Exhibit 99.2

management’s discussion and analysis

October 27, 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 September 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 and total 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 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 “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

	3 months ended September 30		9 months ended September 30
Industry Indicators (average for the period)	2004	2003	2004	2003
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	43.90	30.20	39.10	31.00
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	56.60	41.35	51.20	44.75
Light/heavy crude oil differential US$/barrel – WTI at Cushing less Bow River at Hardisty	12.10	8.10	10.70	7.40
Natural gas US$/mcf at Henry Hub	6.35	5.10	6.00	5.75
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.70	6.30	6.70	7.05
New York Harbour 3-2-1 crack (1) US$/barrel	6.75	6.35	7.55	5.40
Exchange rate: Cdn$:US$	0.77	0.72	0.75	0.70

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

Outstanding Share Data (as at September 30, 2004)

Common shares		453 420 617
Common share options – total		21 278 882
Common share options – exercisable		7 749 062

	2004 Quarter ended			2003 Quarter ended				2002 Quarter ended
Summary of Quarterly Results	Sep. 30	June 30	Mar. 31	Dec. 31	Sep. 30	June 30	Mar. 31	Dec. 31
($ millions, except per share data)
Revenues	2 315	2 201	1 795	1 698	1 788	1 385	1 700	1 409
Net earnings	337	203	227	302	291	116	366	256
Net earnings attributable to common shareholders per share
Basic	0.74	0.44	0.48	0.67	0.63	0.27	0.84	0.55
Diluted	0.73	0.43	0.46	0.61	0.61	0.24	0.77	0.54

ANALYSIS OF CONSOLIDATED STATEMENTS OF EARNINGS AND CASH FLOWS

Net earnings for the third quarter of 2004 were $337 million, compared to $291 million for the third quarter of 2003. The increase in net earnings was primarily due to a 3% increase in crude oil and natural gas production, higher benchmark commodity prices, a more favourable sales mix of sweet crude oil and diesel fuel compared to sour crude and bitumen, higher refining margins in the Canadian downstream operations, and higher foreign exchange gains on U.S. dollar denominated long-term debt. These factors were partially offset by higher Oil Sands Alberta Crown royalties, higher crude oil hedging losses, wider light/heavy crude oil price differentials, higher corporate expenses related to stock-based compensation, and a 7% strengthening in the Canadian dollar that decreased operating revenues.

Cash flow from operations in the third quarter was $585 million, essentially unchanged from $584 million in the same period of 2003. While earnings were higher than the third quarter of 2003, cash flow from operations was flat due to higher cash overburden spending.

Net earnings for the first nine months of 2004 were $767 million, compared to $773 million in the same period of 2003. Increases in net earnings were due to an 8% increase in crude oil and natural gas production, higher benchmark commodity pricing, higher refining margins in the Canadian downstream operations, and the impacts of year-over-year non-cash federal and provincial income tax adjustments. These factors were partially offset by higher Oil Sands Alberta Crown royalties, higher crude oil hedging losses, wider light/heavy crude oil price differentials and higher corporate expenses due to stock-based compensation. Year-to-date net earnings were also impacted by lower foreign exchange gains on U.S. dollar denominated long-term debt and the effects of a 7% strengthening in the Canadian dollar that decreased operating revenues.

Cash flow from operations for the first nine months of 2004 was approximately $1.50 billion, compared to approximately $1.56 billion in the first nine months of 2003. This decrease was primarily due to the same factors that impacted net earnings for the nine months ended September 30, 2004, excluding the impacts of the non-cash income tax adjustments and unrealized foreign exchange gains, as well as higher cash overburden spending in 2004.

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 September 30				9 months ended September 30
($ millions, after tax)	2004		2003		2004		2003
Net earnings before the following items	351		289		890		778
Firebag in-situ start-up costs	—		—		(14	)	—
Oil Sands Alberta Crown royalties	(78	)	(6	)	(186	)	(16	)
Impact of income tax rate reductions on opening net future income tax liabilities	—		(1	)	53		(87	)
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	64		9		24		98
Net earnings as reported	337		291		767		773
Net earnings attributable to common shareholders as reported	337		285		755		783

