management’s discussion and analysis July 27, 2005

This Management’s Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 15 for additional information.

This MD&A should be read in conjunction with our June 30, 2005 unaudited interim consolidated financial statements and notes. Readers should also refer to our MD&A on pages 14 to 52 of our 2004 Annual Report and to our 2004 Annual Information Form. All financial information is reported in Canadian dollars and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel, referred to in this MD&A, are not prescribed by GAAP and are outlined and reconciled in “Non GAAP Financial Measures” on page 14.

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

Base operations refer to Oil Sands mining and upgrading operations.

Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

References to “we,” “our,” “us,” “Suncor,” or “the company” mean Suncor Energy Inc., its subsidiaries and joint venture investments, unless the context otherwise requires.

The tables and charts in this document form an integral part of this MD&A.

Additional information about Suncor filed with Canadian securities commissions and the United States Securities and Exchange Commission, including quarterly and annual reports and the Annual Information Form (AIF/40-F) is available on-line at www.sedar.com and www.sec.gov.

selected financial information

Industry Indicators

	3 months ended June 30		6 months ended June 30
(average for the period)	2005	2004	2005	2004

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

(1) New York Harbour 3-2-1 crack is an industry indicator measuring the margin on a barrel of oil for gasoline and distillate. It is calculated by taking two times the New York Harbour gasoline margin plus one times the New York Harbour distillate margin and dividing by three.

Outstanding Share Data (as at June 30, 2005)

Common shares		456 760 467
Common share options – total		19 629 554
Common share options – exercisable		10 173 806

Summary of Quarterly Results

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

NET EARNINGS COMPONENTS

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

	3 months ended June 30				6 months ended June 30
($ millions, after tax)	2005		2004		2005		2004
Net earnings before the following items	53		227		115		425
Firebag in-situ start-up costs (1)	—		—		—		(14	)
Oil Sands fire accrued insurance proceeds (1)	72		—		113		—
Impact of income tax rate reductions on opening future income tax liabilities	—		—		—		53
Unrealized foreign exchange losses on U.S. dollar denominated long-term debt	(13	)	(25	)	(18	)	(46	)
Net earnings as reported	112		202		210		418

(1) Before deduction of Alberta Crown Royalties.

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2005 second quarter net earnings of $117 million, compared with $231 million in the second quarter of 2004. The decrease in net earnings was primarily due to decreased revenues as a result of the January fire. The fire resulted in lower production and sales volumes and a less favourable sales mix of sweet crude oil and diesel fuel compared to sour crude and bitumen due to reduced upgrading capacity. Partially offsetting these negative factors were net insurance proceeds related to the fire that increased net earnings by $72 million (see page 7), an increase in the average realization for oil sands crude products, primarily reflecting a 39% increase in average benchmark WTI crude oil prices.

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

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

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

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

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

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

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

During the second quarter, cash operating costs for base operations averaged $18.95 per barrel, compared to $12.10 per barrel during the second quarter of 2004. Despite lower costs, cash operating costs per barrel increased due to applying the total dollars to fewer barrels of base operations production as a result of the fire. For further details on cash operating costs as a non GAAP financial measure, including the calculation and reconciliation to GAAP measures refer to page 14.

Oil Sands Fire

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

We carry property loss and business interruption (BI) insurance policies with a combined coverage limit of up to US$1.15 billion, net of deductible amounts, which is expected to substantially mitigate, upon receipt of these funds, the financial impact of the fire.

The primary property loss policy of US$250 million has a deductible per incident of US$10 million and the primary BI policy of US$200 million has a deductible of 30 days from the date of the fire. Coverage of US$700 million can be used for either property loss or BI. For BI purposes, this coverage has a deductible of 90 days from the date of the fire.

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

During the second quarter of 2005, we accrued $113 million before tax ($176 million before tax for the six months ended June 30, 2005) of insurance proceeds, net of the write-off of the net book value of the damaged assets and the expenses incurred to fight the fire, safe the site and investigate the cause and extent of the damage.

