EXHIBIT 2

Interim Management's Discussion and Analysis for the third fiscal quarter ended

September 30, 2003

Exhibit 2

Management’s Discussion and Analysis

All financial figures are unaudited and in Canadian dollars unless noted otherwise.

This Management’s Discussion and Analysis should be read in conjunction with the attached September 30, 2003 unaudited consolidated interim financial statements and notes. Readers should also refer to Suncor’s 2002 Annual Information Form and Management’s Discussion and Analysis on pages 16 to 38 of Suncor’s 2002 Annual Report.

Industry Indicators

	3 months ended Sept 30		9 months ended Sept 30
(average for the period)	2003	2002	2003	2002

West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	30.20	28.25	31.00	25.40
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	41.35	43.65	44.75	39.30
Light/heavy crude oil differential US$/barrel – WTI @ Cushing less Bow River @ Hardisty	8.10	5.40	7.40	5.35
Natural gas US$/thousand cubic feet @ Henry Hub	5.10	3.25	5.75	3.00
Natural gas Cdn$/gigajoule @ AECO	5.95	3.10	6.70	3.50
New York Harbour 3-2-1 crack (1)US$/barrel	6.35	3.10	5.40	2.95
Exchange rate: Cdn$:US$	0.72	0.64	0.70	0.64

(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.

ANALYSIS OF CONSOLIDATED EARNINGS AND CASH FLOW

Net earnings for the quarter were $295 million, compared to $184 million for the third quarter of 2002. Increased earnings were primarily the result of:

• Record crude oil production.

• Benchmark crude oil and natural gas prices that were higher than the third quarter of 2002.

• Higher downstream margins and the incremental earnings impact of the company’s Denver-based refining and marketing operations, which were acquired August 1, 2003.

• Lower crude oil hedging losses.

These positive impacts were partly offset by:

• A lower realization on Suncor’s crude oil sales basket and natural gas prices as a result of a stronger Canadian dollar compared to the U.S. dollar. Because crude oil and natural gas are sold based on U.S. dollar benchmark prices, the narrowing exchange rate reduces the Canadian dollar value of Suncor’s products. The realization on the sales basket was also impacted by a lower percentage of high-value products in Suncor’s sales mix.

• Higher expenses at the company’s Sarnia refinery resulting from a fire on August 14, 2003 and the 11-day operational impacts of an unrelated power outage in Ontario and the northeastern United States.

Cash flow from operations for the third quarter of 2003 increased to $584 million from $447 million reported in the third quarter of 2002. The increase was primarily due to the same factors that increased earnings.

Net earnings for the first nine months of 2003 increased to $784 million from $503 million in the same period of 2002, primarily due to higher production volumes, higher benchmark commodity prices and higher unrealized foreign exchange gains. These positive impacts were partially offset by an increase in non-cash future income tax expense, a stronger Canadian dollar, higher crude oil hedging losses, wider heavy/sour crude oil price differentials and a $34 million non-recurring after-tax gain on the sale of Suncor’s retail natural gas marketing business in 2002.

Cash flow from operations for the first nine months increased to $1.56 billion, compared to $980 million in the first nine months of 2002. The increase was primarily due to the same factors that impacted earnings, excluding the impacts of the unrealized foreign exchange gain and the non-cash future tax expense. In 2002, cash flow from operations was reduced by payments made under Suncor’s long-term employee incentive plan.

The following table explains some of the factors impacting Suncor’s net earnings. For comparability purposes, readers should rely on the reported net earnings, which are prepared and presented in the interim Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles (GAAP).

Net Earnings Components

	3 months ended Sept 30				9 months ended Sept 30
($ millions)	2003		2002		2003		2002

Net earnings before the following items	287		210		773		453
Sale of retail natural gas marketing business	—		—		—		34
Impact of income tax changes	(1	)	—		(87	)	10
Unrealized foreign exchange gains/(losses) on U.S. dollar denominated long-term debt	9		(26	)	98		6
Net earnings as reported	295		184		784		503
Net earnings attributable to common shareholders as reported	289		169		794		483

ANALYSIS OF SEGMENTED EARNINGS AND CASH FLOW

Oil Sands

Oil Sands recorded third quarter net earnings of $261 million, compared with $233 million in the third quarter of 2002. The increase reflects higher production, higher benchmark crude oil prices and lower crude oil hedging losses of $36 million in the third quarter of 2003, compared to $55 million in the third quarter of 2002. These factors were partly offset by a lower realization on Suncor’s crude oil sales basket as a result of a stronger Canadian dollar and a lower percentage of high-value products in Suncor’s sales mix. Earnings were also partly offset by a higher effective income tax rate, higher natural gas prices and higher operating and maintenance expenses in the third quarter of 2003, compared to the same period in 2002.

