MANAGEMENT’S DISCUSSION AND ANALYSIS

October 25, 2006

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, 2006 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 17 to 58 of our 2005 Annual Report and to our Annual Information Form, dated March 1, 2006. All financial information is reported in Canadian dollars and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in “Non-GAAP Financial Measures” on page 56 of our 2005 Annual Report, and page 14 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 otherwise requires. Any reference to “year-to-date” or “YTD” means the nine month period ended September 30.

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 Annual Information Form filed with the SEC under cover of Form 40-F, is available on-line at www.sedar.com, www.sec.gov and our website, www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A. All such references are inactive textual references only.

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 the “Significant Capital Project Update” on page 12.

SELECTED FINANCIAL INFORMATION

Industry Indicators	3 months ended September 30		9 months ended September 30
(average for the period)	2006	2005	2006	2005
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	70.50	63.20	68.20	55.40
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	79.40	76.40	75.60	68.30
Light/heavy crude oil differential US$/barrel
WTI at Cushing less Lloyd Blend at Hardisty	17.25	19.20	21.40	19.90
Natural Gas US$/mcf at Henry Hub	6.55	8.25	7.45	7.10
Natural Gas (Alberta spot) Cdn$/mcf at AECO	6.05	8.15	7.20	7.40
New York Harbour 3-2-1 crack (1) US$/barrel	10.20	14.45	10.65	9.60
Exchange rate: Cdn$:US$	0.89	0.84	0.89	0.82

(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 the New York Harbour distillate margin and dividing by three.

Outstanding Share Data (as at September 30, 2006)

Common shares		459 595 964
Common share options – total		19 783 179
Common share options – exercisable (1)		8 934 086

(1) Options which have vested and are available for exercise.

Summary of Quarterly Results

	2006 quarter ended			2005 quarter ended				2004 quarter ended
($ millions, except per share data)	Sept. 30	Jun. 30	Mar. 31	Dec. 31	Sept. 30	Jun. 30	Mar. 31	Dec. 31
Revenues	4 114	4 070	3 858	3 521	3 149	2 385	2 074	2 333
Net earnings	682	1 218	713	693	315	83	67	326
Net earnings attributable to common shareholders per share
Basic	1.48	2.65	1.56	1.52	0.69	0.18	0.15	0.72
Diluted	1.45	2.59	1.52	1.48	0.67	0.18	0.14	0.71

ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the third quarter of 2006 were $682 million, compared to $315 million for the third quarter of 2005. The increase in net earnings was primarily due to:

· an increase in Oil Sands crude oil production following recovery work to repair portions of the plant damaged in a January 2005 fire and the subsequent expansion of synthetic crude oil production capacity to 260,000 barrels per day (bpd) in October 2005. While production in the third quarter of 2006 was higher than the third quarter of 2005, it was below capacity due to unplanned maintenance.

· an increase in the average price realization for Oil Sands crude oil to $71.99 per barrel in the third quarter of 2006 from $56.01 per barrel during the third quarter of 2005.

· higher refining margins in our U.S. downstream operations.

· a reduction in stock-based compensation expense, primarily reflecting the decline in our share price.

These positive net earnings impacts were partially offset by higher insurance premiums assessed during the third quarter of 2006 (see page 6), lower earnings in our Natural Gas business due primarily to lower price realizations, and the absence of fire insurance receipts during the third quarter of 2006 (compared to $105 million after-tax insurance proceeds received during the third quarter of 2005).

Cash flow from operations in the third quarter of 2006 was $1,153 million, compared to $651 million in the same period of 2005. Cash flow from operations was higher due primarily to the same factors that impacted net earnings.

Net earnings for the first nine months of 2006 were $2,613 million compared to $465 million in the same period of 2005. In addition to the factors listed above, the increase in net earnings was also due to reductions in the federal and Alberta income tax rates during the second quarter of 2006.

Cash flow from operations for the first nine months of 2006 was $3,787 million, compared to $1,250 million in the first nine months of 2005. Excluding the impact of the income tax rate reductions, the increase was primarily due to the same factors that impacted net earnings for the first nine months of 2006.

Excluding the revaluation impact of the federal and Alberta tax rate reductions on opening future taxes, our effective tax rate for the first nine months of 2006 was 33%, compared to 39% in the first nine months of 2005. The year-to-date effective tax rate is consistent with our full year expectations. The higher effective tax rate in 2005 was due to 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 was a capital tax insensitive to earnings), had a greater impact on the overall effective tax rate.