During the fourth quarter, we intend to focus on commissioning newly expanded components of the base plant that are expected to bring production capacity to 260,000 bpd. Construction of a second vacuum unit, a key component to reaching that milestone, is nearing completion. Firebag Stage Two is scheduled to begin steaming in the third quarter of 2005. In addition, Suncor is continuing to progress plans to expand capacity to 350,000 bpd in 2008. See page 12 for an update on our significant growth projects currently in progress.

Oil Sands Crown Royalties and Cash Income Taxes

Crown royalties in effect for Oil Sands operations require payments to the Government of Alberta, based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty) for each project, subject to a minimum payment of 1% of R. In April 2004, the Alberta government confirmed it would modify our royalty treatment because it does not recognize the Firebag in-situ facility as an expansion to our existing Oil Sands project. Accordingly, for Alberta Crown royalty purposes, our oil sands operations are considered two separate projects: base oil sands mining and associated upgrading operations with royalties based on upgraded product values and the current Firebag in-situ project with royalties based on bitumen values. Alberta Oil Sands Crown royalties may be subject to change as policies arising from the Government’s position are finalized and audits of 2004 and prior years are completed.

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

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

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

• current forecasts of capital and operating costs for the remainder of 2005;

• an average annual Cdn$/US$ exchange rate of $0.81;

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

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

Alberta Crown royalties payable in 2005 and subsequent years continue to be highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates, and total capital and operating costs for each Project. In addition, 2004 was a transition year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed in 2004 to reduce our 2004 Alberta Crown royalty obligation. No such carry forward of allowable costs exists for 2005 and subsequent years.

Assuming anticipated levels of operating expenses and capital expenditures for each project remain relatively constant, variability in expected Oil Sands Crown royalty expense is primarily a function of changes in expected annual Oil Sands revenue. Absent the impact of the January 4, 2005 fire, we expect that Alberta Oil Sands Crown royalty expense for the period 2005 to 2007 would range from approximately 12% to 14% of total Oil Sands Revenue based on WTI prices of US$40 to US$50 per barrel respectively. For subsequent years, this percentage range may decline as anticipated new in-situ production attracts royalties based on bitumen values. This royalty percentage range is based on the following assumptions: a natural gas price of US$6.25 per thousand cubic feet (mcf) at Henry Hub; a light/heavy oil differential to the U.S. Gulf Coast of US$9 per barrel, and a Cdn$/US$ exchange rate of $0.80.

Alberta Oil Sands Crown royalty expense in 2005 and 2006 may be significantly impacted by the amount and timing of the recognition of the business interruption insurance proceeds. Accordingly, the range of annualized royalty expense as a percentage of revenues may differ from that stated above, and these differences may be material.

Based on our current long-term planning assumptions, the 25% R-C royalty would continue to apply to our existing Oil Sands base operations in future years and the 1% minimum royalty would apply to our Firebag Project until the next decade. We continue to discuss with the government the terms of our option to transition our base operations to the generic bitumen-based royalty regime in 2009. After 2009, the royalty on our base operations would be based on bitumen value if we exercise our option to transition to the Province of Alberta’s generic regime for oil sands royalties. In the event that we exercise this option, future upgrading operations would not be included for Oil Sands Crown royalty purposes.

The timing of when the Oil Sands operations will be fully cash taxable is highly dependent on crude oil commodity prices and capital invested. At WTI prices between US$34 per barrel and US$50 per barrel, an average annual Cdn$/US$ foreign exchange rate of $0.80, future investment plans and certain other assumptions, we do not believe we will be fully cash taxable until the next decade. At sustained forward prices, based on the assumptions stated above, we anticipate that Oil Sands and Natural Gas operations will be partially cash taxable commencing in 2009 at WTI prices of US$34 per barrel, and in 2007 at WTI prices of US$40 per barrel to US$50 per barrel, until the next decade, at which point they are expected to become fully cash taxable. However, in any particular year, our Oil Sands and Natural Gas operations may be subject to some cash income tax due to the sensitivity to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for tax purposes.

The information in the preceding paragraphs under “Oil Sands Crown Royalties and Cash Income Taxes” incorporates operating and capital cost assumptions included in our current budget and long-range plan, and is not an estimate, forecast or prediction of actual future events or circumstances.