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded 2004 third quarter net earnings of $263 million, compared with $259 million in the third quarter of 2003. Increases in net earnings were due to a 45% increase in U.S. dollar denominated benchmark WTI crude oil prices, 3% higher crude oil production due to incremental Firebag bitumen production of 7,300 barrels of oil per day (bpd), and a more favourable sales mix of sweet crude oil and diesel fuel compared to sour crude and bitumen. These positive factors were primarily offset by higher Alberta Crown royalties, an increase in crude oil hedging losses, and a 7% strengthening of the Canadian dollar against the U.S. dollar that reduced operating revenues in the third quarter of 2004. Net earnings were also reduced, as anticipated, due to higher Firebag and overburden amortization expense, reduced margins due to the settlement of the inventory monetization program and higher transportation charges due to initial recognition of third party shipping credits in 2003. General operating costs and unscheduled maintenance costs at Firebag, higher general operating costs within base operations, and a one percent increase in the segmented effective tax rate also impacted net earnings.

Cash flow from operations for the quarter was $509 million, compared to $488 million in the third quarter of 2003. The increase was primarily due to the same factors that impacted net earnings, offset by an increase in cash overburden spending.

Net earnings for the first nine months were $733 million, compared to $634 million in the first nine months of 2003. In addition to the impact of non-cash income tax adjustments in 2004 and 2003, the increase in 2004 was primarily due to a 26% increase in U.S. dollar denominated benchmark WTI crude oil prices, and an 8% increase in crude oil production, including Firebag bitumen production of 9,400 bpd. These factors were offset, as anticipated, by higher Alberta Crown royalties and higher Firebag and overburden amortization, as well as higher crude oil hedging losses, general operating costs and unscheduled maintenance costs at Firebag, and higher general operating costs and unscheduled maintenance costs within the base plant. A 7% strengthening of the Canadian dollar against the U.S. dollar that reduced operating revenues in 2004 also impacted year-to-date net earnings.

Cash flow from operations for the first nine months of 2004 was approximately $1.30 billion, compared to $1.35 billion in the first nine months of 2003, primarily due to the same factors that impacted net earnings, as well as increased cash overburden spending.

Oil Sands production during the third quarter averaged 237,500 bpd, comprising 230,200 bpd of upgraded crude oil from base operations and 7,300 bpd of bitumen production from Firebag in-situ operations. This compares to production of 231,500 bpd of upgraded crude oil in the third quarter of 2003. Production in 2003 did not include any volumes from Firebag, which began producing bitumen in early 2004.

Third quarter production from Firebag was lower than originally targeted due to unscheduled maintenance in August and early September to the facility’s water treatment system. As a result of the shutdown, Suncor has further reduced its targeted annual bitumen production from Firebag to an average 10,000 bpd, compared with the revised target of 13,000 bpd.

Sales during the third quarter averaged 226,400 bpd, compared with 227,400 bpd during the third quarter of 2003. The sales mix of higher value sweet products increased to 63%, compared to 59% in 2003. Sales volumes were lower than production primarily due to the impact of unplanned maintenance and ongoing capacity restrictions related to the company’s proprietary pipeline between Oil Sands and Edmonton.

During the third quarter, cash operating costs for base operations averaged $10.50 per barrel, primarily reflecting seasonal operating cost and natural gas consumption trends. For further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures, see page 10.

Suncor’s next major growth stage targets oil sands production capacity of 260,000 bpd in late 2005. Construction of a second vacuum unit, a key component to reaching that milestone, is 75% complete. Construction of Firebag Stage 2, which is planned to provide bitumen supplies to future upgrader expansions, is 40% complete with steaming planned to start in late 2005. Both projects are on schedule and on budget.

Oil Sands Alberta 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 2004, 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.

In July, Suncor issued a statement of claim against the Crown, seeking, among other things, to overturn the government’s decision on the royalty treatment of Firebag. The Crown has issued a statement of defence. To date,

there have been no significant further developments with respect to these legal proceedings.

Alberta Crown 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 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 third quarter pretax Alberta Crown royalty estimate of $122 million ($78 million after tax) was based on:

• average 2004 crude oil pricing of approximately US$41.50 WTI per barrel (based on an average price of US$39 WTI per barrel for the first nine months of 2004, as well as forward crude oil pricing at September 30, 2004 of US$49 per barrel for the remainder of the year).

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

• an average annual Canadian/U.S. foreign exchange rate of $0.76.

Using these assumptions, Suncor revised its estimate of 2004 annualized pretax royalties to approximately $425 million ($272 million after tax).

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 Province of Alberta’s 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 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.

