004	Suncor Energy Inc.
	2007 Third Quarter

Management’s discussion and analysis

October 25, 2007

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, 2007 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 18 to 60 of our 2006 Annual Report and to our Annual Information Form (AIF), dated February 28, 2007. All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in Non-GAAP Financial Measures on page 58 of our 2006 Annual Report, and page 13 of this MD&A.

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

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, partnerships and joint venture investments, unless the context requires otherwise.

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 periodic, quarterly and annual reports and the AIF, filed with the SEC under cover of Form 40-F, is available on-line at www.sedar.com, www.sec.gov and www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A and is not incorporated into the MD&A by reference.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for significant capital projects that, in some cases, are still in the early stages of development. These costs are estimates only. The actual amounts may differ and these differences may be material. For a further discussion of our significant capital projects and the range of cost estimates associated with an “on-budget” project, see “Significant Capital Project Update” on page 11.

Selected financial information

Industry Indicators	Three months ended September 30		Nine months ended September 30
(average for the period)	2007	2006	2007	2006
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	75.40	70.50	66.20	68.20
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	80.25	79.40	73.10	75.60
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty	22.85	18.80	19.60	21.60
Natural Gas US$/mcf at Henry Hub	6.15	6.55	6.90	7.45
Natural Gas (Alberta spot) Cdn$/mcf at AECO	5.60	6.05	6.80	7.20
New York Harbour 3-2-1 crack (1) US$/barrel	11.95	10.20	15.40	10.65
Exchange rate: Cdn$:US$	0.96	0.89	0.91	0.89

(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, 2007)
Common shares		461 940 543
Common share options – total		27 871 518
Common share options – exercisable		8 076 247

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	005
2007 Third Quarter

Summary of Quarterly Results

	2007 three months ended			2006 three months ended				2005 three months ended
($ millions, except per share data)	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31
Revenues	4 666	4 358	3 951	3 787	4 114	4 070	3 858	3 521
Net earnings	677	641	551	358	682	1 218	713	693
Net earnings attributable to common
shareholders per share
Basic	1.47	1.39	1.20	0.78	1.48	2.65	1.56	1.52
Diluted	1.43	1.36	1.17	0.76	1.45	2.59	1.52	1.48

Analysis of Consolidated Statements of Earnings and Cash Flows

Net earnings for the third quarter of 2007 were $677 million ($1.47 per common share), compared to $682 million ($1.48 per common share) in the third quarter of 2006. Excluding the impact of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt and project start-up costs, earnings for the third quarter of 2007 were $588 million ($1.27 per common share), compared to $691 million ($1.50 per common share) in the third quarter of 2006.

The decrease in net earnings was primarily due to a reduction in oil sands sales volumes and increased downstream refined product purchases; both the result of planned maintenance outages. Sales were down in oil sands because a planned maintenance outage in July impacted production rates, while refined product purchases were increased to ensure customer requirements were met during a planned outage at the Sarnia refinery. These negative impacts were partially offset by higher price realizations for oil sands products.

Cash flow from operations in the third quarter of 2007 was $1.027 billion, compared to $1.153 billion in the same period of 2006. Cash flow from operations was lower partially due to the same factors that impacted net earnings, as well as an increase in cash income tax expenses in the third quarter of 2007, compared to the third quarter of 2006.

Net earnings for the first nine months of 2007 were $1.869 billion ($4.06 per common share), compared to $2.613 billion ($5.69 per common share) for the same period in 2006. Excluding the impacts of income tax rate revaluations, net insurance proceeds (relating to the January 2005 fire), unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt, and project start-up costs, earnings for the first nine months of 2007 were $1.640 billion ($3.56 per common share), compared to $1.972 billion ($4.30 per common share) in the same period for 2006. Earnings decreased as a result of increased maintenance and lower production during the first nine months of 2007, compared to the same period in 2006.

Cash flow from operations for the first nine months of 2007 was $2.701 billion, compared to $3.787 billion in the first nine months of 2006. Cash flow from operations was lower partially due to the same factors that impacted net earnings, as well as an increase in cash income tax expenses in the first nine months of 2007, compared to the first nine months of 2006.

