EXHIBIT 3

Management’s Discussions and Analysis for the fiscal year ended December 31, 2002, dated February 27, 2003

Management’s Discussion and Analysis

This Management’s Discussion and Analysis 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 38 for additional information. All financial information is reported in Canadian dollars unless noted otherwise. Natural gas converts to crude oil equivalent at a ratio of six thousand cubic feet to one barrel. References to “Suncor” or “the company” mean Suncor Energy Inc., its subsidiaries and joint venture investments, unless the context otherwise requires. “Notes” refers to the notes to Suncor’s 2002 Consolidated Financial Statements.

The tables and charts in this document form an integral part of Management’s Discussion and Analysis.

Suncor Overview and Strategic Priorities

Suncor Energy Inc. is an integrated Canadian energy company with its corporate head office located in Calgary, Alberta. Suncor’s core business segment, Oil Sands, mines and upgrades oil sands near Fort McMurray, Alberta, to produce refinery feedstock and diesel fuel. Suncor’s conventional Natural Gas business (NG) produces natural gas in Western Canada, providing revenues and creating a price hedge against the company’s internal natural gas consumption. The Energy Marketing and Refining business (EM&R) refines crude oil and markets finished petroleum products to customers primarily in Ontario and Quebec, including retail customers in Ontario under the Sunoco brand.

Suncor’s overall corporate strategy is based on:

•Developing Oil Sands large resource base through mining and in-situ technology.

•Expanding Oil Sands facilities to increase the production of crude oil.

•Controlling costs through a strong operational focus, economies of scale and improved management of engineering, procurement and construction on major projects.

•Reducing risk associated with natural gas price volatility by producing volumes exceeding internal demand.

•Developing new marketing and refining opportunities that further integrate Suncor’s upstream and downstream businesses.

•Managing environmental and social performance to earn continued support among community, government and other stakeholders for Suncor’s ongoing operations and growth plans.

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Net Earnings Components

Year ended December 31

($ millions)	2002		2001		2000
Net earnings before the following items:	710		424		414
Natural Gas divestments and restructuring	—		5		39
Stuart Oil Shale Project asset write-down	—		(3	)	(80	)
Sale of retail natural gas marketing business	35		—		—
Oil Sands project start-up costs(1)	(2	)	(90	)	(9	)
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	8		—		—
Impact of income tax rate reductions on opening future tax balances(2)	10		52		13
Net earnings	761		388		377

Cash Flow Provided from Operations Components

Year ended December 31

($ millions)	2002		2001		2000
Cash flow provided from operations before the following items:	1 443		1 061		1 009
Natural Gas divestments and restructuring	—		(1	)	(9	)
Oil Sands project start-up costs and overburden removal(1)	(3	)	(229	)	(42	)
Cash flow provided from operations	1 440		831		958

(1)Project start-up costs refer to costs associated with Project Millennium in 2000 and 2001 and costs associated with the Firebag In-situ Oil Sands Project in 2002.

(2)See note 8.

The above tables are intended to enhance readers’ understanding of some of the factors impacting Suncor’s net earnings and cash flow provided from operations. For comparability purposes readers should rely on the reported net earnings and cash flow provided from operations, which are prepared and presented in the Consolidated Financial Statements in accordance with Canadian generally accepted accounting principles.

Earnings Analysis

Net Earnings and Cash Flow Analysis

Net earnings for 2002 increased to $761 million from $388 million in 2001, primarily as a result of higher sales revenues from increased Oil Sands production and improved crude oil price realizations. Net earnings were also positively impacted by reduced project start-up costs at Oil Sands, a gain on the sale of EM&R’s retail natural gas marketing business and an unrealized foreign exchange gain. These increases were partially offset by higher crude oil hedging losses and higher cash and non-cash operating expenses, financing costs and higher income taxes. The higher 2002 income taxes are partly a result of the positive earnings impact of enacted rate reductions in 2001 on the company’s future income tax liabilities.

Cash flow provided from operations in 2002 was $1.44 billion, compared with $831 million in 2001. The increase was primarily due to the same factors that increased net earnings, excluding the gain on the sale of the company’s retail natural gas marketing business. These favourable factors were partially offset by payments under Suncor’s long-term employee incentive plan and increased overburden removal expenditures.

Consolidated Financial Results

Year ended December 31

($ millions)	2002	2001	2000
Net earnings	761	388	377
Cash flow provided from operations	1 440	831	958
Investing activities	861	1 680	1 607
Dividends
Common shares	77	75	75
Preferred securities	48	48	47
Long-term debt	2 686	3 113	2 192
Return on capital employed (%) (1)	14.6	17.8	16.6
Return on capital employed (%) (2)	13.8	7.5	9.3

(1)Net earnings adjusted for after-tax long-term interest expense, divided by average capital employed. Average capital employed is the total of shareholders’ equity and short-term and long-term debt, less capitalized costs of major projects in progress, at the beginning and end of the year, divided by two.

(2)Average capital employed includes capitalized costs related to major projects in progress.

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Industry Indicators

(Average for the year unless otherwise noted.)	2002		2001		2000
WTI crude oil US$/barrel at Cushing	26.10		25.90		30.25
Canadian 0.3% par crude Cdn$/barrel at Edmonton	40.75		39.34		44.56
Light/heavy crude oil differential US$/barrel WTI @ Cushing/Bow River @ Hardisty	5.95		9.50		6.85
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	3.25		4.40		3.90
Natural gas (Alberta spot) Cdn$/mcf at AECO	4.05		6.30		5.00
New York Harbour 3-2–1 crack US$/barrel(1)	3.35		4.45		5.45
Refined product demand (Ontario) percentage change over prior year	0.8	(2)	(2.6	)	2.6
Exchange rate: Cdn$:US$	0.64		0.64		0.67

(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.

(2)Estimate.

Consolidated Earnings Analysis

Revenues were $4.904 billion in 2002, compared to $4.199 billion in 2001. This increase was primarily the result of the following items:

•The Project Millennium expansion increased Oil Sands sales to an average 205,300 barrels per day (bpd) from 121,500 bpd in 2001. In addition, expanded hydrotreating capacity increased the sales mix percentage of higher value sweet crude oil and diesel fuel relative to lower value sour crude oil and bitumen to 62/38% in 2002 from 58/42% in 2001. Increased production and a higher value sales mix were the most significant factors in the overall increase in consolidated revenues.

Project Millennium

A $3.4 billion expansion of Suncor’s Oil Sands mining and upgrading operations was commissioned in December 2001.

•Suncor’s overall crude oil price realization increased in 2002, averaging $33.65 per barrel (including the effect of pretax hedging losses of $243 million), compared to $29.17 per barrel in 2001 (including the effect of pretax hedging losses of $224 million). The increase was due to the strengthening of the West Texas Intermediate (WTI) benchmark price during 2002, higher Oil Sands production and the narrowing of sour crude oil and bitumen price differentials.

•Marketing revenue for third party crude oil and bitumen increased to $149 million in 2002 from $99 million in 2001. This marketing is undertaken to increase market intelligence and create new markets and customers for Suncor’s proprietary crude oil.

The above factors were partially offset by the following:

•NG revenues in 2002 were $315 million, compared to revenues of $458 million in 2001. Suncor’s average natural gas sales price decreased to $3.91 per thousand cubic feet (mcf) in 2002, from $6.09 per mcf in 2001.

•Sales in EM&R were $2.361 billion in 2002, compared to $2.588 billion in 2001. The decrease primarily reflects lower refining volumes, lower product prices and the impact of the sale of the retail natural gas marketing business in 2002.

Purchases of crude oil and products decreased to $1.298 billion in 2002 from $1.595 billion in 2001. The decrease was primarily due to reductions in EM&R’s purchase requirements where improved refinery reliability, lower downstream sales levels and the sale of its retail natural gas marketing business, reduced the need for third party product purchases.

Operating, selling and general expenses were $1.292 billion in 2002, compared to $1.012 billion in 2001. The increase primarily relates to the higher expense of operating the expanded facilities at Oil Sands, including additional expenses related to unplanned maintenance shutdowns, employee benefits and insurance costs. These factors were partially offset by decreases in long-term incentive compensation costs (see note 11b), research and development costs and the absence of costs in 2002 related to the Stuart Oil Shale Project.

The continued weak performance of equity markets increased Suncor’s employee future benefits cost to $52 million in 2002 from $30 million in 2001. Benefit costs are expected to increase to about $60 million in 2003. Annual costs beyond 2003 may change depending on market performance and/or changes in assumptions (see note 7).

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In 2002 insurance expenses were $22 million reflecting an increase of $14 million due to higher premiums as a result of tightening insurance market capacity. In 2003, the company anticipates a further $5 million increase reflecting continued tight capacity.

To mitigate its exposure to property and business interruption losses, the company has purchased insurance policies with a combined coverage up to US$1.150 billion, net of deductible amounts. The policies stipulate a property loss deductible of US$10 million per incident and a business interruption loss deductible per incident based on the greater of US$50 million or 30 days of gross earnings lost (as defined in the respective insurance policies). Gross earnings can be influenced by such factors as production levels and commodity prices.

Depreciation, depletion and amortization increased to $585 million in 2002, compared to $360 million in 2001. Depreciation on Project Millennium assets that came into service in January 2002 accounted for approximately half of the increase. Overburden amortization was also up in 2002 reflecting increased production levels, higher removal costs and, to a lesser extent, a higher composite life-of-mine overburden stripping ratio of 0.47 compared to 0.43 in 2001.

Exploration costs in 2002 increased to $26 million, compared to $22 million in 2001. The increase primarily relates to lease retention costs incurred with respect to the Firebag In-situ Oil Sands Project.

Firebag In-situ Oil Sands Project

Firebag is designed to recover bitumen from deep oil sands deposits using horizontal drilling technology with minimal surface disturbance.

Royalty expenses decreased to $98 million in 2002, from $134 million in 2001, primarily due to lower natural gas prices. This decrease was partly offset by higher Oil Sands royalties due to higher production. The Oil Sands Crown royalty rate in 2002 was unchanged from 2001 at 1% of gross revenue.

Financing expenses (after capitalization of interest on projects) increased to $124 million in 2002, from $16 million in 2001. In 2001 interest of $103 million was capitalized on Project Millennium. Overall, financing costs (before capitalization of interest on projects) increased in 2002 to $155 million from $143 million in 2001, reflecting higher average debt levels in 2002.

Income tax expense increased to $383 million in 2002 from $125 million in 2001. Suncor’s effective income tax rate in 2002 was 33%. This reflected a higher than anticipated 10% net reduction related to the federal resource allowance deduction and non-deductible Crown royalties (see note 8). Suncor’s 2001 effective income tax rate was 24%, primarily reflecting a future income tax reduction of 6% related to federal resource allowance and non-deductible Crown royalties, as well as the effect of an 11% reduction in federal and provincial income tax rates on the revaluation of future income taxes.

Suncor anticipates its effective tax rate in 2003 will be about 35%. The effective rate can vary depending on changes in such factors as enacted tax rates, the resource allowance deduction and non-deductible Crown royalties. Based on prior years’ investment levels and planned future investment plans, Suncor does not expect its upstream operations to be cash taxable until 2010. This expectation can change depending on such factors as commodity prices, profitability, capital investments and changes in tax rates and laws.

Dividends

During 2002, Suncor’s annual common share dividend, after accounting for the two-for-one stock split in May 2002, was $0.17 per share, unchanged from 2001. Dividend levels are reviewed quarterly in light of Suncor’s growth-related initiatives, financial position, financing requirements, cash flow and other factors considered relevant by the Board of Directors.

Corporate Office Expenses

Corporate office after-tax expenses increased to $128 million in 2002 from $92 million in 2001. The increase reflects the higher financing costs discussed above, partially offset by lower long-term compensation costs and lower research and development expenditures.

The corporate office had a net cash deficiency of $225 million in 2002, compared to $165 million in 2001. The increase is a result of the payments associated with the long-term compensation plan and higher capital expenditures, partially offset by lower net income tax payments.

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Trading Activities

In 2002, Suncor’s Board of Directors approved commencement of energy trading activities and after developing an appropriate control framework, the company began limited trading activities in November. Trading activities are principally focused on the commodities the company produces, adding potential for new revenue and providing a new window into energy product markets. The company uses the mark-to-market method of accounting for the new energy trading activities. Under mark-to-market accounting, physical and financial energy contracts are recorded at fair value at each balance sheet date. The net gain or loss from the revaluation of these contracts is recorded in the Statement of Earnings for the period. Net trading losses were negligible for the period ended December 31, 2002.

A separate risk management function directs and monitors practices and policies and provides independent verification and valuation of Suncor’s trading and marketing activities.

Critical Accounting Policies

Suncor’s critical accounting policies are defined as those that are both important to the portrayal of the company’s financial position and operations and require management to make judgments based on underlying estimates and assumptions about future events and their effects. Underlying estimates and assumptions are based on historical experience and other factors that are believed by management to be reasonable under the circumstances. These estimates and assumptions are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as Suncor’s operating environment changes. The company believes the following are the most critical accounting policies and estimates used in the preparation of its consolidated financial statements. For information concerning the company’s other significant accounting policies, see “Summary of Significant Accounting Policies” on page 41 of the Consolidated Financial Statements.

Property, Plant and Equipment

Suncor accounts for upstream exploration and production activities using the “successful efforts” method. The application of the successful efforts method of accounting requires Suncor’s management to determine the proper classification of activities designated as developmental or exploratory, which ultimately determines the appropriate accounting treatment of the costs incurred. The results from a drilling program can take considerable time to analyze and the determination that commercial reserves have been discovered requires both judgment and industry experience. Where it is determined that exploratory drilling will not result in commercial production, the exploratory costs are written off and reported as “dry hole” costs (see note 18). Despite this, properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities insufficient to be economic. Tests of impairment of capitalized properties are based on estimates of future cash flow from the properties. Estimates of future cash flows are subject to significant management judgment concerning oil and gas prices, production quantities and operating costs. Where management assesses that a property is fully or partially impaired, the book value of the property is either completely removed from the company’s records (“written off”) or partially removed from the company’s records (“written down”).

The company’s plant and equipment, including upgrading and refining assets, are amortized on a straight-line basis over the estimated useful life of the assets. The company determines useful life based on prior experience with similar assets and, as necessary, in consultation with others who have expertise with the assets in question. However, the actual useful life of the assets may differ from management’s original estimate due to factors such as technological obsolescence, regulatory requirements and maintenance activity.

Employee Future Benefits

The company provides a range of benefits to its employees and retired employees, including pensions and other post-retirement health and dental care benefits as described in note 7. The determination of obligations under the company’s benefit plans and related expenses requires the use of actuarial valuation methods and assumptions. Assumptions typically used in determining these amounts include, as applicable, rates of employee turnover, future claim costs, discount rates, future salary and benefit levels, return on plan assets, mortality rates and future medical costs. The fair value of plan assets is determined using market values. Actuarial valuations are subject to management judgment. As a result, the accrued benefit obligation and net periodic benefit cost for both pensions and other post-retirement benefits may differ significantly if different assumptions are used, as described in note 7.

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Reclamation and Environmental Remediation Costs

Suncor’s reclamation and environmental remediation costs represent the costs of reclaiming the environment or restoring a site to a useful and acceptable condition, as determined by statutory or regulatory authorities, by contractual agreement, or by Suncor management. The scope of the activities and the nature of the costs are normally outlined in the current reclamation or environmental remediation plan. These include costs specifically related to the reclamation or environmental remediation project and any other costs that can be clearly identified with the project.

Estimated reclamation costs at Oil Sands and NG are accrued on the unit of production basis based on proved and probable reserves. Estimated environmental remediation costs in EM&R are accrued in the period for those sites where assessments indicate that such work is required. Reclamation and environmental remediation costs are charged against earnings and reported as operating, selling and general expenses.

On an annual basis at Oil Sands and NG, the most probable costs of reclamation are estimated in current-year dollars, based on current information, the estimated timing of remedial actions, existing regulatory requirements and technology. If it is not possible to determine a most probable estimate, the lowest estimate in the range of equally probable estimates is used.

The greatest area of judgment and uncertainty with respect to the company’s reclamation estimates relates to its Oil Sands mining leases where there is a requirement to provide for land productivity equivalent to predisturbed conditions. To reclaim tailings ponds, Suncor is using a process referred to as consolidated tailings. At this time no ponds have been fully reclaimed using this technology, although work is under way. The success and time to reclaim the tailings ponds could increase or decrease the current reclamation cost estimates. The company continues to monitor and assess other possible technologies and/or modifications to the consolidated tailings process now being used.

Suncor currently estimates remaining cash reclamation expenditures will be $610 million over the next 40 years. A 10% change in this estimate could impact Oil Sands annual reclamation provision by $3 million pretax.

Reserve Estimates

On an annual basis Suncor engages Gilbert Laustsen Jung Associates Ltd. (GLJ), independent petroleum consultants to either audit (Oil Sands mining leases) or conduct independent evaluations (Firebag in-situ and NG’s conventional leases) of the company’s reserve (1) estimates. The accuracy of any reserve estimate is a matter of interpretation and judgment and is a function of the quality and quantity of available data gathered over time.

Reserve Reconciliation(1)

	Oil Sands Mining Leases (millions of barrels of gross synthetic crude oil)						Firebag In-situ Leases (millions of barrels of gross synthetic crude oil)					Natural Gas Leases (billions of gross cubic feet)
					Proved +					Proved +
	Proved		Probable		Probable		Proved	Probable		Probable		Proved
December 31, 2000	422		2 034		2 456		—	—		—		797
Additions	—		—		—		—	1 664	(2)	1 664	(2)	27
Revisions	(1	)	(5	)	(6	)	—	—		—		(3	)
Production	(45	)	—		(45	)	—	—		—		(65	)
Dispositions	—		—		—		—	—		—		(1	)
December 31, 2001	376		2 029		2 405		—	1 664		1 664		755
Additions	3		45		48		144	32		176		53
Revisions	54		(511	)	(457	)	—	—		—		(35	)
Production	(75	)	—		(75	)	—	—		—		(65	)
Dispositions	—		—		—		—	—		—		(2	)
December 31, 2002	358		1 563		1 921		144	1 696		1 840		706

(1)In their audits or evaluations of Suncor’s mining and in-situ leases, GLJ state they believe there is a 90% probability and 50% probability that proved and probable reserves estimates, respectively, will be exceeded. Accordingly, Suncor’s probable oil sands reserves have not been further reduced for risk associated with obtaining production from such reserves. GLJ’s mining and in-situ reserves estimates consider recovery from leases for which regulatory approvals have been granted, and are stated before the deduction of Crown and other royalties. Suncor reports its proved and probable reserves in accordance with Canadian disclosure requirements. The terms “proved” and “probable” reserves have the meanings ascribed to them in National Policy 2B of the Canadian Securities Administrators. U.S. companies are prohibited from disclosing estimates of probable reserves for non-mining properties in filings with the United States Securities and Exchange Commission. As a result, Suncor’s reserve estimates may not be comparable to those made by U.S. companies.

(2)For Firebag reserves, the additions in 2001 and the year-end 2001 closing balance have been adjusted from a bitumen value of 2.029 billion barrels based on assumed coker (synthetic crude) yields of between 80% and 82%.

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Oil Sands Mining Reserves

Proved and probable oil reserves estimates on Oil Sands mining leases are based on a detailed geological assessment, including drilling density and laboratory tests. Estimates also consider current production capacity and upgrading yields, current mine plans, operating life and regulatory constraints.

Subsequent to year-end 2002, management completed its reserve review and received the report of the independent consultants. As a result of this review, there was a revision to Suncor’s probable Oil Sands mining reserves. Approximately half of this probable reserve revision reflects management’s decision not to mine in less economic areas, as permitted by regulatory changes. The company could decide to mine these leases in the future. The balance of the revision incorporates additional knowledge and understanding of the Millennium mine.

Management will reflect the impact of the negative reserve revision in Oil Sands results beginning in 2003.

Firebag In-situ Reserves

For the Firebag Project, reserve estimates increased in 2002 primarily through the recognition of 144 million barrels of proved non-producing reserves. This increase reflects reclassification of a portion of probable reserves to proved status, now that the first stage of construction of the project is nearly complete and other similar industry projects have demonstrated commercial success of the in-situ process.

Natural Gas Reserves

Suncor’s NG proved reserves declined in 2002 as a result of production in the year and revisions due to operating experience. These factors were only partially offset by drilling additions.

Overburden

As part of the process of mining oil sands, it is necessary to remove surface material such as muskeg, glacial deposits and sand. Overburden removal may precede mining of the oil sands deposit by as much as two years. Accordingly, the quantity of overburden removed in a given period may not bear any relationship to the quantity of oil sands actually mined in the period.

In order to ensure a proper matching of costs with revenues (such that each tonne of oil sands mined is allocated a proportionate share of overburden removal costs), the company has adopted the deferral method of accounting for overburden removal costs, whereby all such costs are initially set up as a deferred charge (see note 3).

To allocate the deferred overburden charges, a life-of-mine approach has been adopted for each mine pit, relating the removal of all overburden to the mining of all of the oil sands ore on leases where there is regulatory approval. By adopting this approach, an overburden stripping ratio is calculated that allows for the matching of revenues and expenses such that overburden removal costs are averaged over the life of the mine. Over time, through a combination of increased mine areas (as with the Millennium mine expansion), additional drilling activity and operational experience, the company has seen its stripping ratios vary, which can increase or decrease the overburden amortization costs charged to the earnings statement (see Oil Sands Overview on page 27).

Outlook

Production Growth at Oil Sands

Suncor is targeting an increase in production capacity to 260,000 bpd in 2005. Work is also under way to finalize plans for the Voyageur growth strategy, which has a goal of increasing production to 500,000 bpd to 550,000 bpd by 2010 to 2012. (For further details, see Oil Sands Overview on page 27).

Integration

The company continues to assess downstream integration opportunities to capture greater long-term value from its oil sands production. Natural gas production and the use of the natural gas in Suncor’s operations is also a component of the corporate integration strategy (see Natural Gas Overview on page 32 and Energy Marketing and Refining Overview on page 35).

Capital Spending

In 2003, Suncor plans capital spending of more than $1 billion, with $496 million directed towards Oil Sands growth projects. This includes spending to support stage one of the Firebag Project as well as construction of a new vacuum unit for the Oil Sands upgrading facilities. Another $215 million will be spent to maintain Oil Sands operations, which includes completing a maintenance shutdown. In the downstream, the company plans to spend $145 million in 2003. The bulk of this spending will be allocated towards projects at Suncor’s Sarnia refinery to meet pending gasoline and distillate desulphurization initiatives and integrate production streams from Oil Sands. Spending will also be directed to the Sunoco retail network to help maintain its competitive position in the Ontario market. The balance of Suncor’s capital budget for 2003 is allocated to support the company’s goal of growing

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natural gas production ($160 million), and fund technology upgrades and renewable energy investments ($35 million).

Climate Change

Suncor’s effort to reduce greenhouse gas emissions is reflected in its pursuit of greater internal energy efficiency, investment in emissions offsets and carbon capture research and development.

Suncor continues to consult with governments about the impact of the Kyoto Protocol and plans to continue to actively manage its greenhouse gas emissions. Suncor currently estimates that in 2010 the impact of the Kyoto Protocol on Oil Sands cash operating costs would be about $0.20 to $0.27 per barrel. This estimate assumes a reduction obligation of 15% from 2010 business-as-usual energy intensity and that the maximum price for carbon credits would, as the Government of Canada indicated in late 2002, be capped at $15 per tonne of carbon dioxide equivalent. Based on these assumptions, Suncor does not currently anticipate the cost implications of the Kyoto Protocol will have a material impact on its business or future growth plans. The ultimate impact of Canada’s anticipated implementation of the Kyoto Protocol, however, remains subject to numerous risks, uncertainties and unknowns. These include the outcome of discussions between the federal and provincial governments, the form, impact and effectiveness of implementing legislation, the ultimate allocation of reduction obligations among economic sectors, and other details of Canada’s implementation plan, as well as international developments. In addition, the Government of Canada has not yet indicated what, if any, limitations will be placed on the price of carbon credits after 2012. It is not possible to predict how these and other Kyoto related issues will ultimately be resolved.

Kyoto Protocol

An international agreement to reduce emissions of greenhouse gases. Canada ratified the Kyoto Protocol in December 2002.

business-as-usual energy intensity

Reflects the level of greenhouse gas emissions that would have occurred in the absence of energy efficiency and process improvements after 1990.

Renewable Energy

As the company expands its hydrocarbon-based businesses, Suncor expects to continue to work toward the development of renewable energy, which has the potential to reduce environmental impacts and create additional business investment opportunities.

This strategy was reflected in the company’s announcement to invest $100 million between 2000 and 2005 on renewable energy projects.

In 2002, Suncor officially launched the SunBridge Wind Power Project, a partnership with Enbridge Inc. In 2003, Suncor’s goal is to launch investment plans for additional wind power projects.

Risk/Success Factors Affecting Performance

Suncor believes that while its business strategies will provide strategic advantages, they also present issues that will require prudent risk management. The issues Suncor must manage include, but are not limited to, commodity prices, environmental regulations, stakeholder support for growth plans, regional labour issues and the further specific issues discussed under Risk/Success Factors Affecting Performance for each Suncor business as well as the more detailed risk factors described in Suncor’s most recent Annual Information Form/Form 40-F, filed with securities regulatory authorities.

Commodity Prices

Suncor’s future financial performance remains closely linked to hydrocarbon commodity prices, which can be influenced by many factors including global and regional supply and demand, worldwide political events and the weather. These factors, among others, can result in a high degree of price volatility. For example, from 2000 to 2002 the monthly average price for benchmark WTI crude oil ranged from a low of US$19 per barrel to a high of US$34 per barrel. During the same period, the natural gas Henry Hub benchmark monthly average price ranged from a low of US$1.89 per mcf to a high of US$9.79 per mcf.

Crude oil and natural gas prices are based on a U.S. dollar benchmark that results in Suncor’s realized prices being influenced by the Canadian/U.S. currency exchange rate, creating an element of uncertainty for the company. However, the impact of foreign exchange fluctuations on earnings is partially mitigated by the company’s U.S. dollar denominated long-term debt and preferred securities. The company estimates that a

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$0.01 change in the Cdn$:US$ exchange rate would have a $10 million after-tax impact on net earnings with respect to U.S. dollar denominated long-term debt and a $3 million after-tax impact on net earnings attributable to common shareholders related to U.S. dollar denominated preferred securities.

During 2002, the fluctuation of the Canadian dollar against the U.S. dollar resulted in a net $8 million after-tax unrealized foreign exchange gain on the company’s U.S. dollar denominated long-term debt and a $1 million after-tax unrealized foreign exchange gain with respect to Suncor’s U.S. dollar denominated preferred securities.

Hedging

Suncor cannot control or accurately predict the prices of crude oil or natural gas, or currency exchange rates. For this reason, the company has a hedging program that fixes a price or range of prices for crude oil for a percentage of Suncor’s total production (see note 5). Suncor’s risk management objective with its hedging program is to reduce its exposure to market volatility and support the company’s ability to finance growth.

The Audit Committee and the Board of Directors meet with management regularly to assess Suncor’s hedging thresholds in light of its price forecast and cash requirements. To add more certainty to Suncor’s ability to finance future capital programs and repay debt, the Board authorized hedging approximately 35% of the company’s crude oil volumes in 2003 and up to 30% for the period 2004 to 2006. In 2002, hedging decreased Suncor’s earnings by $160 million. In 2001, hedging decreased earnings by $148 million.

Environmental Regulation

Environmental legislation affects nearly all aspects of Suncor’s operations, imposing certain standards and controls on activities relating to oil and gas mining and conventional exploration, development and production. Environmental legislation also affects refining, distribution and marketing of petroleum products and petrochemicals and requires companies engaged in those activities to obtain necessary permits to operate. Environmental assessments and approvals are required before initiating most new projects or undertaking significant changes to existing operations.

In addition to these specifically known requirements, Suncor expects changes to environmental legislation could impose further requirements on companies operating in the energy industry. Some of the issues include the possible cumulative impacts of oil sands development in the Athabasca region; the need to reduce or stabilize various emissions; issues relating to global climate change, including the uncertainties and risks associated with Canada’s implementation of the Kyoto Protocol and uncertainties associated with predicting emission intensity levels from Suncor’s future production; and other potential impacts of government regulation in areas such as land reclamation and restoration, water quality and reformulated fuels to support lower vehicle emissions. Changes in environmental regulation could have an adverse effect on Suncor in terms of product demand, product formulation and quality, methods of production and distribution and operating costs. The complexity of these issues makes it difficult to predict their future impact on the company. Management anticipates capital expenditures and operating expenses could increase in the future as a result of the implementation of new and increasingly stringent environmental regulations.

Other Factors

Other critical factors affecting Suncor’s financial results include volumes and margins of refined product sales, success of the natural gas exploration and development program including coal bed methane initiatives, interest rates and the company’s ability to manage both day-to-day operating costs as well as reclamation and remediation costs and project costs on existing and future projects.

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Sensitivity Analysis

							Approximate Change in
							Pretax
	2002						Cash Flow from	After-tax
	Average			Change			Operations	Earnings
Oil Sands
Price of crude oil ($/barrel)	Cdn$	33.65		US$	1.00		81	54
Sweet/sour differential ($/barrel)	Cdn$	7.86		US$	1.00		28	19
Sales (barrels/day)	205 300			1,000			11	7
Natural Gas
Price of natural gas ($/mcf)	Cdn$	3.91		0.10			5	2
Production of natural gas (mmcf/d)	179			10			11	4
Energy Marketing and Refining
Retail gasoline margins (cents/litre)	6.6			0.1			2	1
Refining/wholesale margin (cents/litre)	4.8			0.1			5	3
Consolidated
Exchange rate: Cdn$:US$	0.64			0.01			34	32
Interest rate — on variable rate borrowings	3.1		%(1)	1		%	14	9

(1)Borrowing with interest at weighted average variable rates of 3.1% at December 31.

The sensitivity analysis shows the main factors affecting Suncor’s annual pretax cash flow from operations and after-tax earnings (in Cdn$ millions) based on actual 2002 operations. The table illustrates the potential financial impact of these factors applied to Suncor’s 2002 results. A change in any one factor could compound or offset other factors.

Liquidity and Capital Resources

Net debt decreased to $2.671 billion at the end of 2002, a reduction of $462 million, excluding the $10 million effect of an unrealized foreign currency translation gain. As at December 31, 2002, the company had fixed-term debt (before the effect of interest rate swap transactions) of approximately $1.8 billion, with the balance comprised of variable rate borrowings and fixed-term capital leases.

Suncor has sufficient lines of credit to meet working capital requirements and will continue to monitor capital markets for opportunities to refinance bank debt with long-term debt. Suncor’s undrawn lines of credit at December 31, 2002 were approximately $1.1 billion.

In the first quarter of 2002, Suncor issued US$500million of 7.15% unsecured notes due 2032 from a US$1 billion unallocated shelf prospectus. The net proceeds from the sale were used to repay commercial paper and bank borrowings. Also in the first quarter of 2002, Suncor filed a shelf prospectus with Canadian securities regulatory authorities, enabling it to issue up to a further $500 million in medium-term notes in Canada if required. No notes were issued under the Canadian shelf prospectus during the year.

Interest expense continues to be influenced by the composition of the company’s debt portfolio (in particular its variable rate borrowings) with short-term floating interest rates at historic lows. To manage its fixed versus floating rate exposure, Suncor has entered into a number of interest rate swaps with investment grade counterparties, resulting in the swapping of $490 million of net fixed rate debt to variable rate borrowings.

Suncor’s capital resources at December 31, 2002, consist primarily of cash flow provided from operations, available lines of credit and the remaining debt and equity capacity under the shelf prospectuses. Suncor’s level of earnings and cash flow provided from operations depends on many factors, including commodity prices, production levels and downstream margins. Suncor believes it will be able to fund its 2003 capital spending program of approximately $1 billion from the above-noted capital resources.

Debt reduction is a priority for Suncor as it prepares for the next stages of growth. Management believes a phased approach to future growth projects should improve its ability to manage project costs and provide further opportunities for debt reduction. This approach, along with anticipated higher Oil Sands sales levels and the hedging of approximately 35% of crude oil

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production in 2003, should allow Suncor to continue reducing both the absolute debt level and the ratio of net debt to cash flow provided from operations. Suncor’s long-term target for this ratio is 2.0 times at mid-cycle commodity pricing. At the end of 2002 this ratio was 1.9 times compared to 3.8 times as at December 31, 2001. The decrease is due to a combination of increased cash flow from operations, lower year-end net debt and lower project spending with the completion of Project Millennium.

Aggregate Contractual Obligations and Off-balance Sheet Financing

	Payments Due by Period
($ millions)	Total	2003	2004 — 2005	2006 — 2007	Later years
Commercial paper	548	—	—	548	—
Bank debt	199	—	199	—	—
Fixed-term debt and capital leases	1 939	12	223	406	1 298
Operating lease agreements and pipelinecapacity and energy services commitments	5 207	216	413	409	4 169
Total	7 893	228	835	1 363	5 467

At December 31, 2002 Suncor had three off-balance sheet arrangements with Special Purpose Entities (SPE) as described in note 9c. In 2002, the company had in place a securitization program to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable having a maturity of 45 days or less to a third party SPE. In 1999, the company sold 2,130,000 barrels of its crude oil inventory for $49 million to a SPE while retaining use of the inventory for its operations through a five-year agreement. Also in 1999, the company entered into an equipment sale and leaseback arrangement with a SPE for proceeds of $30 million.

The company is currently in the process of assessing the impact of recently issued U.S. accounting interpretations and will assess new Canadian accounting interpretations when issued. These new standards may require consolidation of one or more of the above-noted off-balance sheet arrangements.

Planning Assumptions

	2002 Actual	Current Plan	2001 Plan
	Average for	Average next	Average next
	the year	3-year range	3-year range
Crude oil — WTI US$ per barrel	26.10	20.00 - 22.00	19.00 - 21.00
Natural gas — US$/thousand cubic feet @ Henry Hub	3.25	3.40 - 3.60	3.00 - 3.45
Exchange rate: Cdn$:US$	0.64	0.65	0.65 - 0.69

The above are planning assumptions and are not estimates or predictions of actual future events or circumstances. This table does not incorporate potential cross-relationships, and does not necessarily accurately predict future results.

Recently Issued Accounting Standards

For a discussion of recently issued Canadian accounting standards relating to “Hedging Relationships” and “Asset Retirement Obligations,” see “Summary of Significant Accounting Policies” on page 41.

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Oil Sands Overview

Suncor’s Oil Sands business, located near Fort McMurray, Alberta, continues to be the primary focus of the company’s development plans throughout the next decade. The business mines oil sands ore, extracting and upgrading the bitumen into refinery feedstock and diesel fuel.

Oil Sands strategy is based on:

•Increasing oil production by applying proven technologies to develop Suncor’s oil sands resources.

oil sands

Oil sands are naturally occurring mixtures of bitumen, water, sand and clay.

•Reducing costs through application of technologies, economies of scale, direct management of growth projects, strategic alliances with key suppliers and continuous improvement of operations.

•Building strategic business relationships to mitigate downstream risk and capture value from the production and marketing of synthetic crude oil and by-products.

Summary of Results

Year ended December 31

($ millions unless otherwise noted)	2002	2001	2000
Revenue	2 659	1 385	1 336
Production (thousands of bpd)	205.8	123.2	113.9
Average sales price ($/barrel)	33.65	29.17	31.67
Net earnings	793	283	315
Cash flow providedfrom operations	1 480	486	655
Total assets	6 896	6 409	5 079
Investing activities	630	1 476	1 715
ROCE (%)(1)	16.8	20.1	22.8
ROCE (%)(2)	15.6	6.4	10.6

(1)Excluding capitalized costs related to major projects in progress.
(2)Includes capitalized costs related to major projects in progress.

Analysis of Net Earnings

Oil Sands net earnings were $793 million in 2002, compared with $283 million in 2001. Increased earnings were primarily the result of higher sales revenues from both increased production and the strengthening of benchmark crude prices over the course of the year. Net earnings also benefited from an improved sales mix of higher value sweet crude oil and diesel fuel relative to lower value sour crude oil and bitumen, lower product differentials and the absence of Project Millennium start-up costs. Partially offsetting these factors were higher cash and non-cash expenses, higher hedging losses, and a higher effective tax rate in 2002 compared to 2001. The 2001 effective tax rate was lower due to the positive earnings impact of enacted provincial rate reductions in 2001 applied to Oil Sands future income tax liabilities.

During 2002, Oil Sands production increased to an average of 205,800 barrels per day (bpd), compared to 123,200 bpd in 2001. The higher production resulted in

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increased average sales of 205,300 bpd, compared to 121,500 bpd in 2001. The impact of higher sales levels increased year-over-year net earnings by $593 million.

The increase in production and sales was primarily the result of Suncor’s Project Millennium expansion, which was commissioned in December 2001. Project Millennium increased Oil Sands production capacity to 225,000 bpd. However, challenges in bringing the new Millennium facilities to capacity during the first half of 2002 impacted production and sales levels for the year. Oil Sands production steadily climbed to 227,600 bpd in the fourth quarter from the first quarter average of 179,300 bpd. By the end of 2002, the Millennium assets were performing well with what management believes were relatively few technical issues for a plant of its scale and complexity.

Net earnings were also favourably impacted by an increase in Oil Sands crude oil price realization that averaged $33.65 per barrel (including pretax hedging losses) in 2002 compared to $29.17 per barrel (including pretax hedging losses) in 2001.

The increase in average price realization was due to three factors:

•A strengthening of the 2002 WTI benchmark price throughout the year, which corresponded with increasing production. On an overall basis, the WTI benchmark price averaged US$26.10 per barrel in 2002, compared to US$25.90 per barrel in 2001.

•Improved sweet crude oil and diesel product mix, which increased to 62% of total Oil Sands production from 58% in 2001.

•Narrowing of sour crude oil and bitumen price differentials partially offset by the narrowing of the diesel premium.

The impact of these favourable factors increased Oil Sands 2002 net earnings by $204 million.

Royalties

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), subject to a minimum payment of 1% of gross revenues before hedging activity. In both 2002 and 2001, Oil Sands was subject to the minimum 1% rate. However, as a result of increased sales levels, Crown royalties increased to $28 million in 2002 from $15 million in 2001.

Based on current assumptions in Suncor’s annual planning cycle relating to future oil prices, production levels, operating costs and capital expenditures, the company expects to continue to pay the minimum 1% rate until 2010.

The Firebag in-situ leases, which are not yet in production, will be under the same royalty regime as Suncor’s mining leases.

In addition to Crown royalties, Suncor paid royalties to Anadarko Petroleum Corporation (Anadarko) for mining a lease on which Anadarko had a royalty interest. Royalties paid to Anadarko were $5 million in 2002, compared to $15 million in 2001. Mining on the lease was substantially completed in 2002 and Suncor does not anticipate paying significant royalties to Anadarko in future years. In 2002, Suncor commenced mining on a lease subject to a royalty in favour of Petro-Canada, calculated at 1.5% of the net sale proceeds from the lease. No royalties were payable to Petro-Canada in 2002.

The increase in Crown and other royalties year-over-year reduced Oil Sands after-tax income by $2 million.

Expenses

Cash operating costs (excluding project start-up costs) increased to $829 million compared to $493 million in 2001, reducing Oil Sands after-tax earnings by approximately $205 million. The increase was primarily due to higher structural operating costs associated with the increase in production capacity, including higher natural gas consumption, maintenance and increased labour costs. Oil Sands also incurred additional costs related to a two-day power outage in the first quarter, work performed on the new Millennium facilities during the first half of the year and an unplanned maintenance shutdown in the third quarter of 2002.

Project start-up costs were $3 million in 2002, compared to $141 million in 2001. The decrease reflects reduced costs resulting from the completion of Project Millennium. The decrease resulted in an after-tax earnings improvement of $88 million.

During 2002, Oil Sands incurred exploration costs of $9 million related to retention activities on its Firebag leases, reducing Oil Sands after-tax earnings by $6 million. There were no such costs in 2001. During 2003, Oil Sands anticipates a similar level of costs pertaining to its Firebag leases.

Non-cash charges (depreciation, depletion and amortization) increased to $450 million in 2002 from $233 million in 2001. The increase was primarily due to additional depreciation related to the Project Millennium assets and $99 million in higher overburden amortization costs. These factors decreased after-tax earnings by $141 million.

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The higher overburden amortization in 2002 primarily reflects increased production levels, higher removal costs and, to a lesser extent, a higher composite life-of-mine overburden stripping ratio.

In 2002, Oil Sands composite stripping ratio was 0.47 cubic metres of overburden for every tonne of ore mined. In 2001 this ratio was 0.43 cubic metres per tonne.

The higher composite stripping ratio in 2002 was a result of a higher proportion of production from Millennium, which had a higher stripping ratio (0.58) than Steepbank (0.36). In 2003, the Millennium mine pit ratio will change to 0.56. Over time, with a greater proportion of total mining production expected to come from Millennium, and assuming no other changes, the composite stripping ratio will approach the estimated Millennium life-of-mine ratio of 0.56. This will increase the overburden amortization cost.

Partially offsetting expected higher overburden amortization costs is an expected improvement in bitumen recovery. The company estimates that on a life-of-mine basis, the bitumen recovery per tonne of ore in the Millennium mine pit will be approximately 0.69 barrels, compared to 0.61 in Steepbank.

Due to the use of judgment and the extended time frame associated with the company’s stripping ratio and bitumen recovery estimates, actual results may differ and these differences may be material.

Net Cash Surplus Analysis

Cash flow provided from operations was $1.48 billion in 2002, compared with $486 million in 2001. The increase was primarily due to the factors that increased net income as described above, partially offset by an increase in overburden expenditures.

Oil Sands working capital increased by $121 million in 2002, compared to an increase of $35 million in 2001. This $86 million year-over-year increase in working capital is primarily due to higher trade receivables as a result of both higher sales levels and a higher WTI benchmark at year-end 2002, partially offset by increased accrued hedging losses.

Investing activities decreased to $630 million in 2002 from $1.476 billion in 2001. The decrease was primarily due to lower capital expenditure requirements in 2002 with the completion of Project Millennium in 2001, partially offset by increased capital spending on the Firebag Project and related upgrader improvements of $408 million.

These combined factors resulted in a net cash surplus of $729 million in 2002, compared to a net cash deficiency of $1.025 billion in 2001.

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Outlook

The foundation of Suncor’s growth plans is the resource base estimated to be in place on the company’s oil sands leases. Independent estimates currently place total Oil Sands mining and in-situ recoverable bitumen resources at nearly 13 billion barrels including proved and unrisked probable in-situ and mining bitumen reserves estimated at approximately 4.7 billion barrels.

resources

Resources include proved and probable reserves (see page 21). Resources also include quantities of oil and gas that are estimated, on a given date, to be potentially recoverable from known accumulations and undiscovered accumulations, that are not proved or probable reserves. Resources are a higher risk and are generally believed to be less likely to be recovered than proved and probable reserves. Total resources include synthetic crude oil estimates for both mining leases and for in-situ oil sands leases. Information on probable reserves and resources included in Management’s Discussion and Analysis are reported in accordance with Canadian disclosure requirements. U.S. companies are prohibited in filings with the United States Securities and Exchange Commission from disclosing estimates of probable reserves and resources for non-mining properties. As a result, Suncor’s reserve estimates may not be comparable to those made by U.S. companies.

Suncor’s future plans for Oil Sands remain focused on activities expected to increase production, decrease operating costs and improve environment, health and safety performance.

Production Plans

In 2003, production at Oil Sands is expected to average about 215,000 bpd. Production will be lower than the plant’s 225,000 bpd capacity as a result of a 30-day maintenance shutdown, currently scheduled for the second quarter of 2003. The maintenance work will result in the shutdown of Upgrader #1. Production at Oil Sands is expected to average 110,000 bpd during the maintenance period. Costs for the maintenance shutdown are budgeted at $65 million to $70 million. These costs will be amortized over the period to the next planned shutdown, tentatively scheduled for 2005 or 2006.

During the maintenance shutdown, Suncor plans to tie a new fractionator into the upgrader complex, replacing the existing unit, which has been in operation since 1967.

Operating Costs

Reducing operating costs is a strategic priority for Oil Sands. The business’s goal for 2003 is to reduce its average cash operating cost to $12.50 per barrel (excluding project start-up costs). This goal assumes a production rate average of 215,000 bpd, reflecting both the production and cost impact of the 30-day maintenance shutdown.

The company expects production rates will improve following the maintenance shutdown. The higher production, combined with cost-saving initiatives Oil Sands expects to implement, have resulted in a target of reducing cash operating costs during the fourth quarter of 2003 to as low as $10 to $11 per barrel (excluding project start-up costs).

Suncor’s cash operating cost goals assume the price of natural gas will average about US$3.60 per thousand cubic feet during 2003. Continued high natural gas prices will pose a significant challenge to reaching year-end cost reduction goals. A change of US$1 per thousand cubic feet in the Henry Hub price of natural gas would result in a change of approximately Cdn$0.50 per barrel to cash operating costs. However, because Suncor is a net producer of natural gas, continued high prices will have a positive impact on earnings.

Beyond 2003, Oil Sands will continue to pursue cost reductions while also developing and integrating new technologies and processes that have the potential to further improve competitiveness.

Firebag In-situ Oil Sands Project

The first stage of the Firebag In-situ Oil Sands Project is expected to begin commercial bitumen production in 2004. Full production from the first stage, targeted at 35,000 barrels per day of bitumen, is not expected until mid-2005. Combined with associated investments in the upgrader, the Firebag Project is expected to contribute to a planned increase in Oil Sands production capacity to 260,000 bpd in 2005, at a total cost of approximately $1 billion. The project remains on schedule and on budget. Engineering is under way on the second stage of Firebag.

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Voyageur

In late 2001, Suncor issued a public disclosure document for the Voyageur growth strategy, which targets increasing production to 500,000 to 550,000 bpd in 2010 to 2012. When Suncor originally announced plans, the company stated it would apply for regulatory approval in late 2002.

Following initial stakeholder consultation and preliminary engineering, Suncor modified its Voyageur plan, deferring applications for regulatory approval until further details about each project phase are known and can be more fully discussed with stakeholders. Although the timing of Suncor’s regulatory approval strategy has changed, the company’s goal of increasing production capacity to 500,000 to 550,000 bpd in 2010 to 2012 remains the same.

Cost estimates for the Voyageur growth strategy will be provided once preliminary engineering is completed for each phase. Ultimate development of the Voyageur growth project requires approval of regulators and Suncor’s Board of Directors.

Risk/Success Factors Affecting Performance

Management believes the strategic advantages of Oil Sands growth include:

•Economies of scale associated with higher levels of production from the existing Oil Sands infrastructure.

•Parallel processing in the extraction and upgrading processes that provides flexibility to schedule periodic plant maintenance while continuing to generate production from the remaining units.

•Access to nearly 13 billion barrels of bitumen resources with the potential to generate production growth without the level of exploration risk associated with conventional oil and gas operations.

Certain issues Suncor must manage that may affect performance include, but are not limited to the following:

•Suncor’s ability to finance Oil Sands growth in a volatile commodity pricing environment. Also refer to Corporate Overview, Liquidity and Capital Resources on page 25.

•The ability to complete future Oil Sands growth projects both on time and on budget. This could be impacted by competition from other projects (including other oil sands projects) for skilled people, increased demands on the Fort McMurray, Alberta infrastructure (housing, roads, schools, etc.), or higher prices for the products and services required to operate and maintain the Oil Sands plant. Suncor continues to address these issues through a comprehensive recruitment and retention strategy, working with the community to determine infrastructure needs, designing Oil Sands expansion to reduce unit costs, seeking strategic alliances with service providers and developing internal core competency in engineering, procurement and project management.

•Potential changes in the demand for refinery feedstock and diesel fuel. Suncor believes it can reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding its customer base and offering customized blends of refinery feedstock to meet customer specifications.

•Volatility in crude oil and natural gas prices and exchange factors and the light/heavy and sweet/sour crude oil differentials. Prices and differentials are difficult to predict and impossible to control.

•Unplanned production or operational outages and slowdowns. Outages can impact both production levels and costs.

•Suncor’s relationship with its trade unions. Work disruptions have the potential to adversely affect Oil Sands operations and growth projects. Suncor’s current collective agreement with the Communications, Energy and Paperworkers Union, Local 707 expires May 1, 2004.

These factors and estimates are subject to certain risks, assumptions and uncertainties discussed on page 38 under “Forward-looking Statement.” Also refer to Corporate Overview, Risk/Success Factors Affecting Performance on page 23.

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Natural Gas Overview

Suncor’s Natural Gas business (NG) produces conventional natural gas in Western Canada and is exploring potential opportunities for coal bed methane production in North America. NG’s production provides a price hedge for the natural gas consumed internally within Suncor’s oil sands operations and downstream refinery.

In 2002, NG continued to advance its four-point strategy for profitable growth:

•Focusing on natural gas production to keep pace with growing projected internal consumption to maintain a price hedge.

price hedge

Suncor-generated natural gas production that exceeds internal consumption provides the company a degree of protection from volatile market prices. In 2002, Suncor produced 179 million cubic feet per day (mmcf/d) of natural gas compared to consumption of approximately 110 mmcf/d.

•Building competitive operating areas.

•Improving base business efficiency.

•Creating new, low-capital business opportunities.

NG’s 2002 average natural gas and liquids production volume of 33,700 barrels of oil equivalent per day (boe/d) was comparable to the 2001 average of 33,400 boe/d. Volume additions from new production in NG’s core Western Canada operating areas were partially offset by natural reservoir declines in existing wells. Natural gas volumes as a percentage of total NG production remained constant at 88% in 2002 and 2001.

Summary of Results

Year ended December 31

($ millions unless otherwise noted)	2002	2001	2000
Revenue	315	458	428
Production (thousands boe/d)	33.7	33.4	40.5
Natural gas (mmcf/day)	179	177	200
Natural gas liquids (thousands bpd)	2.4	2.4	3.0
Crude oil (thousands bpd)	1.5	1.5	4.2
Average sales price
Natural gas ($/thousand cubic feet)	3.91	6.09	4.72
Natural gas liquids ($/barrel)	29.35	34.38	36.66
Crude oil ($/barrel)	31.72	33.92	29.50
Net earnings	35	117	98
Cash flow providedfrom operations	164	280	238
Total assets	765	722	762
Investing activities	158	113	(186	)
ROCE (%)	9.2	32.1	17.2

Natural gas converts to barrels of oil equivalent (boe) at a 6:1 ratio (six thousand cubic feet of natural gas:barrel of oil)

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Analysis of Net Earnings

NG’s net earnings decreased to $35 million in 2002, from $117 million in 2001. The decrease was primarily due to lower natural gas prices, increased expenses and a higher effective income tax rate in 2002 compared to 2001, partially offset by lower royalty expenses. The 2001 effective tax rate was lower due to the positive earnings impact of enacted provincial rate reductions in 2001 applied to NG’s future income tax liabilities.

Pricing

In 2002, NG’s average price realized for natural gas was $3.91 per thousand cubic feet (mcf), 36% lower than the average $6.09 per mcf realized in 2001. High industry inventory levels at the beginning of 2002 and weaker industrial demand due to economic recession in the United States contributed to lower prices during the year. Prices for crude oil, which accounts for about 5% of NG production, were marginally lower at $31.72 per barrel (including hedging losses), compared to $33.92 per barrel (including hedging losses) in 2001. Natural gas liquids, accounting for the remaining 7% of production, averaged $29.35 per barrel in 2002, compared to $34.38 per barrel in 2001. The combined impact of the above pricing factors decreased earnings by $85 million compared to 2001.

Total Expenses

Royalties on NG production decreased to $65 million ($5.27 per boe) in 2002, from $104 million ($8.56 per boe) in 2001, reflecting lower average commodity prices. Lower royalties had a positive impact on earnings of $17 million for 2002.

Total expenses, excluding royalties, restructuring costs and divestment gains, increased to $179 million in 2002 from $168 million in 2001. Natural gas purchases were $7 million higher reflecting increased purchases made by NG on behalf of Suncor’s Sarnia refinery. Operating expenses increased to $69 million in 2002 from $64 million in 2001 due to increased maintenance and higher costs related to employee benefits. Non-cash depreciation, depletion and amortization expenses of $75 million in 2002 increased by $5 million as a result of higher depletion rates. Offsetting these items were exploration expenses, which decreased by $5 million in 2002 due to lower seismic expenditures as a result of reduced exploration activities. The combined impact of the above expense items decreased earnings by $6 million compared to 2001.

Net Cash Surplus Analysis

NG had a net cash surplus of $28 million in 2002, compared to a net cash surplus of $211 million in 2001. Cash flow provided from operations decreased to

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$164 million in 2002, from $280 million in 2001 primarily as a result of lower prices and higher expenses, partially offset by lower royalty payments. Working capital decreased by $22 million in 2002, compared to a decrease of $44 million in 2001, due to a reduction in accounts receivable. Investing activities increased to $158 million in 2002, compared to $113 million in 2001. The $45 million increase reflects increased development drilling in existing focus areas, partially offset by lower divestment proceeds.

Outlook

NG’s long-term goal is to achieve a sustainable return on capital employed of a minimum of 12% at mid-cycle natural gas prices (US$3.00 to US$3.50/mcf). To meet this target, management plans to increase production and continue work to improve base business efficiency, with a focus on reducing operating costs and capturing supply chain management benefits.

NG’s long-term strategy is to increase production to exceed growing internal natural gas demands at the company’s other integrated businesses. Internal demand in the latter half of 2003 is expected to grow to approximately 120 mmcf/d from 110 mmcf/d in 2002 in response to steam requirements for the Firebag In-situ Oil Sands Project. Internal demand is expected to continue to increase as subsequent stages of the Firebag Project begin production.

Suncor has budgeted $160 million in capital spending to support NG’s 2003 production target of 185 to 190 mmcf/d of natural gas and approximately 3,300 barrels per day of liquids. The company plans to continue to leverage its expertise and existing assets to bring established reserves into production in western Alberta and northeastern British Columbia. However, increasing production will likely require expansion through industry arrangements such as farm-ins, joint ventures and acquisitions, which could expand the size and number of operating areas.

farm-ins

Acquisitions of all or part of the operating rights from the working interest owner. The acquirer assumes all or some of the burden of development in return for an interest in the property. The assignor usually retains an overriding royalty but may retain any type of interest.

Risk/Success Factors Affecting Performance

Certain issues Suncor must manage that may affect performance of the NG business include, but are not limited to, the following:

•Consistently and competitively finding and developing reserves that can be brought on stream economically. Positive or negative reserve revisions arising from technical and economic factors can have a corresponding positive or negative impact on asset valuation and depletion rates.

•The impact of market demand for land and services on capital and operating cost. Market demand and the availability of opportunities also influences the cost of acquisitions and the willingness of competitors to farm-out prospects.

•Risks and uncertainties associated with obtaining regulatory approval for exploration and development activities. These risks could add to costs or cause delays to projects.

These factors and estimates are subject to certain risks, assumptions and uncertainties discussed on page 38 under “Forward-looking Statement.” Also refer to the Corporate Overview, Risk/Success Factors Affecting Performance on page 23.

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Energy Marketing and Refining Overview

Suncor’s Energy Marketing and Refining (EM&R) business markets the company’s refined products to industrial, wholesale and commercial customers principally in Ontario and Quebec, and to retail customers in Ontario through Sunoco-branded and joint venture operated retail networks. EM&R operates Suncor’s refinery in Sarnia, Ontario, which has capacity to process 70,000 barrels per day of crude oil into gasolines, distillates and petrochemicals.

EM&R’s downstream strategy is focused on:

•Enhancing the profitability of refining operations by improving reliability and product yields and enhancing operational flexibility to process a variety of feedstock.

•Increasing the profitability and efficiency of retail networks by improving average site throughput and growing non-fuel ancillary retail revenue.

•Creating downstream integration opportunities to capture greater long-term value from Oil Sands production.

EM&R’s retail networks in Ontario provide marketing channels for the company’s refined products, accounting for approximately 62% of EM&R’s total 2002 sales volumes of 91,100 barrels per day (bpd). EM&R’s retail networks include 287 Sunoco-branded retail service stations, 18 Sunoco-branded Fleet Fuel Cardlock sites, and two 50% retail joint venture(1) businesses comprising 148 Pioneer retail service stations, 50 UPI retail service stations and 15 UPI bulk distribution facilities for rural and farm fuels.

(1)Pioneer Group Inc. is an independent company with which Suncor has a 50% joint venture partnership. UPI Inc. is a 50% joint venture company with GROWMARK Inc., a Midwest U.S. retail farm-supply and grain marketing co-operative.

Wholesale and industrial gasoline and distillates sales were approximately 33% of EM&R’s refined product sales in 2002. The remaining 5% was comprised of petrochemicals sold through Sun Petrochemicals Company, a 50% joint venture between a Suncor subsidiary and a U.S. based company.

Prior to April 2002, EM&R also marketed natural gas to approximately 125,000 commercial and residential customers in Ontario. EM&R divested its Ontario retail natural gas marketing business during the second quarter of 2002 in order to focus on its core refined products business.

Summary of Results

Year ended December 31

($ millions unless otherwise noted)	2002	2001	2000
Revenue	2 361	2 588	2 604
Refined product sales (thousands of cubic metres)
Sunoco retail gasoline	1 642	1 575	1 539
Total	5 286	5 419	5 360
Net earnings (loss) breakdown:
Rack Back	10	47	69
Rack Forward	16	23	(1	)
Gain on sale of retail naturalgas marketing business	35	—	—
Tax adjustments	—	10	13
Total net earnings	61	80	81
Cash flow providedfrom operations	107	165	174
Investing activities	34	71	59
Net cash surplus	63	111	155
ROCE (%)	12.5	18.4	20.5

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Analysis of Net Earnings

EM&R’s 2002 net earnings were $61 million, compared with $80 million in 2001. Excluding the net earnings effects of the gain on the sale of the retail natural gas marketing business, net earnings were $26 million in 2002, compared to $80 million in 2001. This decrease was primarily due to reduced refining margins and higher cash operating costs, partially offset by the benefits of higher refinery crude utilization. Net earnings in 2002 were also lower compared to 2001 as 2001 earnings included the positive impact of a tax rate reduction on EM&R’s future income tax liabilities.

Rack Back

Net earnings for Rack Back were $10 million in 2002, compared with $47 million in 2001, including the impact of a $9 million gain on liquidation of excess natural gas supplies in 2001. The decrease was primarily due to lower refining margins and higher operating expenses, partially offset by improved refinery yield.

Rack Back and Rack Forward

EM&R’s financial reporting is based on its Rack Back/Rack Forward organizational structure. The Rack Back division includes the procurement and refining of crude oil and feedstock, and sales and distribution to the Sarnia refinery’s largest industrial and reseller customers. Rack Forward includes retail operations, cardlock and industrial/commercial sales, and the UPI and Pioneer joint venture businesses.

Refining margins decreased 16% to 4.8 cents per litre (cpl) in 2002, compared to 5.7 cpl in 2001, reflecting weak gasoline and distillates margins across North America. Lower margins reduced earnings for 2002 by $32 million, more than offsetting an $18 million improvement in earnings due to higher refinery yield and lower product purchase costs.

Rack Back sales volumes (including volumes sold to the Rack Forward business) averaged 14,500 cubic metres per day (91,100 bpd), down from 14,800 cubic metres per day (93,400 bpd) in 2001. Reduced sales volumes reflect the non-renewal of jet fuel contracts and lower distillate sales driven by weakened demand, partially offset by higher gasoline and petrochemical sales volumes. This resulted in a decline in Rack Back earnings of $3 million compared to 2001. EM&R’s refined product market share in its primary market of Ontario declined to 17% in 2002, compared to 18% in 2001. Approximately 86% of EM&R’s refined products were sold to the Ontario market in 2002.

In addition to a 34-day planned maintenance shutdown on a portion of the refinery’s operations in the second quarter, there were a number of unplanned outages in 2002 that affected plant availability. Following planned and unplanned maintenance work, all units returned to normal performance level with an improved crude utilization rate of 100% and 108% in the last two quarters of 2002, respectively. Overall, the refinery’s crude utilization averaged 95% in 2002, compared to 92% in 2001. Despite additional product purchases that were made to satisfy customer demand during the planned and unplanned periods of lower production, total product purchases made in 2002 were lower compared to 2001 due to the improvement in refinery reliability.

Rack Back’s after-tax expenses were $20 million higher in 2002 compared to 2001, due in part to higher employee future benefits of $4 million, higher electricity costs of $3 million due to deregulation of the Ontario electricity market and increased maintenance and other general and administrative expenses. Expenses were also higher in 2002 compared to 2001 as 2001 results included a $9 million gain on liquidation of excess natural gas supplies.

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Rack Forward

Rack Forward net earnings for 2002 increasedto $51 million, compared to $23 million in 2001.Excluding the net earnings effect of a $35 milliongain on the sale of the retail natural gas marketingbusiness, Rack Forward net earnings decreased to$16 million compared to $23 million in 2001. Thedecrease was primarily attributable to lower earningsfrom the commercial and reseller sales channels andhigher employee future benefits costs, which werepartially offset by improved retail gasoline volumes.Also impacting Rack Forward’s results was a $3 millionreduction in retail natural gas marketing earnings over2001. This business was sold at the beginning of the second quarter of 2002.

Gasoline sales volumes in the Sunoco-branded retailnetwork grew by more than 4% in 2002 despitethe closure of 19 sites, contributing to an earningsimprovement of $2 million.  Average site throughputwas 5.8 million litres per site in 2002, a 7%improvement from the 5.4 million litres per site in2001, reflecting continued improvement in networkefficiency. EM&R’s Ontario retail gasoline market share,including all Sunoco and joint venture operated retailsites, remained constant at 20%. EM&R’s Sunoco-branded retail gasoline margin averaged 6.6 cpl,unchanged from 2001.

Royalty and ancillary income was $1 million higherthan 2001, reflecting continued expansion of non-fuelproducts and services in the retail network. Due toaggressive price competition and commodity pricevolatility throughout 2002, earnings from thecommercial and reseller sales channels declined by$2 million.

ancillary income

Income earned from non-fuel products and services such as car washes, sale of fast foods and confectionery items.

Rack Forward expenses were $5 million highercompared to 2001 primarily due to higher employeefuture benefits and higher marketing costs.

Net earnings from the retail joint ventures withPioneer and UPI totalled $5 million in 2002,unchanged from 2001.

Net Cash Surplus Analysis

Cash flow from operations decreased to $107 millionin 2002 from $165 million in 2001 as a result of lowerearnings as described above. Working capital increasedby $10 million in 2002, compared to a decline of$17 million in 2001 reflecting the impact of the saleof the retail natural gas marketing business and a netincrease in trade receivables reflecting highercommodity prices.

Cash used in investing activities was $34 million in2002, compared to $71 million in 2001. Higher capitalspending and deferred maintenance costs in 2002 weremore than offset by the $62 million net proceeds fromthe sale of the retail natural gas marketing business.Investing activities in 2002 also included $18 millionfor the planned maintenance shutdown at the Sarniarefinery, compared to $9 million in 2001.

The impact of these factors decreased the 2002 netcash surplus to $63 million, compared to $111 millionin 2001.

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Outlook

To enhance competitiveness and to position the Sunoco-branded retail network for growth, EM&R plans to develop new Sunoco retail sites, upgrade existing facilities and close down low-volume, under-performing retail assets. EM&R will also target increased fuel and non-fuel revenue by focusing marketing initiatives on premium petroleum and ancillary offerings.

To further integrate the company’s upstream and downstream businesses, EM&R continues to assess new marketing and refining investment opportunities to capture the greatest long term value from Suncor’s Oil Sands production.

Regulation regarding low-sulphur gasoline specifications prescribes limits for sulphur levels in gasoline to an average of 150 parts per million (ppm) from mid-2002 to the end of 2004, and a maximum of 30 ppm by 2005. To meet these specifications, EM&R is constructing a desulphurization unit at the Sarnia refinery at an estimated cost of $40 million. The project is expected to be completed in 2003, more than a year ahead of the legislated deadline.

In 2002, the Canadian government passed legislation limiting the concentration of sulphur in diesel fuel produced or imported for use in on-road vehicles. The legislation places a limit on sulphur levels of 500 ppm until May 31, 2006 and a maximum of 15 ppm thereafter. Capital spending required by EM&Rfor compliance is estimated to be approximately $225 million from 2003 through 2005.

Risk/Success Factors Affecting Performance

Certain issues Suncor must manage that may affect performance of the EM&R business include, but are not limited to, the following:

•While EM&R’s margins improved in the second half of 2002, management expects fluctuations in demand for refined products, margin and price volatility and market competitiveness, including potential new market entrants, will continue to impact the business environment.

•Environment Canada is expected to finalize regulations reducing sulphur in off-road diesel and light fuel oil to take effect later in the decade. Capital spending required is subject to the development of such regulations and strategic assessment. Several strategic options are being evaluated by EM&R to enhance integration with Oil Sands and increase value through integration with the diesel desulphurization facilities.

These factors and estimates are subject to certain risks, assumptions and uncertainties discussed below. Also refer to the Corporate Overview, Risk/Success Factors Affecting Performance on page 23.

Forward-looking Statement

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 and production volumes, operating and financial results, 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 and involve a number of risks, uncertainties and assumptions. Suncor’s business is subject to 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.

The risks, uncertainties and other factors that could influence actual results include: 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; the ability of Suncor to receive timely regulatory approvals; the successful implementation of its growth projects including the Firebag In-situ Oil Sands Project and Voyageur; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other resource development; 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 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 exploration or development projects or capital expenditures; actions by governmental authorities including increasing taxes, government fees, 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. 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 the Alberta Securities Commission and certain other securities regulatory authorities. 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.

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