Exhibit 99.2

MANAGEMENT’S DISCUSSION AND ANALYSIS

August 1, 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 June 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 2005 Annual Information Form. All financial information is reported in Canadian dollars and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in “Non-GAAP Financial Measures” on page 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.

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 (AIF) filed with the SEC under cover of Form 40-F, is available on-line at www.sedar.com and 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 many cases, are still in the early stages of development. These costs are preliminary 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 June 30 (Q2)		6 months ended June 30
($ average for the period)	2006	2005	2006	2005
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	70.70	53.15	67.10	51.50
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	78.30	66.45	73.70	64.20
Light/heavy crude oil differential US$/barrel WTI at Cushing less Lloyd Blend at Hardisty	17.90	21.30	23.45	20.30
Natural Gas US$/mcf at Henry Hub	6.80	6.80	7.90	6.55
Natural Gas (Alberta spot) Cdn$/mcf at AECO	6.25	7.35	7.75	7.05
New York Harbour 3-2-1 crack (1) US$/barrel	14.65	8.40	10.90	7.20
Exchange rate: Cdn$:US$	0.90	0.80	0.88	0.81

(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 June 30, 2006)

Common shares		459 195 688
Common share options — total		19 610 092
Common share options — exercisable (1)		9 255 119

(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)	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30
Revenues	4 070	3 858	3 521	3 149	2 385	2 074	2 333	2 332
Net earnings	1 218	713	693	315	83	67	326	338
Net earnings attributable to common shareholders per share
Basic	2.65	1.56	1.52	0.69	0.18	0.15	0.72	0.75
Diluted	2.59	1.52	1.48	0.67	0.18	0.14	0.71	0.73

ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the second quarter of 2006 were $1,218 million, compared to $83 million for the second quarter of 2005. The increase in net earnings was primarily due to:

· an increase in Oil Sands crude oil production following completion of 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

· an increase in the average price realization for Oil Sands crude oil to $75.34 per barrel in the second quarter of 2006 from $45.98 per barrel during the second quarter of 2005

· the substantive enactment of both federal and Alberta provincial income tax rate reductions. These reductions had the following impacts on second quarter 2006 net earnings:

i) 3.1% reduction in the federal income tax rate resulted in a $292 million reduction in federal income taxes due to the revaluation of opening deferred income tax liabilities

ii) 1.5% reduction in the Alberta provincial income tax rate resulted in a $127 million reduction in Alberta provincial income taxes due to the revaluation of opening deferred income tax liabilities

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

These positive net earnings impacts were partially offset by higher Oil Sands operating costs due primarily to increased production volume, higher royalty expense and higher dry hole costs in our Natural Gas business.

Cash flow from operations in the second quarter of 2006 was $1,320 million, compared to $305 million in the same period of 2005. Excluding the impact of the reduced income tax rates, the same factors impacting net earnings contributed to higher cash flow from operations.

Net earnings for the first half of 2006 were $1,931 million compared to $150 million in the same period of 2005. Cash flow from operations for the first six months of 2006 was $2,634 million, compared to $599 million in the first half of 2005. The increases in both net earnings and cash flow from operations during the first half of 2006 were primarily due to the same factors listed above.

Excluding the impact of the federal and Alberta provincial income tax and large corporation tax rate reductions, our effective tax rate for the first half of 2006 was 34%, compared to 45% in the first half of 2005. This effective tax rate in the first half of 2006 is consistent with our expectations for 2006. The higher effective tax rate in the first half of 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 is a capital tax insensitive to earnings), had a greater impact on the overall effective tax rate.

IMPACT OF TAX RATE CHANGES ON SECOND QUARTER 2006 SEGMENTED EARNINGS

A summary of the impacts on the tax rate changes on Q2 2006 earnings follows.

Tax Rate Changes

($ millions) increase (decrease) in earnings	Oil Sands	Natural Gas	Energy Marketing & Refining — Canada	Corporate		Total
Federal	290	36	5	(39	)	292
Alberta provincial	139	17	—	(29	)	127
	429	53	5	(68	)	419

NET EARNINGS COMPONENTS

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

	3 months ended June 30 (Q2)			6 months ended June 30
($ millions, after tax)	2006	2005		2006		2005
Net earnings before the following items	755	38		1 277		78
Firebag Stage 2 start-up costs	—	—		(13	)	—
Oil Sands fire accrued insurance proceeds (1)	—	58		205		90
Impact of income tax rate reductions on opening future income tax liabilities	419	—		419		—
Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	44	(13	)	43		(18	)
Net earnings as reported	1 218	83		1 931		150

(1) Accrued business interruption proceeds of $385 million (US$330 million) net of income taxes and Alberta Crown royalties. For discussion see page 8.

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2006 second quarter net earnings of $1,109 million, compared with $85 million in the second quarter of 2005. Net earnings were higher primarily as a result of:

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

· an increase in the average realization of Oil Sands crude products. The price increase reflects a 33% increase in average benchmark WTI crude oil prices, the absence of crude oil hedging losses in the second quarter of 2006 (see “Derivative Financial Instruments” on page 12) and a larger portion of high value products in our 2006 sales mix, due to an unplanned hydrotreater outage that negatively impacted our sales mix in 2005.

These positive impacts were partially offset by the 13% strengthening of the Canadian dollar compared to the U.S. dollar (because crude oil is sold based on U.S. dollar benchmark prices, the stronger Canadian dollar reduces the realized value of Suncor’s products).

Operating expenses before tax were $456 million in the second quarter of 2006 compared to $292 million in the second quarter of 2005. The increase in operating costs was primarily due to the following factors:

· higher total production levels

· higher contract mining costs due to the impact of the worldwide tire shortage

· increased costs at our in-situ operations primarily due to higher production volumes related to Firebag Stage 2, which began commercial operations in March 2006

· higher energy and maintenance costs due to unplanned maintenance

· a change in accounting policy for non-monetary transactions (see page 13) whereby certain natural gas costs and

offsetting revenues of $31 million were recorded in the second quarter of 2006

· higher insurance premium expense in Oil Sands. The premiums are fully offset in the corporate segment and do not impact consolidated results as they were paid to a newly formed self-insurance entity (see page 11)

Transportation and other costs were $36 million in the second quarter of 2006 compared to $21 million in the second quarter of 2005. The increase in transportation costs was due primarily to increased shipped volumes out of the Fort McMurray area.

Depreciation, depletion and amortization expense was $92 million in the second quarter of 2006 compared to $79 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 $278 million in the second quarter of 2006 compared to $94 million in the second quarter of 2005. The increase was due to higher commodity prices and sales volumes, partially offset by higher operating costs and capital cost deductions. See page 8 “Oil Sands Crown Royalties and Cash Income Taxes”.

Reductions in the federal and Alberta provincial income tax rates and year-to-date effective rate adjustments resulted in a combined $448 million increase in net earnings in the second quarter of 2006, reducing Oil Sands deferred tax balances.

Cash flow from operations for the second quarter of 2006 was $1,099 million, compared to $210 million in the second quarter of 2005. Excluding the impact of depreciation, depletion and amortization, and the revaluation of deferred tax balances, the increase was primarily due to the same factors that impacted net earnings.

Net earnings for the first six months of 2006 were $1,829 million, compared to $168 million in the first six months of 2005.

Cash flow from operations for the first six months of 2006 increased to $2,308 million from $458 million in the first six months of 2005. The year-to-date increases in net earnings and cash flow from operations were due to the same factors that impacted net earnings and cash flow from operations as outlined above.

Oil Sands production during the second quarter of 2006 averaged approximately 267,300 bpd, including 258,800 bpd of synthetic crude oil and approximately 8,500 bpd of bitumen sold directly to the market. This compared to production of approximately 128,200 bpd in the second quarter of 2005, of which 9,600 bpd of bitumen were sold directly to the market. The increase in production volumes was due to the completion in 2005 of fire damage repairs to our upgrader and subsequent commissioning of a facility that increased production capacity. During 2006, Suncor expects most of its bitumen to be upgraded into crude oil. However, under certain market or operational conditions, Suncor-produced bitumen may be sold directly to the market.

Sales during the second quarter averaged 265,300 bpd, compared with 121,100 bpd during the second quarter of 2005. The proportion of higher value diesel fuel and sweet crude products increased to 59% of total sales in the second quarter of 2006 compared to 47% in the second quarter of 2005 due to the impact of the fire and the unplanned maintenance on our hydrotreater. Sales prices averaged $75.34 per barrel during the second quarter of 2006 compared to $45.98 per barrel in the second 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. 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 second quarter, cash operating costs averaged $18.30 per barrel, compared to $27.10 per barrel during the second 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. 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.

Oil Sands Fire Insurance Update

In the second quarter of 2006 the final installment of the business interruption (BI) claim settlement from the January 2005 fire was received. The installment was accrued as net insurance proceeds in the first quarter of 2006, and did not impact second quarter net earnings.

In addition to our BI policy coverage, our primary property loss policy of US$250 million has a deductible per incident of US$10 million. During the second quarter of 2006 we received $33 million (US$30 million) in additional proceeds from the property loss policy. These proceeds had been previously accrued during 2005. There was no impact on second quarter 2006 net earnings. To date, we have received $148 million (US$125 million) in proceeds from our property loss insurers. Final settlement of the claim is anticipated in early 2007.

Oil Sands Growth Update

Suncor’s next major growth phase targets an increase in oil sands production capacity to 350,000 bpd in 2008. The centrepiece of the expansion is the addition of a third pair of cokers to Upgrader 2. Engineering on this portion of the project is nearing completion and construction is approximately 45% complete. This project is on schedule and on budget.

Work under way also includes the expansion of Suncor’s Firebag 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 15% complete for the expansion project and approximately 55% complete for the cogeneration project.

In June 2006, Suncor acquired three new oil sands permits, located approximately five kilometres southwest of the company’s Fort McMurray oil sands operations. The three land permits are adjacent to mining leases previously acquired by Suncor.

In July 2006, a regulatory hearing was held on Suncor’s planned third upgrader and Steepbank Mine extension. During the hearing, Suncor and various stakeholders addressed the economic benefits and social and environmental challenges related to the project. The regulator is expected to deliver its written decision before the end of the year. Pending regulatory and Board of Directors approval, Suncor plans to begin construction in 2007.

The upgrader, mine and associated facilities are central to the company’s goal of increasing production to between 500,000 and 550,000 bpd in the 2010 to 2012 timeframe. Suncor has not yet announced capital cost estimates for the project as these costs, together with the final configuration of the project, are still under development. However, preliminary figures including those in Suncor’s Voyageur regulatory approval application, are under upward pressure. The company expects to advance project development plans and cost estimates to a level appropriate to seek Board of Directors’ approval 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 Note 10 to the interim financial statements or page 27 of our 2005 Annual Report.

In the second quarter of 2006 we recorded a pretax royalty estimate of $278 million ($184 million after tax) compared to $94 million ($57 million after tax) for the second quarter of 2005. We estimate 2006 annualized oil sand royalties to be approximately $1.0 billion ($675 million after tax), compared to $500 million ($305 million after tax) in 2005 based on six months of actual results including the final $385 million in business interruption insurance proceeds, basing the balance of the year estimate on 2006 forward crude oil pricing of US$75.21 as at June 30, 2006, current forecasts of production, capital and operating costs for the remainder of 2006, a Canadian/US foreign exchange rate of $0.90, and no further receipts of property loss insurance proceeds other than those recorded to date. Accordingly, actual royalties may be materially different. 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 and total capital and operating costs for each project. The following table sets forth our estimates of royalties in the years 2006 through 2012, and certain assumptions upon which we have based our estimates.

ANTICIPATED ROYALTY 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 that 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 the next decade. In any particular year, our Oil Sands and NG operations may be subject to some cash income tax due to the sensitivity to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for income tax purposes.

As with the estimate of the 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, and income tax legislation including taxation rates, are subject to alteration by governments. Accordingly, 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.

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 the company’s current budget and long-range plan, and is not an estimate, forecast or prediction of actual events or circumstances.

Natural Gas

Natural Gas recorded 2006 second quarter net earnings of $60 million, compared with $27 million during the second quarter of 2005. A reduction in the federal and Alberta provincial income tax rates and year-to-date effective rate adjustments resulted in a combined $61 million increase in second quarter 2006 earnings. Excluding these tax impacts, earnings in the second quarter of 2006 were lower than those in the same period in 2005 primarily as a result of an increase in dry hole costs and lower natural gas price realizations, partially offset by higher production volumes and hedging gains. Realized natural gas prices in the second quarter of 2006 were $6.38 per mcf compared to $7.29 per mcf in the second quarter of 2005, reflecting lower benchmark commodity prices.

Cash flow from operations for the second quarter of 2006 was $65 million compared with $81 million for the second quarter of 2005. Excluding the impact of lower income tax rates, the decrease was primarily due to the same factors that impacted net earnings.

For the first half of 2006, net earnings were $102 million, compared to $53 million in the first six months of 2005. This increase in earnings was due to the income tax adjustments noted above. Excluding the tax adjustments, year-to-date earnings were relatively unchanged with higher production volumes and higher price realizations being

offset by higher operating costs and higher exploration expenses including dry hole costs.

Cash flow from operations for the first six months of 2006 was $165 million, compared to $164 million reported in the same period in 2005.

Natural gas production in the second quarter of 2006 was 189 million cubic feet (mmcf) per day, compared to 175 mmcf per day in the second quarter of 2005. Our 2006 production outlook targets an average of 205 to 210 mmcf per day for the year, exceeding Suncor’s projected purchases for internal consumption.

ENERGY MARKETING & REFINING — CANADA (EM&R)

EM&R recorded 2006 second quarter net earnings of $63 million, compared to $5 million in the second quarter of 2005. The increase in net earnings was primarily due to strong refining margins and a favourable judgement of an outstanding vendor legal action in 2006. This judgement is currently under appeal. The increase in second quarter earnings was partially offset by lower retail volumes resulting from the competitive price environment in the Greater Toronto Area, and reduced refinery utilization resulting from operational issues to be addressed during the next scheduled maintenance shutdown planned for September 2006. As a result, during the second quarter of 2006, refinery utilization was 89%, compared to 100% in the second quarter of 2005. A reduction in the federal income tax rate and year-to-date effective rate adjustments resulted in a combined $10 million increase to second quarter 2006 earnings, reducing EM&R deferred and current tax balances.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $4 million in the second quarter of 2006, compared to $3 million in the second quarter of 2005.

Cash flow from operations increased to $102 million in the second quarter of 2006 from $26 million in the second quarter of 2005. Excluding the impact of lower income tax rates, the increase was primarily due to the same factors that affected net earnings.

EM&R recorded net earnings of $81 million for the first half of 2006 compared to $2 million during the first half of 2005. This increase reflects strong refining margins in a high price environment, despite the impact of lower plant utilization resulting from operational issues in the first half of 2006.

Cash flow from operations for the first six months of 2006 was $153 million, compared to $48 million in the first six months of 2005. Excluding the impact of lower income tax rates, the increase in cash flows was primarily due to the same factors that affected net earnings.

The first phase of our diesel desulphurization and oil sands integration project began commissioning in June 2006 (completed in July 2006), in line with our revised schedule. This component of the project will enable production of Ultra Low Sulphur Diesel to comply with regulatory requirements now in effect. The full project is anticipated to be on budget.

In addition, our new ethanol facility began commissioning and start-up in late June 2006 (completed in July 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 our gasoline products. The primary feedstock for the facility is corn.

For an update on our significant growth projects currently in progress, see page 12. There is a 60 day major maintenance shutdown scheduled for the third quarter of 2006 that we expect will impact our earnings.

Refining & Marketing — U.S.A. (R&M)

R&M recorded net earnings of $57 million in the second quarter of 2006 compared to earnings of $31 million during the second quarter of 2005. Net earnings in 2006 were positively impacted by higher refining margins following the completion of a planned maintenance shutdown in early April 2006 and increased production volumes resulting from the acquisition of our second Commerce City refinery on May 31, 2005. The increase was partially offset by higher finished product purchases during the shutdown. During the second quarter of 2006, refinery crude utilization was 102%, unchanged from the 102% refinery crude utilization recorded in the second quarter of 2005.

Cash flow from operations for the second quarter was $96 million compared to cash flow from operations of $52 million in the second quarter of 2005. Cash flow from operations was impacted by the same factors that increased net earnings during the quarter.

R&M recorded net earnings of $55 million in the first six months of 2006, compared to net earnings of $37 million in the same period in 2005. Cash flow from operations was $96 million for the six months ended June 30, 2006, compared to $70 million during the same period in 2005. The increases in net earnings and cash flow from operations were due to the same factors that impacted net earnings and cash flow from operations in the second quarter.

Our diesel desulphurization and oil sands integration project was operational in June 2006. The new facilities allow production of Ultra Low Sulphur Diesel fuel to comply with regulatory requirements now in effect. In addition to the modifications to meet clean fuels regulations, we anticipate the upgrade will improve the refinery’s environmental performance, and enables Suncor to integrate a broader slate of crude oil types, including up to 10,000 to 15,000 bpd of sour synthetic crude from the company’s Canadian oil sands production. 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 (revised from the original US$300 million). The project was completed on schedule and within the final cost estimate.

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

There are minor maintenance shutdowns scheduled for each of the two refineries in mid 2007 that we expect to impact earnings. The shutdowns are planned for approximately 12-16 days each.

Corporate

Corporate recorded net expenses in the second quarter of 2006 of $71 million, compared to net expenses of $65 million during the second quarter of 2005. After-tax unrealized foreign exchange on U.S. dollar denominated long-term debt was a $44 million gain in the second quarter of 2006 compared to a $13 million loss in the second quarter of 2005.

Net expenses were higher primarily as a result of higher depreciation, depletion and amortization expense related to the implementation of our new enterprise resource planning (ERP) system beginning January 2006, and a revaluation of federal and Alberta provincial income tax rates. Partially offsetting these factors was insurance premium revenue earned by our newly formed selfinsurance company. The self-insurance premium revenue is fully offset in the Oil Sands segment, and does not impact consolidated results (see page 6).

Cash flow used in operations in the second quarter of 2006 was $42 million, compared to $64 million used in the second quarter of 2005. The decreased use of cash was primarily due to insurance related costs.

Corporate had net expenses of $136 million in the first six months of 2006, compared to $110 million in the same period of 2005. The increase in expenses, excluding unrealized foreign exchange, was primarily due to the same factors that affected net earnings in the second quarter. After-tax unrealized foreign exchange on our U.S. dollar denominated debt was a $43 million gain for the first six months of 2006, compared to an $18 million loss for the same period in 2005.

Cash flow used in operations was $88 million in the first half of 2006 compared to $141 million in the first half of 2005. The decreased use of cash was due to the same factors impacting cash flow from operations for the second quarter of 2006.

Rate reductions in the federal and Alberta provincial income tax rates and year-to-date effective rate adjustments resulted in a combined $64 million increase in net expenses, decreasing Corporate deferred and current tax asset balances.

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 $111 million at the end of the second quarter, compared to a deficiency of $426 million at the end of the second quarter of 2005.

During the first half of 2006, net debt decreased to approximately $2.2 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 foreign exchange gains on U.S. dollar denominated debt.

During the second quarter of 2006, the following changes to our available credit facilities were completed:

· a $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five-year term maturing in June 2011. In addition, the credit limit was increased by $500 million to $2 billion total funds available

· a $200 million credit facility agreement was renegotiated and the credit limit was increased by $100 million to $300 million total funds available

· a $600 million credit facility agreement matured and was not renewed

At June 30, 2006 our undrawn lines of credit were approximately $1.8 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.

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.

(all amounts in $ millions)	Cost estimate (1)		Spent YTD in 2006		Total spent to date		Status (1)
Oil Sands
Coker unit (2)	$	2 100	$	315	$	1 245	Project is on schedule and on budget.
Firebag cogeneration and expansion	$	400	$	85	$	205	Project is on schedule and on budget.
EM&R
Diesel desulphurization and oil sands integration	$	800	$	175	$	650	Diesel desulphurization component commissioning underway (completed in July 2006). Oil sands integration component on schedule. Project is on budget. (3)
R&M
Diesel desulphurization and oil sands integration	$	540 (US$445)	$	115 (US$95)	$	530 (US$435)	Project commissioning underway (completed in July 2006). In line with revised cost estimate. (4)

(1) Estimating and budgeting for major capital projects is a process that involves uncertainties and that evolves in stages, each with progressively more refined data and a correspondingly narrower range of uncertainty. At very early stages, when broad engineering design specifications are developed, the level of uncertainty can result in price ranges with -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) See page 11 for discussion.

Suncor’s Voyageur project has not yet been approved by regulators nor by Suncor’s Board of Directors. Suncor has not yet announced capital cost estimates for its Voyageur project as the project cost estimates, together with the final configuration of the project, are still under development. However, preliminary figures including those in Suncor’s Voyageur 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 Voyageur project will be included in the above table at that time.

Derivative Financial Instruments

As at June 30, 2006, crude oil hedges totaling 50,000 bpd of production were outstanding for the remainder of 2006 and 2007. These costless collar hedges have a floor of US$50/bbl and an average ceiling of approximately US$92/bbl.

Effective May 15, 2006 one of our business interruption insurance providers discontinued operations. We continue to evaluate options to replace this coverage and anticipate having resolution by early 2007.

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

We had no crude oil hedging losses in the second quarter of 2006 compared to an after-tax loss of $84 million in the second quarter of 2005. This was primarily as a result of crude oil swaps in place in prior years, which expired at 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 June 30:

($ millions)	2006		2005
Revenue hedge swaps and collars	(48	)	(292	)
Margin hedge swaps	—		(12	)
Interest rate and cross-currency interest rate swaps	9		40
Specific cash flow hedges of individual transactions	8		11
	(31	)	(253	)

Energy Marketing and Trading Activities

For the second quarter ended June 30, 2006, we recorded net pretax earnings of $nil compared to the $1 million loss recorded during the second quarter of 2005 related to the settlement and revaluation of financial energy trading contracts. In the second quarter, the settlement of physical trading activities resulted in net pretax earnings of $6 million compared to $7 million pretax earnings in the second 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 $4 million for the quarter ended June 30, 2006 compared to earnings of $3 million in the second quarter of 2005. The fair value of unsettled financial energy trading assets and liabilities at June 30, 2006 and December 31, 2005 were as follows:

($ millions)	2006	2005
Energy trading assets	21	82
Energy trading liabilities	13	70
Net energy trading assets	8	12

Control Environment

Based on their evaluation as of June 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 Securities and Exchange Commission rules and forms. In addition, other than as described below, as of June 30, 2006, there were no changes in our internal controls over financial reporting that occurred during the six month period ended June 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 control 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 several business units have implemented our new ERP system, designed to support our growth plan. The business units affected by this implementation were Oil Sands, Natural Gas, EM&R – Canada, Corporate and our Major Projects group. 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.

The phased implementation of our ERP system is currently planned to be largely completed during the balance of 2006.

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 second quarter of 2006 was $31 million. For the six months ended June 30, 2006 the amount of total gross-up of revenues and purchases of crude oil and products was $79 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 June 30, 2006 interim basis, please refer to page 30 of the second 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 June 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 June 30 (Q2)		6 months ended June 30
			2006	2005	2006	2005
Cash flow from operations ($ millions)	A		1 320	305	2 634	599
Weighted number of shares outstanding (millions of shares)	B		459.0	456.1	458.6	455.5
Cash flow from operations (per share)	(A / B	)	2.88	0.67	5.74	1.32

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 June 30						Six months ended June 30
		2006			2005			2006			2005
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		456			292			964			613
Less: natural gas costs and inventory changes		(60	)		(30	)		(167	)		(105	)
Less: non-monetary transactions		(31	)		—			(79	)		—
Accretion of asset retirement obligations		7			5			14			11
Taxes other than income taxes		9			7			19			14
Cash costs		381		15.65	274		23.50	751		15.60	533		21.95
Natural gas		62		2.55	42		3.60	144		3.00	110		4.55
Imported bitumen (net of other reported product purchases)		2		0.10	—		—	3		0.05	1		0.05
Total cash operating costs	A	445		18.30	316		27.10	898		18.65	644		26.55
In-situ (Firebag) start-up costs	B	—		—	—		—	21		0.45	—		—
Total cash operating costs after start-up costs	A+B	445		18.30	316		27.10	919		19.10	644		26.55
Depreciation, depletion and amortization		92		3.80	79		6.75	185		3.85	158		6.50
Total operating costs		537		22.10	395		33.85	1 104		22.95	802		33.05
Production (thousands of barrels per day)		267.3			128.2			266.0			134.1

OIL SANDS OPERATING COSTS — IN-SITU BITUMEN PRODUCTION

	Quarter ended June 30						Six months ended June 30
	2006			2005			2006			2005
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	52			30			105			62
Less: natural gas costs and inventory changes	(26	)		(13	)		(45	)		(30	)
Taxes other than income taxes	1			—			2			—
Cash costs	27		8.50	17		21.50	62		10.95	32		12.90
Natural gas	26		8.15	13		16.40	45		7.95	30		12.10
Cash operating costs	53		16.65	30		37.90	107		18.90	62		25.00
Depreciation, depletion and amortization	12		3.75	6		7.60	29		5.10	14		5.65
Total operating costs	65		20.40	36		45.50	136		24.00	76		30.65
Production (thousands of barrels per day)	35.0			8.7			31.3			13.7

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

The risks, uncertainties and other factors that could influence actual results include but are not limited to changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; commodity prices and currency exchange rates; Suncor’s ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example the Firebag in-situ development and Voyageur) and regulatory projects (for example, the clean fuels refinery modifications projects in Suncor’s downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error and increase the level of accuracy; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other resource development; future environmental laws; the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from the January 2005 fire at the Oil Sands facility and other uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties, changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as the January 2005 fire, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor.

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