Inquiries John Rogers (403) 269-8670

006	Suncor Energy Inc.
	2007 Third Quarter

Our effective tax rate for the first nine months of 2007 was 28%, compared to 33% in the first nine months of 2006. The lower effective tax rate in 2007 was due to a reduction in the federal income tax rate enacted in the second quarter of 2007 and the fully phased-in resource tax changes that resulted in Crown royalties becoming fully deductible and eliminated the resource allowance. During 2007, we expect our oil sands and refining and marketing businesses will become partially cash taxable. During the first nine months of 2007 we recorded $314 million in current income tax expense compared to a recovery of $11 million in the first nine months of 2006 (see page 8 for a more detailed discussion).

Net Earnings Components

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

	Three months ended September 30				Nine months ended September 30
($ millions, after-tax)	2007		2006		2007		2006
Net earnings before the following items:	588		691		1 640		1 972
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	108		—		199		43
Impact of income tax rate reductions on opening future income tax liabilities	—		—		67		419
Oil sands fire accrued insurance proceeds (1)	—		—		—		205
Project start-up costs	(19	)	(9	)	(37	)	(26	)
Net earnings as reported	677		682		1 869		2 613

(1) Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown royalties.

Analysis of Segmented Earnings and Cash Flow

Oil Sands

Oil sands recorded 2007 third quarter net earnings of $556 million, compared with $582 million in the third quarter of 2006. Excluding the impact of project start-up costs, earnings for the third quarter of 2007 were $573 million, compared to $588 million in the third quarter of 2006. Earnings decreased primarily as a result of reduced sales volumes, an increase in depreciation, depletion and amortization, and higher royalty expenses. This was partially offset by higher average price realizations and a strong product mix for oil sands crude products during the third quarter of 2007. The increased price realization reflects higher benchmark WTI crude oil prices and the strengthening price differentials on our sweet and sour crude blends, partially offset by the increase in the value of the Canadian dollar.

Operating expenses were $515 million in the third quarter of 2007 compared to $509 million in the third quarter of 2006. The increase in operating expenses was primarily due to higher maintenance expenditures, in addition to an increase in stock-based compensation expense.

Transportation and other costs were $32 million in the third quarter of 2007, compared to $41 million in the third quarter of 2006. The decrease was due to reduced volumes shipped out of the Fort McMurray area.

Depreciation, depletion and amortization expense was $126 million in the third quarter of 2007, compared to $96 million during the same period in 2006. The increase resulted from continued growth in the depreciable cost base after the commissioning of new assets.

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	007
2007 Third Quarter

Alberta Crown royalty expense was $145 million in the third quarter of 2007, compared to $119 million in the third quarter of 2006. The increase was due mainly to higher current and future oil prices. See page 8 for a discussion of Alberta oil sands Crown royalties.

Project start-up costs for the third quarter of 2007 were $24 million, compared to $8 million in the third quarter of 2006. This increase was due primarily to initial start-up costs related to expansion work to increase production capacity to a targeted 350,000 bpd in 2008.

Cash flow from operations was $918 million in the third quarter of 2007, compared to $924 million in the third quarter of 2006. Cash flows were reduced by cash income taxes in the third quarter of 2007 that were largely absent in the third quarter of 2006. This impact was partially offset by the receipt of deferred revenues in the third quarter of 2007.

Net earnings for the first nine months of 2007 were $1.428 billion, compared to $2.389 billion in the first nine months of 2006. Cash flow from operations for the first nine months of 2007 decreased to $2.072 billion from $3.245 billion in the first nine months of 2006. The year-to-date decreases in net earnings and cash flow from operations were a result of lower sales volumes, a smaller income tax rate reduction in 2007, and the absence of net insurance proceeds (relating to the January 2005 fire) in the first nine months of 2007.

Oil sands production averaged 239,100 bpd in the third quarter of 2007. Production during the third quarter of 2006 averaged 242,800 bpd. Production was down as the result of a planned maintenance outage in July.

Sales volumes during the third quarter of 2007 averaged 223,900 bpd, compared with 238,000 bpd during the third quarter of 2006. The proportion of higher value diesel fuel and sweet crude products increased to 55% of total sales volumes in the third quarter of 2007, compared to 44% in the third quarter of 2006.