Based on crude oil pricing of US$34 per barrel WTI (an assumed long range mid-cycle price) and an average annual Canadian/U.S. foreign exchange rate of $0.80, prior years’ investment levels, future investment plans and certain other assumptions, Suncor does not believe its oil sands operation will be fully cash taxable until the next decade, 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 crude oil and natural gas price volatility or the timing of recognition of capital expenditures for tax purposes.

The information in the above paragraphs under “Oil Sands Alberta Crown Royalties” 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.

Natural Gas

Natural Gas recorded 2004 third quarter net earnings of $23 million, compared with $26 million during the third quarter of 2003. Higher production volumes and natural gas prices were more than offset by higher royalties, increased depletion, depreciation and amortization, and higher exploration expense including dry hole expense.

Cash flow from operations for the third quarter of 2004 was $80 million, unchanged from the third quarter of 2003.

Year-to-date net earnings were $80 million, compared to $81 million in the first nine months of 2003. Notwithstanding higher production volumes during the first nine months of the year, net earnings were offset by lower realized natural gas prices and higher depreciation, depletion and amortization expenses.

Cash flow from operations for the first nine months of the year was $253 million, compared to $234 million in the same period in 2003, reflecting the same factors that affected net earnings.

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 third quarter was 201 mmcf per day, compared to 194 mmcf per day in the third quarter of 2003. The 2004 production outlook targets an average of 200 to 205 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 2004 third quarter net earnings of $29 million, compared to net earnings of $9 million in the third quarter of 2003. The increase was primarily due to improved refinery utilization and higher refining margins offset by significantly lower retail margins.

Cash flow from operations for the third quarter increased to $52 million from $27 million in the third quarter of 2003 due to the same factors that increased net earnings.

Rack Forward, the retail and commercial customer division of EM&R, recorded a third quarter 2004 net loss of $3 million, compared to earnings of $4 million in the third quarter of 2003. Retail margins decreased to an average of 3.7 cents per litre (cpl) from 7.0 cpl in the third quarter of 2003 due to continuing competitive pressures in the Ontario market. Sales volumes were relatively flat between the third quarters of 2004 and 2003.

Rack Back, the refining and large industrial customer division of EM&R, recorded net earnings of $30 million in the third quarter of 2004, compared to net earnings of $4 million in the third quarter of 2003. The increase was primarily due to higher refining margins driven by higher chemical and distillate margins, partly offset by higher operating costs due

to higher natural gas prices. Refinery utilization in the third quarter increased to 104% from 91% in the same period of 2003. Refining margins on Suncor’s proprietary refined products averaged 8.8 cpl, compared to 6.5 cpl in 2003.

Energy marketing and trading activities, including physical trading activities, resulted in net earnings of $2 million in the third quarter of 2004, compared to $1 million in the same period of 2003.

EM&R recorded net earnings of $56 million for the first nine months of 2004, compared to $47 million in the same period of 2003. The increase year-over-year reflects higher refining margins and higher mark-to-market gains on inventory related derivatives. These positive impacts were partly offset by lower Rack Forward earnings due to retail competition and higher refined product purchases at prices above historical averages to fulfill customer commitments during the second quarter maintenance shutdown.

Cash flow from operations for the first nine months of 2004 increased to $131 million from $117 million in the first nine months of 2003, primarily due to the same factors that affected net earnings.

Refining & Marketing – U.S.A.

Refining & Marketing – U.S.A. (R&M) recorded net earnings of $15 million in the third quarter of 2004 compared to earnings of $14 million during the third quarter of 2003 (the R&M operations were acquired on August 1, 2003). Net earnings in 2004 were negatively impacted by reduced refining margins for asphalt and other heavy refined product sales, lower retail margins and higher depreciation and amortization and transportation costs. These factors were offset by lower income tax expense due to year-to-date reductions in the segmented effective tax rate.

Cash flow from operations for the third quarter was $21 million compared to $25 million in the third quarter of 2003, due to the same factors that impacted net earnings.

Refining margins in the third quarter 2004 averaged 5.1 cpl, compared to 7.9 cpl in the third quarter of 2003. Refinery utilization at the Denver refinery averaged 99% compared to 101% in the third quarter of 2003.

As a result of competitive pressures, retail margins averaged 4.2 cpl in the third quarter of 2004, compared to 6.4 cpl in the same period of 2003.

R&M recorded net earnings of $24 million and cash flow from operations of $36 million for the nine month period ended September 30, 2004.

In August 2004, the Denver refinery began construction on a US$300 million capital project upgrade to meet clean fuels regulations and to modify the refinery to handle 10,000 to 15,000 bpd of oil sands sour crude.

Corporate

Corporate recorded net earnings in the third quarter of 2004 of $7 million, compared to a net loss of $17 million during the third quarter of 2003. Corporate expenses were lower in 2004 primarily due to the impact of higher unrealized foreign exchange gains on U.S. dollar denominated long-term debt of $64 million in 2004 compared to $9 million in 2003. Excluding the impact of these gains, net earnings were negatively impacted by realized foreign exchange losses on operating accounts, higher stock-based compensation expense, attributable to expensing both time-based and performance based options and deferred share units, as well as costs related to the implementation of the company’s Enterprise Resource Planning (ERP) system.

Cash flow used in operations in the third quarter was $77 million, compared to $36 million used in the third quarter of 2003. Excluding the impact of unrealized foreign exchange gains on the U.S. dollar denominated debt and non-cash stock-based compensation expenses, the increase was primarily due to the earnings factors described above, as well as an increase in current income tax allocations from Suncor’s business segments.

Corporate recorded a net loss of $126 million in the first nine months of 2004, compared to a net loss of $3 million in the same period of 2003. After tax unrealized foreign exchange gains on Suncor’s U.S. dollar denominated debt for the first nine months of 2004 were $24 million, compared to gains of $98 million for the same period in 2003. Excluding the impacts of foreign exchange gains, the net loss for the first nine months of 2004 was higher primarily due to higher stock-based compensation costs, attributable to expensing both time-based and performance-based options and deferred share units, as well as costs related to the implementation of the ERP system. The net cash deficiency in the first nine months of 2004 increased to $218 million from the prior year net cash deficiency of $171 million, primarily due to the factors that affected net earnings, excluding the effects of unrealized foreign exchange gains on the U.S. dollar debt and non-cash stock-based compensation expenses.

During October 2004, Suncor met the predetermined performance criteria for the vesting of 2,097,000 common share options held by executive and non-executive employees. The vested options represent approximately 20% of the outstanding common share options granted under the SunShare Performance Stock Option Plan (“SunShare”), and less than 0.5% of the issued and outstanding common shares of Suncor. In the third quarter, the company recognized an additional $5 million of stock-based compensation expense related to the vesting of these options.

The company also believes it will meet performance criteria at the end of 2004 resulting in the subsequent vesting of up to 2,150,000 additional common share options,

representing approximately an additional 20% of the total common share options granted under SunShare. As the company has been accruing the costs of these options throughout 2004, there will not be any requirement for a one-time incremental accrual of stock-based compensation expense during the fourth quarter to reflect the vesting of these performance based options.

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 $212 million at the end of the third quarter, compared to a deficiency of $27 million at the end of the third quarter 2003. The increase in the working capital deficiency primarily reflects higher trade payables due to higher commodity prices and higher Alberta Crown royalty accruals, as well as increased trade payables associated with the company’s capital spending program. These increases were partially offset by higher trade receivables and inventory due to higher commodity prices and inventory levels.

In the third quarter, Suncor renewed $1.7 billion of its then outstanding credit facilities. The company’s new facilities are comprised of a $1.5 billion three year committed revolving facility and a $200 million 364 day revolving facility with a one year term period. Suncor’s undrawn lines of credit at September 30, 2004 were approximately $1.6 billion. Net debt decreased to approximately $2.2 billion from $2.5 billion at June 30, 2004. 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, 2004, 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 recognized a final $11 million after tax reduction in margins on the subsequent resale of a portion of this inventory. This amount has 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 a percentage of Suncor’s total production of crude oil, natural gas and refined products for specified periods of time. 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 third quarter of 2004, strategic crude oil hedging decreased Suncor’s after tax net earnings by $115 million compared to an after tax decrease of $36 million in the third quarter of 2003.

In accordance with the Board of Director’s decision in the first quarter of 2004 to suspend the crude oil hedging program, the company did not enter into any new strategic crude oil arrangements in the second or third 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 September 30:

($ millions)	2004		2003
Revenue hedge swaps and options	(586	)	(174	)
Margin hedge swaps	—		1
Interest rate swaps	26		32
	(560	)	(141	)

The company also uses derivative instruments to hedge risks specific to individual transactions. The estimated fair value of the unrealized net gains on these instruments was $13 million at September 30, 2004 compared to unrealized net gains of $1 million at December 31, 2003.

Energy Marketing and Trading Activities

For the quarter ended September 30, 2004 Suncor recorded a net pretax gain of $3 million compared to nil earnings during the third quarter of 2003, related to the settlement and revaluation of financial energy trading contracts. In the third quarter the settlement of physical trading activities also resulted in a net pretax gain of $2 million compared to a $1 million pretax gain in the third quarter of 2003. 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. The fair value of unsettled energy trading assets and liabilities at September 30, 2004 and December 31, 2003 were as follows:

($ millions)	September 30 2004	December 31 2003
Energy trading assets	20	5
Energy trading liabilities	9	5

Control Environment

Based on their evaluation as of the end of the three month period ended September 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 September 30, 2004, there were no changes in Suncor’s internal controls over financial reporting that occurred during the three month period ended September 30, 2004 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting.

At September 30, 2004, certain of the R&M business unit’s compensating controls and processes that were initially put in place at the time of the acquisition have been enhanced. The R&M business unit will continue to implement additional enhancements of their internal controls over financial reporting as deemed necessary.

Suncor is 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 also expected to be completed from 2004 to 2006 in connection with the implementation of Suncor’s ERP installation. 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.

Non-GAAP Financial Measures

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

Suncor provides a detailed numerical reconciliation of ROCE on an annual basis in the company’s annual MD&A, which is to be read in conjunction with the company’s annual consolidated financial statements. For a summarized narrative reconciliation of ROCE calculated on a September 30, 2004 interim basis, please refer to page 26 of the company’s Third Quarter 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 September 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 September 30		9 months ended September 30
			2004	2003	2004	2003
Cash flow from operations ($millions)	A		585	584	1 497	1 555
Dividends paid on preferred securities ($millions pretax)	B		—	11	9	34
Weighted average number of common shares outstanding (millions of shares)	C		453	450	453	449
Cash flow from operations (per share)	(A / C	)	1.29	1.30	3.31	3.46
Dividends paid on preferred securities (pretax, per share)	(B / C	)	—	0.03	0.02	0.08
Cash flow from operations after deducting dividends paid on preferred securities (per share)	[(A-B / C]		1.29	1.27	3.29	3.38

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 September 30						9 months ended September 30 (1)
		2004			2003			2004			2003
		$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel
Operating, selling and general expenses		174			186			614			620
Less: natural gas costs and inventory changes		4			(23	)		(80	)		(121	)
Accretion of asset retirement obligations		5			6			15			16
Taxes other than income taxes		7			6			21			18
Cash costs		190		9.00	175		8.20	570		9.45	533		9.30
Natural gas		30		1.40	35		1.65	117		1.90	135		2.35
Imported bitumen (net of other reported product purchases)		2		0.10	—		—	11		0.20	4		0.05
Cash operating costs – mining	A	222		10.50	210		9.85	698		11.55	672		11.70
Start-up costs		1			3			23			8
Add: in-situ inventory changes		—			—			2			—
Less: pre-start-up commissioning costs		(1	)		(3	)		(1	)		(8	)
In-situ (Firebag) start-up costs	B	—		—	—		—	24		0.40	—		—
Total cash operating costs	A+B	222		10.50	210		9.85	722		11.95	672		11.70
Depreciation, depletion and amortization		121		5.70	113		5.30	363		6.00	341		5.95
Total operating costs		343		16.20	323		15.15	1 085		17.95	1 013		17.65
Production (thousands of barrels per day)		230.2			231.5			220.3			210.3

OIL SANDS OPERATING COSTS – FIREBAG IN-SITU BITUMEN PRODUCTION

	Quarter ended September 30					9 months ended September 30 (1)
	2004			2003		2004			2003
	$ millions		$ /barrel	$ millions	$ /barrel	$ millions		$ /barrel	$ millions	$ /barrel
Operating, selling and general expenses	19			—		43			—
Less: natural gas costs and inventory changes	(9	)		—		(24	)		—
Accretion of asset retirement obligations	—			—		—			—
Taxes other than income taxes	—			—		—			—
Cash costs	10		14.90	—	—	19		9.30	—	—
Natural gas	8		11.90	—	—	24		11.70	—	—
Cash operating costs	18		26.80	—	—	43		21.00	—	—
Depreciation, depletion and amortization	5		7.45	—	—	13		6.35	—	—
Total operating costs	23		34.25	—	—	56		27.35	—	—
Production (thousands of barrels per day)	7.3			—		11.2			—

(1) Production in the base operations for the nine months ended September 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.