations (per share)	(A / B	)	0.67	1.08	1.32	2.00

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 June 30							Six months ended June 30
	2005				2004 (1)			2005			2004 (1)
	$ millions			$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	182				226			392			440
Less: natural gas costs and inventory changes	(17		)		(51	)		(75	)		(84	)
Accretion of asset retirement obligations	5				5			11			10
Taxes other than income taxes	7				7			14			14
Cash costs	177			16.30	187		9.75	342		15.70	380		9.70
Natural gas	29			2.65	44		2.30	80		3.65	87		2.20
Imported bitumen (net of other reported product purchases)	—			—	1		0.05	1		0.05	9		0.25
Cash operating costs	A	206		18.95	232		12.10	423		19.40	476		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		0.60
Total cash operating costs	A+B	206		18.95	232		12.10	423		19.40	500		12.75
Depreciation, depletion and amortization	103			9.45	119		6.20	202		9.30	243		6.20
Total operating costs	309			28.40	351		18.30	625		28.70	743		18.95
Production (thousands of barrels per day)	119.5				210.8			120.4			215.3

14

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

	Quarter ended June 30						Six months ended June 30
	2005			2004 (1)			2005
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	28			24			60
Less: natural gas costs and inventory changes	(13	)		(15	)		(30	)
Accretion of asset retirement obligations	—			—			—
Taxes other than income taxes	—			—			—
Cash costs	15		18.95	9		6.55	30		12.10
Natural gas	13		16.40	16		11.65	30		12.10
Cash operating costs	28		35.35	25		18.20	60		24.20
Depreciation, depletion and amortization	6		7.60	8		5.80	14		5.65
Total operating costs	34		42.95	33		24.00	74		29.85
Production (thousands of barrels per day)	8.7			15.1			13.7

(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.

legal notice – forward-looking information

This management’s discussion and analysis contains certain forward-looking statements that are based on our current expectations, estimates, projections and assumptions that were made by us in light of our experience and its perception of historical trends.

All statements that address expectations or projections about the future, including statements about our 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 “outlook,” “expects,” “anticipates,” “plans,” “intends,” “believes,” “could,” “focus,” “scheduled,” “goal,” “proposed,” “continue,” “target,” “forecast,” “objective,” “budgeted,” “estimate,” 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. Our actual results may differ materially from those expressed or implied by our forward-looking statements and readers are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to changes in the general economic, market and business conditions; fluctuations in supply and demand for our products; commodity prices and currency exchange rates; our 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 our 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 our capital assets; the cumulative impact of other resource development; future environmental laws; the accuracy of our reserve, resource and future production estimates and our success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; the availability and cost of resources, including labour required to complete growth projects in the Fort McMurray competitive environment; 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 we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as the January 2005 fire, blowouts, freeze-ups, equipment failures and other similar events affecting us or other parties whose operations or assets directly or indirectly affect us.

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 second fiscal quarter ended June 30, 2005

consolidated statements of earnings

(unaudited)

	Second quarter			Six months ended June 30
($ millions)	2005		2004	2005		2004
Revenues (note 12)	2 380		2 201	4 441		3 996
Expenses
Purchases of crude oil and products	1 039		777	1 855		1 308
Operating, selling and general (note 6)	460		445	928		845
Energy marketing and trading activities (note 3)	209		110	343		177
Transportation and other costs	33		29	67		56
Depreciation, depletion and amortization (note 2)	168		178	333		353
Accretion of asset retirement obligations	7		7	15		13
Exploration	2		5	19		38
Royalties (note 9)	123		137	238		228
Taxes other than income taxes	126		123	246		242
Loss (gain) on disposal of assets	(1	)	1	(1	)	—
Project start-up costs	3		—	6		22
Financing expenses (notes 2 and 4)	21		53	28		112
	2 190		1 865	4 077		3 394
Earnings Before Income Taxes	190		336	364		602
Provision for Income Taxes (note 2)
Current	24		4	53		24
Future	54		130	101		160
	78		134	154		184
Net Earnings	112		202	210		418
Per Common Share (dollars), (note 5)
Basic	0.24		0.44	0.46		0.92
Diluted	0.24		0.43	0.45		0.90
Cash dividends	0.06		0.06	0.12		0.11

See accompanying notes.