The average price realization for oil sands crude products increased to $76.97 per barrel in the third quarter of 2007, compared to $71.99 per barrel in the third quarter of 2006. A 7% increase in average benchmark WTI crude oil prices and the strengthening of our sweet and sour crude blends relative to WTI were partially offset by an 8% increase in the value of the Canadian dollar. Because crude oil is primarily sold based on U.S. dollar benchmark prices, a strengthening Canadian dollar produced a corresponding reduction in the Canadian dollar value of our products.

During the third quarter of 2007, cash operating costs averaged $25.10 per barrel, compared to $23.70 per barrel during the third quarter of 2006. The increase in cash operating costs per barrel was primarily due to higher maintenance costs and slightly lower production resulting from the planned outage. Refer to page 13 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Outlook

Unscheduled outages throughout the year have impacted year-to-date results at oil sands. As a result, management has revised its oil sands operation outlook, targeting an annual production average of 240,000 bpd to 245,000 bpd and cash operating costs of about $26.50 to $27.00 per barrel. The original outlook was an annual production average of 260,000 bpd to 270,000 bpd and cash operating costs of $21.50 to $22.50 per barrel.

Suncor is making progress to address challenges at its in-situ operation, where high emissions have resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has been capped at approximately 42,000 barrels of bitumen per day. As a result, commissioning of units to increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35%, will be delayed. Suncor’s revised outlook reflects this constraint.

To mitigate the impact to production, we are examining ways to increase bitumen supply from our mining operations. We are also accelerating the construction of emission abatement equipment, which will result in additional maintenance and capital costs being incurred.

An expansion project to increase production capacity to 350,000 bpd in the second half of 2008 is on schedule and on budget. Engineering is complete and construction is approximately 90% complete.

We remain on target for capital spending of approximately $3.5 billion this year on various components of our oil sands expansion.

For an update on our significant growth projects currently in progress see page 11.

Inquiries John Rogers (403) 269-8670

008	Suncor Energy Inc.
	2007 Third Quarter

Oil Sands Crown Royalties

On September 18, 2007, the Alberta Royalty Review Panel released its report recommending broad changes to the current royalty regime for both conventional and oil sands resource development. In its report, the panel recommends a significant increase in the royalty rate applicable to oil sands projects and the implementation of additional taxes. Although the government has indicated plans to make changes to the Alberta Crown Royalty regime in response to this report, we do not have sufficient information to determine the impact of changes the government may implement. Future royalties and taxes payable, as well as the determination of net mining and in-situ reserves, may be affected.

In the third quarter of 2007, we recorded a pretax royalty estimate of $145 million ($105 million after tax) compared to $119 million ($81 million after tax) for the third quarter of 2006.

We estimate 2007 annualized oil sands Crown royalties under current legislation to be approximately $600 million ($435 million after tax), compared to actual 2006 oil sands Crown royalties of $911 million ($619 million after tax). The decrease in the oil sands Crown royalties estimate is due primarily to an increase in allowable capital expenditures claimed and the absence of net insurance proceeds (relating to the January 2005 fire). This estimate is based on nine months of actual results and the balance of the year estimated on 2007 forward crude pricing of US$78.50 as at September 30, 2007, current forecasts of production, eligible capital and operating costs for the remainder of 2007, and a Cdn$/US$ foreign exchange rate of $1.01. Accordingly, actual results will differ, and these differences may be material.

Oil Sands Cash Income Taxes

We estimate we will incur cash taxes of approximately 50% to 70% of the expected 2007 provision for income tax expense. We do not anticipate any significant cash tax in subsequent years until approximately the middle of the next decade. In any year we may be subject to cash income tax due to sensitivity to crude oil and natural gas commodity price volatility, and the timing of recognition of capital expenditures for income tax purposes.

During the third quarter of 2007 oil sands recorded $45 million in current income tax expense, compared to $2 million in the comparative quarter in 2006.