Bridge Analysis of Net Earnings ($ millions)

Bridge Analysis of Net Cash Flow ($ millions)

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 (Q3)		9 months ended September 30
($ millions, after tax)	2006	2005	2006		2005
Net earnings before the following items	682	157	1 959		235
Firebag Stage 2 start-up costs	—	—	(13	)	—
Oil Sands fire accrued insurance proceeds (1)	—	105	205		195
Impact of income tax rate reductions on opening future income tax liabilities (2)	—	—	419		—
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	—	53	43		35
Net earnings as reported	682	315	2 613		465

(1) Accrued business interruption proceeds net of income taxes and Alberta Crown Royalties. For discussion see page 8.

(2) Impacts of the Federal and Alberta income tax rate changes enacted in the second quarter of 2006.

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2006 third quarter net earnings of $583 million, compared with $225 million in the third quarter of 2005. Net earnings were higher primarily as a result of:

· the increase in production and sales volumes following completion in September 2005 of recovery work to repair portions of the facilities damaged in a January 2005 fire and the subsequent expansion of crude oil production capacity to 260,000 bpd in October 2005.

· an increase in the average price realization for Oil Sands crude products. The price increase reflects an 11.5% increase in average benchmark WTI crude oil prices, and the absence of crude oil hedging losses in the third quarter of 2006 (see “Derivative Financial Instruments” on page 12), compared to a $102 million after-tax loss in the third quarter of 2005.

These positive impacts were partially offset by operational issues and unplanned maintenance during the third quarter of 2006 that resulted in production volumes below plant capacity, and a decrease of higher value diesel fuel and sweet crude products in our sales mix. In addition, the 6% strengthening of the Canadian dollar compared to the U.S. dollar reduced net earnings. Because our crude oil is sold based on U.S. dollar benchmark prices, the stronger Canadian dollar reduces the realized value of Suncor’s products.

Purchases of crude oil and products were $71 million in the third quarter of 2006 compared to $8 million in the third quarter of 2005. The increase was due to the purchase of additional finished products to meet plant and customer demands during unplanned maintenance that occurred during the third quarter of 2006.

Operating expenses before tax were $510 million in the third quarter of 2006 compared to $353 million in the third quarter of 2005. The increase in operating costs was primarily due to the following factors:

· higher total production levels.

· higher contract mining costs in order to manage the impact of the worldwide heavy vehicle tire shortage.

· higher costs associated with unplanned maintenance.

· a change in accounting policy for non-monetary transactions (see page 13) whereby certain natural gas costs and offsetting revenues of $25 million were recorded in the third quarter of 2006.

· higher insurance premium expense in Oil Sands resulting from:

i) additional premium expenses related to losses incurred by one of our business interruption insurers as a result of claims stemming from losses in the Gulf of Mexico during the summer of 2005 (see page 11)

ii) insurance premiums paid to a newly formed self-insurance entity, all of which are fully offset in the corporate segment, and do not impact consolidated results (see page 11)

Transportation and other costs were $41 million in the third quarter of 2006 compared to $23 million in the third quarter of 2005. The increase in transportation costs was due primarily to increased volumes shipped out of the Fort McMurray area.

Depreciation, depletion and amortization expense was $96 million in the third quarter of 2006 compared to $83 million during the same period in 2005. The increase was due primarily to the inclusion of newly commissioned upgrading facilities and Firebag Stage 2 operations in our depreciable cost base during the fourth quarter of 2005 and first quarter of 2006, respectively.

Alberta Crown royalty expense was $119 million in the third quarter of 2006 compared to $136 million in the third quarter of 2005. The decrease was due mainly to the year-to-date adjustment of estimated royalty expense as a result of the lower forward curve for crude commodity prices for the balance of the year, partially offset by the net impact of higher sales volumes. See page 8 for a discussion of Alberta Oil Sands Crown royalties.

Cash flow from operations was $926 million in the third quarter of 2006, compared to $441 million in the third quarter of 2005. Excluding the impact of depreciation, depletion and amortization, the decrease was primarily due to the same factors that impacted net earnings.

Net earnings for the nine months ended September 30, 2006 were $2,412 million, compared to $393 million for the nine months ended September 30, 2005. This increase is due to the same factors that impacted the third quarter 2006 net earnings, as well as federal and Alberta income tax rate reductions enacted in the second quarter of 2006 that resulted in a $419 million increase to net earnings.

Cash flow from operations for the first nine months of 2006 was $3,234 million compared to $899 million in the first nine months of 2005. The increase was primarily due to the same factors that impacted net earnings, excluding the impact of depreciation, depletion and amortization, and the revaluation of future tax balances resulting from the reduction of federal and Alberta income tax rates.

Oil Sands production during the third quarter of 2006 averaged 242,800 barrels per day (bpd), consisting of 236,200 bpd of synthetic crude oil and 6,600 bpd of bitumen, which was sold directly to the market. Third quarter oil sands production was lower than full capacity due to unplanned maintenance. Comparative production during the third quarter of 2005, which was reduced due to damage from a fire earlier in the year, averaged 148,200 bpd, including 23,000 bpd of bitumen.

Subsequent to the end of the quarter, in early October, additional maintenance was required. With the combined impact of these maintenance issues, Suncor has revised our annual oil sands production target for 2006. The original target of 260,000 bpd of synthetic crude oil has been revised to 255,000 to 260,000 bpd of synthetic crude oil.

Sales during the third quarter averaged 238,000 bpd, compared with 144,500 bpd during the third quarter of 2005. The proportion of higher value diesel fuel and sweet crude products decreased to 44% of the total sales in the third quarter of 2006, compared to 56% in the third quarter of 2005, due to operational limitations and unplanned maintenance. Sales prices averaged $71.99 per barrel during the third quarter of 2006 compared to $56.01 per barrel in the third quarter of 2005.

Effective January 1, 2006, cash operating costs per barrel, before commissioning and start-up costs, reflect a change in accounting policy to expense overburden costs as incurred (see page 13), as well as the inclusion of research and development costs. The change in accounting policy for overburden resulted in higher cash costs and lower non-cash costs. Therefore, recorded cash operating costs per barrel have increased, but total operating costs were not significantly impacted by this accounting change. Commencing in the first quarter of 2006, cash operating costs per barrel now reflect total Oil Sands operations including mining and in-situ production costs. In the past, operating costs per barrel for base (mining and upgrading) operations and in-situ operations were disclosed separately. All comparative balances have been retroactively restated for these changes in all 2006 Reports to Shareholders.

During the third quarter, cash operating costs averaged $23.70 per barrel, compared to $27.65 per barrel during

Bridge Analysis of Net Earnings ($ millions)

the third quarter of 2005. The decrease in cash operating costs per barrel is due to our cash operating expenses being applied to significantly more barrels of production. However, cash operating costs during the third quarter of 2006 were higher than our original full year outlook of $18.75 to $19.50, due mainly to increased insurance premiums and lower than capacity production volumes. As a result, we have revised our full year outlook for 2006 cash operating costs per barrel upward to $20.50 to $21.00. Refer to page 14 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

We have also revised our original target for the price realization on our Oil Sands crude sales basket outlook downward from Cdn$5.50 to Cdn$6.50 below WTI to Cdn$6.00 to Cdn$7.00 below WTI. The lower price realization reflects the impact of lower than expected market prices for sweet synthetic crude.

Oil Sands Fire Insurance Update

There were no additional insurance proceeds received during the third quarter of 2006. Final settlement of our business interruption policy was received in the second quarter of 2006 and only our property loss policy claim remains outstanding. Final settlement of this claim is anticipated early in 2007. To date we have received $148 million (US$125 million) in proceeds from our property loss insurers.

Oil Sands Growth Update

Suncor’s growth plans target oil sands production of 500,000 to 550,000 bpd in the 2010 to 2012 timeframe. The next major milestone in the company’s plans is an increase in oil sands production capacity to 350,000 bpd in 2008. The centrepiece of this expansion is the addition of a third pair of cokers to Upgrader 2. Engineering on this portion of the project is nearing completion and construction is approximately 65% complete. This project is on schedule and on budget.

Work under way also includes the expansion of Suncor’s in-situ operations, with construction targeted for completion in 2007. The project, which is expected to increase the bitumen production capacity of Firebag Stages 1 and 2, also includes the addition of cogeneration facilities. This project is also on schedule and on budget, with construction approximately 25% complete for the expansion project and approximately 80% complete for the cogeneration project. As Suncor continues to develop its in-situ operations, we expect to seek Board of Directors’ approval for Firebag Stage 3 in 2007.

In July 2006, a regulatory hearing was held on Suncor’s planned third upgrader and Steepbank Mine extension. A decision on the project application is expected before the end of the year. The company expects to advance project development plans and cost estimates to a level appropriate to seek Board of Directors’ approval in 2007. Pending regulatory and Board approval, Suncor plans to begin construction of both projects in 2007.

For an update on our significant growth projects currently in progress see page 12.

Oil Sands Crown Royalties and Cash Income Taxes

For a description of the Alberta Crown royalty regimes in effect for Suncor Oil Sands operations, see page 27 of our 2005 Annual Report.

In the third quarter of 2006 we recorded a pretax royalty estimate of $119 million ($81 million after tax) compared to $136 million ($88 million after tax) for the third quarter of 2005. We estimate 2006 annualized Crown Royalties to be approximately $880 million ($600 million after tax), compared to $406 million ($259 million after tax) paid in 2005. The 2006 estimate is based on:

· nine months of actual results including the final $385 million in business interruption insurance proceeds

· the balance of the year estimate on 2006 forward average crude oil pricing of US$64.36 as at September 30, 2006

· current production, capital and operating cost estimates for the remainder of 2006

· a Canadian/US foreign exchange rate of $0.89, and

· no further receipts of property loss insurance proceeds other than those recorded to date.

Because our 2006 annualized Crown royalties estimates are based on these and other assumptions, our actual royalties may be materially different. Our Alberta Crown royalties payable in 2006 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, timing of the receipt of property damage insurance proceeds, foreign exchange rates, the valuation of bitumen, and total capital and operating costs for each project.

The following table sets forth our estimates of royalties expense in the years 2006 through 2012, and certain assumptions on which we have based our estimates.

ANTICIPATED ROYALTY EXPENSE BASED ON CERTAIN ASSUMPTIONS (For the period from 2006 – 2012)
WTI Price/bbl (US$)	40	50	60
Natural gas price per mcf at Henry Hub (US$)	6.75	8.25	10.00
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast (US$)	9.60	12.60	15.10
Cdn$/US$ exchange rate	0.80	0.85	0.90
Crown Royalty Expense (based on percentage of total Oil Sands revenue) (%)
2006 – 08	8 – 10	10 – 12	12 – 14
2009 – 12 (1)	5 – 7	6 – 8	6 – 8

(1) Assuming we exercise our option to transition our base operations in 2009 to the generic bitumen-based royalty regime.

For 2007, we estimate we will have partial cash taxes in the range of 70-100% of expected effective tax rates, based on current prices, current forecasts of production, capital and operating costs for the remainder of 2006 and 2007 and no further receipts of property loss insurance proceeds other than those recorded to date. Any cash tax in 2007 would be due in February 2008. We do not expect any significant cash tax in subsequent years until some time in the next decade. In any particular year, our Oil Sands and Natural Gas operations may be subject to some 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.

The forward-looking information in the preceding paragraphs and table 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 events or circumstances.

As with the estimate of 2006 Oil Sands royalties, 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 oil sands project in the case of Alberta Crown royalties). In addition, all aspects of the current Alberta oil sands royalty regime, including royalty rates and the royalty base, including the value of bitumen, and the income tax legislation, including taxation rates, are subject to alteration and interpretation by the government. In light of these uncertainties and the potential for unanticipated events to occur, 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. Actual differences may be material.

Natural Gas

Natural Gas recorded 2006 third quarter net earnings of $12 million, compared with $24 million during the third quarter of 2005. The decrease in net earnings was primarily as a result of lower price realizations partially offset by lower dry hole costs and lower royalties. Realized natural gas prices in the third quarter of 2006 were $6.33 per thousand cubic feet (mcf) compared to $8.32 per mcf in the third quarter of 2005, reflecting lower benchmark commodity prices.

Cash flow from operations for the third quarter of 2006 was $68 million compared to $104 million from the third quarter of 2005. The decrease is due to the same factors affecting net earnings, excluding dry hole costs and depreciation, depletion and amortization expenses.

Year-to-date net earnings were $114 million, compared to $77 million in the first nine months of 2005. The increase in year-to-date earnings resulted primarily from the reduction in the federal and Alberta income tax rates enacted in the second quarter of 2006. Excluding the tax adjustment, net earnings were $61 million for the first nine months of 2006 compared to $77 million for the same period in 2005. The decrease in 2006 compared to 2005 resulted from higher seismic expenses and dry hole costs, higher operating costs and higher depreciation, depletion and amortization costs. Realized natural gas prices and production volumes year-to-date were in line with those in 2005.

Bridge Analysis of Net Earnings ($ millions)

Cash flow from operations for the first nine months of 2006 was $233 million, compared to $268 million for the first nine months of 2005, reflecting the same factors that affected net earnings excluding dry hole costs and depreciation, depletion and amortization expenses and the revaluation of future tax balances resulting from the reduction of federal and Alberta income tax rates.

Natural gas production in the third quarter of 2006 was 191 million cubic feet (mmcf) per day, compared to 200 mmcf per day in the third quarter of 2005. Our 2006 production outlook targets have been adjusted to an average of 195 to 200 mmcf per day for the year, from the originally disclosed estimates of 205 to 210 mmcf per day, due to shut-in production as a result of pipeline and processing facility constraints.

Energy Marketing & Refining – Canada (EM&R)

EM&R recorded 2006 third quarter net earnings of $17 million, unchanged from the third quarter of 2005. Higher physical trading profits were offset by lower refining margins and lower refinery utilization as a result of a major planned maintenance shutdown beginning in September 2006. Higher depreciation, depletion and amortization costs associated with the completion of capital projects, was fully offset by a reduction in operating costs during the third quarter of 2006. During the third quarter of 2006, refinery utilization was 85%, compared to 96% in the third quarter of 2005. The lower utilization rate was due to planned maintenance in September of 2006.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $8 million in the third quarter of 2006, compared to $2 million in the third quarter of 2005.

Cash flow from operations was $51 million in the third quarter of 2006, compared to $44 million in the third quarter of 2005. This increase reflects the impact of the same factors affecting net earnings excluding depreciation, depletion and amortization costs.

EM&R recorded net earnings of $98 million for the first nine months of 2006 compared to $19 million during the first nine months of 2005. The increase reflects strong refining margins, the one-time federal income tax rate reduction enacted in the second quarter of 2006, and the favourable judgment to Suncor of an outstanding vendor legal action in the second quarter of 2006. The decision is currently under appeal.

Cash flow from operations for the first nine months of 2006 was $204 million, compared to $92 million in the first nine months of 2005. The increase was primarily due to the same factors that affected net earnings, excluding the revaluation of deferred tax balances resulting from the reduction of federal income tax rates.

The first phase of our diesel desulphurization and oil sands integration project began commissioning in June 2006 and was completed in July 2006. As planned, phase two of the project will continue into 2007. However, labour shortages and material supply issues have put upward cost pressures on the overall project. As a result, the cost estimate for both phases of the project will likely increase.

As of September 2006 a major maintenance shutdown was under way and is expected to affect our fourth quarter 2006 earnings. A significant portion of the shutdown work is directly related to phase two of our diesel desulphurization and oil sands integration project, and is impacted by the same labour and material supply pressures as noted above.

Our new ethanol facility began production on July 1, 2006. The facility, the largest of its kind in Canada, is expected to produce approximately 200 million litres of ethanol annually. The ethanol produced will be used for blending purposes in specific types of our gasoline products. The facility was completed on time and below budget, and is currently operating at design specifications.

For an update on our significant growth projects currently in progress see page 12.

Bridge Analysis of Net Earnings ($ millions)

Refining & Marketing – U.S.A. (R&M)

R&M recorded net earnings of $70 million in the third quarter of 2006 compared to net earnings of $50 million during the third quarter of 2005. The increase in net earnings for 2006 was primarily due to stronger refining margins. The increase was partially offset by lower retail margins and increased depreciation, depletion and amortization costs after the completion of our

Bridge Analysis of Net Earnings ($ millions)

maintenance shutdown in the second quarter of 2006, and our diesel desulphurization and oil sands integration project. During the third quarter of 2006 refinery utilization was 104%, consistent with the third quarter of 2005.

Cash flow from operations for the third quarter of 2006 was $118 million compared to $82 million in the third quarter of 2005. The increase was due to the same factors that increased net earnings, excluding depreciation, depletion and amortization.

R&M recorded net earnings of $125 million for the first nine months of 2006, compared to $87 million for the first nine months of 2005. The increase in net earnings was due to higher refining margins, a stronger sales mix of higher value diesel fuel, and the increased production volumes resulting from the acquisition of our second Commerce City refinery on May 31, 2005.

Cash flow from operations was $214 million for the nine months ended September 30, 2006, compared to $152 million during the same period in 2005. The increase in cash flow from operations was due to the same factors that increased net earnings.

With the completion of the diesel desulphurization and oil sands integration project during the second quarter of 2006, R&M is now expected to be capable of processing up to 15,000 bpd of sour synthetic crude oil from Suncor’s oil sands operations.

Corporate

Corporate recorded net expenses in the third quarter of 2006 of $Nil, compared to net expenses of $1 million during the third quarter of 2005. After-tax unrealized foreign exchange on U.S. dollar denominated long-term debt was $Nil in the third quarter of 2006 compared to a $53 million gain in the third quarter of 2005.

The following corporate expenses for the nine month period ending September 2006, were higher than during the same period in 2005: financing expenses (no unrealized foreign exchange gains on U.S. dollar denominated long-term debt compared to a gain in 2005); depreciation, depletion and amortization for our new enterprise resource planning system implemented in January 2006; and eliminations of intersegment profits. These higher expenses were totally offset by a reduction in our stock-based compensation in the third quarter of 2006 compared to 2005 resulting from the decline in our share price, and insurance premium revenue earned by our wholly-owned self-insurance company. The self-insurance premium revenue is fully offset in the Oil Sands segment, and does not impact consolidated results (see page 6).

Cash used in operations was $10 million in the third quarter of 2006 compared to $20 million in the third quarter of 2005. Cash used in operations is lower primarily due to insurance related costs.

Corporate had net expenses of $136 million in the first nine months of 2006, compared to net expenses of $111 million in the same period of 2005. The increase in expenses, excluding unrealized foreign exchange, was primarily due to the same factors affecting net expenses during the third quarter of 2006 after the additional benefit of the revaluation of future tax balances resulting from the reduction of federal and Alberta income tax rates in the second quarter of 2006.

Cash flow used in operations was $98 million in the nine months ended September 30, 2006 compared to cash flow used in operations of $161 million in the nine months ended September 30, 2005. The decrease was due to the same factors that impacted third quarter 2006 cash flow from operations.

Analysis of Financial Condition and Liquidity

Excluding cash and cash equivalents, short-term debt and future income taxes, Suncor had an operating working capital surplus of $35 million at the end of the third quarter, compared to a deficiency of $223 million at the end of the third quarter of 2005.

During the first nine months of 2006, net debt decreased to approximately $1.8 billion from $2.9 billion at December 31, 2005. The decrease in debt levels was primarily a result of higher cash flow from operations and unrealized foreign exchange gains on U.S. dollar denominated long-term debt.

At September 30, 2006 our undrawn lines of credit were approximately $2.1 billion. We believe we have the capital resources from our undrawn lines of credit, cash flow from operations, and if necessary additional sources of financing to fund our 2006 capital spending program and to meet our current working capital requirements. If additional capital is required, we believe adequate additional financing is available at market terms and rates. As reported in our 2005 Annual Report, we anticipate capital spending of approximately $3.5 billion for 2006.

Effective May 15, 2006 one of our business interruption insurance providers discontinued operations. During the third quarter 2006, our Oil Sands business recorded additional premium expenses for losses incurred by this insurer for claims relating to activity in the Gulf of Mexico during the summer of 2005. We continue to evaluate options to replace this coverage and anticipate having resolution by early 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 final Board of Directors’ approval.

				Spent YTD			Total spent
(all amounts in $ millions)	Cost estimate (1)			in 2006			to date			Status (1)
Oil Sands
Coker unit (2)	$	2 100		$	485		$	1 425		Project is on schedule and on budget.
Firebag cogeneration and expansion	$	400		$	140		$	260		Project is on schedule and on budget.
EM&R
Diesel desulphurization and oil	$	800		$	230		$	705		Diesel desulphurization component
sands integration										complete. Oil sands integration
										component is under upward cost
										pressures. Project cost estimate is
										under review.(3)
R&M
Diesel desulphurization and oil	$	540		$	115		$	530		Project complete.(4)
sands integration	US$ (445		)	US$ (95		)	US$ (435		)

(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. The projects noted in the above table have cost estimates within this range of uncertainty. These ranges establish an expected high and low capital cost estimate for a project. When we say that a project is “on budget”, we mean that we still expect the final project capital cost to fall within the current range of uncertainty for the project. Even at this stage, the uncertainties in the estimating process and the impact of future events, can and will cause actual results to differ, in some cases materially, from our estimates.

(2) Excludes costs associated with bitumen feed

(3) See page 10 for discussion.

(4) In the first quarter of 2006, the project budget was increased to a final expected cost of US$445 million from then-current estimates of US$390 million.

The addition of a third upgrader has not yet been approved by regulators or by Suncor’s Board of Directors. Suncor has not yet announced firm capital cost estimates for this project as the cost estimate, together with the final configuration of the project, is still under development. However, preliminary figures including those in Suncor’s regulatory approval application are under upward pressure. Detailed engineering is not expected until 2007, at which time final approval to proceed with the project will be considered by Suncor’s Board of Directors. Subject to Board and regulatory approval, the project will be included in the above table at that time.

To date approximately $900 million has been approved for planning and scoping initiatives related to project design for the third upgrader.

Suncor’s Firebag Stage 3 project is expected to be submitted for final Board of Director’s approval in 2007. To date approximately $550 million has been approved for planning and scoping initiatives related to project design.

Derivative Financial Instruments

We have continued to enter into crude oil costless collar hedges during the third quarter of 2006. As at September 30, 2006, crude oil hedges totaling 50,000 bpd of production were outstanding for the remainder of 2006, 60,000 bpd for 2007, and 10,000 bpd for 2008. These costless collar hedges have a floor ranging between US$50 to US$60/bbl and a ceiling of approximately US$92/bbl in 2007 up to US$101/bbl in 2008.

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 crude oil hedging losses in the third quarter of 2006 compared to an after-tax loss of $102 million in the third quarter of 2005. This was primarily as a result of crude oil swaps placed in prior years which expired by December 31, 2005.

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:

($ millions)	2006		2005
Revenue hedge swaps and collars	14		(184	)
Margin hedge swaps	—		(17	)
Interest rate and cross-currency interest rate swaps	13		27
Specific cash flow hedges of individual transactions	(3	)	14
	24		(160	)

Energy Marketing and Trading Activities

For the third quarter ended September 30, 2006, we recorded a net pretax loss of $2 million compared to $3 million of net pretax earnings recorded during the third quarter of 2005, related to the settlement and revaluation of financial energy trading contracts.

In the third quarter, the settlement of physical trading activities resulted in net pretax earnings of $14 million compared to $1 million of net pretax earnings in the third quarter of 2005. These balances 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 earnings of $8 million for the quarter ended September 30, 2006, compared to earnings of $2 million for the third quarter of 2005.

The fair value of unsettled financial energy trading assets and liabilities at September 30, 2006 and December 31, 2005 were as follows:

($ millions)	2006	2005
Energy trading assets	24	82
Energy trading liabilities	17	70
Net trading assets	7	12

Control Environment

Based on their evaluation as of September 30, 2006, 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 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, 2006, there were no changes in our internal control over financial reporting that occurred during the three month period ended September 30, 2006 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.

Since the beginning of the 2006 fiscal year, our internal control over financial reporting has undergone significant changes and redesign as all our businesses have implemented our new ERP system, designed to support our growth plan. Implementing an ERP system on a widespread basis involves major changes in business processes and extensive organizational training. We believe our phased-in approach reduces the risks associated with making these changes. In addition, we are taking the steps we believe are necessary 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.

Change in Accounting Policies

(a) Overburden Removal Costs

On January 1, 2006, the company retroactively adopted EIC 160 “Stripping Costs Incurred in the Production Phase of a Mining Operation”. Under the new standard, overburden removal costs should be deferred and amortized only in instances where the activity benefits future periods, otherwise the costs should be charged to earnings in the period incurred. At Suncor, overburden removal precedes mining of the oil sands deposit within the normal operating cycle, and is related to current production. In accordance with the new standard, overburden removal costs are treated as variable production costs and expensed as incurred. Previously overburden removal was deferred and amortized on a life of mine approach.

(b) Non-monetary Transactions

On January 1, 2006, the company prospectively adopted CICA Handbook section 3831 “Non-monetary Transactions”. The standard requires all non-monetary transactions to be measured at fair value (if determinable) unless future cash flows are not expected to change significantly as a result of a transaction or the transaction is an exchange of a product held for sale in the ordinary course of business. The company was required to record the effects of an existing contract at Oil Sands that exchanges off-gas produced as a by-product of the upgrading operations

for natural gas. An equal amount of revenues for the sale of the off-gas, and purchases of crude oil and products for the purchase of the natural gas was recorded. The amount of the gross-up of revenues and purchases of crude oil and products in the third quarter of 2006 was $25 million. For the nine months ended September 30, 2006 the amount of total gross-up of revenues and purchases of crude oil and products was $104 million.

Non-GAAP Financial Measures

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

Suncor provides a detailed numerical reconciliation of ROCE on an annual basis in the company’s annual MD&A, which is to be read in conjunction with the company’s annual consolidated financial statements. For a summarized narrative reconciliation of ROCE calculated on a September 30, 2006 interim basis, please refer to page 30 of the third quarter 2006 Report to Shareholders.

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, 2006 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
		2006	2005	2006	2005
Cash flow from operations ($ millions)	A	1 153	651	3 787	1 250
Weighted average number of common shares outstanding (millions of shares)	B	459.4	457.0	458.9	456.0
Cash flow from operations (per share)	(A / B)	2.51	1.42	8.25	2.74

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 – TOTAL OPERATIONS

		Quarter ended September 30						Nine months ended September 30
		2006			2005 (1)			2006			2005 (1)
		$millions		$/barrel	$millions		$/barrel	$millions		$/barrel	$millions		$/barrel
Operating, selling and general expenses		510			353			1 474			966
Less: natural gas costs and inventory changes		(32	)		(73	)		(199	)		(178	)
Less: non-monetary transactions		(25	)		—			(104	)
Accretion of asset retirement obligations		7			7			21			18
Taxes other than income taxes		9			8			28			22
Cash costs		469		21.00	295		21.65	1 220		17.30	828		21.85
Natural gas		58		2.60	82		6.00	202		2.85	192		5.05
Imported bitumen (net of other reported product purchases)		3		0.10	—		—	6		0.10	1		0.05
Total cash operating costs	A	530		23.70	377		27.65	1 428		20.25	1 021		26.95
In-situ (Firebag) start-up costs	B	—		—	—		—	21		0.30	—		—
Total cash operating costs after start-up costs	A+B	530		23.70	377		27.65	1 449		20.55	1 021		26.95
Depreciation, depletion and amortization		96		4.30	83		6.10	281		4.00	241		6.35
Total operating costs		626		28.00	460		33.75	1 730		24.55	1 262		33.30
Production (thousands of barrels per day)		242.8			148.2			258.1			138.8

OIL SANDS OPERATING COSTS – IN-SITU BITUMEN PRODUCTION

		Quarter ended September 30						Nine months ended September 30
		2006			2005 (1)			2006			2005 (1)
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		44			44			128			106
Less: natural gas costs and inventory changes		(26	)		(28	)		(71	)		(58	)
Taxes other than income taxes		1			—			3			—
Cash costs		19		5.55	16		7.55	60		6.60	48		10.45
Natural gas		26		7.60	28		13.25	71		7.80	58		12.65
Cash operating costs	A	45		13.15	44		20.80	131		14.40	106		23.10
In-situ (Firebag) start-up costs	B	—		—	—		—	21		2.30	—		—
Total cash operating costs after start-up costs	A+B	45		13.15	44		20.80	152		16.70	106		23.10
Depreciation, depletion and amortization		19		5.55	9		4.25	48		5.30	23		5.00
Total operating costs		64		18.70	53		25.05	200		22.00	129		28.10
Production (thousands of barrels per day)		37.2			23.0			33.3			16.8

(1) Firebag start-up costs have not previously been separately identified in past quarterly Reports to Shareholders. We have segregated these costs for comparable information purposes to provide additional detail to the individual components of cash costs.

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,” “vision,” “goal,” “will likely,” “may,” “pending,” “proposed,” “target,” “objective,” and similar expressions. These statements are not guarantees of future performance and involve a number of risks and uncertainties, some that are similar to other oil and gas companies and some that are unique to Suncor. Suncor’s actual results may differ materially from those expressed or implied by its forward-looking statements and readers are cautioned not to place undue reliance on them.

The risks, uncertainties and other factors that could influence actual results include but are not limited to changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; commodity prices and currency exchange rates; Suncor’s ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example the Firebag in-situ development and Voyageur) and regulatory projects (for example, the clean fuels refinery modifications projects in 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 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; 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 fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor.

The foregoing important factors are not exhaustive. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian securities commissions 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.