EXHIBIT 2

Interim Management’s Discussion and Analysis for the second fiscal quarter ended June 30, 2004

management’s discussion and analysis

July 26, 2004

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 12 for additional information.

This MD&A should be read in conjunction with Suncor’s June 30, 2004 unaudited interim consolidated financial statements and notes. Readers should also refer to Suncor’s 2003 Annual Information Form and Management’s Discussion and Analysis on pages 16 to 51 of Suncor’s 2003 Annual Report. 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 operating costs, referred to in this MD&A, are not prescribed by GAAP and are outlined and reconciled in “Non-GAAP Financial Measures” on page 10.

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

Base operations refers 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 “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.

INDUSTRY INDICATORS

	3 months ended June 30		6 months ended June 30
(average for the period)	2004	2003	2004	2003
West Texas Intermediate (WTI) crude oil US$/barrel @ Cushing	38.30	28.90	36.75	31.40
Canadian 0.3% par crude oil Cdn$/barrel @ Edmonton	51.00	41.60	48.50	46.50
Light/heavy crude oil differential US$/barrel – WTI @ Cushing less Bow River @ Hardisty	11.00	6.55	10.05	7.05
Natural gas US$/mcf @ Henry Hub	5.95	5.50	5.85	6.05
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.80	7.00	6.70	7.45
New York Harbour 3-2-1 crack (1) US$/barrel	8.90	3.55	7.90	4.95
Exchange rate: Cdn$:US$	0.74	0.72	0.75	0.69

(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.

SELECTED FINANCIAL INFORMATION

Outstanding Share Data(as at June 30, 2004)
Common shares	452 928 675
Common share options	21 638 518
Common share options – exercisable	8 233 599

Summary of Quarterly Results

	2004 Quarter ended		2003 Quarter ended				2002 Quarter ended
($ millions, except per share data)	June 30	Mar. 31	Dec. 31	Sep. 30	June 30	Mar. 31	Dec. 31	Sep. 30
Revenues	2 201	1 795	1 698	1 788	1 385	1 700	1 409	1 257
Net earnings	203	227	302	291	116	366	256	183
Net earnings attributable to common shareholders per share
Basic	0.44	0.48	0.67	0.63	0.27	0.84	0.55	0.38
Diluted	0.43	0.46	0.61	0.62	0.24	0.77	0.54	0.37

4

ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the second quarter of 2004 were $203 million, compared to $116 million for the second quarter of 2003. The increase in net earnings in 2004 was primarily due to higher crude oil and natural gas production, as well as higher benchmark commodity prices. This was partially offset by higher Oil Sands royalties, higher hedging losses, the effects of maintenance shutdowns in both of the company’s downstream operations, foreign exchange losses on U.S. dollar denominated long-term debt, and a 3% strengthening in the Canadian dollar that decreased operating revenues. Earnings in the second quarter of 2003 were impacted by a planned maintenance shutdown in Oil Sands as well as a one-time non-cash income tax adjustment related to changes in federal and provincial tax policies and rates.

Cash flow from operations in the second quarter was $490 million, compared to $358 million in the same period of 2003. The increase was primarily due to the same factors that impacted earnings, excluding the impact of the non-cash income tax adjustment in 2003.

Net earnings for the first half of 2004 were $430 million, compared to $482 million in the same period of 2003. The decrease was primarily due to higher Oil Sands royalty expenses, higher hedging losses, foreign exchange losses on U.S. dollar denominated long-term debt and the effects of an 8% strengthening in the Canadian dollar in the first six months of 2004 compared to 2003 that decreased operating revenues. These negative impacts were partly offset by higher crude oil and natural gas production, higher benchmark commodity prices and year-over-year non-cash federal and provincial income tax adjustments.

Cash flow from operations for the first six months of 2004 was $912 million, compared to $971 million in the first half of 2003. This decrease was primarily due to the same factors that impacted earnings, excluding the impacts of the non-cash income tax adjustments.

NET EARNINGS COMPONENTS

This table explains some of the factors impacting Suncor’s net earnings on an after-tax basis. For comparability purposes readers should rely on the reported net earnings that are presented in the company’s 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)	2004		2003		2004		2003
Net earnings before the following items	296		160		539		489
Firebag in-situ start-up costs	—		—		(14	)	—
Oil Sands Crown royalties	(68	)	(3	)	(108	)	(10	)
Impact of income tax changes and rate reductions on opening future income tax liabilities	—		(86	)	53		(86	)
Unrealized foreign exchange gains (losses) on U.S. dollar denominated long-term debt	(25	)	45		(40	)	89
Net earnings as reported	203		116		430		482
Net earnings attributable to common shareholders as reported	203		125		418		498

5

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2004 second quarter net earnings of $232 million, compared with $70 million in the second quarter of 2003. The increase was primarily due to higher benchmark crude oil prices and higher crude oil production. In addition, 2003 net earnings were reduced by a one-time non-cash income tax adjustment related to changes in federal and provincial tax policies and rates. These positive factors were offset by higher Crown royalties, an increase in hedging losses, higher natural gas costs, higher depreciation, depletion and amortization expenses, costs related to unscheduled upgrader maintenance, and a 3% strengthening of the Canadian dollar against the U.S. dollar that reduced operating revenues in the second quarter of 2004.

Cash flow from operations for the quarter was $421 million, compared to $321 million in the second quarter of 2003. The increase was primarily due to the same factors that impacted net earnings, excluding the impact of 2003 non-cash income tax adjustments.

Net earnings for the first six months were $470 million, compared to $375 million in the first six months of 2003. In addition to the impact of favourable 2004 first quarter tax adjustments due to a decrease in the provincial income tax rate, the increase in net earnings was primarily due to the same factors that impacted earnings in the second quarter.

Cash flow from operations for the first six months of 2004 decreased to $786 million from $862 million in the first six months of 2003, primarily due to the same factors that impacted net earnings, excluding the impact of non-cash income tax adjustments in 2004 and 2003.

Oil sands production during the second quarter averaged 225,900 barrels of oil per day (bpd), comprised of 210,800 bpd of upgraded crude oil from the base operations and 15,100 bpd of bitumen production from the company’s Firebag in-situ operations. This compares to production of 188,200 bpd of upgraded crude oil in the second quarter of 2003, when operations were impacted by a 30-day planned maintenance shutdown.

Oil Sands production volumes in the second quarter of 2004 were lower than expected due to the extension of scheduled coker and furnace maintenance in April, as well as unscheduled maintenance in June as a result of wear caused by higher mineral content in the bitumen sourced from the Millennium mine pit. Oil Sands is currently evaluating various capital and/or operating alternatives to address this issue on a long-term basis. As a result of lower than anticipated production during the second quarter, Suncor revised its 2004 annual production target from its base operations to 220,000 bpd from the original target of 225,000 to 230,000 bpd.

Sales during the second quarter averaged 231,800 bpd, compared with 184,400 bpd during the second quarter of 2003. The increase in sales was directly related to the higher production levels in 2004 compared to 2003. The sales mix of higher value products increased to 64% compared to 59% in 2003.

During the second quarter, cash operating costs for the base operations averaged $12.10 per barrel, reflecting higher than forecasted natural gas prices, unplanned maintenance and lower than anticipated production. Suncor has revised its 2004 annual cash operating cost target for the base operations to $12.00 to $12.50 per barrel, compared to the original target of $10.75 to $11.75 per barrel, based on actual costs incurred to date and updated natural gas pricing forecasts for the remainder of the year of US$6.30/mcf at Henry Hub. For further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures see page 11.

Included in cash from investing activities in the Oil Sands schedules of segmented data, are the proceeds from the sale of certain proprietary technology.

Suncor’s next major growth stage targets oil sands production capacity of 260,000 bpd in 2005. Construction of a second vacuum unit, a key component to reaching that milestone, is 65% complete. Construction of Firebag Stage 2, which is planned to provide bitumen supplies to future upgrader expansions, is 25% complete with steaming planned to start in late 2005. Both projects are on schedule and on budget.

Preliminary planning for construction of a proposed third upgrader near the company’s existing Oil Sands facilities is now under way. As part of the regulatory process, Suncor is preparing an Environmental Impact Assessment (EIA) to identify potential environmental impacts and mitigation strategies related to the proposed expansion. The proposed upgrader is a key component of Suncor’s plan to increase production to 500,000 to 550,000 bpd in 2010 to 2012.

Oil Sands Crown Royalties

Crown royalties in effect for each Oil Sands Project require payments to the Government of Alberta, based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. In April, the Alberta government confirmed it would modify Suncor’s royalty treatment because it does not recognize the company’s Firebag in-situ facility as an expansion to the company’s existing Oil Sands Project. Accordingly, for Alberta Crown royalty purposes, Suncor’s oil sands operations are considered as two separate projects: Suncor’s base oil sands mining and associated upgrading operations and Suncor’s current Firebag in-situ oil sands project. On this basis, Suncor has provided for estimated additional Crown royalty obligations in 2004. Royalties payable in 2004 or any subsequent year, are 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

6

is a transition year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million would be claimed before the 25% R-C royalty applies to the current year’s results.

Oil Sand’s second quarter pretax Crown royalty estimate of $105 million ($68 million after-tax) was based on:

•average 2004 crude oil pricing of approximately US$37 WTI per barrel (based on US$37 WTI per barrel for both actual average pricing for the first six months of 2004, as well as 2004 forward crude oil pricing at June 30 for the remainder of the year).

•current forecasts of capital and operating costs for the remainder of 2004.

•a Canadian/U.S foreign exchange rate of $0.75.

Using these assumptions, Suncor revised its estimate of 2004 annualized pretax royalties to approximately $310 million ($202 million after tax).

Suncor estimates that for every US$1 per barrel change in the average WTI price for calendar 2004, Suncor’s 2004 royalty obligation would change by approximately $25 million.

Further, based on the company’s current long-term planning assumptions, the 25% R-C royalty would continue to apply to the existing Oil Sands Project in future years and the 1% minimum royalty would apply to the Firebag Project until the next decade. The company continues to discuss the terms of Suncor’s option to transition to the generic bitumen-based royalty regime in 2009. After 2009 the royalty would be based on bitumen value if Suncor exercised its option to transition to the Province of Alberta’s generic regime for oil sands royalties. In the event that Suncor exercises this option, upgrading would not be included in the Oil Sands Project for royalty purposes.

This sensitivity analysis 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 future events or circumstances.

Suncor’s time horizon for cash income taxes for its oil sands operations to be fully cash taxable is not expected until the next decade, based on US$34 per barrel WTI, prior years’ investment levels, future investment plans and certain other assumptions stated above. However, in any particular year, the company’s upstream oil sands and natural gas operations may be subject to some cash income tax due to natural gas price volatility or the timing of recognition of capital expenditures for tax purposes.

Natural Gas

Natural Gas recorded 2004 second quarter net earnings of $35 million, compared with $28 million during the second quarter of 2003. Excluding the impact of a $5 million non-cash future income tax adjustment, earnings for the second quarter of 2003 were $23 million. The increase in 2004 was primarily due to higher production volumes, higher realized natural gas prices and lower exploration costs. These factors were partly offset by higher depletion, depreciation and amortization expenses.

Cash flow from operations for the second quarter of 2004 was $90 million, compared to $66 million in the second quarter of 2003. The increase was primarily due to higher production and higher gas prices.

Year-to-date net earnings were $57 million, compared to $55 million in the first six months of 2003. Excluding the effect of the $5 million non-cash future income tax adjustment described above, earnings for the first six months of 2003 were $50 million. The increase in year-to-date earnings resulted from higher production volumes and lower royalty expenses, partially offset by higher depreciation, depletion and amortization expenses.

Cash flow from operations for the first six months of the year was $173 million, compared to $154 million reported in the same period in 2003, reflecting the same factors that affected net earnings, excluding the impact of the non-cash income tax adjustments in 2003.

Suncor’s strategy calls for natural gas production to exceed natural gas purchases for internal consumption, retaining the company’s position as a net seller into the North American market. Natural gas production in the second quarter of 2004 increased by 19% to 209 mmcf per day, compared to 175 mmcf per day in the second quarter of 2003. The 2004 revised production outlook targets an average of 195 to 200 mmcf per day for the year, exceeding Suncor’s projected 2004 purchases of about 120 to 130 mmcf per day.

Energy Marketing & Refining – Canada

Energy Marketing and Refining – Canada (EM&R) recorded a 2004 second quarter net loss of $3 million, compared to net earnings of $17 million in the second quarter of 2003. The decrease was primarily due to reduced earnings from refining activities as a result of scheduled and unscheduled maintenance to portions of Suncor’s Sarnia, Ontario refinery between April 7 and June 1. Earnings were also affected by weaker retail gasoline margins. These negative impacts were partially offset by mark-to-market gains on inventory-related derivatives and increased earnings from energy marketing and trading activities.

Cash flow from operations for the second quarter decreased to $23 million from $41 million in the second quarter of 2003 due to the same factors that decreased earnings.

Rack Forward, the retail and commercial customer division of EM&R, recorded a second quarter 2004 net loss of $4 million, compared to earnings of $6 million in the second quarter of 2003. Retail margins decreased to an average of 4.3 cents per litre (cpl) from 6.2 cpl in the second quarter of 2003 due to competitive pressures

7

in the Ontario market. Sales volumes were relatively flat quarter over quarter.

Rack Back, the refining and large industrial customer division of EM&R, recorded a net loss of $3 million in the second quarter, compared to net earnings of $12 million in the second quarter of 2003. The decrease was primarily due to a loss of refining margins during the shutdown, as well as higher natural gas prices. During the shutdown, EM&R purchased refined product from third parties at prices above historical averages to fulfill customer commitments. These negative earnings factors were partially offset by mark-to-market gains on inventory related derivatives that increased by $6 million quarter over quarter.

During the second quarter, crude utilization decreased to 85% from 100% in 2003 due primarily to the maintenance shutdown. Refining margins on Suncor’s proprietary refined products averaged 7.4 cpl, compared to 4.7 cpl in 2003.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $4 million in the second quarter of 2004, compared to a loss of $1 million in the same period of 2003.

EM&R recorded year-to-date net earnings of $27 million, compared to $38 million in the same period of 2003. The decrease in net earnings reflects lower rack forward earnings due to retail competition and lower refinery utilization related to the second quarter maintenance shutdown, offset by higher mark-to-market gains on inventory related derivatives, as well as higher energy marketing and trading income.

Cash flow from operations for the first six months of 2004 was $79 million compared to $90 million in the first six months of 2003, primarily due to the same factors that affected net earnings.

Progress continues on the planned construction of a new ethanol plant, as the company finalizes both the $22 million contribution agreement with the federal government and its purchase of the land for the plant site.

Refining & Marketing – U.S.A.

Refining & Marketing – U.S.A. (R&M) recorded net earnings of $12 million in the second quarter of 2004, primarily as a result of strong refining margins, partially offset by lower than capacity refinery production due to a scheduled maintenance shutdown on certain refinery units, which was completed on April 19. Cash flow from operations for the second quarter was $21 million. There are no comparative earnings or cash flow data for the second quarter of 2003 as the R&M operations were acquired on August 1, 2003.

Refining margins in the second quarter averaged 9.0 cpl, compared to 5.0 cpl in the first quarter of 2004. Crude utilization at the Denver refinery averaged 86%, reflecting the effects of the planned April shutdown. In order to meet customer demands during the shutdown, R&M purchased refined products from third-party suppliers at market prices.

Retail margins averaged 6.2 cpl in the second quarter of 2004, compared to 5.0 cpl in the first quarter of 2004. Retail sales volumes in the second quarter were lower than the first quarter of 2004 primarily due to increasing competitive pressures from discount gasoline merchants as well as record high gasoline prices during the quarter.

R&M recorded year-to-date net earnings of $9 million and cash flow from operations of $15 million.

Corporate

Corporate recorded a net loss in the second quarter of 2004 of $73 million, compared to net earnings of $1 million during the second quarter of 2003. Results in 2004 included a $25 million after-tax unrealized foreign exchange loss on the company’s U.S. dollar denominated long-term debt, compared to a $45 million after-tax gain in the second quarter of 2003. Corporate expenses were also higher in 2004 due to the implementation of the company’s Enterprise Resource Planning (ERP) system, and higher stock-based compensation expense, attributable to expensing options and deferred share units, as initiated in the second quarter of 2003.

Cash flow used in operations in the quarter was $65 million, compared to the $70 million used in the second quarter of 2003. The slight decrease was primarily due to the earnings factors described above, excluding the impact of the unrealized foreign exchange losses on the U.S. dollar denominated debt, as well as a decrease in current income tax allocations.

Corporate recorded a net loss of $133 million in the first six months of 2004, compared to earnings of $14 million in the same period of 2003. Year-to-date, after-tax unrealized foreign exchange losses on Suncor’s U.S. dollar denominated debt were $40 million, compared to gains of $89 million in 2003. Excluding the impacts of the foreign exchange and consistent with the second quarter, the net loss for the first six months of 2004 was higher primarily due to costs related to the implementation of the ERP system and higher stock-based compensation costs. The net cash deficiency in the first half of 2004 of $141 million was comparable to the prior year net cash deficiency of $135 million.

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 $77 million at the end of the second quarter, compared to a deficiency of $152 million at the end of second quarter 2003. The decrease primarily reflects higher trade receivables and inventory due to higher commodity prices and inventory levels. This decrease was partially offset by higher trade payables due to higher commodity prices and higher Oil Sands Crown royalty accruals.

8

In the second quarter, net debt decreased to approximately $2.5 billion from $2.6 billion at March 31, 2004. Suncor’s undrawn lines of credit at June 30, 2004 were approximately $1.5 billion. Suncor believes it has the capital resources from its undrawn lines of credit and cash flow from operations to fund the balance of its 2004 capital spending program and to meet its current working capital requirements. The 2004 capital spending forecast has not changed significantly from that reported in the company’s 2003 annual MD&A.

On June 25, the company repurchased approximately 2.1 million barrels of crude oil originally sold to a Variable Interest Entity (VIE) in 1999, for net consideration of $49 million. As the company economically hedged the repurchase of the inventory, the net consideration paid was equal to the original proceeds Suncor received in 1999 when it sold the inventory to the VIE. During the third quarter, Suncor will recognize a final $11 million after-tax reduction in margins on subsequent resale of a portion of this inventory. This amount will partially offset mark-to-market gains recorded in previous periods on the economic hedges.

Derivative Financial Instruments

The company’s strategic hedging program permits the company to fix a price or range of prices for crude oil for specified periods of time for a percentage of Suncor’s total production. 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 2004, strategic crude oil hedging decreased Suncor’s net earnings by $86 million after-tax compared to an after-tax decrease of $21 million in the second quarter of 2003.

In accordance with the Board of Director’s decision to suspend the hedging program in the first quarter, the company did not enter into any new strategic crude oil arrangements in the second quarter of 2004.

The fair value of 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)	2004		2003
Revenue hedge swaps and options	(466	)	(175	)
Margin hedge swaps	(2	)	4
Interest rate swaps	25		36
	(443	)	(135	)

Energy Marketing and Trading Activities

For the quarter ended June 30, 2004 Suncor recorded a net pretax gain of $4 million compared to a $1 million pretax loss during the second quarter of 2003, related to the settlement and revaluation of financial energy trading contracts. In the second quarter the settlement of physical trading activities also resulted in a net pretax gain of $4 million compared to a $1 million pretax gain in the second quarter of 2003. These gains were included as energy trading and marketing activities in the consolidated statement of earnings. The fair value of unsettled energy trading assets and liabilities at June 30, 2004 and December 31, 2003 were as follows:

($ millions)	June 302004	December 31 2003
Energy trading assets	14	5
Energy trading liabilities	5	5

Control Environment

Based on their evaluation as of the end of the three month period ended June 30, 2004, Suncor’s Chief Executive Officer and Chief Financial Officer concluded that Suncor’s 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) are effective to ensure that information required to be disclosed by Suncor in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in Securities and Exchange Commission rules and forms.

As at June 30, 2004, there were no changes in Suncor’s internal controls over financial reporting that occurred during the three month period ended June 30, 2004 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting, other than the new software applications implemented in both Suncor’s crude oil marketing and major projects groups. In connection with these system conversions, internal controls have been modified to reflect the new system environment. Suncor has reviewed the effectiveness of the design of the new internal controls and processes and believes them to be adequate.

9

Suncor continues to identify the need to implement a more robust control environment to support the R&M business unit’s financial reporting and disclosure processes. At June 30, 2004, certain of the compensating controls and processes that were initially put in place at the time of the acquisition have been enhanced.

Suncor will continue to periodically evaluate its disclosure controls and procedures and internal controls over financial reporting and intends to make modifications from time to time as deemed necessary. Suncor is also continuing its previously disclosed review of internal controls, including a comprehensive review of its existing internal controls over financial reporting. Further development of, and enhancements to, control processes and computerized systems are expected to be completed from 2004 to 2006 in connection with the implementation of Suncor’s current ERP installation.

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, 2004 interim basis, please refer to page 26 of the Quarterly Operating Summary included in the company’s 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, 2004 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
			2004	2003	2004	2003
Cash flow from operations ($ millions)	A		490	358	912	971
Dividends paid on preferred securities ($ millions pretax)	B		—	11	9	23
Weighted average number of common shares outstanding (millions of shares)	C		453	449	452	449
Cash flow from operations (per share)	(A / C	)	1.08	0.80	2.02	2.16
Dividends paid on preferred securities (pretax, per share)	(B / C	)	—	0.03	0.02	0.05
Cash flow from operations after deducting dividends paid on preferred securities (per share)	[(A-B) / C]		1.08	0.77	2.00	2.11

10

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

		3 months ended June 30						6 months ended June 30
		2004			2003			2004			2003
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		226			209			440			434
Less: natural gas costs and inventory changes		(51	)		(37	)		(84	)		(98	)
Accretion of asset retirement obligations		5			5			10			10
Taxes other than income taxes		7			6			14			12
Cash costs		187		9.75	183		10.70	380		9.70	358		9.95
Natural gas		44		2.30	42		2.45	87		2.20	100		2.75
Imported bitumen (net of other reported product purchases)		1		0.05	2		0.10	9		0.25	4		0.10
Cash operating costs	A	232		12.10	227		13.25	476		12.15	462		12.80
Start-up costs		—			3			22			5
Add: in-situ inventory changes		—			—			2			—
Less: pre-start-up commissioning costs		—			(3	)		—			(5	)
Firebag in-situ start-up costs	B	—		—	—		—	24		0.60	—		—
Total cash operating costs	A+B	232		12.10	227		13.25	500		12.75	462		12.80
Depreciation, depletion and amortization		118		6.15	108		6.30	242		6.20	228		6.30
Total operating costs		350		18.25	335		19.55	742		18.95	690		19.10
Production (thousands of barrels per day)		210.8			188.2			215.3(1)			199.6

(1)Production in the base operations for the six months ended June 30, 2004 includes upgraded Firebag in-situ volumes of 5,900 bpd produced in the first quarter of 2004 during the Firebag start-up period.

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

	3 months ended June 30
	2004			2003
	$ millions		$/barrel	$ millions	$/barrel
Operating, selling and general expenses	24			—
Less: natural gas costs and inventory changes	(15	)		—
Accretion of asset retirement obligations	—			—
Taxes other than income taxes	—			—
Cash costs	9		6.55	—	—
Natural gas	16		11.65	—	—
Cash operating costs	25		18.20	—	—
Depreciation, depletion and amortization	8		5.80	—	—
Total operating costs	33		24.00	—	—
Production (thousands of barrels per day)	15.1			—

11

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,” “plans,” “intends,” “believes,” “projects,” “indicates,” “could,” “vision,” “goal,” “target,” “objective” and similar expressions. These statements are not guarantees of future performance as they are based on current facts and assumptions 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 or 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 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 fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian Securities Commissions and the SEC. 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.

12