The 2007 federal budget proposes to phase out the accelerated capital cost allowance that was originally intended to offset some of the risk associated with the large capital investment required to bring oil sands projects to production. The accelerated capital cost allowance will continue to be available for assets acquired before 2012 on major projects where major construction commenced before March 19, 2007. We believe Suncor’s Voyageur expansion, targeted for completion in 2012, will fall under the current accelerated capital cost allowance provisions. Voyageur is expected to increase production capacity to 500,000 bpd to 550,000 bpd. Plans include the addition of a third upgrader, expansion to increase bitumen feedstock and the construction of related infrastructure. Construction of this multi-phased expansion project, including coke drum fabrication and site preparation, has begun (for details on capital spending in progress see page 11). Non-grandfathered oil sands capital will be eligible for the accelerated capital cost allowance as it is gradually phased out between 2011 and 2015 when the standard 25% declining balance rate applies.

Uncertainties and Sensitivities

The forward-looking information in the preceding “Oil Sands Crown Royalties” and “Oil Sands Cash Income Taxes” sections 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 events or circumstances.

Anticipated royalty and cash taxes are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each project. In addition, all aspects of the current Alberta oil sands Crown royalty regime (including royalty rates, the royalty base and the value of bitumen for royalty purposes), and income tax legislation (including taxation rates), are subject to alteration by the government.

In light of proposed legislative changes, other uncertainties, and the potential for unanticipated events, we strongly caution that it is impossible to accurately predict even a range of annualized royalty expense as a percentage of revenues or approximate cash tax, or the impact these royalties and cash taxes may have on our financial results. Differences may be material.

Natural Gas

Our natural gas business recorded net earnings of nil in the third quarter of 2007, compared with $12 million of net earnings during the third quarter of 2006. The decrease in net earnings was primarily the result of lower price realizations, higher depreciation, depletion and amortization costs, and higher lifting costs. These factors were partially offset by higher production volumes and lower exploration expense.

Cash flow from operations for the third quarter of 2007 was $47 million, compared to $68 million from the third quarter of 2006. The decrease is primarily due to the same factors affecting net earnings, excluding depreciation, depletion and amortization expenses.

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	009
2007 Third Quarter

Year-to-date net earnings were nil, compared to $112 million in the first nine months of 2006. The decrease in earnings is due mainly to a smaller income tax rate reduction in 2007 as well as lower price realizations and higher exploration, lifting, depreciation, depletion and amortization and transportation expenses.

Cash flow from operations for the first nine months of the year was $181 million, compared to $233 million reported in the same period in 2006. The year-to-date decrease in cash flow from operations was due to lower price realizations and higher transportation and lifting costs.

Natural gas and liquids production in the third quarter of 2007 was 211 million cubic feet equivalent (mmcfe) per day, compared to 208 mmcfe per day in the third quarter of 2006. Our 2007 production outlook targets an average of 215 to 220 mcfe per day for the year, offsetting Suncor’s projected purchases for internal consumption at our oil sands operations.

Realized natural gas prices in the third quarter of 2007 were $5.39 per thousand cubic feet (mcf), compared to $6.33 per mcf in the third quarter of 2006, reflecting the lower benchmark commodity price.

Part of the Alberta Royalty Review Panel’s report recommends changes to the current royalty regime for conventional oil and gas. Although the government has indicated plans to make changes to the Alberta Crown Royalty regime in response to this report, we do not have sufficient information to determine the impact of changes the government may implement. Future royalties and tax payable, as well as the determination of net conventional reserves, may be affected.

Refining and Marketing

Consistent with the company’s organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment – Refining & Marketing. Comparative figures have been reclassified to reflect the combination of the previously disclosed Energy Marketing & Refining - Canada (EM&R) and Refining & Marketing – U.S.A. (R&M) segments. There was no impact to previously reported net earnings as a result of the combination. The results of company-wide energy marketing and trading will continue to be included in this segment. The financial results relating to the sales of oil sands and natural gas production will continue to be reported in their respective business segments.

Our refining & marketing business recorded 2007 third quarter net earnings of $40 million, compared to net earnings of $85 million in the third quarter of 2006. Net earnings were lower due to reduced production capacity caused by the planned outage at our Sarnia, Ontario refinery which resulted in decreased production and increased product purchases to meet customer commitments. These negative impacts were partially offset by increased sales volumes at our Commerce City, Colorado refinery.