Cash flow from operations for the third quarter was $488 million, compared to $443 million in the third quarter of 2002. The increase was primarily due to the same factors that increased earnings.

Net earnings for the first nine months of 2003 were $634 million, compared to $545 million in the first nine months of 2002. The increase was primarily due to higher production volumes and higher U.S. dollar benchmark crude oil prices. These positive factors were partially offset by a stronger Canadian dollar, higher non-cash future income tax expense (including the effects of a tax rate increase in the second quarter), wider heavy/sour crude oil price differentials, higher average natural gas prices and higher operating and maintenance costs.

Cash flow from operations for the first nine months increased to $1.350 billion from $1.022 billion in the first nine months of 2002, primarily due to the same factors that increased earnings in 2003 compared to 2002.

Third quarter production averaged a record 231,500 barrels of crude oil per day (bpd), compared to 207,900 bpd in the third quarter of 2002. Sales during the third quarter averaged 227,400 bpd, compared with 206,700 bpd during the third quarter of 2002. Sales were slightly lower than production during the quarter because of issues related to a number of refinery maintenance shutdowns in the U.S. Midwest market and the August power failure in Ontario and the northeast United States. The power failure temporarily halted pipeline shipments, forcing Suncor to retain a higher than normal inventory. Inventory for the quarter, which grew by approximately 400,000 barrels, is expected to be reduced in the fourth quarter of 2003.

Cash operating costs averaged $9.85 per barrel for the third quarter of 2003, below the company’s target of $10.00 to $10.50 per barrel. Second quarter 2003 cash operating costs were $13.20 per barrel. The decrease from

the second quarter was primarily due to higher production volume, higher sour crude product mix (which requires less processing than sweet crude) and seasonally reduced natural gas consumption. Suncor continues to expect cash operating costs for 2003 to average $11.25 to $11.75 per barrel.

Suncor includes cash operating cost per barrel data because investors may use this information to estimate the company’s ability to generate net earnings and cash flow from operations. This additional information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. Refer to page 9 of this document for more details.

Crown royalties in effect for Oil Sands mining operations require payments to the Government of Alberta of 25% of net revenues less allowable costs, including the deduction of capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of gross revenues before hedging activity. Suncor is currently in discussion with the government about several aspects of the company’s Oil Sands royalties, including the classification for royalty purposes of Suncor’s Firebag leases, and the terms under which the company will complete its transition to the government’s generic bitumen-based royalty regime in 2009, which may involve a reduction in allowed costs for royalty purposes. At this time, it is not possible to predict the ultimate resolution of these discussions or the impact on future royalty payments.

Based on current assumptions in Suncor’s long-range plans relating to future oil prices, production levels, operating costs and capital expenditures, Suncor would continue to pay the minimum 1% royalty rate until approximately 2009. Continuing higher oil prices at or near current levels could cause the 25% R-C royalty to commence at an earlier date, as could the ultimate resolution of discussions with the government on royalty issues.

Natural Gas

Natural Gas recorded third quarter net earnings of $27 million, compared to $1 million during the third quarter of 2002. The increase primarily reflects the favourable impact of higher commodity prices, higher volumes and a lower effective income tax rate, partially offset by a strengthening Canadian dollar, and higher non-cash and royalty expenses.

Cash flow from operations for the third quarter of 2003 was $80 million, up from $36 million in the third quarter of 2002. Cash flow from operations in the third quarter reflected the same factors that affected net earnings.

Net earnings for the first nine months of 2003 were $92 million, compared to $18 million in the first nine months of 2002. The increase resulted from higher commodity pricing, higher volumes, and the impact of lower non-cash future income tax expense recorded in the second quarter. These factors were partially offset by a strengthening Canadian dollar, higher royalties, higher non-cash exploration expenses, and higher depreciation, depletion and amortization expenses.