16

consolidated balance sheets

(unaudited)

	June 30	December 31
($ millions)	2005	2004
Assets
Current assets
Cash and cash equivalents	48	88
Accounts receivable	882	627
Inventories	500	423
Future income taxes	86	57
Total current assets	1 516	1 195
Property, plant and equipment, net (note 2)	11 483	10 326
Deferred charges and other	442	320
Total assets	13 441	11 841
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	10	30
Accounts payable and accrued liabilities (note 9)	1 764	1 306
Income taxes payable	30	32
Taxes other than income taxes	14	41
Total current liabilities	1 818	1 409
Long-term debt	2 919	2 217
Accrued liabilities and other	884	749
Future income taxes (note 2)	2 675	2 545
Shareholders’ equity (see below)	5 145	4 921
Total liabilities and shareholders’ equity	13 441	11 841

Shareholders’ Equity

	Number			Number
	(thousands)			(thousands)
Share capital	456 760	707		454 241	651
Contributed surplus		42			32
Cumulative foreign currency translation		(52	)		(55	)
Retained earnings (note 2)		4 448			4 293
		5 145			4 921

See accompanying notes.

17

consolidated statements of cash flows

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2005		2004		2005		2004
Operating Activities
Cash flow from operations	305		490		599		904
Decrease (increase) in operating working capital
Accounts receivable	51		(87	)	(175	)	(219	)
Inventories	(36	)	(70	)	(40	)	(103	)
Accounts payable and accrued liabilities	239		143		453		254
Taxes payable	(5	)	(11	)	(28	)	(3	)
Cash flow from operating activities	554		465		809		833
Cash Used in Investing Activities	(903	)	(347	)	(1 518	)	(697	)
Net Cash Surplus (Deficiency) Before Financing Activities	(349	)	118		(709	)	136
Financing Activities
Increase (decrease) in short-term debt	2		(1	)	(20	)	6
Net increase (decrease) in other long-term debt	347		(116	)	658		(468	)
Issuance of common shares under stock option plan	21		3		52		20
Dividends paid on common shares	(26	)	(24	)	(51	)	(45	)
Deferred revenue	14		—		30		—
Cash provided by (used in) financing activities	358		(138	)	669		(487	)
Increase (Decrease) in Cash and Cash Equivalents	9		(20	)	(40	)	(351	)
Cash and Cash Equivalents at Beginning of Period	39		57		88		388
Cash and Cash Equivalents at End of Period	48		37		48		37

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	—	—	—		418
Dividends paid on common shares	—	—	—		(45	)
Issued for cash under stock option plan	20	—	—		—
Issued under dividend reinvestment plan	4	—	—		(2	)
Stock-based compensation expense	—	9	—		—
Foreign currency translation adjustment	—	—	11		—
At June 30, 2004	628	16	(15	)	3 679
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	—	—	—		210
Dividends paid on common shares	—	—	—		(51	)
Issued for cash under stock option plan	52	—	—		—
Issued under dividend reinvestment plan	4	—	—		(4	)
Stock-based compensation expense	—	10	—		—
Foreign currency translation adjustment	—	—	3		—
At June 30, 2005	707	42	(52	)	4 448

See accompanying notes.

19

schedules of segmented data

(unaudited)

	Second quarter
									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	460		815		130		132		887		764		575		372		—		1		2 052		2 084
Energy marketing and trading activities	—		—		—		—		214		117		—		—		—		—		214		117
Net insurance proceeds (note 12)	113		—		—		—		—		—		—		—		—		—		113		—
Intersegment revenues	76		93		7		16		—		—		—		—		(83	)	(109	)	—		—
Interest	—		—		—		—		—		—		1		—		—		—		1		—
	649		908		137		148		1 101		881		576		372		(83	)	(108	)	2 380		2 201
Expenses
Purchases of crude oil and products	12		30		—		—		658		573		453		282		(84	)	(108	)	1 039		777
Operating, selling and general	210		250		23		19		117		96		39		38		71		42		460		445
Energy marketing and trading activities	—		—		—		—		209		110		—		—		—		—		209		110
Transportation and other costs	21		19		6		6		2		—		4		4		—		—		33		29
Depreciation, depletion and amortization	110		127		30		29		18		16		6		4		4		2		168		178
Accretion of asset retirement obligations	5		5		1		1		1		1		—		—		—		—		7		7
Exploration	—		2		2		3		—		—		—		—		—		—		2		5
Royalties	94		105		29		32		—		—		—		—		—		—		123		137
Taxes other than income taxes	7		7		1		2		89		87		29		27		—		—		126		123
Loss (gain) on disposal of assets	—		3		—		(2	)	(1	)	—		—		—		—		—		(1	)	1
Project start-up costs	3		—		—		—		—		—		—		—		—		—		3		—
Financing expenses	—		—		—		—		—		—		—		—		21		53		21		53
	462		548		92		90		1 093		883		531		355		12		(11	)	2 190		1 865
Earnings (loss) before income taxes	187		360		45		58		8		(2	)	45		17		(95	)	(97	)	190		336
Income taxes	(70	)	(129	)	(18	)	(23	)	(3	)	(1	)	(14	)	(5	)	27		24		(78	)	(134	)
Net earnings (loss)	117		231		27		35		5		(3	)	31		12		(68	)	(73	)	112		202

20

schedules of segmented data (continued)

(unaudited)

	Second quarter
									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		231		27		35		5		(3	)	31		12		(68	)	(73	)	112		202
Exploration expenses	—		—		2		3		—		—		—		—		—		—		2		3
Non-cash items included in earnings
Depreciation, depletion and amortization	110		127		30		29		18		16		6		4		4		2		168		178
Income taxes	70		129		18		23		3		1		14		5		(51	)	(28	)	54		130
Loss (gain) on disposal of assets	—		3		—		(2	)	(1	)	—		—		—		—		—		(1	)	1
Stock-based compensation expense	—		—		—		—		—		—		—		—		6		5		6		5
Other	(2	)	3		4		4		1		1		1		(1	)	19		31		23		38
Overburden removal outlays	(77	)	(58	)	—		—		—		—		—		—		—		—		(77	)	(58	)
Increase (decrease) in deferred credits and other	(3	)	(14	)	—		(2	)	—		8		—		1		21		(2	)	18		(9	)
Total cash flow from (used in) operations	215		421		81		90		26		23		52		21		(69	)	(65	)	305		490
Decrease (increase) in operating working capital	125		(3	)	(11	)	(24	)	20		(23	)	29		(20	)	86		45		249		(25	)
Total cash flow from (used in) operating activities	340		418		70		66		46		—		81		1		17		(20	)	554		465
Cash from (used in) investing activities:
Capital and exploration expenditures	(510	)	(246	)	(72	)	(37	)	(114	)	(40	)	(96	)	(27	)	(12	)	(11	)	(804	)	(361	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		(62	)	—		—		—		(62	)	—
Deferred maintenance shutdown expenditures	(35	)	—		—		—		—		(24	)	(1	)	(6	)	—		—		(36	)	(30	)
Deferred outlays and other investments	—		(1	)	—		—		(1	)	(8	)	—		—		(1	)	8		(2	)	(1	)
Proceeds from disposals	—		40		—		3		1		2		—		—		—		—		1		45
Total cash (used in) investing activities	(545	)	(207	)	(72	)	(34	)	(114	)	(70	)	(159	)	(33	)	(13	)	(3	)	(903	)	(347	)
Net cash surplus (deficiency) before financing activities	(205	)	211		(2	)	32		(68	)	(70	)	(78	)	(32	)	4		(23	)	(349	)	118

21

schedules of segmented data (continued)

(unaudited)

	Six months ended June 30
									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	1 013		1 481		261		223		1 652		1 442		986		661		1		1		3 913		3 808
Energy marketing and trading activities	—		—		—		—		351		195		—		—		—		(8	)	351		187
Net insurance proceeds (note 12)	176		—		—		—		—		—		—		—		—		—		176		—
Intersegment revenues	153		192		13		58		—		—		—		—		(166	)	(250	)	—		—
Interest	—		—		—		—		—		—		1		—		—		1		1		1
	1 342		1 673		274		281		2 003		1 637		987		661		(165	)	(256	)	4 441		3 996
Expenses
Purchases of crude oil and products	21		42		—		—		1 219		1 011		782		506		(167	)	(251	)	1 855		1 308
Operating, selling and general	452		464		44		39		225		192		71		71		136		79		928		845
Energy marketing and trading activities	—		—		—		—		343		185		—		—		—		(8	)	343		177
Transportation and other costs	45		36		11		11		3		1		8		8		—		—		67		56
Depreciation, depletion and amortization	217		251		61		57		36		33		12		7		7		5		333		353
Accretion of asset retirement obligations	11		10		3		2		1		1		—		—		—		—		15		13
Exploration	10		15		9		23		—		—		—		—		—		—		19		38
Royalties	181		167		57		61		—		—		—		—		—		—		238		228
Taxes other than income taxes	14		14		1		2		172		170		59		56		—		—		246		242
Loss (gain) on disposal of assets	—		3		—		(3	)	(1	)	—		—		—		—		—		(1	)	—
Project start-up costs	6		22		—		—		—		—		—		—		—		—		6		22
Financing expenses	—		—		—		—		—		—		—		—		28		112		28		112
	957		1 024		186		192		1 998		1 593		932		648		4		(63	)	4 077		3 394
Earnings (loss) before income taxes	385		649		88		89		5		44		55		13		(169	)	(193	)	364		602
Income taxes	(151	)	(179	)	(35	)	(32	)	(3	)	(17	)	(18	)	(4	)	53		48		(154	)	(184	)
Net earnings (loss)	234		470		53		57		2		27		37		9		(116	)	(145	)	210		418
As at June 30
TOTAL ASSETS	10 165		8 530		1 089		822		1 574		1 201		1 092		495		(479	)	8		13 441		11 056

22

schedules of segmented data (continued)

(unaudited)

	Six months ended June 30
									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)	234		470		53		57		2		27		37		9		(116	)	(145	)	210		418
Exploration expenses	—		—		9		23		—		—		—		—		—		—		9		23
Non-cash items included in earnings
Depreciation, depletion and amortization	217		251		61		57		36		33		12		7		7		5		333		353
Income taxes	151		179		35		32		3		17		18		4		(106	)	(72	)	101		160
Loss (gain) on disposal of assets	—		3		—		(3	)	(1	)	—		—		—		—		—		(1	)	—
Stock-based compensation expense	—		—		—		—		—		—		—		—		10		9		10		9
Other	23		(8	)	6		8		8		(7	)	3		(8	)	7		51		47		36
Overburden removal outlays	(152	)	(112	)	—		—		—		—		—		—		—		—		(152	)	(112	)
Increase (decrease) in deferred credits and other	(6	)	3		—		(1	)	—		9		—		3		48		3		42		17
Total cash flow from (used in) operations	467		786		164		173		48		79		70		15		(150	)	(149	)	599		904
Decrease (increase) in operating working capital	120		8		(27	)	(37	)	(33	)	9		(44	)	(44	)	194		(7	)	210		(71	)
Total cash flow from (used in) operating activities	587		794		137		136		15		88		26		(29	)	44		(156	)	809		833
Cash from (used in) investing activities:
Capital and exploration expenditures	(880	)	(474	)	(154	)	(107	)	(192	)	(65	)	(163	)	(45	)	(24	)	(17	)	(1 413	)	(708	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		(62	)	—		—		—		(62	)	—
Deferred maintenance shutdown expenditures	(60	)	—		—		—		—		(25	)	(1	)	(6	)	—		—		(61	)	(31	)
Deferred outlays and other investments	(1	)	(3	)	—		—		(2	)	(12	)	—		—		(1	)	8		(4	)	(7	)
Proceeds from disposals	21		40		—		7		1		2		—		—		—		—		22		49
Total cash (used in) investing activities	(920	)	(437	)	(154	)	(100	)	(193	)	(100	)	(226	)	(51	)	(25	)	(9	)	(1 518	)	(697	)
Net cash surplus (deficiency) before financing activities	(333	)	357		(17	)	36		(178	)	(12	)	(200	)	(80	)	19		(165	)	(709	)	136

23

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 June 30, 2005 and the results of its operations and cash flows for the three and six month periods ended June 30, 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 June 30
($ millions, increase)	2005	2004
Property, plant and equipment	36	38
Total assets	36	38
Future income tax liabilities	13	14
Retained earnings	23	24
Total liabilities and shareholders’ equity	36	38

Change in Consolidated Statements of Earnings

	Second quarter				Six months ended June 30
($ millions, increase/(decrease))	2005		2004		2005		2004
Depreciation, depletion and amortization	1		1		1		2
Financing expenses	—		—		—		15
Future income taxes	—		—		—		(5	)
Net earnings	(1	)	(1	)	(1	)	(12	)
Per common share – basic (dollars)	—		—		—		—
Per common share – diluted (dollars)	—		—		—		—

(b) Consolidation of Variable Interest Entities

On January 1, 2005 the company prospectively adopted Canadian Accounting Guideline 15 – “Consolidation of Variable Interest Entities (VIEs)”. 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.

24

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 activities are reported as revenue and as energy trading and marketing expenses in the Consolidated Statement of Earnings.

Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. For the quarter ended June 30, 2005 these activities resulted in a net pretax gain of $7 million (2004-pretax gain $4 million). For the six months ended June 30, 2005 physical energy marketing contracts resulted in a net pretax gain of $9 million (2004 – pretax gain of $5 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 June 30, 2005, a net pretax loss of $1 million (2004 – pretax gain $4 million) resulted from the settlement and revaluation of the financial energy contracts. For the six months ended June 30, 2005 a net pretax gain of $1 million (2004 – pretax gain $6 million) was recorded. 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:

	June 30	December 31
($ millions)	2005	2004
Energy trading assets	34	26
Energy trading liabilities	21	9

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

4. FINANCING EXPENSES

	Second quarter				Six months ended June 30
($ millions)	2005		2004		2005		2004
Interest on debt	38		36		71		85
Capitalized interest	(31	)	(12	)	(57	)	(23	)
Net interest expense	7		24		14		62
Foreign exchange loss on long-term debt	16		30		22		55
Other foreign exchange gain	(2	)	(1	)	(8	)	(5	)
Total financing expenses	21		53		28		112

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Second quarter		Six months ended June 30
($ millions)	2005	2004	2005	2004
Net earnings	112	202	210	418
(millions of common shares)
Weighted-average number of common shares	456	453	455	452
Options issued under stock-based compensation plans	10	7	11	10
Weighted-average number of diluted common shares	466	460	466	462
(dollars per common share)
Basic earnings per share (b)	0.24	0.44	0.46	0.92
Diluted earnings per share (c)	0.24	0.43	0.45	0.90	(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 six months ended June 30, 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 net earnings, divided by the weighted-average number of diluted common shares.

25

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 413,000 options to new employees in the second quarter of 2005, for a total of 677,000 options granted in the six months ended June 30, 2005 (386,000 options granted during the second quarter of 2004; 1,196,000 options granted in the six months ended June 30, 2004).

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. On June 30, 2005, we met an additional predetermined performance criterion under the SunShare plan, resulting in the vesting of 50% of the outstanding, unvested SunShare options on April 30, 2008. As we had been accruing the costs of these options, the impact on net earnings for the second quarter and the six months ended June 30, 2005 was not significant.

Under the company’s other plans, 64,000 options were granted in the second quarter of 2005, for a total of 1,355,000 options granted in the six months ended June 30, 2004 (58,000 options granted during the second quarter of 2004; 1,284,000 granted in the six months ended June 30, 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 during the various periods and the weighted-average assumptions used in their determination are as noted below:

	Second quarter						Six months ended June 30
	2005			2004			2005			2004
Quarterly dividend per share	$	0.06		$	0.06		$	0.06		$	0.06	*
Risk-free interest rate	3.59		%	3.73		%	3.73		%	3.73		%
Expected life	5 years			6 years			6 years			6 years
Expected volatility	28		%	29		%	28		%	29		%
Weighted-average fair value per option	$	14.76		$	11.82		$	14.09		$	11.77

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

Stock-based compensation expense recognized in the second quarter of 2005 related to stock options plans was $6 million (2004 – $5 million). For the six months ended June 30, 2005 stock-based compensation expense recognized was $10 million (2004 – $9 million).

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

	Second quarter		Six months ended June 30
($ millions, except per share amounts)	2005	2004	2005	2004
Net earnings – as reported	112	202	210	418
Less: compensation cost under the fair value method for pre-2003 options	7	6	9	21
Pro forma net earnings	105	196	201	397
Basic earnings per share
As reported	0.24	0.44	0.46	0.92
Pro forma	0.23	0.43	0.44	0.88
Diluted earnings per share
As reported	0.24	0.43	0.45	0.90
Pro forma	0.23	0.42	0.43	0.86

26

(b) Performance Share Units (PSUs)

In the second quarter of 2005 the company issued 9,000 PSUs (2004 – 2,000). For the six months ended June 30, 2005, the company issued 445,000 PSUs (2004 -353,000). Expense recognized in the second quarter of 2005 was $ 5 million (2004 – $1 million). Expense recognized for the six months ended June 30, 2005 was $ 8 million (2004 – $2 million).

7. EMPLOYEE FUTURE BENEFITS LIABILITY

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 six months ended June 30.

	Pension Benefits
	Second quarter				Six months ended June 30
	2005		2004		2005		2004
Current service costs	8		6		16		12
Interest costs	9		9		19		17
Expected return on plan assets	(7	)	(6	)	(14	)	(12	)
Amortization of net actuarial loss	6		4		11		9
Net periodic benefit cost	16		13		32		26

	Other Post-retirement Benefits
	Second quarter		Six months ended June 30
	2005	2004	2005	2004
Current service costs	1	2	3	3
Interest costs	2	1	4	3
Amortization of net actuarial loss	—	1	—	1
Net periodic benefit cost	3	4	7	7

8. SUPPLEMENTAL INFORMATION

	Second quarter		Six months ended June 30
($ millions)	2005	2004	2005	2004
Interest paid	23	23	69	78
Income taxes paid	21	12	55	32

Strategic Crude Oil Hedges at June 30, 2005

	Quantity	Average Price	Revenue Hedged	Hedge
	(bbl/day)	(US$/bbl) (a)	(Cdn$ millions) (b)	Period (c)
Swaps	36 000	22.77	185	2005

Margin Hedges at June 30, 2005

	Quantity	Average Margin	Margin Hedged	Hedge
	(bbl/day)	(US$/bbl)	(Cdn$ millions) (b)	Period
Refined product and crude swaps	9 300	6.62	14	2005	(d)
Refined product and crude swaps	6 800	11.78	9	2006	(e)

Natural Gas Hedges at June 30, 2005

	Quantity	Average Price	Revenue Hedged	Hedge
	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period (c)
Costless collars	25 000	6.91 – 8.11	21 – 25	2005	(f)
Swaps	4 000	6.99	5	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 June 30, 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 July to December 2005, inclusive.

(e)For the period January to March 2006, inclusive.

(f)For the period July to October 2005, inclusive.

27

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. Firebag is being treated by the government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes. The 2004 calendar year 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 $181 million ($110 million after-tax) for the first six months of 2005 ($108 million after-tax in 2004). The annualized estimate of $500 million ($305 million after-tax) was based on six months of actual results, together with 2005 forward crude oil pricing as at June 30, 2005, current forecasts of capital and operating costs for the remainder of 2005, a Canadian/US foreign exchange rate of $0.81, and no receipts of business interruption insurance proceeds other than those recorded to date (see note 12). Accordingly, actual results will differ, and these differences may be material.

10. ACQUISITION OF REFINERY AND RELATED ASSETS

On May 31, 2005, the company acquired all of the issued shares of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero for cash consideration of $37 million. Additional payments for working capital and associated inventory brought the total purchase price to $62 million. The acquired company’s principal assets are a Denver refinery and a products terminal located in Grand Junction, Colorado. The preliminary allocation of fair value to the assets acquired and liabilities assumed was $79 million for property, plant and equipment, $30 million for inventory, and $41 million for environmental liabilities assumed. The fair value assigned to other liabilities was $6 million. The acquisition was accounted for by the purchase method of accounting.

The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition. The new operations have been reported as part of the Refining and Marketing – U.S.A. segment in the Schedules of Segmented Data.

11. CREDIT FACILITIES

During the second quarter, the company entered into a new $600 million credit facility agreement. The new facility is fully revolving for 364 days and expires in 2006.

12. SUBSEQUENT EVENT

In July 2005, the Company received $61 million in proceeds related to its business interruption insurance coverage. The business interruption insurance proceeds related to business activity in the second quarter of 2005 and have accordingly been recognized as revenue in the second quarter. Additional business interruption insurance proceeds will be recorded at the time of unconditional receipt.

28

highlights

(unaudited)

	2005	2004
Cash Flow from Operations (dollars per common share)
For the three months ended June 30
Cash flow from operations (1)	0.67	1.08
For the six months ended June 30
Cash flow from operations (1)	1.32	2.00
Ratios
For the twelve months ended June 30
Return on capital employed (%) (2)	13.9	19.0
Return on capital employed (%) (3)	11.1	16.7
Net debt to cash flow from operations (times) (4)	1.7	1.3
Interest coverage on long-term debt (times)
Net earnings (5)	10.0	9.2
Cash flow from operations (6)	13.0	11.9
As at June 30
Debt to debt plus shareholders’ equity (%) (7)	36.3	37.4
Common Share Information
As at June 30
Share price at end of trading
Toronto Stock Exchange – Cdn$	57.92	34.01
New York Stock Exchange – US$	47.32	25.61
Common share options outstanding (thousands)	19 630	21 639
For the six months ended June 30
Average number outstanding, weighted monthly (thousands)	455 486	452 283

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 – $880 million; 2004 – $1,006 million) adjusted for after-tax financing expenses (2005 – income of $60 million; 2004 – expense of $68 million) for the twelve month period ended; divided by average capital employed (2005 – $5,897 million; 2004 – $5,645 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 – $7,385 million; 2004 – $6,432 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.

29

quarterly operating summary

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30	Mar 31	Dec 31	Sep 30	June 30	June 30	June 30	Dec 31
	2005	2005	2004	2004	2004	2005	2004	2004
OIL SANDS
Production (a)
Base operations	119.5	121.2	206.9	230.2	210.8	120.4	212.4	215.6
Firebag	8.7	18.7	15.6	7.3	15.1	13.7	10.5	10.9
Total production	128.2	139.9	222.5	237.5	225.9	134.1	222.9	226.5
Sales (a)
Light sweet crude oil	48.3	75.3	115.3	113.5	118.7	61.8	115.4	114.9
Diesel	9.0	11.8	25.5	28.7	29.7	10.4	28.6	27.9
Light sour crude oil	54.2	38.5	80.9	76.3	68.9	46.4	71.6	75.1
Bitumen	9.6	18.4	11.0	7.9	14.5	13.9	7.3	8.4
Total sales	121.1	144.0	232.7	226.4	231.8	132.5	222.9	226.3
Average sales price (1),(b)
Light sweet crude oil	39.20	45.41	50.55	46.03	45.70	42.80	42.98	45.60
Other (diesel, light sour crude oil and bitumen)	50.47	47.31	39.62	42.29	38.28	48.80	37.16	39.13
Total	45.98	46.44	44.68	44.08	41.88	46.23	40.09	42.28
Total *	57.24	54.80	54.40	52.72	48.18	55.92	45.83	49.78
CASH OPERATING COSTS AND TOTAL OPERATING COSTS – BASE OPERATIONS
Cash costs	16.30	15.10	10.90	9.00	9.75	15.70	9.70	9.80
Natural gas	2.65	4.70	2.20	1.40	2.30	3.65	2.20	2.00
Imported bitumen	—	0.10	0.10	0.10	0.05	0.05	0.25	0.15
Cash operating costs (2),(c)	18.95	19.90	13.20	10.50	12.10	19.40	12.15	11.95
Firebag start-up costs	—	—	—	—	—	—	0.60	0.30
Total cash operating costs (3),(c)	18.95	19.90	13.20	10.50	12.10	19.40	12.75	12.25
Depreciation, depletion and amortization	9.45	9.05	6.25	5.70	6.20	9.30	6.20	6.10
Total operating costs (4),(c)	28.40	28.95	19.45	16.20	18.30	28.70	18.95	18.35
CASH OPERATING COSTS AND TOTAL OPERATING COSTS – FIREBAG
Cash costs	18.95	8.90	7.00	14.90	6.55	12.10	6.55	8.30
Natural gas	16.40	10.10	10.45	11.90	11.65	12.10	11.65	11.20
Cash operating costs (5),(c)	35.35	19.00	17.45	26.80	18.20	24.20	18.20	19.50
Depreciation, depletion and amortization	7.60	4.75	5.55	7.45	5.80	5.65	5.80	6.00
Total operating costs (6),(c)	42.95	23.75	23.00	34.25	24.00	29.85	24.00	25.50
(for the period ended)
Capital employed (i)	4 303	4 231	4 169	4 182	4 525
(for the twelve months ended)
Return on capital  employed (j)	17.2	19.6	22.9	22.8	22.6
Return on capital employed (j) ****	13.4	15.9	18.8	19.0	19.2

30

quarterly operating summary (continued)

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30	Mar 31	Dec 31	Sep 30	June 30	June 30	June 30	Dec 31
	2005	2005	2004	2004	2004	2005	2004	2004
NATURAL GAS
Gross production **
Natural gas (d)	175	191	193	201	209	183	203	200
Natural gas liquids (a)	2.2	3.0	2.9	2.6	2.2	2.6	2.2	2.5
Crude oil (a)	1.0	0.9	1.0	1.0	1.1	0.9	1.0	1.0
Total gross production (e)	32.4	35.7	36.1	37.1	38.1	34.0	37.0	36.8
Average sales price (1)
Natural gas (f)	7.29	6.81	7.02	6.49	6.77	7.04	6.66	6.70
Natural gas (f) *	7.26	6.74	6.98	6.53	6.84	6.99	6.72	6.73
Natural gas liquids (b)	52.52	38.32	46.46	42.06	43.53	44.38	40.85	42.82
Crude oil – Conventional (b)	63.86	61.40	55.26	55.43	47.08	62.68	45.71	50.41
Net wells drilled
Conventional – Exploratory ***	—	5	—	3	3	5	7	10
– Development	2	5	5	3	—	7	8	16
	2	10	5	6	3	12	15	26
(for the period ended)
Capital employed (i)	564	490	448	410	421
(for the twelve months ended)
Return on capital employed (j)	22.5	26.2	27.1	30.4	29.9
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.8	4.6	4.8	4.6	4.5	4.7	4.4	4.6
Other	4.1	4.0	4.1	4.3	4.1	4.0	4.0	4.1
Jet fuel	0.8	0.9	1.0	1.0	0.7	0.9	0.9	0.9
Diesel	3.3	2.7	3.3	3.0	3.1	3.0	3.0	3.1
Total transportation fuel sales	13.0	12.2	13.2	12.9	12.4	12.6	12.3	12.7
Petrochemicals	0.8	0.8	0.8	0.7	0.6	0.8	0.7	0.8
Heating oils	0.3	0.8	0.5	0.2	0.3	0.5	0.5	0.4
Heavy fuel oils	1.4	1.0	0.8	0.5	0.7	1.2	0.8	0.7
Other	0.6	0.3	0.3	1.0	1.5	0.5	1.1	0.8
Total refined product sales	16.1	15.1	15.6	15.3	15.5	15.6	15.4	15.4
Margins (h)
Refining (7)	7.3	4.8	7.9	8.8	7.4	6.1	7.7	8.0
Refining (7) *	7.6	4.8	7.8	8.8	8.0	6.3	8.0	8.1
Retail (8)	3.8	4.7	4.5	3.7	4.3	4.3	4.6	4.4
Crude oil supply and refining
Processed at Sarnia refinery (g)	11.1	10.1	11.3	11.6	9.5	10.6	10.7	11.1
Utilization of refining capacity (j)	100	91	101	104	85	95	97	100
(for the period ended)
Capital employed (i)	507	525	512	528	587
(for the twelve months ended)
Return on capital employed (j)	10.1	8.4	14.6	11.2	7.8
Return on capital employed (j) ****	8.1	7.3	13.6	10.8	7.8

31

quarterly operating summary (continued)

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30	Mar 31	Dec 31	Sep 30	June 30	June 30	June 30	Dec 31
	2005	2005	2004	2004	2004	2005	2004	2004
REFINING AND MARKETING – U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.7	0.6	0.7	0.7	0.7
Other	5.0	3.8	3.9	4.3	3.6	4.4	3.5	3.8
Jet fuel	0.7	0.7	0.6	0.7	0.5	0.7	0.4	0.5
Diesel	3.1	2.6	2.5	2.5	1.9	2.9	2.0	2.2
Total transportation fuel sales	9.5	7.8	7.7	8.2	6.6	8.7	6.6	7.2
Asphalt	1.9	1.6	1.1	1.9	1.8	1.8	1.5	1.5
Other	1.2	0.7	0.7	0.8	0.5	1.0	0.4	0.6
Total refined product sales	12.6	10.1	9.5	10.9	8.9	11.5	8.5	9.3
Margins (h)
Refining (7)	9.5	6.3	7.7	5.1	9.0	7.9	7.1	6.7
Refining (7) *	9.5	6.3	7.7	5.3	9.3	7.9	7.3	6.8
Retail (8)	4.3	3.3	6.0	4.2	6.2	3.8	5.6	5.4
Crude oil supply and refining
Processed at Denver refinery (g)	11.4	9.2	9.5	9.5	8.2	10.3	8.1	8.8
Utilization of refining capacity (j)	102	96	100	99	86	100	85	92
(for the period ended)
Capital employed (i)	349	262	232	241
(for the twelve months ended)
Return on capital employed (j)	17.6	14.5	12.2	10.0
Return on capital employed (j) ****	13.8	12.2	11.0	9.6

32

quarterly operating summary (continued)

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. 1m³ (cubic metre) = approx. 6.29 barrels

33

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:	July 27, 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:	July 27, 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 second fiscal quarter ended June 30, 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:	July 27,2005

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 second fiscal quarter ended June 30, 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:	July 27,2005

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.