Energy marketing and trading activities, including physical trading activities, resulted in a net pretax gain of $1 million in the third quarter of 2007, compared to an $11 million pretax gain in the third quarter of 2006. See page 12 for further details on our energy marketing and trading activities.

Cash flow from operations was $83 million in the third quarter of 2007, compared to $162 million in the third quarter of 2006. This decrease reflects the impact of the same factors affecting net earnings.

During the third quarter of 2007, combined refinery crude oil utilization was 102%, compared to 95% in the third quarter of 2006. The higher utilization rate in the third quarter of 2007 was largely due to improved reliability

Inquiries John Rogers (403) 269-8670

010	Suncor Energy Inc.
	2007 Third Quarter

at our Commerce City refinery, partially offset by lower production at the Sarnia refinery due to the planned shutdown that began in September.

Net earnings for the first nine months of 2007 were $345 million, compared to $212 million during the first nine months of 2006. This increase, compared to the first nine months of 2006, reflects increased sales volumes and strong margins resulting from tight supply of refined products when operational issues lowered refinery utilizations.

Cash flow from operations for the first nine months of 2007 was $546 million, compared to $399 million in the first nine months of 2006. The increase in cash flows was primarily due to the same factors that affected net earnings.

Work continues on modifications to the Sarnia refinery that are expected to enable the facility to process up to 40,000 bpd of oil sands sour crude. A partial outage to tie-in new facilities, which began in early September, is expected to be completed in the fourth quarter of 2007.

Planned maintenance at portions of the Commerce City refinery is also underway, and is expected to conclude by the end of October . The refinery is expected to operate at reduced rates during the outage.

For an update on our significant growth projects currently in progress see page 11.

Corporate

During the first quarter of 2007, we began allocating stock-based compensation expense from the corporate segment to each of the reportable businesses. Comparative figures have been reclassified to reflect this change in presentation. There was no impact to consolidated net earnings as a result of the allocation.

Corporate recorded $81 million in net earnings in the third quarter of 2007, compared to net earnings of $3 million during the third quarter of 2006. Net earnings increased mainly due to the foreign exchange gains on our U.S dollar denominated long-term debt as a result of the continued strengthening of the Canadian dollar. After-tax unrealized foreign exchange gains on U.S. dollar denominated long-term debt were $108 million in the third quarter of 2007 compared to nil in the third quarter of 2006. The higher foreign exchange gains in 2007 were partially offset by an increase in stock-based compensation expense.

Cash used in operations was $21 million in the third quarter of 2007, compared to $1 million used in the third quarter of 2006. The increase in cash used in operations is primarily due to increased operating expenses.

Corporate had net earnings of $96 million in the first nine months of 2007, compared to a net loss of $100 million in the same period of 2006. Expenses decreased primarily due to the foreign exchange gains on our U.S dollar denominated long-term debt as a result of the continued strengthening of the Canadian dollar. Year-to-date 2007 after-tax unrealized foreign exchange gains on our U.S. dollar denominated debt were $199 million, compared to $43 million in 2006. Expenses were also higher in the comparative period of 2006 due to the impact of a large income tax revaluation on opening future income tax assets.

Cash used in operations was $98 million in the first nine months of 2007, compared to $90 million used in the first nine months of 2006. The increased use of cash in 2007 was due primarily to an increase in operating expenses partially offset by the absence of system implementation costs.

Breakdown of Net Corporate Earnings

Three months ended September 30 ($ millions)	2007	2006
Corporate earnings	81	3
Group eliminations	—	(13	)
Total	81	(10	)

Analysis of Financial Condition and Liquidity

Excluding cash and cash equivalents, short-term debt and future income taxes, Suncor had an operating working capital deficiency of $738 million at the end of the third quarter of 2007, compared to a surplus of $35 million at the end of the third quarter of 2006.

During the first nine months of 2007, net debt increased to approximately $2.8 billion from $1.8 billion at December 31, 2006. The increase in net debt levels was primarily a result of capital spending on our growth strategies.

In March, Suncor issued $600 million of 5.39% Medium Term Notes under an outstanding $2 billion debt shelf prospectus. In June, Suncor issued US$750 million of 6.50% Notes, and in September issued a further US$400 million of 6.50% Notes, both under an outstanding US$2 billion debt shelf prospectus. The proceeds of these issuances were used for general corporate purposes, including repayment of short-term borrowings, supporting Suncor’s ongoing capital spending program and for working capital requirements.

At September 30, 2007 our undrawn credit facilities were approximately $1.9 billion. Outstanding debt shelf prospectuses filed in 2007 in Canada and the U.S. enable

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	011
2007 Third Quarter

the company to issue, subject to Board of Directors authorization, up to $1.4 billion in debt in Canada and US$850 million in debt in the US. We believe we have the capital resources from our undrawn credit facilities, cash flow from operations, and access to debt capital markets to fund the remainder of our 2007 capital spending program and to meet our current working capital requirements. If additional capital is required, we believe adequate additional financing will continue to be available at market terms and rates. As reported in our 2006 Annual Report, we anticipate capital spending of approximately $5.3 billion for 2007.

Significant Capital Project Update

A summary of the progress on our significant projects under construction is provided below. All projects listed below have received Board of Directors approval.

			Spent 2007	Total spent
	Cost Estimate	(1)	Year-to-date	to date
Description	($ millions)		($ millions)	($ millions)	Status (1)
Oil Sands
Coker unit	$2 100		$445	$2 035	Project is on schedule
					and on budget.
Naphtha unit (2)	$650		$190	$275	Project is on schedule
					and on budget.
Steepbank extraction plant (3)	$880		$200	$265	Project is on schedule
					and on budget.
Firebag cogeneration and expansion	$400		$65	$380	Project is mechanically complete. (4)
Refining and Marketing
Diesel desulphurization and
oil sands integration	$960		$95	$895	Diesel desulphurization component
					complete. Oil sands integration
					component is scheduled for
					completion in Q4 2007. (5)

(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 -30%/+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. Cost estimates do not include commissioning and start-up expenses.

(2) The naphtha unit is expected to enhance the product mix of our oil sands production.

(3) The Steepbank extraction plant is intended to replace and enhance existing base plant extraction facilities.

(4) Cogeneration is operational, however commissioning of the units required to complete the expansion of bitumen production by about 35% has been delayed. See page 7 for discussion.

(5) See page 9 for discussion.

Key components of the multi-phased Voyageur growth strategy are still pending approval from regulators and Suncor’s Board of Directors. As a result, Suncor has not yet announced a firm capital cost estimate for its planned third upgrader and expansions to increase bitumen supply, which include the addition of future stages of the Firebag in-situ operation.

However, engineering for these projects is underway and advance construction is in progress. To date, approximately $900 million has been approved for preparatory work related to the third upgrader, including engineering, site preparation and fabrication of major vessels. Approximately $1.4 billion in capital spending has also been approved to date by the Board of Directors for future expansions at Firebag.

Approval to proceed with these projects will be considered by Suncor’s Board of Directors once final cost estimates are complete. Preliminary cost estimates, including those provided in Suncor’s Voyageur regulatory approval application, have a wide range of uncertainty and are under upward pressure.

Inquiries John Rogers (403) 269-8670

012	Suncor Energy Inc.
	2007 Third Quarter

Derivative Financial Instruments

Effective January 1, 2007, new accounting standards were implemented relating to financial instruments. For a more detailed discussion, see Change in Accounting Policies on page 13. These changes did not significantly impact earnings as a result of the adoption.

The company has hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar West Texas Intermediate (WTI) commodity price risk for 2007 and 2008. At September 30, 2007, costless collar crude oil hedges totaling 60,000 bpd of production were outstanding for the remainder of 2007 and 10,000 bpd for 2008. Prices for these barrels are fixed within a range from an average of US$51.64/bbl up to an average of US$101.06/bbl.

We intend to consider additional costless collars of up to approximately 30% of our annual planned crude oil production if strategic opportunities are available.