Cash flow from operations for the first nine months of the year was $234 million, up from $111 million reported in the same period of 2002. The increase reflects the same factors that affected net earnings.

Natural gas production in the third quarter of 2003 was 194 million cubic feet per day (mmcf/d), compared to 181 mmcf/d in the third quarter of 2002. Year-to-date production was 184 mmcf/d, up from 178 mmcf/d during the first nine months of 2002.

Offsetting increasing internal natural gas consumption continues to be a key long-term strategy in Natural Gas. With the acquisition of the Denver refinery, it is estimated that current Suncor natural gas purchases are approximately 130 mmcf/d. Oil Sands consumes an additional 40 mmcf/d of non-purchased gas received, as available, under an existing third-party agreement in exchange for coker gases produced as a byproduct of upgrading operations.

Energy Marketing and Refining – Canada

Energy Marketing and Refining – Canada (EM&R) recorded 2003 third quarter net earnings of $10 million, unchanged from the third quarter of 2002. Increased earnings due to higher refining margins were offset by increased expenses at the Sarnia refinery resulting from a fire on August 14, 2003 and an unrelated power outage that struck much of Ontario and the northeastern United States, significantly impacting operations for 11 days. Higher commercial and reseller margins were partially offset by lower retail volumes.

Cash flow from operations in the third quarter was $27 million, compared to $35 million in the third quarter of 2002.

Rack Forward, the retail and commercial customer division of EM&R, recorded third quarter net earnings of $5 million, compared with $4 million in the third quarter of 2002. Higher commercial and reseller margins were partially offset by lower retail volumes resulting from the weakened economic conditions in southwestern Ontario.

Rack Back, the refining and industrial customer division of EM&R, reported third quarter net earnings of $4 million, compared to $5 million in the third quarter of 2002. The decrease was primarily due to increased expenses incurred following the power outage as well as reduced refinery utilization. These negative impacts were partially offset by third quarter refining margins, which averaged 6.5 cents per litre, a 48% improvement over the same quarter of 2002. The increase in margins was primarily the result of reduced supply following the power outage and stronger than normal demand.

Energy marketing and trading activities resulted in net earnings of $1 million in the third quarter of 2003, remaining even with the $1 million in net earnings from energy marketing activity in the third quarter of 2002. Trading activities did not commence until the fourth quarter of 2002.

EM&R recorded year-to-date net earnings of $47 million, compared to $10 million in the same period of 2002 (excluding a one-time $34 million after-tax gain in 2002 on the sale of the retail natural gas marketing business).

Cash flow from operations for the first nine months of 2003 increased to $117 million from $63 million in the first nine months of 2002, primarily due to higher refining margins and improved refinery utilization.

On October 29, the Sarnia refinery completed the majority of a 32-day maintenance shutdown on a portion of the plant. During the shutdown, a gasoline desulphurization unit was tied into the refinery. The unit, which is planned to begin operating later in the fourth quarter, is intended to enable Suncor to produce gasoline with sulphur content less than 30 parts per million, ahead of the legislated deadline of January 1, 2005.

Subsequent to the end of the quarter, Suncor and Shell Canada Products announced an agreement under which Suncor’s Sarnia refinery will process Shell’s Sarnia refinery high sulphur diesel into ultra low sulphur diesel. Shell will pay a fee for this service.

This 20-year agreement enables both companies to meet federal regulations for ultra low sulphur diesel fuel that take effect on June 1, 2006. The new regulations will limit sulphur in on-road diesel fuel to a maximum of 15 parts per million, from its current maximum level of 500 parts per million.

Engineering and construction details of Suncor’s new facilities are in development and being finalized. Subject to regulatory approval, Suncor expects construction to begin in May 2004, with project completion expected in the first quarter of 2006. The project will cost an estimated $300 million, an increase from Suncor’s original estimate of $225 million due to the larger scale required to handle Shell diesel volumes.

Refining and Marketing – U.S.A.

On August 1, 2003, Suncor acquired a Denver-area refinery and related pipeline and retail assets. The acquisition is expected to provide Suncor with the flexibility to move additional Oil Sands production into the U.S. marketplace. Suncor paid US$150 million (about Cdn$210 million) for the assets, plus the cost of crude oil, product inventories and other closing adjustments.

The acquisition includes:

• A 60,000 barrel per day refinery located in the Denver area.

• 43 Phillips 66-branded retail stations, primarily in the Denver area – plus contract agreements with more than 150 Phillips-branded marketer outlets throughout the state of Colorado.

• The Rocky Mountain and Centennial pipeline systems. Suncor has 100% ownership of the 483 kilometre (300 mile) Rocky Mountain pipeline system and 65% ownership of the 140 kilometre (87 mile) Centennial pipeline system.

Based on preliminary engineering, the company estimates it will spend US$175 million to $225 million (approximately Cdn$250 million to $325 million) between 2003 and 2006 to meet low sulphur fuels legislation and to begin preliminary work to enable the refinery to integrate Oil Sands sour crude blends. Post 2006, Suncor expects to have the potential to integrate as much as 50,000 bpd of Oil Sands crude into the refinery, including 15,000 to 20,000 bpd of Oil Sands sour crude.

As part of the agreement to acquire these assets, Suncor will assume obligations at the refinery that ConocoPhillips had with the United States Environmental Protection Agency and the State of Colorado. These obligations are expected to require expenditures between US$25 million to $30 million (approximately Cdn$35 to $45 million) between 2003 and 2006. The expenditures, intended to reduce air emissions at the refinery, are expected to be primarily capital.

With the acquisition of the U.S. downstream assets, Suncor assumed a workforce of approximately 585 employees, including about 300 retail employees, bringing Suncor’s total workforce to more than 4,000 employees. Suncor also assumed the existing contract with the local Paper, Allied-Industrial Chemical and Energy Workers International Union. This four-year contract will expire in January 2006.

For the two months ended September 30, Refining and Marketing – U.S.A. net earnings were $14 million, including after-tax transition start-up costs of approximately $2 million. Cash flow from operations for the two months was $25 million.

Since assuming ownership of the Denver-based assets, development of an effective and functioning control environment to support financial reporting and disclosure processes has been a key management priority. While significant advances were made throughout the period, further development and refinement will be required in the short term. Management believes it has put in place temporary compensating controls and processes to mitigate known deficiencies.

As part of Suncor’s growth strategy, the company will continue to seek additional downstream integration opportunities. Those opportunities could include long-term contracts, joint ventures and potential acquisitions or expansion of Suncor’s existing assets.

Corporate

Corporate recorded a net loss of $17 million in the third quarter of 2003, compared to a net loss of $60 million during the same period in 2002. The lower expense in 2003 is primarily due to an unrealized after-tax foreign exchange gain of $9 million in 2003, compared to a $26 million loss in 2002. Expenses were also reduced by lower overall interest costs resulting from increased capitalization of interest due to higher capital spending. Corporate office expenses include a stock-based compensation expense of $2 million related to stock option grants made in 2003. On a prospective basis, Suncor began expensing options in 2003.

Cash flow used in operations in the quarter was $36 million, compared to $67 million in the third quarter of 2002.

Corporate recorded a net loss of $3 million in the first nine months of 2003, compared to a loss of $104 million in the same period of 2002. The decrease resulted from a reduction in after-tax net interest expenses of approximately $25 million due to lower borrowing levels and the increased capitalization of interest due to higher capital spending, and an increase in the unrealized after-tax foreign exchange gain of $92 million. These positive factors were partially offset by the effect of a stock-based compensation expense of $5 million related to stock options granted in 2003.

Cash flow used in operations in the first nine months of 2003 was $171 million, compared to $216 million in the first nine months of 2002. The decrease was primarily due to employee long-term incentive plan costs paid in 2002, partially offset by higher income tax payments in 2003.

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 $27 million at the end of the third quarter, compared to a deficiency of $118 million at the end of 2002. The decrease in the deficiency primarily reflects the purchase of inventory associated with the acquisition of the Denver assets.

The Denver asset purchase and settlement of payables related to the second quarter planned maintenance shutdown at Oil Sands resulted in an increase in net debt during the third quarter of about $100 million. Despite this increase, Suncor’s net debt at the end of the quarter was approximately $365 million lower than 2002 year-end net debt of $2.7 billion (excluding 2003 unrealized foreign exchange impacts, net debt was approximately $240 million lower). Suncor continues to target its debt level at approximately two times cash flow at mid-cycle oil prices.

Suncor’s undrawn lines of credit as of September 30, 2003 were approximately $1.1 billion. Further, outstanding shelf prospectuses filed in 2002 in Canada and the U.S. enable the company to issue, respectively, up to Cdn$500 million in medium-term notes in Canada and up to US$500 million in debt or equity in Canada or the U.S.

Suncor continues to believe its capital resources as at September 30, 2003 and cash flow from operations are sufficient to fund its 2003 capital spending budget, which was revised to $1.5 billion in the second quarter from the original 2003 estimate of approximately $1 billion. The original estimate did not include capital spending for the U.S. downstream acquisition.

Crude oil and natural gas prices are based on a U.S. dollar benchmark that results in Suncor’s realized commodity prices being influenced by the Canadian/U.S. currency exchange rate, creating an element of uncertainty for the company. Suncor currently estimates that an annualized one cent change in the Canadian/U.S. exchange rate would result in a change in cash flow from operations of approximately $40 million and a change in net earnings of approximately $20 million. The net earnings effect includes the impact of offsetting foreign exchange gains (losses) on the company’s U.S. dollar denominated debt.

Based on current estimates, management does not believe that movements in Canadian/U.S. foreign exchange rates would have a material impact on the reported results of its U.S. operations acquired in the third quarter.

Oil Sands and Natural Gas Reclamation Cost Estimates

In connection with company and external party reviews in Oil Sands and Natural Gas, Suncor has increased its reclamation cost estimate to approximately $950 million, from the previous estimate of $650 million. Approximately $230 million of the increase is due to an increase in Oil Sands 2002 cost estimate from $610 million to approximately $840 million. These increases reflect changes in the scope, cost and timing of reclamation recovery activities, including the consolidated tailings technology at Oil Sands and gas plant and facilities reclamation at Natural Gas. The majority of the costs in Oil Sands are projected to occur over a time horizon extending up to approximately 2060. In the fourth quarter of 2003, prospective changes in the reclamation cost estimate will result in additional after-tax expenses of approximately $2 million.

Oil Sands Operating Costs

	3 months ended September 30						9 months ended September 30
	2003			2002			2003			2002
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	192			187			636			595
Less: natural gas costs and inventory changes	(23	)		(14	)		(121	)		(72	)
Taxes other than income taxes	6			6			18			17
Cash costs	175		8.20	179		9.35	533		9.30	540		10.00
Natural gas	35		1.65	20		1.05	135		2.35	82		1.50
Imported bitumen (net of other reported product purchases)	—		—	—		—	4		0.05	—		—
Cash operating costs	210		9.85	199		10.40	672		11.70	622		11.50
Depletion, depreciation and amortization	111		5.20	119		6.25	336		5.85	323		5.95
Total operating costs	321		15.05	318		16.65	1 008		17.55	945		17.45
Production (thousands of barrels per day)	231.5			207.9			210.3			198.4

Legal Notice – Forward-looking Information

This news release contains certain forward-looking statements that are based on Suncor’s current expectations, estimates, projections and assumptions made in light of its experience and its perception of historical trends. The forward-looking statements speak only as of the date hereof and Suncor undertakes no duty to update these statements to reflect subsequent changes in assumptions (or the trends or factors underlying them) or actual events or experience.

All statements that address expectations or projections about the future, including statements about Suncor’s strategy for growth, expected and future production volumes, operating and financial results, are forward-looking statements. Some of the forward-looking statements may be identified by words like “expected,” “target,” “aimed,” “outlook,” “planned” 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 as a result of known and unknown risks, uncertainties and other factors, such as changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; fluctuations in commodity prices; fluctuations in currency exchange rates; Suncor’s ability to respond to changing markets and access the capital markets; the ability of Suncor to receive timely regulatory approvals; the successful and timely implementation of its growth projects including the Firebag in-situ operations and Voyageur; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other resource development projects; Suncor’s ability to comply with current and future environmental laws; the accuracy of Suncor’s production estimates and production levels and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations, joint venture partners, suppliers and customers; 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 exploration or development projects or capital expenditures; actions by governmental authorities including increasing taxes, 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. See Suncor’s current Annual Information Form, Annual Report and Quarterly Reports to Shareholders and other documents Suncor files with securities regulatory authorities, for further details.