Natural Gas

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

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

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

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

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

Energy Marketing & Refining – Canada

Energy Marketing and Refining – Canada (EM&R) has historically reported its segmented results on a Rack Back/Rack Forward divisional basis. The Rack Back division included Ontario refining operations, as well as sales and distribution to the Sarnia refinery’s largest industrial and reseller customers and the Sun Petrochemicals Company (SPC) joint venture. Rack Forward included retail operations, cardlock and industrial/commercial sales as well as the UPI and Pioneer joint ventures.

EM&R’s Rack Back and Rack Forward organizational structures have now been consolidated into one unit for the purposes of external segmented reporting. Prior year amounts have been reclassified to conform to this presentation. EM&R’s external results continue to be measured and analyzed on a margin basis.

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

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

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

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

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

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

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

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

Refining & Marketing – U.S.A.

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

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

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

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

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

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

Corporate

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

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

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, 2,062,000 SunShare options vested, representing approximately 25% of the then outstanding unvested options under the SunShare Plan. On June 30, 2005, we met an additional predetermined performance criterion under the SunShare plan, resulting inthe vesting of 50% of the remaining outstanding, unvested SunShare options on April 30, 2008. As we have been accruing the costs of these options, the impact on net earnings for the second quarter and the six months ended June 30, 2005 was not significant.

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

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

Analysis of Financial Condition and Liquidity

Excluding cash and cash equivalents, short-term borrowings and future income taxes, Suncor had an operating working capital deficiency of $426 million at the end of the second quarter, compared to a deficiency of $77 million at the end of the second quarter of 2004. The increase in our working capital deficiency is due primarily to increased accounts payable balances as a result of increased construction activity and the purchase of higher volumes of feedstock and refined products at higher commodity prices. This was partially offset by higher accounts receivable balances as a result of higher commodity prices and accrued insurance proceeds.

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

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

SIGNIFICANT CAPITAL PROJECT UPDATE

					Spent 2005			Total Spent
	Board of	Cost Estimate (1)			Year to Date			to Date
Description	Directors’ Approval	($ millions)			($ millions)			($ millions)			Status
Oil Sands
Millennium vacuum unit	Yes	$	425		$	37		$	430	(1)	Project is on schedule.
											Commissioning and start up
											planned for Q4 2005.

Firebag Stage Two	Yes	$	515		$	78		$	477		Project is on schedule.
											Initial steaming planned for Q3 2005.

Coker Unit (2)	Yes	$	2 100		$	239		$	638		Project is on schedule for
											completion in 2008.

EM&R
Clean fuels and Oil Sands integration	Yes	$	800		$	158		$	336		Project components are on
											schedule for completion in 2006 and 2007.

R&M
Clean fuels and	Yes	$	360		$	153		$	289		Project is on schedule for
Oil Sands integration		(US$300		)	(US$123		)	(US$229		)	completion in 2006.

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

(2) Excludes costs associated with bitumen feed.

Derivative Financial Instruments

In the first quarter of 2004 we suspended our strategic hedging program and have not entered into any new strategic crude oil hedges. Our strategic hedging program permitted us to fix a price or range of prices for a percentage of our total production of crude oil for specified periods of time.

We continue to be party to crude oil hedges, covering 36,000 bpd of production placed prior to the suspension of the program. For accounting purposes, amounts received or paid on settlement of hedge contracts are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings. In the second quarter of 2005, strategic crude oil hedging decreased our after-tax net earnings by $78 million, compared with $86 million in the second quarter of 2004.

The fair value of strategic derivative hedging instruments is the estimated amount, based on brokers’ quotes and/or internal valuation models, the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss), on the contracts, were as follows at June 30:

($ millions)	2005		2004

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

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

Energy Marketing and Trading Activities

For the quarter ended June 30, 2005, we recorded a net pretax loss of $1 million compared to the $4 million gain recorded during the second quarter of 2004, related to the settlement and revaluation of financial energy trading contracts. In the second quarter, the settlement of physical trading activities resulted in a net pretax gain of $7 million compared to a $4 million pretax gain in the second quarter of 2004. These gains were included as energy marketing and trading activities in the Consolidated Statement of Earnings. The above amounts do not include the impact of related general and administrative costs. Total after tax energy marketing and trading activities resulted in a gain of $3 million for the quarter ended June 30, 2005 compared to a gain of $4 million in the second quarter of 2004. The fair value of unsettled financial energy trading assets and liabilities at June 30, 2005 and December 31, 2004 were as follows:

($ millions)	2005	2004

Energy trading assets	34	26
Energy trading liabilities	21	9

Control Environment

Based on their evaluation as of June 30, 2005, our chief executive officer and chief financial officer concluded that our disclosure controls and procedures (as defined in Rules 13(a) – 15(e) and 15(d) – 15(e) under the United States Securities and Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms. In addition, other than as described below, as of June 30, 2005, there were no changes in our internal controls over financial reporting that occurred during the six month period ended June 30, 2005 that have materially affected, or are reasonably likely to materially affect our internal controls over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal controls over financial reporting and will make any modifications from time to time as deemed necessary.

We are currently in the process of implementing an enterprise resource planning (ERP) system in all of our businesses to support our growth plan. The phased implementation is currently planned to be complete by 2006. Implementing an ERP system on a widespread basis involves significant changes in business processes and extensive training. We believe a phased-in approach reduces the risks associated with making these changes. We believe we are taking the necessary steps to monitor and maintain appropriate internal controls during this transition period. These steps include deploying resources to mitigate internal control risks and performing additional verifications and testing to ensure data integrity.

We have concluded that our disclosure controls and procedures have operated effectively and free of any material weaknesses for the quarter ended June 30, 2005. In connection with the continued implementation of our ERP system, we expect there will be a significant redesign of processes during 2006, some of which relate to internal controls over financial reporting and disclosure controls and procedures.

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

Change in Accounting Policies

Effective January 1, 2005, we retroactively adopted the Canadian Accounting Standards Board amendment to Handbook Section 3860 “Financial Instruments – Disclosure and Presentation”. The amendment requires that certain obligations that must or could be settled with an entity’s own equity investments, be presented as liabilities. Accordingly, we have reclassified our preferred securities from equity to long-term debt, resulting in an increase to property, plant and equipment of $36 million, an increase in future tax liabilities of $13 million and an increase in retained earnings of $23 million.

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

Non GAAP Financial Measures

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

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

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of Suncor’s June 30, 2005 unaudited interim consolidated financial statements.

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

			3 months ended June 30		6 months ended June 30
			2005	2004	2005	2004

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

The following tables outline the reconciliation of Oil Sands cash and total operating costs to expenses included in the Schedules of Segmented Data in the company’s financial statements. Amounts included in the tables below for base operations and Firebag in-situ reconcile to the schedules of segmented data when combined.

OIL SANDS OPERATING COSTS – BASE OPERATIONS

	Quarter ended June 30							Six months ended June 30
	2005				2004 (1)			2005			2004 (1)
	$ millions			$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel

Operating, selling and general expenses	182				226			392			440
Less: natural gas costs and inventory changes	(17		)		(51	)		(75	)		(84	)
Accretion of asset retirement obligations	5				5			11			10
Taxes other than income taxes	7				7			14			14
Cash costs	177			16.30	187		9.75	342		15.70	380		9.70
Natural gas	29			2.65	44		2.30	80		3.65	87		2.20
Imported bitumen (net of other reported product purchases)	—			—	1		0.05	1		0.05	9		0.25
Cash operating costs	A	206		18.95	232		12.10	423		19.40	476		12.15
Start-up costs	—				—			—			22
Add: in-situ inventory changes	—			—	—		—	—		—	2
Less: pre-start-up commissioning costs	—			—	—		—	—		—	—
In-situ (Firebag) start-up costs	B	—		—	—		—	—		—	24		0.60
Total cash operating costs	A+B	206		18.95	232		12.10	423		19.40	500		12.75
Depreciation, depletion and amortization	103			9.45	119		6.20	202		9.30	243		6.20
Total operating costs	309			28.40	351		18.30	625		28.70	743		18.95
Production (thousands of barrels per day)	119.5				210.8			120.4			215.3

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

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

(1) Production in the base operations for the year ended December 31, 2004 includes Firebag in-situ volumes of 5,900 bpd produced in the first quarter of 2004 during the Firebag start-up period.

legal notice – forward-looking information

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

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

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

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