We had no hedging gains or losses from our crude oil hedges in the third quarter of 2007, and $2 million of hedging gains from our crude oil hedges in the first nine months of 2007. There were no crude oil hedging gains in the first nine months of 2006.

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. In addition to our strategic hedging program, we also use derivative instruments to hedge risks specific to individual transactions. Such amounts, which also represent the unrecognized and unrecorded gain (loss), on the contracts, were as follows at September 30:

Fair Value of Hedging Derivative Financial Instruments

($ millions)	2007	2006
Revenue hedge swaps and collars	—	14
Fixed to float interest rate swaps	6	13
Specific cash flow hedges of individual transactions	6	(3	)
Total	12	24

Energy Marketing and Trading Activities

The net pretax earnings (loss) for the three and nine months ended September 30, were as follows:

Net Pretax Earnings (Loss)

	Three months				Nine months
	ended September 30				ended September 30
($ millions)	2007		2006		2007		2006
Physical energy contracts trading activity	5		14		26		30
Financial energy contracts trading activity	(3	)	(2	)	(7	)	(3	)
General and administrative costs	(1	)	(1	)	(2	)	(2	)
Total	1		11		17		25

The fair value of unsettled (unrealized) financial energy trading assets and liabilities at September 30, 2007 and December 31, 2006 are as follows:

Fair Value of Unsettled (Unrealized) Financial

Energy Trading Assets and Liabilities

($ millions)	2007		2006
Energy trading assets	2		16
Energy trading liabilities	13		13
Net trading assets (liabilities)	(11	)	3

Greenhouse Gas Regulation and Risk

On March 8, 2007 the Alberta government introduced the Climate Change and Emissions Management Amendment Act, which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year. Suncor’s oil sands operations are subject to this legislation. The act calls for intensity reductions of 12% from an average 2003 to 2005 baseline, by July 1, 2007.

To comply with this new legislation, Suncor must, by the end of 2007, determine and file baseline emission data with regulators. In March 2008, compliance with the legislation will commence. Mitigation options available to Suncor include internal emission reductions, utilizing offset projects or contributing to a climate change emission management fund.

The actual costs to Suncor will be dependent on a variety of factors that are not yet certain, including baseline calculation, facilities definition and potential offset credits. However, Suncor is currently accruing $0.10/bbl which reflects our estimated cost of compliance.

The Ontario provincial, Colorado state and Canadian federal governments are also in various stages of developing greenhouse gas management legislation and regulation. At this time, no such legislation has been tabled in any of these jurisdictions and any potential impacts are unknown.

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	013
2007 Third Quarter

While there remains uncertainty around the outcome and impacts of climate change regulation, we continue to actively manage our emissions and to pursue opportunities such as carbon capture and sequestration and renewable energy development.

Control Environment

Based on their evaluation as of September 30, 2007, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13(a) – 15(e) and 15(d) – 15(e) under the United States Securities and Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, as of September 30, 2007, there were no changes in our internal control over financial reporting that occurred during the three month period ended September 30, 2007 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.

Change in Accounting Policies

On January 1, 2007 the company adopted CICA Handbook Section 3855 “Financial Instruments, Recognition and Measurement”, Section 1530 “Comprehensive Income” and Section 3865 “Hedging”. These sections establish the accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. The comparative interim consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

Transaction costs and the related cash flow impacts are included in the fair value assessments of each financial asset and financial liability instrument.

Generally, all derivatives, whether designated in hedging relationships or not, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk each period are recognized in the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income each period and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in the Consolidated Statements of Earnings immediately for both fair value and cash flow hedges.

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same Consolidated Statements of Earnings caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

In addition to containing the effective portions of the gains/losses on our cash flow hedges, the accumulated other comprehensive income account will also contain the cumulative foreign currency translation adjustment of our foreign operations.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments were recorded to the balance sheet:

Financial assets		$42 million
Financial liabilities		$29 million
Retained earnings		$5 million
Accumulated other comprehensive loss		$63 million

The comparative interim consolidated financial statements have not been restated, except for presentation of the foreign currency translation adjustment of $71 million.

Non-GAAP Financial Measures

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

Inquiries John Rogers (403) 269-8670

014	Suncor Energy Inc.
	2007 Third Quarter

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, 2007 interim basis, please refer to page 33.

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, 2007 unaudited interim consolidated financial statements.

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

			Three months ended September 30		Nine months ended September 30
			2007	2006	2007	2006
Cash flow from operations ($ millions)	A		1 027	1 153	2 701	3 787
Weighted-average number of shares outstanding (millions of shares)	B		461.5	459.4	460.8	458.9
Cash flow from operations ($ per share)	(A/B	)	2.23	2.51	5.86	8.25

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.

Oil Sands Operating Costs – Total Operations

		Three months ended September 30						Nine months ended September 30
		2007			2006			2007			2006
		$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel
Operating, selling and general expenses		515			509			1 783			1 502
Less: natural gas costs, inventory changes and stock-based compensation		(17	)		(31	)		(257	)		(227	)
Less: non-monetary transactions		(17	)		(25	)		(80	)		(104	)
Accretion of asset retirement obligations		10			7			30			21
Taxes other than income taxes		15			9			39			28
Cash costs		506		23.00	469		21.00	1 515		24.15	1 220		17.30
Natural gas		46		2.10	58		2.60	223		3.55	202		2.85
Imported bitumen (net of other reported product purchases)		—		—	3		0.10	3		0.05	6		0.10
Total cash operating costs	A	552		25.10	530		23.70	1 741		27.75	1 428		20.25
Project start-up costs	B	24		1.10	8		0.35	47		0.75	32		0.45
Total cash operating costs after start-up costs	A+B	576		26.20	538		24.05	1 788		28.50	1 460		20.70
Depreciation, depletion and amortization		126		5.70	96		4.30	334		5.30	281		4.00
Total operating costs		702		31.90	634		28.35	2 122		33.80	1 741		24.70
Production (thousands of barrels per day)		239.1			242.8			229.8			258.1

For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc.	015
2007 Third Quarter

Oil Sands Operating Costs – In-situ Bitumen Production Only

	Three months ended September 30						Nine months ended September 30
	2007			2006			2007			2006
	$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel
Operating, selling and general expenses	67			44			204			128
Less: natural gas costs and inventory changes	(30	)		(26	)		(100	)		(71	)
Taxes other than income taxes	2			1			5			3
Cash costs	39		11.85	19		5.55	109		11.15	60		6.60
Natural gas	30		9.10	26		7.60	100		10.25	71		7.80
Cash operating costs	69		20.95	45		13.15	209		21.40	131		14.40
In-situ (Firebag) start-up costs	—		—	—		—	—		—	21		2.30
Total cash operating costs	69		20.95	45		13.15	209		21.40	152		16.70
Depreciation, depletion and amortization	22		6.70	19		5.55	58		5.95	48		5.30
Total operating costs	91		27.65	64		18.70	267		27.35	200		22.00
Production (thousands of barrels per day)	35.8			37.2			35.8			33.3

Legal notice – forward-looking information

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

All statements that address expectations or projections about the future, including statements about Suncor’s strategy for growth, expected and future expenditures, commodity prices, costs, schedules, production volumes, operating and financial results and expected impact of future commitments, are forward-looking statements. Some of the forward-looking statements may be identified by words like “expects,” “anticipates,” “estimates,” “plans,” “scheduled,” “intends,” “believes,” “projects,” “indicates,” “could,” “focus,” “goal,” “proposed,” “target,” “objective,” “may,” “outlook,” “on our way,’ “looking forward,” “investigating,” “continue,” ‘strategy,” and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; commodity prices and currency exchange rates; Suncor’s ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example the Firebag in-situ development and Voyageur) and regulatory projects; the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other resource development; future environmental laws; the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; 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 (for example, the Government of Alberta’s current review of the Crown Royalty regime, the Government of Canada’s current review of greenhouse gas emission regulations and the issuance of the September 21, 2007 Alberta Environment order and the September 24, 2007 EUB directive); 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 blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor.

The foregoing important factors are not exhaustive. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian securities commissions at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

Inquiries John Rogers (403) 269-8670