suncor overview and strategic priorities

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. The company operates four business segments:

• Oil Sands Suncor’s core business unit, located near Fort McMurray, Alberta, produces bitumen recovered from oil sands and upgrades it to refinery feedstock, diesel fuel and byproducts.

• Natural Gas (NG) produces natural gas in Western Canada, providing revenues and serving as a price hedge against the company’s purchased natural gas consumption.

• Energy Marketing and Refining – Canada (EM&R) operates a 70,000 barrel per day (bpd) capacity refinery in Sarnia, Ontario and markets refined petroleum products to customers primarily in Ontario and Quebec, including retail customers in Ontario under the Sunoco brand. (Sunoco in Canada is separate and unrelated to Sunoco in the United States, which is owned by Sunoco, Inc. of Philadelphia.) EM&R also manages Suncor’s company-wide energy marketing and trading activities and sales of all Oil Sands and NG production. Financial results relating to the sales of Oil Sands and NG production are reported in those business segments.

• Refining and Marketing – U.S.A. (R&M) operates a 60,000 bpd capacity refinery in the Denver, Colorado area as well as related pipeline assets. R&M’s retail network of 43 Phillips 66-branded stations operates primarily in the Denver area. In addition, the business has contract agreements with about 140 Phillips 66-branded outlets that operate throughout Colorado.

Suncor’s strategic priorities are:

Operational:

• Developing Suncor’s oil sands resource base through mining and in-situ technology and supplementing Suncor bitumen production with third-party supply.

• Expanding Oil Sands extraction and upgrading facilities to increase crude oil production.

• Integrating Oil Sands production into the North American energy market through Suncor’s refineries and the refineries of other customers to reduce vulnerability to supply and demand imbalances.

• Managing environmental and social performance to earn continued stakeholder support for Suncor’s ongoing operations and growth plans.

• Maintaining a strong focus on worker, contractor and community safety as an overriding operational priority.

Financial:

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

• Reducing risk associated with natural gas price volatility by producing natural gas volumes that meet or exceed purchases.

• Maintaining a strong balance sheet by controlling debt and closely managing capital cost outlays.

• Targeting opportunities that support a minimum 15% return on capital employed (ROCE) at US$28 West Texas Intermediate (WTI) crude oil prices and a Cdn$/US$ exchange rate of $0.75.

Suncor Energy Inc. 2004 Annual Report

selected financial information

Annual Financial Data

Year ended December 31 ($ millions except per share data)	2004	2003	2002
Revenues	8 621	6 571	5 032
Net earnings	1 100	1 075	749
Total assets	11 804	10 501	9 011
Long-term debt	2 217	2 448	2 686
Dividends
Common shares	103	87	77
Preferred securities	9	45	48
Net earnings attributable to common shareholders per share – basic	2.40	2.41	1.61
Net earnings attributable to common shareholders per share – diluted	2.36	2.24	1.58
Cash dividends per share	0.23	0.19	0.17

Outstanding Share Data

As at December 31, 2004 (thousands)
Number of common shares		454 241
Number of common share options		20 687
Number of common share options – exercisable		9 067

Quarterly Financial Data

2004
Quarter ended

2003
Quarter ended

($ millions except per share)

Dec. 31

Sept. 30

June 30

Mar. 31

Dec. 31

Sept. 30

June 30

Mar. 31

Revenues

2 310

2 315

2 201

1 795

1 698

1 788

1 385

1 700

Net earnings

333

337

203

227

302

291

116

366

Net earnings attributable to common shareholders per share

Basic

0.73

0.74

0.44

0.48

0.67

0.63

0.27

0.84

Diluted

0.72

0.73

0.43

0.46

0.62

0.61

0.24

0.77

Net Earnings(1)

($ millions)

	04	03	02
Oil Sands	995	888	782
Natural Gas	115	120	34
Energy Marketing and Refining – Canada	80	53	61
Refining and Marketing – U.S.A.(3)	34	18	—

Capital Employed(1) (2)

($ millions)

	04	03	02
Oil Sands	4 169	4 050	4 512
Natural Gas	448	400	422
Energy Marketing and Refining – Canada	512	551	485
Refining and Marketing – U.S.A.(3)	232	270	—

Cash Flow from Operations(1)

($ millions)

	04	03	02
Oil Sands	1 752	1 803	1 475
Natural Gas	319	298	164
Energy Marketing and Refining – Canada	188	164	112
Refining and Marketing – U.S.A.(3)	59	34	—

(1) Excludes Corporate and Eliminations segment.

(2) Excludes major projects in progress.

(3) Refining and Marketing – U.S.A. 2003 data reflects five months of operations since acquisition on August 1, 2003.

Suncor Energy Inc. 2004 Annual Report

Quarterly net earnings for 2004 and 2003 fluctuated due to a number of factors:

• U.S. dollar denominated crude oil prices were higher on average in 2004 compared to 2003.

• Oil Sands Alberta Crown royalties increased significantly during 2004 as a result of a modification in the Province of Alberta’s royalty classification for Firebag in-situ operations and higher crude oil prices (see page 24).

• The impact of scheduled and unscheduled maintenance at Oil Sands (including in-situ operations) reduced production during 2004. In the second quarter of 2003, there was a planned 30-day maintenance shutdown on Upgrader 1 that reduced production capacity during that period.

• Cash operating costs fluctuated due to the factors impacting Oil Sands production and the price and purchased volume of natural gas used for energy in Oil Sands operations.

• Commodity and refined product prices fluctuated as a result of global and regional supply and demand, as well as seasonal demand variations. In the downstream, seasonal fluctuations were reflected in higher demand for vehicle fuels and asphalt in summer and heating fuels in winter.

• Realized commodity prices were unfavourably impacted in 2004 and 2003 by increases in the Canadian dollar compared to the U.S. dollar, which reduced the Canadian dollar revenue earned. The stronger Canadian dollar also resulted in net foreign exchange gains on U.S. dollar denominated debt in 2004 and 2003. These gains were higher in 2003 due to the greater appreciation of the Canadian dollar during 2003 compared to 2004.

• A 1% reduction in the Province of Alberta’s corporate tax rates in the first quarter of 2004 increased 2004 net earnings by $53 million. In 2003, changes to federal taxation policies relating to the resource sector and changes to both the Alberta and Ontario provincial tax rates reduced 2003 net earnings by $89 million.

Consolidated Financial Analysis

This analysis provides an overview of Suncor’s consolidated financial results for 2004 compared to 2003. For a detailed analysis, see the various business segment analyses.

Net Earnings

Suncor’s net earnings were $1.1 billion in 2004, compared with $1.075 billion in 2003 (2002 – $749 million). The increase was primarily due to higher U.S. dollar benchmark crude oil prices (net of widening light/heavy crude oil differentials), increased production, and non-cash reductions in income tax expense due to year-over-year changes in tax rates and resource allowance deductions. These positive impacts were largely offset by higher Oil Sands Alberta Crown royalties, higher crude oil hedging losses and the impact of a stronger Canadian dollar.

Net Earnings Components (1)

Year ended December 31 ($ millions, after tax)	2004		2003		2002
Net earnings before the following items:	1 248		1 048		718
Firebag in-situ start-up costs	(14	)	—		—
Oil Sands Alberta Crown royalties	(261	)	(21	)	(22	)
Impact of income tax rate reductions on opening net future income tax liabilities	53		(89	)	10
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	74		137		8
Sale of retail natural gas marketing business	—		—		35
Net earnings as reported	1 100		1 075		749
Net earnings attributable to common shareholders as reported	1 088		1 085		722

(1) This table explains some of the factors impacting Suncor’s after-tax net earnings. For comparability purposes, readers should rely on the reported net earnings that are prepared and presented in the company’s consolidated financial statements and notes in accordance with Canadian GAAP.

Suncor Energy Inc. 2004 Annual Report

Industry Indicators

(Average for the year unless otherwise noted)	2004	2003	2002
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	41.40	31.05	26.10
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	52.55	43.55	40.75
Light/heavy crude oil differential US$/barrel WTI at Cushing less Bow River at Hardisty	12.80	8.00	5.95
Light/heavy crude oil differential US$/barrel WTI at Cushing less Lloyd Light Blend at Hardisty	13.55	8.65	6.55
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	6.20	5.45	3.25
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.80	6.70	4.05
New York Harbour 3-2-1 crack US$/barrel (1)	6.90	5.30	3.35
Refined product demand (Ontario) percentage change over prior year (2)	4.3	2.5	0.6
Exchange rate: Cdn$/US$	0.77	0.72	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.

(2) Figures for 2002 and 2003 are based on published government data. Figures for 2004 are internal estimates based on preliminary government data.

Revenues were $8.6 billion in 2004, compared with $6.6 billion in 2003 (2002 – $5.0 billion). The increase resulted primarily from the following:

• Average commodity prices were higher in 2004 than in 2003. A 33% increase in average U.S. dollar WTI benchmark pricing increased the selling price of Oil Sands crude oil production. Mitigating this increase, average light/heavy crude oil differentials compared to the WTI benchmark index widened approximately 60%. As a result, the net price Suncor received on certain sour crude oil and bitumen sales did not increase by as much as the increase in WTI.

• In 2004, Oil Sands sales averaged 226,300 bpd, compared with 218,300 bpd in 2003 (2002 – 205,300 bpd). Increased crude oil production drove higher sales volumes. Oil Sands sales in 2004 included production of 10,900 bpd of bitumen from Firebag in-situ operations, which commenced operations during the year. Overall sales volumes in 2004 were lower than anticipated due to the effects of unplanned maintenance at both the base plant and in-situ operations. In 2003, sales volumes were negatively impacted by a planned 30-day maintenance shutdown.

• Refined product wholesale and retail prices in both EM&R and R&M were higher due to higher crude oil feedstock prices. In addition, a 3% increase in refined product sales volumes in EM&R had a positive impact on revenue.

• R&M revenues increased as a result of one full year of operations, compared to five months in 2003 (R&M was acquired on August 1, 2003).

Partially offsetting these increases were the following:

• A 7% increase in the average Cdn$/US$ exchange rate resulted in lower realizations on Suncor’s crude oil sales basket and natural gas sales. Because crude oil and natural gas are primarily sold based on U.S. dollar benchmark prices, a narrowing of the exchange rate difference reduced the Canadian dollar value of Suncor’s products.

• Higher strategic crude oil hedging losses decreased revenues. During 2004, Suncor sold a portion of its crude oil production at fixed prices that were lower than prevailing market prices. After-tax hedging losses in 2004 were $397 million compared to $155 million in 2003.

Overall, higher prices, net of the impact of the higher Cdn$/US$ exchange rate, increased total revenues by approximately $1.2 billion. Higher volumes increased revenues by approximately $220 million and the impact of 12 months of R&M results compared to five months in 2003 increased revenues by approximately $980 million. These impacts were partially offset by hedging losses, which reduced revenues by approximately $380 million.

Purchases of crude oil and crude oil products were $2.9 billion in 2004 compared with $1.7 billion in 2003 (2002 – $1.2 billion). The increase was primarily due to the following:

• Higher benchmark crude oil feedstock prices, which increased purchases by approximately $360 million.

• Higher feedstock requirements as a result of one full year of operations for R&M, compared to five months in 2003, increased purchases by approximately $830 million.

Suncor Energy Inc. 2004 Annual Report

• The repurchase of crude oil originally sold to a Variable Interest Entity (VIE) in 1999 increased purchases at Oil Sands in the second quarter by approximately $55 million.

• The 3% increase in refined product sales in EM&R required the purchase of higher volumes of feedstock and refined products.

Operating, selling and general expenses were $1.8 billion in 2004 compared with $1.5 billion in 2003 (2002 – $1.3 billion). The primary reasons for the increase were:

• The effects of 12 months of operations at R&M in 2004 compared to only five months of operations in 2003.

• The first year of in-situ operations.

• Higher operating expenses, including higher energy costs in all businesses.

• Increased maintenance activities due to scheduled maintenance at the R&M Denver refinery and the EM&R Sarnia refinery as well as unscheduled maintenance at Oil Sands base plant and in-situ operations, and the EM&R Sarnia refinery.

• Corporate costs related to the company’s enterprise resource planning (ERP) implementation project as well as costs related to obtaining certification under the Sarbanes-Oxley Act, Section 404.

• Higher stock-based compensation expense, primarily due to the achievement of certain performance based vesting conditions under the company’s SunShare stock option plan and an increase in the overall number of stock options being expensed.

Transportation and other expenses remained relatively constant at $132 million in 2004 compared to $135 million in 2003 (2002 – $128 million). Increased transportation costs of $13 million in R&M due to a full year of operations, were offset by mark-to-market gains on inventory-related derivatives in Oil Sands. Consistent with 2003, Oil Sands pipeline tolls continued to be reduced by initial shipper toll adjustments. Oil Sands initial shipper toll adjustments are currently expected to continue until at least 2007.

Depreciation, depletion and amortization (DD&A) was $717 million in 2004 compared with $618 million in 2003 (2002 – $595 million). DD&A at Oil Sands increased by $45 million due to higher overburden amortization, higher maintenance shutdown and catalyst amortization, and depletion incurred in in-situ operations, which commenced in 2004. NG depletion increased by $24 million, reflecting higher production levels and a higher depletion base. Higher depreciation and amortization of $16 million associated with 12 months of operations in R&M also contributed to the increase.

Exploration expenses were $55 million in 2004, largely unchanged from $51 million in 2003 (2002 – $26 million). Decreased NG dry hole expenses of $11 million in 2004 were offset by higher seismic expenses in NG and higher core hole drilling activity in Oil Sands.

Royalty expenses were $531 million in 2004 compared with $139 million in 2003 (2002 – $98 million). The significant increase in 2004 was primarily related to increased Alberta Crown royalties at Oil Sands. For a further discussion about Oil Sands Crown royalties, see page 24. Royalties in NG also increased by $18 million due to higher realized natural gas prices and higher production volumes.

Taxes other than income taxes were $496 million in 2004 compared to $426 million in 2003 (2002 – $374 million). The increase was primarily due to additional excise taxes related to R&M operations.

Financing expenses were $9 million in 2004 compared with income of $66 million in 2003 (2002 – expense of $124 million). The increase in expenses was primarily due to $77 million of lower foreign exchange gains on the company’s U.S. dollar denominated long-term debt. Interest expense net of capitalized interest was $87 million in 2004, compared to $83 million in 2003. The relatively unchanged interest expense net of capitalized interest was a result of reasonably stable levels of long-term debt, effective interest rates and average balances of major projects in progress.

Income tax expense was $536 million in 2004 (33% effective tax rate), compared with $726 million in 2003 (40% effective tax rate) (2002 – $378 million – 33% effective tax rate). Income tax expense in both 2004 and 2003 included the effects of adjustments to opening future income tax balances due to changes in tax rates that reduced tax expense by $53 million in 2004 and increased tax expense by $89 million in 2003. Excluding these adjustments, income tax expense in 2004 was $589 million (36% effective tax rate) compared to $637 million in 2003 (35% effective tax rate). The higher effective rate in 2004 was primarily due to the tax effect of lower foreign exchange gains on long-term debt in 2004 compared to 2003.

Corporate Expenses

After-tax corporate expenses were $124 million in 2004 compared to $4 million in 2003 (2002 – $128 million). The increase was due to higher financing costs and higher operating, selling and general expenses (discussed above).

Suncor Energy Inc. 2004 Annual Report

The corporate office had a net cash deficiency of $334 million in 2004, compared with $235 million in 2003 (2002 – $225 million). The increased deficiency was primarily due to the same factors that increased operating, selling and general expenses, as well as changes in working capital.

Consolidated Cash Flow from Operations

Cash flow from operations was $2.02 billion in 2004 compared to $2.08 billion in 2003 (2002 – $1.44 billion). Excluding the impacts of foreign exchange gains and non-cash future income tax expense, cash flow was primarily impacted by the same factors affecting net earnings. In addition, higher cash overburden spending in 2004 reduced cash flow from operations by $47 million compared to 2003.

Dividends

In the second quarter of 2004, Suncor’s Board of Directors approved an increase in the quarterly dividend to $0.06 per share, from $0.05 per share. Total dividends paid during 2004 were $0.23 per share, compared with $0.1925 per share in 2003. The Board periodically reviews the dividend policy, taking into consideration Suncor’s capital spending profile, financial position, financing requirements, cash flow and other relevant factors.

Subsequent Event

On January 4, 2005, a fire at Oil Sands damaged Upgrader 2. As a result, production at Oil Sands base operations was reduced to about 110,000 bpd. Repairs are expected to take several months and Suncor does not expect to return to full capacity of 225,000 bpd until the third quarter of 2005.

The company carries property loss and business interruption insurance policies with a combined coverage limit of up to US$1.15 billion, net of deductible amounts, that will mitigate, upon receipt of these funds, a portion of the financial impact of this incident. The primary property loss policy of US$250 million has a deductible per incident of US$10 million and the primary business interruption policy of US$200 million has a deductible per incident of the greater of US$50 million gross earnings lost (as defined in the insurance policy) or 30 days from the incident. In addition to these primary coverage insurance policies, Suncor has excess coverage of US$700 million that can be used for either property loss or business interruption coverage. For business interruption purposes, this excess coverage begins on the later of full utilization of the primary business interruption coverage or 90 days from the date of the incident. For accounting purposes, the company will accrue insurance proceeds up to the net book value of the damaged assets. Proceeds in excess of this amount, as well as business interruption proceeds, will be recorded when unconditionally settled.

As the company is still evaluating the effect of the fire on its operations, the financial impact of this incident cannot currently be determined.

The impact on liquidity and capital resources is described in more detail below.

Liquidity and Capital Resources

Suncor’s capital resources at December 31, 2004 consisted primarily of cash flow from operations and available lines of credit. Suncor’s level of earnings and cash flow from operations depend on many factors, including commodity prices, production levels, downstream margins related to the operations of EM&R and R&M and Cdn$/US$ exchange rates. In 2005, cash flow from operations will be negatively impacted by the upgrader fire in Oil Sands.

At December 31, 2004, Suncor’s net debt (short and long-term debt less cash and cash equivalents) was approximately $2.2 billion compared to $2.1 billion at December 31, 2003. Including preferred securities, net debt was $2.6 billion at December 31, 2003. In February 2004, Suncor repaid all $125 million of its then outstanding 7.4% debentures. In March 2004, the company redeemed its 9.05% and 9.125% preferred securities for cash consideration of $493 million. Approximately $300 million of the reduction in total net debt, including preferred securities in 2004, was generated from cash flow with the balance attributable to foreign exchange gains.

In 2004, Suncor renewed its available credit facilities of approximately $1.7 billion. Suncor’s undrawn lines of credit at December 31, 2004, were approximately $1.5 billion. Suncor’s current long-term senior debt ratings are A- by Standard & Poor’s, A(low) by Dominion Bond Rating Service and A3 by Moody’s Investors Service. All debt ratings have a stable outlook.

In 2000, Suncor entered into a financing arrangement with a third-party, whereby Suncor sold an undivided interest in Oil Sands energy services assets for $101 million and leased the assets back from the third-party. Suncor repurchased the assets in December 2004 with financing through existing revolving credit facilities. Since this lease was capitalized for accounting purposes, it was included in Suncor’s debt at the end of 2003.

Interest expense on debt continues to be influenced by the composition of the company’s debt portfolio, with Suncor benefiting from short-term floating interest rates

Suncor Energy Inc. 2004 Annual Report

continuing at low levels. To manage fixed versus floating rate exposure, Suncor has entered into interest rate swaps with investment grade counterparties, resulting in the swapping of $600 million of fixed rate debt to variable rate borrowings.

Management of debt levels continues to be a priority given Suncor’s growth plans. The company believes a phased approach to existing and future growth projects should maintain its ability to manage project costs and debt levels.

Suncor believes it has the capital resources to fund its 2005 capital spending program of $2.5 billion and to meet current working capital requirements, notwithstanding the impact of the fire at Oil Sands on cash flow from operations and the cost to repair damaged facilities. However, the time required for Suncor’s Oil Sands facilities to return to full production, and the timing of receipts of the insurance proceeds may significantly impact Suncor’s capital resources and consequently Suncor’s financing plan will be reviewed throughout 2005. If additional capital is required, the company believes adequate additional financing is available at commercial terms and rates.

Suncor anticipates its growth plan to be largely financed from internal cash flow, which is dependent on commodity prices and other factors. After 2005, to support its growth strategy and sustain operations, Suncor is projecting an annual capital spending program of approximately $2.3 billion to $2.5 billion that will continue for the foreseeable future. Actual spending is subject to change due to such factors as internal and external approvals and capital availability. Refer to the discussion under Risk/Success Factors Affecting Performance on page 25 for additional factors that can have an impact on Suncor’s ability to generate funds to support investing activities.

Aggregate Contractual Obligations and Off-balance Sheet Financing

	Payments Due by Period
($ millions)	Total	2005	2006-07	2008-09	Later Years
Fixed-term debt, commercial paper and capital leases (1)	2 217	91	405	3	1 718
Interest payments on fixed-term debt, commercial paper and capital leases (1)	2 544	141	264	229	1 910
Employee future benefits (2)	441	31	70	80	260
Asset retirement obligations (3)	1 079	47	87	57	888
Non-cancellable capital spending commitments (4)	157	157	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	4 798	222	438	458	3 680
Total	11 236	689	1 264	827	8 456

In addition to the enforceable and legally binding obligations quantified in the above table, the company has other obligations for goods and services and raw materials entered into in the normal course of business, which may terminate on short notice. Commodity purchase obligations for which an active, highly liquid market exists and which are expected to be re-sold shortly after purchase, are one example of excluded items.

(1) Includes $2,104 million of U.S. and Canadian dollar denominated debt that is redeemable at the option of the company. Maturities range from 2007 to 2034. Interest rates vary from 5.95% to 7.15%. The company entered into various interest rate swap transactions maturing in 2007 and 2011 that resulted in an average effective interest rate in 2004 ranging from 3.5% to 4.3% on $600 million of the company’s medium-term notes. Approximately $89 million of commercial paper with an effective interest rate of 2.3% was issued in 2004.

(2) Represents the undiscounted expected benefit payments to retirees for pension and other post-employment benefits.

(3) Represents the undiscounted amount of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.

(4) Non-cancellable capital commitments related to capital projects totalled approximately $157 million at the end of 2004. The grouping of commitments outstanding is associated with the Firebag in-situ development ($48 million), expanded production facilities at Oil Sands ($27 million), and desulphurization projects at the company’s refineries ($82 million).

(5) Includes transportation service agreements for pipeline capacity and tankage for the shipment of crude oil from Fort McMurray to Hardisty, Alberta, as well as energy services agreements to obtain a portion of the power and steam generated by a cogeneration facility owned by a major energy company. Non-cancellable operating leases are for service stations, office space and other property and equipment.

Suncor Energy Inc. 2004 Annual Report

The company is subject to financial and operating covenants related to its public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as described in the respective debt agreements, potentially resulting in accelerated repayment of one or more of the debt obligations.

In addition, a very limited number of the company’s commodity purchase agreements, off-balance sheet arrangements and derivative financial instrument agreements, contain provisions linked to debt ratings that may result in settlement of the outstanding transactions should the company’s debt ratings fall below investment grade status.

At December 31, 2004, the company was in compliance with all material covenants and its debt ratings were investment grade with a stable outlook. For more information, see page 21.

Variable Interest Entities and Guarantees

At December 31, 2004, the company had off-balance sheet arrangements with Variable Interest Entities (VIEs), and indemnification agreements with other third parties, as described below.

The company has a securitization program in place 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. The third-party is a multiple party securitization vehicle that provides funding for numerous asset pools. As at December 31, 2004, $170 million in outstanding accounts receivable had been sold under the program. Under the recourse provisions, the company will provide indemnification against credit losses for certain counterparties, which did not exceed $50 million in 2004. A liability has not been recorded for this indemnification as the company believes it has no significant exposure to credit losses. There were no new securitization proceeds in 2004. Proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2004, were approximately $2,073 million. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2004 (2003 and 2002 – $3 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a third-party for proceeds of $30 million. The third-party’s sole asset is the equipment sold to it and leased back by the company. The initial lease term covers a period of seven years and as at December 31, 2004, was accounted for as an operating lease. The company has provided a residual value guarantee on the equipment of up to $7 million should it elect not to repurchase the equipment at the end of the lease term. An early termination purchase option allows for the repurchase of the equipment at a specified date in 2005. Had the company elected to terminate the lease at December 31, 2004, the total cost would have been $25 million. Annualized equipment lease payments in 2004 were $6 million (2003 – $4 million; 2002 – $2 million). This VIE was consolidated effective January 1, 2005.

The company has agreed to indemnify holders of the 7.15% fixed-term U.S. dollar notes, the 5.95% fixed-term U.S. dollar notes and the company’s credit facility lenders for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to the receivables securitization program, and certain facility and equipment leases.

There is no limit to the maximum amount payable under the indemnification agreements described above. The company is unable to determine the maximum potential amount payable as government regulationsand legislation are subject to change without notice. Under these agreements, Suncor has the option to redeem or terminate these contracts if additional costs are incurred.

Outlook

During 2005, management will focus on the following operational priorities:

• Complete fire recovery and planned maintenance at Oil Sands to return to full production in the third quarter.

• Increase natural gas production volumes to 205 to 210 mmcf/d. Suncor will continue to focus on high impact natural gas plays and work to achieve an annual target of 3% to 5% production growth. For more information, see page 43.

• Build for future Oil Sands growth. Expansion projects to increase Oil Sands production capacity to 260,000 bpd are expected to be complete by the end of 2005. Work to bring production capacity to 350,000 bpd in 2008 is also expected to reach several milestones with fabrication and transport of major vessels planned to be completed in 2005. In planning for expansion beyond 2008, Suncor expects to file a regulatory application in 2005 to construct a third upgrader, a key step towards increasing production capacity to 500,000 to 550,000 bpd in the 2010 to 2012 time frame. For more information, see page 39.

Suncor Energy Inc. 2004 Annual Report

• Focus on enterprise-wide efficiency. To more seamlessly integrate Suncor’s operations and prepare for future growth, the company is implementing a company-wide ERP information and management system.

• Advance downstream integration plans. Suncor will reach peak activity on modifications to the Sarnia and Denver refineries to meet 2006 low-sulphur diesel regulations and integrate increased volumes of oil sands production in both refineries. For more information, see pages 47 and 50.

Oil Sands Crown Royalties and Cash Income Taxes

Crown royalties in effect for Oil Sands operations require payments to the Government of Alberta, based on gross revenues less related transportation costs (R), less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. In April 2004, the Alberta government confirmed it would modify Suncor’s royalty treatment because it does not recognize the company’s Firebag in-situ facility as an expansion to the company’s existing Oil Sands Project. Accordingly, for Alberta Crown royalty purposes, Suncor’s oil sands operations are considered two separate projects: base oil sands mining and associated upgrading operations with royalties based on upgraded product values and the current Firebag in-situ project with royalties based on bitumen values. On this basis, Suncor has provided for estimated pretax Alberta Oil Sands Crown royalties in 2004 of $407 million. Alberta Oil Sands Crown royalties may be subject to change as policies arising from the Government’s position are finalized and audits of the 2004 and prior years are completed. Changes to the estimated amounts previously recorded will be reflected in the company’s financial statements on a prospective basis and may be significant.

In July, Suncor issued a statement of claim against the Crown, seeking, among other things, to overturn the government’s decision on the royalty treatment of Firebag. The Crown has issued a statement of defence. To date, there have been no significant further developments with respect to these legal proceedings.

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

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

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

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

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

Suncor Energy Inc. 2004 Annual Report

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

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. The company currently estimates that in 2010 the impact of the Kyoto Protocol on Oil Sands cash operating costs would be an increase of about $0.20 to $0.27 per barrel. This estimate assumes a reduction obligation of 15% from 2010 business-as-usual energy intensity(1) and that the maximum price for carbon credits would, as the Government of Canada indicated in 2002, be capped at $15 per tonne of carbon dioxide equivalent until 2012. Based on these assumptions, Suncor does not currently anticipate that the cost implications of federal and provincial climate change plans will have a material impact on its business or future growth plans.

The ultimate impact of Canada’s 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.

Risk/Success Factors Affecting Performance

Suncor’s financial and operational performance is potentially affected by a number of factors including, but not limited to, commodity prices and exchange rates, environmental regulations, stakeholder support for growth plans, extreme winter weather, regional labour issues and other issues discussed within Risk/Success Factors for each Suncor business segment. A more detailed discussion of risk factors is presented in the company’s most recent AIF/40-F, filed with securities regulatory authorities.

Commodity Prices, Refined Product Margins and Exchange Rates

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, seasonality, worldwide political events and weather. These factors, among others, can result in a high degree of price volatility. For example, from 2002 to 2004 the monthly average price for benchmark WTI crude oil ranged from a low of US$19.70 per barrel to a high of US$53.10 per barrel. During the same three-year period, the natural gas Henry Hub benchmark monthly average price ranged from a low of US$2.00 per mcf to a high of US$9.30 per mcf. Suncor believes commodity price volatility will continue.

Crude oil and natural gas prices are based on U.S. dollar benchmarks that result in Suncor’s realized prices being influenced by the Cdn$/US$ currency exchange rate, thereby creating an element of uncertainty for the company. Should the Canadian dollar strengthen compared to the U.S. dollar, the negative effect on net earnings would be partially offset by foreign exchange gains on the company’s U.S. dollar denominated debt. Conversely, should the Canadian dollar weaken compared to the U.S. dollar, the positive effect on net earnings would be partially offset by foreign exchange losses on the company’s U.S. dollar denominated debt. Cash flow from operations is not impacted by the effects of currency fluctuations on the company’s U.S. dollar denominated debt.

Changes to the Cdn$/US$ exchange rate relationship can create significant volatility in foreign exchange gains or losses. On the outstanding US$1 billion in U.S. dollar denominated debt at the end of 2004, a $0.01 change in the Cdn$/US$ exchange rate would change earnings by approximately $12 million after tax.

During 2004, the strengthening of the Canadian dollar against the U.S. dollar resulted in a $74 million after tax foreign exchange gain on the company’s U.S. dollar denominated debt.

Suncor’s U.S. capital projects are expected to be partially funded from Canadian operations. A weaker Canadian dollar would result in a higher funding requirement for these projects.

(1) Reflects the level of greenhouse gas emissions that would have occurred in the absence of energy efficiency and process improvements after 2000.

Suncor Energy Inc. 2004 Annual Report

Sensitivity Analysis (1)

					Approximate Change in
	2004 Average		Change		Cash Flow from Operations	After-tax Earnings

Oil Sands
Price of crude oil ($/barrel) (2)	$	42.28	US$	1.00	43	28
Sweet/sour differential ($/barrel)	$	8.65	US$	1.00	32	20
Sales (bpd)	226 300		1 000		10	7
Natural Gas
Price of natural gas ($/mcf) (2)	$	6.70	0.10		6	3
Production of natural gas (mmcf/d)	200		10		16	7
Energy Marketing and Refining – Canada
Retail gasoline margins (cpl)	4.4		0.1		2	1
Refining/wholesale margin (cpl) (2)	8.0		0.1		6	4
Refining and Marketing – U.S.A.
Retail gasoline margins (cpl)	5.4		0.1		—	—
Refining/wholesale margin (cpl)	6.7		0.1		3	2
Consolidated
Exchange rate: Cdn$/US$	0.77		0.01		33	10

(1) The sensitivity analysis shows the main factors affecting Suncor’s annual cash flow from operations and after-tax earnings based on actual 2004 operations. The table illustrates the potential financial impact of these factors applied to Suncor’s 2004 results. A change in any one factor could compound or offset other factors.

(2) Includes the impact of hedging activities.

Derivative Financial Instruments

The company periodically enters into commodity-based derivative financial instruments such as forwards, futures, swaps and options to hedge against the potential adverse impact of changing market prices due to variations in underlying commodity indices. The company also periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage exposure to interest rate fluctuations.

The company also uses energy derivatives, including physical and financial swaps, forwards and options to gain market information and to earn trading revenues. These trading activities are accounted for at fair value in the company’s consolidated financial statements.

Derivative contracts accounted for as hedges are not recognized in the Consolidated Balance Sheets. Realized and unrealized gains or losses on these contracts, including realized gains and losses on derivative hedging contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized.

Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.

Commodity Hedging Activities Suncor’s strategic crude oil hedging program has been the subject of periodic management reviews to determine the continued need for hedging in light of the company’s tolerance for exposure to market volatility, as well as its need for stable cash flow to finance future growth. In the first quarter of 2004, Suncor’s Board of Directors suspended the company’s strategic crude oil hedging program. As a result, the company did not enter into any new strategic crude oil arrangements in 2004. The strength of the company’s financial position, combined with stable operating costs and a growing production base, reduces the company’s risk to crude oil price volatility. Suncor intends to settle all of the strategic crude oil hedges that were outstanding at December 31, 2004, as the related financial derivatives mature throughout 2005.

Prior to the suspension of the hedging program, the company had entered contracts to fix the price on 36,000 barrels of crude oil per day at an average price of US$23 per barrel. These contracts expire on December 31, 2005. On settlement, these contracts result in cash receipts to the company, or payments by the company, for the difference between the derivative contract and market rates for the applicable volumes hedged during the contract term. Such cash receipts or

Suncor Energy Inc. 2004 Annual Report

payments offset corresponding decreases or increases in the company’s sales revenues or crude oil purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings. In 2004, crude oil hedging decreased Suncor’s net earnings by $397 million compared to a decrease of $155 million in 2003 (2002 – decrease of $160 million).

Crude oil hedge contracts outstanding at December 31, 2004, were as follows:

		Quantity (bpd)		Average Price (a)		Revenue Hedged ($ millions)		Hedge Period
Crude oil swaps		36 000		23		364	(b)	2005

(a) Average price of crude oil swaps is US$/barrel WTI at Cushing.

(b) The revenue hedged is translated to Cdn$ at the year-end exchange rate for convenience purposes.

Financial Hedging Activities Suncor periodically enters into interest rate swap contracts as part of its strategy to manage exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized as an adjustment to interest expense.

The company has entered into various interest rate swap transactions at December 31, 2004. The swap transactions result in an average effective interest rate that is different from the stated interest rate of the related underlying long-term debt instruments.

Description of swap transaction	Principal Swapped ($ millions)	Swap Maturity	2004 Effective Interest Rate
Swap of 6.10% Medium Term Notes to floating rates	150	2007	3.6	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	4.3	%
Swap of 6.70% Medium Term Notes to floating rates	200	2011	3.5	%

In 2004, these interest rate swap transactions reduced pretax financing expense by $17 million compared to a pretax reduction of $12 million in 2003 (2002 – $13 million).

Fair Value of Strategic Derivative Hedging Instruments

The fair value of derivative hedging instruments is the estimated amount, based on broker quotes and internal valuation models that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:

($ millions)	2004		2003
Revenue hedge swaps and collars	(305	)	(285	)
Margin hedge swaps	5		2
Interest rate swaps	36		32
	(264	)	(251	)

The company also uses derivative instruments to hedge risks specific to individual transactions. The estimated fair value of these instruments was $9 million at December 31, 2004, compared to $1 million at December 31, 2003.

Energy Trading Activities Energy trading activities focus on the commodities the company produces. In addition to those financial derivatives used for hedging activities, the company also uses energy derivatives to gain market information and earn trading revenues. These energy trading activities are accounted for using the mark-to-market method, and as such, physical and financial energy contracts are recorded at fair value at each balance sheet date. During 2004, Suncor recorded a net pretax gain of $11 million compared to a pretax loss of $3 million in 2003 (2002 – nil) related to the settlement and revaluation of financial energy trading contracts. In 2004, the settlement of physical trading activities also resulted in a net pretax gain of $12 million compared to a pretax gain of $2 million in 2003 (2002 – $6 million). These gains were included as energy trading and marketing activities in the Consolidated Statements of Earnings. Net of related general and administrative costs, these activities resulted in 2004 net earnings of $12 million after tax compared to a net loss of $2 million after tax in 2003.

Suncor Energy Inc. 2004 Annual Report

The fair value of unsettled financial energy trading assets and liabilities at December 31 were as follows:

($ millions)	2004	2003
Energy trading assets	26	5
Energy trading liabilities	9	5

The valuation of the above contracts was based on actively quoted prices and internal valuation models.

Counterparty Credit Risk The company may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The company’s exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date. The company minimizes this risk by entering into agreements with counterparties of which substantially all are investment grade. Risk is also minimized through regular management review of potential exposure to, and credit ratings of, such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2004	2003
Derivative contracts not accounted for as hedges	7	30
Unrecognized derivative contracts	21	27
	28	57

Environmental Regulations

Environmental laws affect 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 laws also affect refining, distribution and marketing of petroleum products and petrochemicals and require 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 that changes to environmental laws 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 usage, and reformulated fuels to support lower vehicle emissions. Changes in environmental laws 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.

Regulatory Approvals

Before proceeding with most major projects, Suncor must obtain regulatory approvals. The regulatory approval process can involve stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow.

Critical Accounting Estimates

Suncor’s critical accounting estimates are defined as estimates that are important to the portrayal of the company’s financial position and operations, and require management to make judgments based on underlying assumptions about future events and their effects. Underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances. These 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. Critical accounting estimates are reviewed by the Audit Committee of the Board of Directors annually. The company believes the following are the most critical accounting estimates used in the preparation of its consolidated financial statements.

Suncor Energy Inc. 2004 Annual Report

Property, Plant and Equipment

Suncor accounts for its Oil Sands in-situ and NG exploration and production activities using the “successful efforts” method. This policy was selected over the alternative full-cost method because Suncor believes it provides a more timely accounting of the success or failure of exploration and production activities.

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 dry hole costs are written off and reported as part of Oil Sands and NG exploration expenses in the Consolidated Statements of Earnings. Dry hole expense can fluctuate from year to year due to such factors as the level of exploratory spending, the level of risk sharing with third parties participating in the exploratory drilling and the degree of risk in drilling in particular areas.

Properties that are assumed to be productive may, over a period of time, actually deliver oil and gas in quantities different than originally estimated because of changes in reservoir performance and/or adjustments in reserves. Such changes may require a test for the potential impairment of capitalized properties 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 reduced to fair value and either completely removed from the company’s records (“written off”) or partially removed from the company’s records (“written down”) and reported as part of Oil Sands and NG DD&A expenses in the Consolidated Statements of Earnings.

The company’s plant and equipment are depreciated on a straight-line basis over the estimated useful life of the assets. Firebag and NG property costs are depleted on a unit of production (UOP) basis. In each case, the expense is shown on the DD&A line in both the Consolidated Statements of Earnings and in the Schedules of Segmented Earnings. The straight-line basis reflects asset usage as a function of time rather than production levels. For example, the useful life of plant and equipment at Oil Sands base operations and Firebag operations are not based on recorded reserves as the company has access to other undeveloped properties, and bitumen feedstock from third parties, as well as the ability to provide processing services for other producers’ bitumen. UOP amortization is used where that method better matches the asset utilization with production with which the asset is associated.

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. As the majority of assets are depreciated on a straight-line basis, a 10% reduction in the useful life of plant and equipment would increase annual DD&A by approximately 10%. This impact would be reflected in all business segments with the majority of the impact being in Oil Sands.

Negative revisions in NG reserves estimates will result in an increase in depletion expenses.

Overburden

As part of the process of mining oil sands, it is necessary to remove surface material such as muskeg, glacial deposits and sand. This surface material is referred to as overburden. 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 mined in the period, and as such the cash outlays can be different than the amount amortized. In 2004, the overburden amortization charge was $225 million (2003 – $208 million) compared with actual cash overburden spending of $222 million (2003 – $175 million). Oil Sands overburden amortization is reported as part of DD&A in the Consolidated Statements of Earnings. Deferred overburden costs are reported as part of “deferred charges and other” in the ConsolidatedBalance Sheets.

To ensure 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.

Suncor Energy Inc. 2004 Annual Report

To allocate the deferred overburden charges, a life-of-mine approach has been adopted for each mine pit, relating the removal of all overburden (on a volume basis) to the mining of all of the oil sands ore on leases where there is regulatory approval (on a tonnage basis). By adopting this approach, an overburden “stripping ratio” is calculated that relates overburden removal costs to all proved and probable Oil Sands ore reserves. Over time, through a combination of increased mine areas, 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. In 2004, the stripping ratio increased by approximately 13% due to new operational information and mine plan changes. The effects of the increased stripping ratio were offset by lower per unit overburden removal costs. The net effect of these factors resulted in a $16 million pretax increase in the amount of overburden deferred in the year.

Asset Retirement Obligations (ARO)

Effective January 1, 2004, Suncor adopted the new Canadian accounting standard “Asset Retirement Obligations”. Under this standard, the company is required to recognize a liability for the future retirement obligations associated with the company’s property, plant, and equipment. An ARO is only recognized to the extent of a legal obligation associated with the retirement of a tangible long-lived asset that Suncor is required to settle as a result of an existing or enacted law, statute, ordinance, or written or oral contract, or by legal construction of a contract under the doctrine of promissory estoppel. The ARO is based on estimated costs, taking into account the anticipated method and extent of restoration consistent with legal requirements, technological advances and the possible use of the site. Since these estimates are specific to the sites involved, there are many individual assumptions underlying the company’s total ARO amount. These individual assumptions can be subject to change based on experience.

The ARO is initially measured at fair value and discounted to present value using a credit-adjusted risk-free discount rate of 6% (2003 – 6.5%). The ARO accretes over time until the company settles the obligations and the effect is included in a separate “accretion of asset retirement obligations” expense line in the Consolidated Statements of Earnings. Payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years. The discount rate will be adjusted, when appropriate, to reflect long-term changes in market rates and outlook.

An ARO is not recognized for assets with an indeterminate useful life because the amount cannot be reasonably estimated. An ARO for these assets will be recorded in the first period in which the lives of the assets are determinable.

In connection with company reviews of Oil Sands and NG completed in the fourth quarter of 2004, Suncor increased its estimated undiscounted total obligation to approximately $1.1 billion from the previous estimate of $1.0 billion. The increase was due to a change in the Oil Sands estimate to $940 million primarily reflecting increased estimated land reclamation costs related to the south tailings pond. The majority of the costs in Oil Sands are projected to occur over a time horizon extending to approximately 2060. In 2005, these changes in the ARO estimate are anticipated to result in additional after-tax expense of approximately $6 million.

The greatest area of judgment and uncertainty with respect to the company’s asset retirement obligations 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 technology. 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 asset retirement cost estimates. The company continues to monitor and assess other possible technologies and/or modifications to the consolidated tailings process now being used.

Reserves Estimates

Suncor is a Canadian issuer and is subject to Canadian reporting requirements, including rules in connection with the reporting of its reserves. However, the company has received an exemption from Canadian securities administrators permitting it to report its reserves in accordance with U.S. disclosure requirements. Pursuant to U.S. disclosure requirements, the company discloses net proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from its Firebag in-situ leases, using constant dollar cost and pricing assumptions. As there is no recognized posted bitumen price, these assumptions are based on a posted benchmark oil price (1) adjusted for transportation, gravity and other factors that create the difference (“differential”) in price between the posted benchmark price and Suncor’s bitumen. Both the posted benchmark price and the differential are generally determined as of a point in time, namely, December 31(“Constant Cost and Pricing”). Suncor’s reserves from its

(1) Under U.S. disclosure requirements, the posted benchmark oil price utilized was Lloydminster light blend, a medium density crude oil and under Annual Average Differential Pricing, the posted benchmark oil price utilized was light sweet at Edmonton, a light density crude oil.

Suncor Energy Inc. 2004 Annual Report

Firebag in-situ leases are reported as barrels of bitumen, using these Constant Cost and Pricing assumptions (see Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves for net proved conventional oil and gas reserves).

Pursuant to U.S. disclosure requirements, Suncor also discloses gross proved and probable mining reserves. The estimate of its mining reserves is based in part on the current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing and cost assumptions. In accordance with these rules, the company reports mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80% to 81%. Suncor does not disclose its mining reserves on a net basis as it is continuing to discuss the terms of its option to transition to the Province of Alberta’s generic bitumen-based royalty regime in 2009 and accordingly the net mining reserves calculation cannot be estimated (see Required U.S. Oil and Gas and Mining Disclosure – Proved and Probable Oil Sands Mining Reserves). Suncor’s Firebag in-situ leases are already subject to royalty based on bitumen, rather than synthetic crude oil. (For a full discussion of Suncor’s Oil Sands Crown royalties, see page 24.)

In addition to required disclosure, Suncor’s exemption issued by Canadian securities administrators permits it to provide further disclosure voluntarily. Suncor provides this voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and reserves from its Firebag in-situ leases. In its aggregate voluntary disclosure, Suncor reports reserves on the following basis:

• Gross proved and probable mining reserves, on the same basis as disclosed pursuant to U.S. disclosure requirements (reported as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80% to 81%); and

• Gross proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on normalized constant dollar cost and pricing assumptions. These assumptions use a posted benchmark oil price as of December 31, but apply a differential generally intended to represent a normalized annual average for the year (“Annual Average Differential Pricing”), rather than a point in time differential, in accordance with Canadian Securities Administrators Staff Notice 51-315 (CSA Staff Notice 51-315). Bitumen reserves estimated on this basis are subsequently converted, for comparison purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 82%.

Accordingly, Suncor’s voluntary disclosures of proved and probable reserves from its Firebag in-situ leases will differ from the required U.S. disclosure in three ways. Reserves from Suncor’s Firebag in-situ leases are:

• disclosed on a gross basis versus a net basis under U.S. disclosure requirements;

• converted from barrels of bitumen under U.S. disclosure requirements to barrels of synthetic crude oil for comparability purposes only; and

• evaluated based on 2004 Annual Average Differential Pricing, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

Under the U.S. disclosure requirements described above, Suncor announced on January 21, 2005 that it debooked proved reserves from the company’s Firebag in-situ leases. December 31, 2004 point-in-time posted benchmark oil prices were unusually low and December 31, 2004 point-in-time diluent prices, which form part of the differential calculation, were unusually high. This combination resulted in a determination that Suncor’s proved Firebag in-situ reserves were uneconomic as at December 31, 2004 (see Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves).

Under Suncor’s voluntary disclosure, using 2004 Annual Average Differential Pricing, proved Firebag in-situ reserves were determined to be economic and accordingly, are disclosed under Voluntary Oil Sands Reserves Disclosure. Comparisons of these two reserve estimates will show material differences based primarily on the pricing assumptions used, but will also show differences based on whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, and whether the reserves are reported on a gross or net basis.

All of Suncor’s oil and gas reserves have been evaluated as at December 31, 2004 by independent petroleum consultants, Gilbert Laustsen Jung Associates Ltd. (GLJ). In reports dated February 9, 2005, and February 17, 2005 (GLJ Oil Sands Reports), GLJ evaluated Suncor’s proved and probable reserves on its oil sands mining leases and Firebag in-situ leases respectively, pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions, and CSA Staff Notice 51-315, using 2004 Annual Average Differential Pricing assumptions.

Suncor Energy Inc. 2004 Annual Report

Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory approvals have been granted. The mining reserve estimates are based on a detailed geological assessment and also consider industry practice, drill density, production capacity, extraction recoveries, upgrading yields, mine plans, operating life, and regulatory constraints.

For Firebag in-situ reserve estimates, GLJ considered similar factors such as Suncor’s regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects, and drill density. Suncor’s proved and probable reserves are contained within the AEUB approval area. Proved reserves are delineated with 40 to 80 acre spacing and 3D seismic control while probable reserves are delineated with 80 to 160 acre spacing and 3D seismic control. The major facility expenditures to develop proved undeveloped reserves have obtained final approval by Suncor’s Board. Plans to develop the probable undeveloped reserves in subsequent phases are under way but have not yet received final approval from the Board.

In a report dated February 17, 2005 (GLJ NG Report), GLJ also evaluated Suncor’s proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from mining leases and the Firebag in-situ reserves) as at December 31, 2004.

More information about the evaluation of Suncor’s reserves by GLJ, as well as additional oil and gas data, is available in Suncor’s most recent Annual Information Form.

Reserves estimates will continue to be impacted by both drilling data and operating experience, as well as technological developments and economic considerations.

Required U.S. Oil and Gas and Mining Disclosure

Proved and Probable Oil Sands Mining Reserves

	Gross Oil Sands Mining Leases (2)
Millions of barrels of synthetic crude oil (1)	Proved		Probable		Proved & Probable
December 31, 2003	878		952		1 830
Revisions of previous estimates	140		(105	)	35
Extensions and discoveries	—		—		—
Production	(79	)	—		(79	)
December 31, 2004	939		847		1 786

(1) Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80% to 81%.

(2) Suncor’s gross mining reserves are based in part on its current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing and cost assumptions.

Suncor does not disclose its mining reserves on a net, after royalty basis as it continues to discuss the terms of its option to transition to the Province of Alberta’s generic bitumen based royalty regime in 2009 and accordingly the net mining reserves calculation cannot be estimated (see page 24 for a discussion of our royalty regime).

Proved Conventional Oil and Gas Reserves

The following data is provided on a net basis in accordance with the provisions of the Financial Accounting Standards Board’s Statement No. 69 (Statement 69). This statement requires disclosure about conventional oil and gas activities only, and therefore the company’s Oil Sands mining activities are excluded, while Firebag in-situ reserves are included.

Suncor Energy Inc. 2004 Annual Report

Net Proved Reserves (2)

Crude Oil, Natural Gas Liquids and Natural Gas

Constant Cost and Pricing as at December 31	Oil Sands business: Firebag – crude oil (millions of barrels of bitumen) (1) (3) (4)		Natural Gas business: crude oil and natural gas liquids (millions of barrels) (5)		Total (millions of barrels)		Natural Gas business: natural gas (billions of cubic feet) (5)
December 31, 2003	424		8		432		456
Revisions of previous estimates	(420	)(3)	1		(419	)	(23	)
Purchases of minerals in place	—		—		—		14
Extensions and discoveries	—		—		—		53
Production	(4	)	(1	)	(5	)	(54	)
Sales of minerals in place	—		—		—		—
December 31, 2004	—		8		8		446

(1) Oil Sands business – Firebag net reserves means Suncor’s undivided percentage interest in total reserves after deducting Crown royalties, freehold and overriding royalty interests. The calculation of these third-party interests is uncertain and based on assumptions about future prices, production levels, operating costs and capital expenditures.

(2) Although Suncor is subject to Canadian disclosure rules in connection with the reporting of its reserves, the company has received exemptive relief from Canadian securities administrators permitting it to report its proved reserves in accordance with U.S. disclosure practices.

(3) Estimates of proved reserves from Suncor’s Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31, 2004. Due to unusually low year-end posted benchmark oil prices and unusually high year-end diluent prices, Suncor’s proved reserves were determined to be uneconomic as at this year end point in time.

(4) The company has the option of selling the bitumen production from these leases and/or upgrading the bitumen to synthetic crude oil.

(5) Natural Gas business net reserves means Suncor’s undivided percentage interest in total reserves after deducting interest of third parties, including Crown royalties, freehold and overriding royalties, calculated following generally accepted guidelines, on the basis of prices and the royalty structure in effect at year end and anticipated production rates. The calculation of these third-party interests is uncertain and based on assumptions about future natural gas prices, production levels, operating costs and capital expenditures. Royalties can vary depending upon selling prices, production volumes, timing of initial production and changes in legislation.

Voluntary Oil Sands Reserves Disclosure

Oil Sands Mining and Firebag

In-situ Reserves Reconciliation

The following table sets out, on a gross basis, a reconciliation of Suncor’s proved and probable reserves of synthetic crude oil from its Oil Sands mining leases and bitumen, converted to synthetic crude oil for comparison purposes only, from its Firebag in-situ leases, from December 31, 2003 to December 31, 2004, based on the GLJ Oil Sands Reports, in accordance with CSA Staff Notice 51-315, using 2004 Annual Average Differential Pricing assumptions.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

							Firebag In-situ Leases(1)(3) (Constant Pricing)					Total Mining and In-situ (4) Proved & Probable
	Oil Sands Mining Leases (1)(2)						Firebag In-situ Leases(1)(3) (Constant Pricing)
					Proved & Probable					Proved & Probable
Millions of barrels of synthetic crude oil (1)	Proved		Probable		Proved & Probable		Proved (3)		Probable (4)	Proved & Probable
December 31, 2003	878		952		1 830		387		1 721	2 108		3 938
Revisions of previous estimates	140		(105	)	35		110		179	289		324
Extensions and discoveries	—		—		—		—		—	—		—
Production	(79	)	—		(79	)	(3	)	—	(3	)	(82	)
December 31, 2004	939		847		1 786		494		1 900	2 394		4 180

(1) Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of between 80% and 81% for reserves under Oil Sands Mining Leases and of 82% for reserves under Firebag In-situ Leases. Although virtually all of Suncor’s bitumen from the Oil Sands mining leases is upgraded into synthetic crude oil, the company has the option of selling the bitumen produced from its Firebag in-situ leases and/or upgrading this bitumen to synthetic crude oil and accordingly, these bitumen reserves are converted to synthetic crude oil for comparison purposes only.

(2) Suncor’s gross mining reserves are evaluated in part, based on the current mine plan and estimates of extraction recovery and upgrading yields, rather than an analysis based on constant dollar or forecast pricing assumptions.

(3) Under Required U.S. