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: October, 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.

2

SIGNATURES

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

	SUNCOR ENERGY INC.
Date:	By:
October 27, 2005		“JANICE B. ODEGAARD”
		JANICE B. ODEGAARD
		Vice President, Associate
		General Counsel and
		Corporate Secretary

3

EXHIBIT INDEX

Exhibit	Description of Exhibit
99.1	Press Release Including 2005 Outlook
99.2	Interim Management’s Discussion and Analysis for the Third fiscal quarter ended September 30, 2005
99.3	Interim Unaudited Financial Statements of Suncor Energy Inc. for the Third fiscal quarter ended September 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

4

EX-99.1

EXHIBIT 99.1

Press Release Including 2005 Outlook

Exhibit 99.1

third quarter 2005

Report to shareholders for the period ended September 30, 2005

energy for the future

expanding beyond

Repair and expansion work completed,

company targets strong fourth quarter

High commodity prices and insurance proceeds

offset reduced production

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 document are not prescribed by generally accepted accounting principles (GAAP). For a description of these measures, see “Non GAAP Financial Measures” in Suncor’s 2005 third quarter management’s discussion and analysis. This document makes reference to barrels of oil equivalent (boe). A boe conversion ratio of six thousand cubic feet of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Accordingly, boe measures may be misleading, particularly if used in isolation. Base operations refer to oil sands mining and upgrading operations.

Suncor Energy Inc. reported third quarter 2005 net earnings of $341 million ($0.75 per common share), compared to $337 million ($0.74 per common share) in the third quarter of 2004. Excluding the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-termdebt, 2005 third quarter net earnings were $288 million ($0.63 per common share), compared to $273 million ($0.60 per common share) in the third quarter of 2004. Cash flow from operations was $651 million in the quarter, compared to $585 million in the third quarter of 2004.

The increase in net earnings was due to higher commodity prices, receipt of fire insurance proceeds, higher refining

1

margins and sales volumes in Suncor’s U.S. downstream operations, and lower net interest expenses. This was offset by lower oil sands production and by lower foreign exchange gains on the company’s U.S. dollar denominated long-term debt. With the exception of foreign exchange gains, the same factors impacted third quarter cash flow.

Net earnings for the first nine months of 2005 were $551 million ($1.21 per common share), compared to $755 million ($1.67 per common share) for the same period in 2004. Cash flow from operations for the first nine months of 2005 was $1.250 billion, compared to $1.489 billion in 2004.

Suncor’s total upstream production averaged 184,500 barrels of oil equivalent (boe) per day during the third quarter, compared to 274,600 boe per day in the third quarter of 2004.

Oil sands production during the quarter averaged 148,200 barrels per day (bpd), including 23,000 bpd of in-situ bitumen production. This compares to the third quarter of 2004, when production averaged 237,500 bpd, including 7,300 bpd of in-situ bitumen production. Natural gas production in the third quarter of 2005 was 200 million cubic feet (mmcf) per day, compared to third quarter 2004production of 201 mmcf per day.

During the third quarter, Suncor completed repairs to portions of the oil sands plant damaged by fire on January 4, 2005 and, in October, the company also completed an expansion project that increased oil sands production capacity to 260,000 bpd from the previous capacity of 225,000 bpd. The expansion project was completed on budget and ahead of schedule.

“This major milestone in Suncor’s growth plans sets the stage for a strong finish to 2005 and a solid 2006,” said Rick George, president and chief executive officer. “Increased production capacity and strong commodity prices provide us with a solid financial base to pursue our growth plans.”

With the increase in upgrader capacity, bitumen produced from in-situ operations is now being upgraded. (In the past, nearly all of Suncor’s in-situ bitumen production had been sold directly to the market.) In-situ bitumen production is expected to continue to increase with the commissioning and start-up of stage two of Suncor’s Firebag operation in the fourth quarter. Construction of stage two was also completed on budget and on schedule.

In Suncor’s downstream operations, the company’s U.S. refining and marketing business generated refining margins of 8.9 cents per litre (cpl), compared to 5.1 cpl during the third quarter of 2004. Retail margins averaged 7.5 cpl in the third quarter of 2005, compared to 4.2 cpl the year before. In the company’s Canadian downstream operations, Suncor generated refining margins of 9.2 cpl in the third quarter of 2005, compared to 8.8 cpl during the third quarter of 2004. Retail margins were 5.4 cpl during the third quarter of 2005, compared to 3.7 cpl the year before.

Growth Update

Suncor is now focused on plans to further increase production capacity to 350,000 bpd in 2008. The centrepiece of the expansion is the addition of a third pair of cokers to Upgrader 2. Engineering on this portion of the project is approximately 77% complete and construction is about 22% complete. The project is on schedule and within budget projections. The expansion is expected to coincide with investments in mining and in-situ operations.

In the downstream, modifications to the Sarnia refinery remain on schedule and on budget. Engineering for the low-sulphur fuels portion of the project has concluded and construction is more than half complete. Engineering on modifications to increase the refinery’s capacity for sour crude blends is 70% complete and construction has started.

Modifications to enable the Denver refinery to meet regulatory requirements for low sulphur diesel fuel while also allowing the refinery to process additional volumes of oil sands sour crude are well under way. Suncor is currently reviewing cost estimates for the project and the budget is expected to increase.

As Suncor invests for future growth, prudent debt management remains a priority. At the end of the third quarter, the company’s net debt was $3.3 billion. With oil sands production returned to capacity, debt levels are expected to stabilize.

To provide stability to future earnings and cash flow, Suncor has entered into hedging agreements for 7,000 bpd for the years 2006 and 2007, locking in a minimum price of US$50 per barrel WTI while allowing participation in higher crude oil prices to an average of about US$92 per barrel WTI. The company will consider future hedges up to 30% of crude oil production, if strategic opportunities are available.

2

“Increased production capacity and strong commodity prices provide us with a solid financial base to pursue our growth plans.”

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

With both repairs and expansion complete, production capacity has increased to 260,000 bpd. However, actual production, product mix and related cash operating costs may vary as the company gains experience operating the newly commissioned assets.

Natural Gas

Suncor expects to meet its revised annual natural gas production outlook of 195 to 200 mmcf per day. 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 the balance of 2005 include:

•final timing of the settlement and payment of insurance proceeds related to the oil sands fire. There is no specific schedule for the balance of the payments. While Suncor expects insurance recoveries will continue in the fourth quarter of 2005, final settlement of the claims will extend beyond 2005.

•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.

3

EX-99.2

EXHIBIT 99.2

Interim Management’s Discussion and Analysis for the Third fiscal quarter ended
September 30, 2005

Exhibit 99.2

management’s discussion and analysis

October 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 September 30, 2005 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 14 to 53 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 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 (SEC), including quarterly and annual reports and our 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 September 30		9 months ended September 30
(average for the period)	2005	2004	2005	2004
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	63.20	43.90	55.40	39.10
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	76.40	56.60	68.30	51.20
Light/heavy crude oil differential US$/barrel — WTI at Cushing less Lloyd Blend at Hardisty	19.20	12.85	19.90	11.60
Natural Gas US$/mcf at Henry Hub	8.25	6.35	7.10	6.00
Natural Gas (Alberta spot) Cdn$/mcf at AECO	8.15	6.70	7.40	6.70
New York Harbour 3-2-1 crack (1)US$/barrel	14.45	6.75	9.60	7.55
Exchange rate: Cdn$:US$	0.84	0.77	0.82	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 September 30, 2005)
Common shares	457 287 881
Common share options — total	19 377 539
Common share options — exercisable	9 709 999

Summary of Quarterly Results

($ millions,								2003 Quarter
except per	2005 Quarter ended			2004 Quarter ended				ended
share data)	Sep. 30	June 30	Mar. 31	Dec. 31	Sep. 30	June 30	Mar. 31	Dec. 31
Revenues	3 142	2 380	2 061	2 321	2 326	2 212	1 806	1 709
Net earnings	341	112	98	333	337	202	216	301
Net earnings attributable to common shareholders per share
Basic	0.75	0.24	0.22	0.73	0.74	0.44	0.48	0.67
Diluted	0.73	0.24	0.21	0.72	0.73	0.43	0.46	0.61

4

ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the third quarter of 2005 were $341 million, compared to $337 million for the third quarter of 2004. The increase in net earnings was primarily due to:

•an increase in the average price realization for Oil Sands crude oil to $56.01 per barrel in the third quarter of 2005 from $44.08 per barrel during the third 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 a 9% 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 $135 million (see page 7).

•lower net financing expenses primarily due to higher levels of capitalized interest.

These positive impacts were partially offset by 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. Earnings were also negatively impacted by lower unrealized foreign exchange gains on our U.S. dollar denominated long-term debt, higher royalty expense and higher stock based compensation expense.

Cash flow from operations in the third quarter was $651 million, compared to $585 million in the same period of 2004. Cash flow from operations was higher due primarily to net insurance proceeds, higher refining margins and volumes at our U.S. downstream operations and lower cash financing expense, partially offset by the impacts of the fire on sales volumes.

Net earnings for the first nine months of 2005 were $551 million compared to $755 million in the same period of 2004. In addition to the third quarter factors listed above, the decrease in net earnings was also due to lower refining margins in our Canadian downstream operations and a first quarter 2004 1% reduction in the Alberta corporate income tax rate. This tax rate adjustment resulted in a $53 million one time reduction in non-cash income taxes in the first quarter of 2004 compared to no reduction in the first quarter of 2005.

Cash flow from operations for the first nine months of 2005 was $1,250 million, compared to $1,489 million in the first nine months of 2004. Excluding the tax rate adjustments, the decrease was primarily due to the same factors that impacted net earnings for the first nine months of 2005.

Our effective tax rate for the nine months ended September 30, 2005 was 39%, compared to 33% for the same period 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) had a greater impact on the overall effective tax rate. The effective tax rate in the first nine months of 2004 was also impacted by a revaluation of future taxes following the Alberta tax rate reduction. The effective tax rate for 2005 is expected to be approximately 37%.

5

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 September 30		9 months ended September 30
($ millions, after tax)	2005	2004	2005	2004
Net earnings before the following items	153	273	268	698
Firebag in-situ start-up costs (1)	—	—	—	(14	)
Oil Sands fire accrued insurance proceeds (1)	135	—	248	—
Impact of income tax rate reductions on opening future income tax liabilities	—	—	—	53
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	53	64	35	18
Net earnings as reported	341	337	551	755

(1)  Before deduction of Alberta Crown Royalties.

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2005 third quarter net earnings of $253 million, compared with $263 million in the third quarter of 2004. Net earnings were lower 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. Despite the impacts of the fire, revenues were virtually unchanged in the third quarter of 2005 compared to the third quarter of 2004 as decreased sales volumes were offset by an increase in the average realization for Oil Sands crude products, primarily reflecting a 44% increase in average benchmark WTI crude oil prices, and net fire insurance proceeds accrued or received during the third quarter of 2005.

Purchases of crude oil were $8 million before tax in the third quarter of 2005 compared to $33 million before tax in the third quarter of 2004. Purchases of crude oil were higher in the third quarter of 2004 due to the repurchase of crude oil originally sold to a variable interest entity.

Operating expenses were $281 million before tax in the third quarter of 2005 compared to $193 million before tax in the third quarter of 2004. The increase was due primarily to higher maintenance costs on the undamaged upgrader, and higher natural gas costs reflecting higher natural gas prices as well as increased gas consumption at our in-situ operations. Depreciation, depletion and amortization expense decreased to $112 million before tax in the third quarter of 2005 from $126 million before tax during the same period in 2004. The decrease in Oil Sands production has led to lower amortization of deferred overburden.

Alberta Crown royalty expense was $136 million before tax in the third quarter of 2005 compared to $122 million before tax in the third quarter of 2004. The increase was due to higher commodity prices and net fire insurance proceeds partially offset by lower production as a result of the fire and higher capital and operating cost deductions. See page 7 for a discussion of Alberta Oil Sands Crown royalties.

Cash flow from operations was $445 million in the third quarter of 2005, compared to $509 million in the third quarter of 2004. Excluding the impact of depreciation, depletion and amortization, the decrease was primarily due to the same factors that impacted net earnings. Because of the fire, we continued to redeploy some of our mining resources to overburden removal in the third quarter. For further details on cash flow from operations as a non GAAP financial measure, see page 14.

Net earnings for the nine months ended September 30, 2005 were $487 million, compared to $733 million for the nine months ended September 30, 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 net fire insurance proceeds.

6

Cash flow from operations for the first nine months of 2005 was $912 million compared to $1,295 million in the first nine months of 2004. The decrease was primarily due to the same factors that impacted net earnings, excluding the impact of non-cash income tax adjustments in 2005 and 2004.

Oil Sands production during the third quarter of 2005 averaged 148,200 barrels per day (bpd), comprised of 125,200 bpd of upgraded crude oil from base operations and 23,000 bpd of bitumen production from in-situ operations. This compares to production of 237,500 bpd during the third quarter of 2004 comprised of 230,200 bpd of upgraded crude oil from base operations and 7,300 bpd of bitumen production from in-situ operations. In-situ production in the third quarter of 2004 was negatively impacted by unscheduled maintenance on the facility’s water treatment system.

Sales during the third quarter of 2005 averaged 144,500 bpd, compared with 226,400 bpd during the third quarter of 2004. The sales mix of higher value diesel fuel and sweet crude products decreased to 56% in the third quarter of 2005, compared to 63% in the third quarter of 2004 reflecting the negative impact of the fire and increased bitumen sales from our in-situ operations. Sales prices averaged $56.01 per barrel during the third quarter of 2005 compared to $44.08 per barrel in the third quarter of 2004.

During the third quarter, cash operating costs for base operations averaged $22.60 per barrel, compared to $10.50 per barrel during the third quarter of 2004. The increase in cash operating costs per barrel is due to the impact of higher cash operating expenses as well as 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 reducing production from base operations to approximately 122,000 bpd for the nine months ended September 2005. In September 2005, repairs to the damaged components were completed and Oil Sands base operations returned to full production capacity.

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 significantly mitigate, upon receipt of these funds, the financial impact of the fire on our balance sheet.

The primary property loss policy of US$250 million has a deductible per incident of US$10 million. During the third quarter of 2005 we received $60 million (US$50 million) from the property loss policy bringing total proceeds received to date to $115 million (US$95 million).

The primary BI policy of US$200 million has a deductible of 30 days from the date of the fire. Additional coverage of US$700 million is also available towards our BI claim with a deductible of 90 days from the date of the fire. During the third quarter of 2005 we received $213 million (US$183 million) in proceeds from our BI policies including $166 million (US$143 million) received in October 2005. Total BI proceeds recorded for the nine months ended September 30, 2005 were $410 million (US$343 million). The primary BI policy has been received in full.

BI proceeds are treated in the same manner for royalty purposes as the revenues they replace and accordingly attract Alberta Crown royalties (see below).

Oil Sands Growth Update

In early October, Oil Sands successfully commissioned an expansion to our base operations and increased our production capacity to 260,000 bpd. Construction of a second vacuum unit, a key component in reaching this milestone, was completed on schedule and on budget. With the increase in upgrading capacity in the fourth quarter of 2005, we expect bitumen produced from our in-situ operations to flow to the base operation for upgrading. In the past, nearly all in-situ bitumen production was sold directly to the market. We began steaming Firebag Stage 2 during the third quarter of 2005 and expect bitumen production to begin during the fourth quarter of 2005, gradually increasing through 2006.

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

7

Oil Sands third quarter pretax Alberta Crown royalty estimate of $136 million ($88 million after tax) was based on:

•average 2005 crude oil pricing of approximately US$58.85 WTI per barrel (based on an average price of US$55.40 WTI per barrel for the first nine months of 2005, as well as 2005 forward crude oil pricing at September 30, 2005 of US$69.60 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 $0.83;

•business interruption insurance proceeds of $213 million recorded in the third quarter and $410 million for the first nine months 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 $546 million ($349 million after tax), compared to $407 million ($260 million after tax) in 2004. The increase from our estimate in the second quarter of $500 million 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 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 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.

During the third quarter of 2005, we reached an agreement with the Government of Alberta on the terms and conditions of the company’s option to transition in 2009 to the generic bitumen-based royalty. The option to move to a bitumen based royalty effective January 1, 2009 was initially granted by the government in 1997 but was subject to the finalization of these terms and conditions. Should we elect to transfer to the bitumen-based royalty, future upgrading operations would not be included in the calculation of royalty expense. We would pay a royalty based on 25% of bitumen revenues, minus the amended definition of allowable costs, which will exclude upgrading costs. We have until late 2008 to decide if we will move to the generic bitumen-based royalty. This agreement does not impact the Alberta government’s position on the current royalty treatment of Firebag, or our related statement of claim filed against the Crown.

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.

8

Natural Gas

Natural Gas recorded 2005 third quarter net earnings of $24 million, compared with $23 million during the third quarter of 2004. Increased revenues as a result of higher natural gas prices were offset by higher dry hole costs, increased depletion, depreciation and amortization expenses and slightly lower production volumes. Realized natural gas prices in the third quarter of 2005 were $8.32 per thousand cubic feet (mcf) compared to $6.49 per mcf in the third quarter of 2004 reflecting higher benchmark commodity prices.

Cash flow from operations for the third quarter of 2005 was $104 million compared to $80 million in the third quarter of 2004. The increase was due to the impact of higher natural gas prices partially offset by lower volumes. The increased dry hole costs and depreciation and amortization expenses do not impact cash flow.

Year-to-date net earnings were $77 million, compared to $80 million in the first nine months of 2004. The decrease in year-to-date earnings resulted from lower production volumes, increased depletion, depreciation and amortization expense, increased operating, selling and general expenses, and increased dry hole costs, partially offset by higher natural gas prices.

Cash flow from operations for the first nine months of 2005 was $268 million, compared to $253 million for the first nine months of 2004, reflecting the same factors impacting cash flow from operations for the third quarter of 2005.

Our strategy calls for natural gas production to exceed natural gas purchases for internal consumption. Natural gas production in the third quarter was 200 million cubic feet (mmcf) per day, compared to 201 mmcf per day in the third quarter of 2004. We expect to meet our revised annual outlook for production of 195 to 200 mmcf per day. We also expect the revised annual production outlook to exceed our annual projected purchases for internal consumption.

Energy Marketing & Refining (EM&R) — Canada

EM&R’s Rack Back and Rack Forward organizational structures have 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 third quarter 2005 net earnings of $17 million, compared to net earnings of $29 million in the third quarter of 2004. The decrease in net earnings was primarily due to lower refining volumes, lower refinery utilization and higher energy costs. Third quarter 2005 utilization was 96%, compared to 104% in the third quarter of 2004. The decrease was due to a fire which occurred at the Sarnia refinery in July of this year. The damaged components were back in full operation in August. EM&R’s results continued to be negatively impacted by high prices for synthetic crude oil in 2005.

Refining margins on Suncor’s proprietary refined products were 9.2 cents per litre (cpl) in the third quarter of 2005, compared to 8.8 cpl in the third quarter of 2004. Retail margins were 5.4 cpl in the third quarter of 2005 compared to 3.7 cpl in the third quarter of 2004 reflecting strengthened market conditions towards the end of the third quarter of 2005.

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

9

Cash flow from operations was $44 million in the third quarter of 2005, compared to $52 million in the third quarter of 2004. The decrease was primarily due to the same factors that affected net earnings.

EM&R recorded net earnings of $19 million for the first nine months of 2005 compared to $56 million during the first nine months of 2004. The decrease reflects lower refining margins, higher energy costs, and lower mark-to-market gains on inventory related derivatives, during the first nine months of 2005.

Cash flow from operations for the first nine months of 2005 was $92 million, compared to $131 million in the first nine months of 2004. The decrease was primarily due to the same factors that affected net earnings.

Suncor’s diesel desulphurization and Oil Sands integration project at the Sarnia refinery is on budget and on schedule for completion 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 $50 million in the third quarter of 2005 compared to earnings of $15 million during the third quarter of 2004. Net earnings in 2005 were positively impacted by higher refinery utilizations, increased sales volumes due in part to the acquisition of the Colorado Refining Company on May 31, 2005 (see below), and higher refining and retail margins.

Cash flow from operations for the third quarter of 2005 was $82 million compared to $21 million in the third quarter of 2004. The increase was due to the same factors that increased net earnings.

Refining margins in the third quarter of 2005 averaged 8.9 cpl, compared to 5.1 cpl in the third quarter of 2004, reflecting high prices for light oil products. Refinery utilization at the Denver refinery averaged 104% in the third quarter of 2005 compared to 99% in the third quarter of 2004 when a planned maintenance shutdown occurred. A refinery shutdown originally scheduled for the third quarter of 2005 has been rescheduled to the first quarter of 2006. Retail margins in the third quarter of 2005 averaged 7.5 cpl, compared to 4.2 cpl in the third quarter of 2004.

R&M recorded net earnings of $87 million for the first nine months of 2005, compared to $24 million for the first nine months of 2004. Cash flow from operations was $152 million for the nine months ended September 30, 2005, compared to $36 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 third quarter.

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 bpd Denver refinery located adjacent to our original refinery, as well as a products terminal located in Grand Junction, Colorado.

Modifications to enable the Denver refinery to meet new regulatory requirements for low sulphur diesel fuel while also allowing the refinery to process 10,000 bpd to 15,000 bpd of oil sands sour crude are well under way. However, labour shortages and material supply issues have put upward cost pressure on the project. As a result, the $360 million cost estimate for the projects will likely increase.

See page 12 for an update on our significant capital projects in progress.

10

Corporate

Corporate recorded a net loss of $3 million in the third quarter of 2005, compared to a net gain of $7 million during the third quarter of 2004. The decrease was due primarily to the impact of lower unrealized foreign exchange gains on U.S. dollar denominated long-term debt of $53 million after-tax in the third quarter of 2005 compared to $64 million after-tax gain in the third quarter of 2004. As well, higher stock based compensation expenses and higher insurance costs were partially offset by lower financing expenses. Excluding unrealized foreign exchange gains on U.S. dollar denominated long term debt, financing expenses were $5 million after-tax in the third quarter of 2005 compared to $20 million after-tax in the third 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.

Cash used in operations was $24 million in the third quarter of 2005 compared to $77 million in the third quarter of 2004. Cash used in operations is lower due to lower cash financing expenses and lower current income tax expense.

Corporate recorded a net loss of $119 million in the first nine months of 2005, compared to a loss of $138 million in the same period of 2004. For 2005 year-to-date, after-tax unrealized foreign exchange gains on our U.S. dollar denominated debt were $35 million, compared to after tax gains of $18 million in 2004. Excluding the impact of unrealized foreign exchange gains, the net loss for the first nine months of 2005 was only slightly lower than the same period in 2004. Higher stock based compensation and insurance related costs were offset by lower financing costs.

Cash flow used in operations was $174 million in the nine months ended September 30, 2005 compared to cash flow used in operations of $226 million in the nine months ended September 30, 2004. The decrease was due to the same factors that impacted net earnings.

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 $223 million at the end of the third quarter of 2005, compared to a deficiency of $212 million at the end of the third 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 business interruption insurance proceeds.

During the third quarter of 2005, net debt increased to approximately $3.3 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 January fire and increased capital spending activities. We continue to expect the financial impact of the fire on our balance sheet will be significantly mitigated by insurance proceeds. With production returned to full capacity, debt levels are expected to stabilize as cash flow from operations increase to fund our capital program. At September 30, 2005 our undrawn lines of credit were approximately $920 million. During the second quarter of 2005, we entered into a new $600 million credit facility agreement. The new facility is fully revolving for 364 days and expires in 2006. During the third quarter of 2005 we renewed $200 million of our available credit and term loan facilities. We remain on target to meet our revised 2005 capital spending program of approximately $2.7 billion (excluding costs to repair damage caused by the fire). We feel we have the capital resources from our undrawn lines of credit and cash flow from operations to fund the remainder of our 2005 capital spending program and to meet our current working capital requirements.

11

SIGNIFICANT CAPITAL PROJECT UPDATE

Suncor spent $876 million towards capital investing activities in the third quarter of 2005 compared to $485 million in the third quarter of 2004. A summary of the progress on our significant projects under construction is provided below.

Description	Board of Directors’ Approval	Cost Estimate(1) ($ millions)			Spent 2005 Year to Date ($ millions)			Total Spent to Date ($ millions)			Status
Oil Sands
Millennium vacuum unit	Yes	$	425		$	49		$	441		Project is substantially complete. (2)
Firebag Stage Two	Yes	$	515		$	120		$	540		Project is substantially complete, commissioning is under way.(2)
Coker Unit (3)	Yes	$	2 100		$	390		$	790		Project is on schedule and on budget.
EM&R
Diesel desulphurization	Yes	$	800		$	225		$	403		Project is on schedule and on budget.
R&M
Diesel desulphurization	Yes	$	360	(4)	$	228		$	364		Project cost estimate
		(US$300)			(US$187		)	(US$292		)	is under review.(4)

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

(2)Total project cost is subject to change until all accounts are final.

(3)Excludes costs associated with bitumen feed.

(4)See page 10 for discussion.

Derivative Financial Instruments

During the third quarter of 2005, we resumed our strategic crude oil hedging program, permitting us to fix a price or range of prices for a percentage of our total production of crude oil for specified periods of time. During the third quarter of 2005 we entered into agreements covering 7,000 bpd beginning January 1, 2006 and ending December 31, 2007. Prices for these barrels are fixed within a range of US$50 per barrel to an average of about US$92 per barrel WTI. The company will consider entering further hedges up to 30% of production if strategic opportunities are available.

These new hedges are in addition to the crude oil hedges covering 36,000 bpd of production that were placed prior to 2004. These hedges expire at the end of 2005.

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 third quarter of 2005, strategic crude oil hedging decreased our after-tax net earnings by $102 million, compared with $115 million in the third 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 September 30:

($ millions)	2005		2004
Revenue hedge swaps and options	(184	)	(586	)
Cost and margin hedge swaps	(17	)	—
Interest rate swaps	27		26
	(174	)	(560	)

12

We also use derivative instruments to hedge risks specific to individual transactions. The estimated fair value of these instruments was $14 million at September 30, 2005 compared to $9 million at December 31, 2004.

Energy Marketing and Trading Activities

For the quarter ended September 30, 2005, we recorded a net pretax gain of $3 million compared to the $3 million gain recorded during the third quarter of 2004, related to the settlement and revaluation of financial energy trading contracts. In the third quarter, the settlement of physical trading activities resulted in a net pretax gain of $1 million compared to a $2 million pretax gain in the third quarter of 2004. These gains were included as energy marketing and trading activities in the Consolidated Statement of Earnings. The above amounts do not include the impact of related general and administrative costs. Total after tax energy marketing and trading activities resulted in a gain of $2 million for the quarter ended September 30, 2005, unchanged from the third quarter of 2004. The fair value of unsettled financial energy trading assets and liabilities at September 30, 2005 and December 31, 2004 were as follows:

($ millions)	2005	2004
Energy trading assets	114	26
Energy trading liabilities	101	9

Control Environment

Based on their evaluation as of September 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 SEC rules and forms. In addition, other than as described below, as of September 30, 2005, there were no changes in our internal control over financial reporting that occurred during the nine month period ended September 30, 2005 that have materially affected, or are reasonably likely to materially affect our internal control over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal control 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 completed during 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 September 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 control 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 $37 million, an increase in future tax liabilities of $13 million and an increase in retained earnings of $24 million. Effective January 1, 2005, we retroactively adopted the Canadian Accounting Standards Board amendment to Handbook Section 3860 “Financial Instruments — Disclosure and Presentation”. The amendment requires that certain obligations that must or could be settled with an entity’s own equity investments, be presented as liabilities. Accordingly, we have reclassified our preferred securities from equity to long-term debt, resulting in an increase to property, plant and equipment of $37 million, an increase in future tax liabilities of $13 million and an increase in retained earnings of $24 million.

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

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 September 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 September 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 September 30		9 months ended September 30
			2005	2004	2005	2004
Cash flow from operations ($ millions)	A		651	585	1 250	1 489
Weighted average number of common
shares outstanding (millions of shares)	B		457	453	456	453
Cash flow from operations (per share)	(A / B	)	1.42	1.29	2.74	3.29

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 September 30						9 months ended September 30
		2005			2004(1)			2005			2004(1)
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		238			174			630			614
Less: natural gas costs and inventory changes		(44	)		4			(121	)		(80	)
Accretion of asset retirement obligations		7			5			18			15
Taxes other than income taxes		8			7			22			21
Cash costs		209		18.00	190		9.00	549		16.50	570		9.45
Natural gas		53		4.60	30		1.40	133		4.00	117		1.90
Imported bitumen (net of other reported product purchases)		—		—	2		0.10	1		—	11		0.20
Cash operating costs	A	262		22.60	222		10.50	683		20.50	698		11.55
Start-up costs		—		—	1			—		—	23
Add: in-situ inventory changes		—		—	—			—		—	2
Less: pre-start-up commissioning costs		—		—	(1	)		—		—	(1	)
In-situ (Firebag) start-up costs	B	—		—	—		—	—		—	24		0.40
Total cash operating costs	A+B	262		22.60	222		10.50	683		20.50	722		11.95
Depreciation, depletion and amortization		103		9.00	121		5.70	306		9.20	364		6.00
Total operating costs		365		31.60	343		16.20	989		29.70	1 086		17.95
Production (thousands of barrels per day)		125.2			230.2			122.0			220.3

14

OIL SANDS OPERATING COSTS — FIREBAG IN-SITU BITUMEN PRODUCTION

	Quarter ended September 30						9 months ended September 30
	2005			2004(1)			2005			2004(1)
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	43			19			103			43
Less: natural gas costs and inventory changes	(29	)		(9	)		(58	)		(24	)
Accretion of asset retirement obligations	—			—						—
Taxes other than income taxes	—			—						—
Cash costs	14		6.85	10		14.90	45		9.70	19		9.30
Natural gas	29		13.70	8		11.90	58		12.80	24		11.70
Cash operating costs	43		20.55	18		26.80	103		22.50	43		21.00
Depreciation, depletion and amortization	9		4.10	5		7.45	23		4.95	13		6.35
Total operating costs	52		24.65	23		34.25	126		27.45	56		27.35
Production (thousands of barrels per day)	23.0			7.3			16.8			11.2

(1)Production in the base operations for the nine months ended September 30, 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 our 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 or phrases like “outlook,” “may,”“expects,” “anticipates,” “planned,” “intends,” “believes,” “could,” “should,” “would,” “future,” “strategy,” “sets the stage,” “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; 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 Third fiscal
quarter ended September 30, 2005

consolidated statements of earnings

(unaudited)

	Third quarter				Nine months ended Sept 30
($ millions)	2005		2004		2005		2004
Revenues (note 12)	3 142		2 326		7 583		6 344
Expenses
Purchases of crude oil and products	1 311		806		3 166		2 114
Operating, selling and general (note 6)	534		396		1 462		1 241
Energy marketing and trading activities (note 3)	230		118		573		295
Transportation and other costs	35		40		102		96
Depreciation, depletion and amortization (note 2)	174		183		507		536
Accretion of asset retirement obligations	8		6		23		19
Exploration	29		10		48		48
Royalties (note 9)	172		153		410		381
Taxes other than income taxes	160		140		406		404
Loss (gain) on disposal of assets	—		3		(1	)	3
Project start-up costs	7		1		13		23
Financing expenses (income) (notes 2 and 4)	(58	)	(47	)	(30	)	65
	2 602		1 809		6 679		5 225
Earnings Before Income Taxes	540		517		904		1 119
Provision for Income Taxes (note 2)
Current	(16	)	19		37		43
Future	215		161		316		321
	199		180		353		364
Net Earnings	341		337		551		755
Per Common Share (dollars), (note 5)
Basic	0.75		0.74		1.21		1.67
Diluted	0.73		0.73		1.18		1.64
Cash dividends	0.06		0.06		0.18		0.17

See accompanying notes.

16

consolidated balance sheets

(unaudited)

		September 30			December 31
($ millions)		2005			2004
Assets
Current assets
Cash and cash equivalents		85			88
Accounts receivable		1 266			627
Inventories		456			423
Future income taxes		89			57
Total current assets		1 896			1 195
Property, plant and equipment, net (note 2)		12 179			10 326
Deferred charges and other		473			320
Total assets		14 548			11 841
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt		4			30
Accounts payable and accrued liabilities (note 9)		1 916			1 306
Income taxes payable		8			32
Taxes other than income taxes		21			41
Total current liabilities		1 949			1 409
Long-term debt		3 336			2 217
Accrued liabilities and other		925			749
Future income taxes (note 2)		2 893			2 545
Shareholders’ equity (see below)		5 445			4 921
Total liabilities and shareholders’ equity		14 548			11 841
Shareholders’ Equity
	Number			Number
	(thousands)			(thousands)
Share capital	457 288	723		454 241	651
Contributed surplus		43			32
Cumulative foreign currency translation		(83	)		(55	)
Retained earnings (note 2)		4 762			4 293
		5 445			4 921

See accompanying notes.

17

consolidated statements of cash flows

(unaudited)

	Third quarter				Nine months ended Sept 30
($ millions)	2005		2004		2005		2004
Operating Activities
Cash flow from operations	651		585		1 250		1 489
Decrease (increase) in operating working capital
Accounts receivable	(429	)	43		(604	)	(176	)
Inventories	44		37		4		(66	)
Accounts payable and accrued liabilities	154		47		607		301
Taxes payable	(19	)	9		(47	)	6
Cash flow from operating activities	401		721		1 210		1 554
Cash Used in Investing Activities	(836	)	(478	)	(2 354	)	(1 175	)
Net Cash Surplus (Deficiency) Before Financing Activities	(435	)	243		(1 144	)	379
Financing Activities
Increase (decrease) in short-term debt	(6	)	(25	)	(26	)	(19	)
Net increase (decrease) in other long-term debt	483		(109	)	1 141		(577	)
Issuance of common shares under stock option plan	10		7		62		27
Dividends paid on common shares	(26	)	(27	)	(77	)	(72	)
Deferred revenue	11		11		41		11
Cash provided by (used in) financing activities	472		(143	)	1 141		(630	)
Increase (Decrease) in Cash and Cash Equivalents	37		100		(3	)	(251	)
Effect of Foreign Exchange on Cash and Cash Equivalents	—		(2	)	—		(2	)
Cash and Cash Equivalents at Beginning of Period	48		37		88		388
Cash and Cash Equivalents at End of Period	85		135		85		135

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 inaccounting policy, net of tax (note 2)	—	—		—		14
At December 31, 2003, as restated	604	7		(26	)	3 308
Net earnings	—	—		—		755
Dividends paid on common shares	—	—		—		(72	)
Issued for cash under stock option plan	27	—		—		—
Issued under dividend reinvestment plan	5	—		—		(5	)
Stock-based compensation expense	—	19		—		—
Foreign currency translation adjustment	—	—		(10	)	—
At September 30, 2004	636	26		(36	)	3 986
At December 31, 2004, as previously reported	651	32		(55	)	4 269
Retroactive adjustment for change inaccounting policy, net of tax (note 2)	—	—		—		24
At December 31, 2004, as restated	651	32		(55	)	4 293
Net earnings	—	—		—		551
Dividends paid on common shares	—	—		—		(77	)
Issued for cash under stock option plan	67	(5	)	—		—
Issued under dividend reinvestment plan	5	—		—		(5	)
Stock-based compensation expense	—	16		—		—
Foreign currency translation adjustment	—	—		(28	)	—
At September 30, 2005	723	43		(83	)	4 762

See accompanying notes.

19

schedules of segmented data

(unaudited)

	Third quarter
									Energy Marketing and Refining —				Refining and 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	623		847		168		135		982		785		924		437	—		—		2 697		2 204
Energy marketing and trading activities	—		—		—		—		234		121		—		—	—		—		234		121
Net insurance proceeds (note 12)	211		—		—		—		—		—		—		—	—		—		211		—
Intersegment revenues	163		110		6		5		—		—		—		—	(169	)	(115	)	—		—
Interest	—		—		—		—		—		—		—		1	—		—		—		1
	997		957		174		140		1 216		906		924		438	(169	)	(115	)	3 142		2 326
Expenses
Purchases of crude oil and products	8		33		—		—		740		533		731		353	(168	)	(113	)	1 311		806
Operating, selling and general	281		193		25		22		114		105		48		23	66		53		534		396
Energy marketing and trading activities	—		—		—		—		230		118		—		—	—		—		230		118
Transportation and other costs	23		27		5		5		1		1		6		7	—		—		35		40
Depreciation, depletion and amortization	112		126		36		29		18		18		6		9	2		1		174		183
Accretion of asset retirement obligations	7		5		1		1		—		—		—		—	—		—		8		6
Exploration	—		—		29		10		—		—		—		—	—		—		29		10
Royalties	136		122		36		31		—		—		—		—	—		—		172		153
Taxes other than income taxes	20		18		1		—		86		90		53		32	—		—		160		140
Loss (gain) on disposal of assets	—		4		—		—		—		(1	)	—		—	—		—		—		3
Project start-up costs	7		1		—		—		—		—		—		—	—		—		7		1
Financing expenses	—		—		—		—		—		—		—		—	(58	)	(47	)	(58	)	(47	)
	594		529		133		98		1 189		864		844		424	(158	)	(106	)	2 602		1 809
Earnings (loss) before income taxes	403		428		41		42		27		42		80		14	(11	)	(9	)	540		517
Income taxes	(150	)	(165	)	(17	)	(19	)	(10	)	(13	)	(30	)	1	8		16		(199	)	(180	)
Net earnings (loss)	253		263		24		23		17		29		50		15	(3	)	7		341		337

20

(unaudited)

	Third quarter
									Energy Marketing and Refining —				Refining and 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)	253		263		24		23		17		29		50		15		(3	)	7		341		337
Exploration expenses	—		—		29		10		—		—		—		—		—		—		29		10
Non-cash items included in earnings
Depreciation, depletion and amortization	112		126		36		29		18		18		6		9		2		1		174		183
Income taxes	150		165		17		19		10		13		30		(1	)	8		(35	)	215		161
Loss (gain) on disposal of assets	—		4		—		—		—		(1	)	—		—		—		—		—		3
Stock-based compensation expense	—		—		—		—		—		—		—		—		6		10		6		10
Other	2		(5	)	(2	)	(2	)	(1	)	2		(4	)	(1	)	(61	)	(70	)	(66	)	(76	)
Overburden removal outlays	(68	)	(51	)	—		—		—		—		—		—		—		—		(68	)	(51	)
Increase (decrease) in deferred credits and other	(4	)	7		—		1		—		(9	)	—		(1	)	24		10		20		8
Total cash flow from (used in) operations	445		509		104		80		44		52		82		21		(24	)	(77	)	651		585
Decrease (increase) in operating working capital	(230	)	18		(14	)	26		22		(9	)	118		82		(146	)	19		(250	)	136
Total cash flow from (used in) operating activities	215		527		90		106		66		43		200		103		(170	)	(58	)	401		721
Cash from (used in) investing activities:
Capital and exploration expenditures	(563	)	(305	)	(87	)	(53	)	(114	)	(67	)	(95	)	(52	)	(17	)	(8	)	(876	)	(485	)
Proceeds from property loss	44		—		—		—		—		—		—		—		—		—		44		—
Deferred maintenance shutdown expenditures	(4	)	(1	)	(3	)	—		—		4		(3	)	(1	)	—		—		(10	)	2
Deferred outlays and other investments	—		—		—		—		1		—		—		—		2		—		3		—
Proceeds from disposals	—		2		2		3		1		—		—		—		—		—		3		5
Total cash (used in) investing activities	(523	)	(304	)	(88	)	(50	)	(112	)	(63	)	(98	)	(53	)	(15	)	(8	)	(836	)	(478	)
Net cash surplus (deficiency) before financing activities	(308	)	223		2		56		(46	)	(20	)	102		50		(185	)	(66	)	(435	)	243

21

(unaudited)

	Nine months ended September 30
	Oil Sands				Natural Gas				Energy Marketing and Refining — Canada				Refining and Marketing — U.S.A.				Corporate and Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
EARNINGS
Revenues
Operating revenues	1 636		2 350		429		358		2 634		2 227		1 910		1 098		1		1		6 610		6 034
Energy marketing and trading activities	—		—		—		—		585		316		—		—		—		(8	)	585		308
Net insurance proceeds (note 12)	387		—		—		—		—		—		—		—		—		—		387		—
Intersegment revenues	316		302		19		63		—		—		—		—		(335	)	(365	)	—		—
Interest	—		—		—		—		—		—		1		1		—		1		1		2
	2 339		2 652		448		421		3 219		2 543		1 911		1 099		(334	)	(371	)	7 583		6 344
Expenses
Purchases of crude oil and products	29		75		—		—		1 959		1 544		1 513		859		(335	)	(364	)	3 166		2 114
Operating, selling and general	733		657		69		61		339		297		119		94		202		132		1 462		1 241
Energy marketing and trading activities	—		—		—		—		573		303		—		—		—		(8	)	573		295
Transportation and other costs	68		63		16		16		4		2		14		15		—		—		102		96
Depreciation, depletion and amortization	329		377		97		86		54		51		18		16		9		6		507		536
Accretion of asset retirement obligations	18		15		4		3		1		1		—		—		—		—		23		19
Exploration	10		15		38		33		—		—		—		—		—		—		48		48
Royalties	317		289		93		92		—		—		—		—		—		—		410		381
Taxes other than income taxes	34		54		2		2		258		260		112		88		—		—		406		404
Loss (gain) on disposal of assets	—		7		—		(3	)	(1	)	(1	)	—		—		—		—		(1	)	3
Project start-up costs	13		23		—		—		—		—		—		—		—		—		13		23
Financing expenses	—		—		—		—		—		—		—		—		(30	)	65		(30	)	65
	1 551		1 575		319		290		3 187		2 457		1 776		1 072		(154	)	(169	)	6 679		5 225
Earnings (loss) before income taxes	788		1 077		129		131		32		86		135		27		(180	)	(202	)	904		1 119
Income taxes	(301	)	(344	)	(52	)	(51	)	(13	)	(30	)	(48	)	(3	)	61		64		(353	)	(364	)
Net earnings (loss)	487		733		77		80		19		56		87		24		(119	)	(138	)	551		755
As at September 30
TOTAL ASSETS	10 990		8 744		1 159		819		1 880		1 274		1 239		549		(720	)	14		14 548		11 400

22

(unaudited)

	Nine months ended September 30
	Oil Sands				Natural Gas				Energy Marketing and Refining —Canada				Refining and Marketing — U.S.A.				Corporate and 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)	487		733		77		80		19		56		87		24		(119	)	(138	)	551		755
Exploration expenses	—		—		38		33		—		—		—		—		—		—		38		33
Non-cash items included in earnings
Depreciation, depletion and amortization	329		377		97		86		54		51		18		16		9		6		507		536
Income taxes	301		344		52		51		13		30		48		3		(98	)	(107	)	316		321
Loss (gain) on disposal of assets	—		7		—		(3	)	(1	)	(1	)	—		—		—		—		(1	)	3
Stock-based compensation expense	—		—		—		—		—		—		—		—		16		19		16		19
Other	25		(13	)	4		6		7		(5	)	(1	)	(9	)	(54	)	(19	)	(19	)	(40	)
Overburden removal outlays	(220	)	(163	)	—		—		—		—		—		—		—		—		(220	)	(163	)
Increase (decrease) in deferred credits and other	(10	)	10		—		—		—		—		—		2		72		13		62		25
Total cash flow from (used in) operations	912		1 295		268		253		92		131		152		36		(174	)	(226	)	1 250		1 489
Decrease (increase) in operating working capital	(110	)	26		(41	)	(11	)	(11	)	—		74		38		48		12		(40	)	65
Total cash flow from (used in) operating activities	802		1 321		227		242		81		131		226		74		(126	)	(214	)	1 210		1 554
Cash from (used in) investing activities:
Capital and exploration expenditures	(1 443	)	(779	)	(241	)	(160	)	(306	)	(132	)	(258	)	(97	)	(41	)	(25	)	(2 289	)	(1 193	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		(62	)	—		—		—		(62	)	—
Proceeds from property loss	44		—		—		—		—		—		—		—		—		—		44		—
Deferred maintenance shutdown expenditures	(64	)	(1	)	(3	)	—		—		(21	)	(4	)	(7	)	—		—		(71	)	(29	)
Deferred outlays and other investments	(1	)	(3	)	—		—		(1	)	(12	)	—		—		1		8		(1	)	(7	)
Proceeds from disposals	21		42		2		10		2		2		—		—		—		—		25		54
Total cash (used in) investing activities	(1 443	)	(741	)	(242	)	(150	)	(305	)	(163	)	(324	)	(104	)	(40	)	(17	)	(2 354	)	(1 175	)
Net cash surplus (deficiency) before financing activities	(641	)	580		(15	)	92		(224	)	(32	)	(98	)	(30	)	(166	)	(231	)	(1 144	)	379

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 September 30, 2005 and the results of its operations and cash flows for the three and nine month periods ended September 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 September 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

	Third quarter		Nine months ended September 30
($ millions, increase/(decrease))	2005	2004	2005		2004
Depreciation, depletion and amortization	—	—	1		2
Financing expenses	—	—	—		15
Future income taxes	—	—	—		(5	)
Net earnings	—	—	(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 September 30, 2005 these activities resulted in a net pretax gain of $1 million (2004 — pretax gain of $2 million). For the nine months ended September 30, 2005 physical energy marketing contracts resulted in a net pretax gain of $10 million (2004 — pretax gain of $7 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 September 30, 2005, a net pretax gain of $3 million (2004 — pretax gain of $3 million) resulted from the settlement and revaluation of the financial energy contracts. For the nine months ended September 30, 2005 a net pretax gain of $4 million (2004 — pretax gain of $9 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:

	September 30	December 31
($ millions)	2005	2004
Energy trading assets	114	26
Energy trading liabilities	101	9

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

4. FINANCING EXPENSES (INCOME)

	Third Quarter				Nine months ended September 30
($ millions)	2005		2004		2005		2004
Interest on debt	39		36		110		121
Capitalized interest	(34	)	(17	)	(91	)	(40	)
Net interest expense	5		19		19		81
Foreign exchange (gain) on long-term debt	(64	)	(77	)	(42	)	(22	)
Other foreign exchange (gain) loss	1		11		(7	)	6
Total financing expenses (income)	(58	)	(47	)	(30	)	65

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Third Quarter		Nine months ended September 30
($ millions)	2005	2004	2005	2004
Net earnings	341	337	551	755
(millions of common shares)
Weighted-average number of common shares	457	453	456	453
Options issued under stock-based compensation plans	11	7	9	9
Weighted-average number of diluted common shares	468	460	465	462
(dollars per common share)
Basic earnings per share (b)	0.75	0.74	1.21	1.67
Diluted earnings per share (c)	0.73	0.73	1.18	1.64	(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 nine months ended September 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 314,000 options to new employees in the third quarter of 2005, for a total of 991,000 options granted in the nine months ended September 30, 2005 (256,000 options granted during the third quarter of 2004; 1,452,000 options granted in the nine months ended September 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 third quarter and the nine months ended September 30, 2005 was not significant.

Under the company’s other plans, 63,000 options were granted in the third quarter of 2005, for a total of 1,418,000 options granted in the nine months ended September 30, 2005 (1,000 options granted during the third quarter of 2004; 1,285,000 granted in the nine months ended September 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:

	Third Quarter				Nine months ended September 30
	2005		2004		2005		2004
Quarterly dividend per share	$0.06		$0.06		$0.06		$0.06*
Risk-free interest rate	3.42	%	4.12	%	3.68	%	3.76	%
Expected life	5 years		6 years		6 years		6 years
Expected volatility	28	%	29	%	28	%	29	%
Weighted-average fair value per option	$19.17		$12.50		$14.89		$11.84

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

Stock-based compensation expense recognized in the third quarter of 2005 related to stock options plans was $6 million (2004 — $10 million). For the nine months ended September 30, 2005 stock-based compensation expense recognized was $16 million (2004 — $19 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:

	Third Quarter		Nine months ended September 30
($ millions, except per share amounts)	2005	2004	2005	2004
Net earnings — as reported	341	337	551	755
Less: compensation cost under the fair value method for pre-2003 options	2	20	11	41
Pro forma net earnings	339	317	540	714
Basic earnings per share
As reported	0.75	0.74	1.21	1.67
Pro forma	0.74	0.70	1.18	1.58
Diluted earnings per share
As reported	0.73	0.73	1.18	1.64
Pro forma	0.73	0.69	1.16	1.55

26

(b) Performance Share Units (PSUs)

In the third quarter of 2005 the company issued 6,000 PSUs (2004 — Nil). For the nine months ended September 30, 2005, the company issued 451,000 PSUs (2004 — 353,000). Expense recognized in the third quarter of 2005 was $8 million (2004 — $1 million). Expense recognized for the nine months ended September 30, 2005 was $16 million (2004 — $3 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 nine months ended September 30.

	Pension Benefits
	Third quarter				Nine months ended September 30
	2005		2004		2005		2004
Current service costs	8		6		24		18
Interest costs	10		8		29		25
Expected return on plan assets	(7	)	(6	)	(21	)	(18	)
Amortization of net actuarial loss	4		5		15		14
Net periodic benefit cost	15		13		47		39

	Other Post-retirement Benefits
	Third quarter		Nine months ended September 30
	2005	2004	2005	2004
Current service costs	2	1	5	4
Interest costs	1	2	5	5
Amortization of net actuarial loss	1	—	1	1
Net periodic benefit cost	4	3	11	10

8. SUPPLEMENTAL INFORMATION

	Third quarter		Nine months ended September 30
($ millions)	2005	2004	2005	2004
Interest paid	53	47	122	125
Income taxes paid	6	6	61	38

Strategic Crude Oil Hedges at September 30, 2005

	Quantity	Average Price	Revenue Hedged	Hedge
	(bbl/day)	(US$/bbl)(a)	(Cdn$ millions)(b)	Period(c)
Swaps	36 000	22.77	88	2005
Costless collars	7 000	50.00 — 92.57	148 — 275	2006
Costless collars	7 000	50.00 — 92.57	148 — 275	2007

Margin Hedges at September 30, 2005

	Quantity	Average Margin	Margin Hedged	Hedge
	(bbl/day)	(US$/bbl)	(Cdn$ millions)(b)	Period(c)
Refined product and crude swaps	12 700	7.77	11	2005	(d)
Refined product and crude swaps	5 000	11.67	10	2006	(e)

27

Natural Gas Hedges at September 30, 2005

	Quantity	Average Price	Revenue Hedged	Hedge
Revenue	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period(c)
Costless collars	25 000	6.91 — 8.11	5 — 6	2005	(f)
Swaps	4 000	6.99	3	2005
Costless collars	25 000	10.76 — 16.13	16 — 25	2005	(g)
Swaps	4 000	6.58	10	2006
Costless collars	25 000	10.76 — 16.13	24 — 36	2006	(h)
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 September 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 October to December 2005, inclusive.

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

(f)For the period October 2005.

(g)For the period November to December 2005, inclusive.

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

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 $317 million ($196 million after-tax) for the first nine months of 2005 ($186 million after-tax in 2004). The annualized estimate of $546 million ($349 million after-tax) was based on nine months of actual results, together with 2005 forward crude oil pricing as at September 30, 2005, current forecasts of capital and operating costs for the remainder of 2005, a Canadian/US foreign exchange rate of $0.83, 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. During the third quarter, the company renewed $200 million of its available credit and term loan facilities.

12. SUBSEQUENT EVENT

In October, 2005, the Company received $166 million in proceeds related to its business interruption insurance coverage. The business interruption insurance proceeds related to business activity during the nine months ended September 30, 2005 and have accordingly been recognized as revenue in the third 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 September 30
Cash flow from operations (1)	1.42	1.29
For the nine months ended September 30
Cash flow from operations (1)	2.74	3.29
Ratios
For the twelve months ended September 30
Return on capital employed (%) (2)	13.8	18.8
Return on capital employed (%) (3)	10.5	16.3
Net debt to cash flow from operations (times) (4)	1.8	1.1
Interest coverage on long-term debt (times)
Net earnings (5)	9.8	10.0
Cash flow from operations (6)	12.8	12.7
As at September 30
Debt to debt plus shareholders’ equity (%) (7)	38.0	33.7
Common Share Information
As at September 30
Share price at end of trading (dollars per share)
Toronto Stock Exchange — Cdn$	70.42	40.40
New York Stock Exchange — US$	60.53	32.01
Common share options outstanding (thousands)	19 378	21 279
For the nine months ended September 30
Average number outstanding, weighted monthly (thousands)	455 962	452 565

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 — $884 million; 2004 — $1,056 million) adjusted for after-tax financing expenses (2005 — income of $57 million; 2004 — expense of $18 million) for the twelve month period ended; divided by average capital employed (2005 — $5,929 million; 2004 — $5,724 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 — $7,762 million; 2004 — $6,617 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					Nine months ended		Total year
	Sep 30	June 30	Mar 31	Dec 31	Sep 30	Sep 30	Sep 30	Dec 31
	2005	2005	2005	2004	2004	2005	2004	2004
OIL SANDS
Production (a)
Base operations	125.2	119.5	121.2	206.9	230.2	122.0	218.4	215.6
Firebag	23.0	8.7	18.7	15.6	7.3	16.8	9.4	10.9
Total production	148.2	128.2	139.9	222.5	237.5	138.8	227.8	226.5
Sales (a)
Light sweet crude oil	69.9	48.3	75.3	115.3	113.5	64.4	114.5	114.9
Diesel	10.6	9.0	11.8	25.5	28.7	10.5	28.6	27.9
Light sour crude oil	41.7	54.2	38.5	80.9	76.3	44.8	73.2	75.1
Bitumen	22.3	9.6	18.4	11.0	7.9	16.8	7.8	8.4
Total sales	144.5	121.1	144.0	232.7	226.4	136.5	224.1	226.3
Average sales price (1),(b)
Light sweet crude oil	52.08	39.20	45.41	50.55	46.03	46.34	43.98	45.60
Other (diesel, light sour crude oil and bitumen)	59.70	50.47	47.31	39.62	42.29	52.48	38.96	39.13
Total	56.01	45.98	46.44	44.68	44.08	49.72	41.45	42.28
Total*	67.95	57.24	54.80	54.40	52.72	60.21	48.17	49.78
CASH OPERATING COSTS AND TOTAL OPERATING COSTS — BASE OPERATIONS
Cash costs	18.00	16.30	15.10	10.90	9.00	16.50	9.45	9.80
Natural gas	4.60	2.65	4.70	2.20	1.40	4.00	1.90	2.00
Imported bitumen	—	—	0.10	0.10	0.10	—	0.20	0.15
Cash operating costs (2),(c)	22.60	18.95	19.90	13.20	10.50	20.50	11.55	11.95
Firebag start-up costs	—	—	—	—	—	—	0.40	0.30
Total cash operating costs (3),(c)	22.60	18.95	19.90	13.20	10.50	20.50	11.95	12.25
Depreciation, depletion and amortization	9.00	9.45	9.05	6.25	5.70	9.20	6.00	6.10
Total operating costs (4),(c)	31.60	28.40	28.95	19.45	16.20	29.70	17.95	18.35
CASH OPERATING COSTS AND TOTAL OPERATING COSTS — FIREBAG
Cash costs	6.85	18.95	8.90	7.00	14.90	9.70	9.30	8.30
Natural gas	13.70	16.40	10.10	10.45	11.90	12.80	11.70	11.20
Cash operating costs (5),(c)	20.55	35.35	19.00	17.45	26.80	22.50	21.00	19.50
Depreciation, depletion and amortization	4.10	7.60	4.75	5.55	7.45	4.95	6.35	6.00
Total operating costs (6),(c)	24.65	42.95	23.75	23.00	34.25	27.45	27.35	25.50
(for the period ended)
Capital employed (i)	4 492	4 303	4 231	4 169	4 182
(for the twelve months ended)
Return on capital employed (j)	17.1	17.2	19.6	22.9	22.8
Return on capital employed (j)****	12.8	13.4	15.9	18.8	19.0

30

(unaudited)

	For the quarter ended					Nine months ended		Total year Dec 31 2004
	Sep 30 2005	June 30 2005	Mar 31 2005	Dec 31 2004	Sep 30 2004	Sep 30 2005	Sep 30 2004
NATURAL GAS
Gross production **
Natural gas (d)	200	175	191	193	201	189	203	200
Natural gas liquids (a)	2.2	2.2	3.0	2.9	2.6	2.5	2.3	2.5
Crude oil (a)	0.7	1.0	0.9	1.0	1.0	0.9	1.0	1.0
Total gross production (e)	36.3	32.4	35.7	36.1	37.1	34.8	37.1	36.8
Average sales price (1)
Natural gas (f)	8.32	7.29	6.81	7.02	6.49	7.50	6.60	6.70
Natural gas (f) *	8.34	7.26	6.74	6.98	6.53	7.47	6.66	6.73
Natural gas liquids (b)	58.00	52.52	38.32	46.46	42.06	48.52	41.31	42.82
Crude oil — Conventional (b)	63.77	63.86	61.40	55.26	55.43	62.99	48.85	50.41
Net wells drilled
Conventional — Exploratory ***	4	—	5	—	3	9	10	10
— Development	2	2	5	5	3	9	11	16
	6	2	10	5	6	18	21	26
(for the period ended)
Capital employed (i)	598	564	490	448	410
(for the twelve months ended)
Return on capital employed (j)	22.7	22.5	26.2	27.1	30.4
ENERGY MARKETING AND REFINING — CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.2	4.8	4.6	4.8	4.6	4.5	4.5	4.6
Other	4.2	4.1	4.0	4.1	4.3	4.1	4.1	4.1
Jet fuel	0.9	0.8	0.9	1.0	1.0	0.9	0.9	0.9
Diesel	3.7	3.3	2.7	3.3	3.0	3.2	3.0	3.1
Total transportation fuel sales	13.0	13.0	12.2	13.2	12.9	12.7	12.5	12.7
Petrochemicals	0.7	0.8	0.8	0.8	0.7	0.7	0.8	0.8
Heating oils	0.2	0.3	0.8	0.5	0.2	0.4	0.4	0.4
Heavy fuel oils	0.8	1.4	1.0	0.8	0.5	1.1	0.7	0.7
Other	0.9	0.6	0.3	0.3	1.0	0.5	1.0	0.8
Total refined product sales	15.6	16.1	15.1	15.6	15.3	15.4	15.4	15.4
Margins (h)
Refining (7)	9.2	7.3	4.8	7.9	8.8	7.2	8.1	8.0
Refining (7) *	10.1	7.6	4.8	7.8	8.8	7.5	8.3	8.1
Retail (8)	5.4	3.8	4.7	4.5	3.7	4.6	4.3	4.4
Crude oil supply and refining
Processed at Sarnia refinery (g)	10.7	11.1	10.1	11.3	11.6	10.6	11.0	11.1
Utilization of refining capacity (j)	96	100	91	101	104	96	99	100
(for the period ended)
Capital employed (i)	547	507	525	512	528
(for the twelve months ended)
Return on capital employed (j)	7.7	10.1	8.4	14.6	11.2
Return on capital employed (j) ****	5.6	8.1	7.3	13.6	10.8

31

(unaudited)

	For the quarter ended					Nine months ended		Total year Dec 31 2004
	Sep 30 2005	June 30 2005	Mar 31 2005	Dec 31 2004	Sep 30 2004	Sep 30 2005	Sep 30 2004
REFINING AND MARKETING — U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.7	0.7	0.7	0.7	0.7
Other	8.9	5.0	3.8	3.9	4.3	5.9	3.7	3.8
Jet fuel	0.8	0.7	0.7	0.6	0.7	0.8	0.5	0.5
Diesel	3.9	3.1	2.6	2.5	2.5	3.2	2.2	2.2
Total transportation fuel sales	14.3	9.5	7.8	7.7	8.2	10.6	7.1	7.2
Asphalt	1.8	1.9	1.6	1.1	1.9	1.8	1.6	1.5
Other	1.2	1.2	0.7	0.7	0.8	1.1	0.5	0.6
Total refined product sales	17.3	12.6	10.1	9.5	10.9	13.5	9.2	9.3
Margins (h)
Refining (7)	8.9	9.5	6.3	7.7	5.1	8.5	6.4	6.7
Refining (7) *	8.9	9.5	6.3	7.7	5.3	8.5	6.6	6.8
Retail (8)	7.5	4.3	3.3	6.0	4.2	5.0	5.1	5.4
Crude oil supply and refining
Processed at Denver refinery (g)	14.9	11.4	9.2	9.5	9.5	12.3	8.6	8.8
Utilization of refining capacity (j)	104	102	96	100	99	102	90	92
(for the period ended)
Capital employed (i)	354	349	262	232	241
(for the twelve months ended)
Return on capital employed (j)	32.2	17.6	14.5	12.2	10.0
Return on capital employed (j) ****	21.6	13.8	12.2	11.0	9.6

32

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	(e)	thousands of barrels of oil	(h)	cents per litre
			equivalent per day
(b)	dollars per barrel			(i)	$ millions
		(f)	dollars per thousand cubic feet
(c)	dollars per barrel rounded			(j)	percentage
	to the nearest $0.05	(g)	thousands of cubic metres per day
(d)	millions of cubic feet per day

Metric conversion

Crude oil, refined products, etc. 1m 3 (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:	October 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:	October 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 third fiscal quarter ended September 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:	October 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 third fiscal quarter ended September 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:	October 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.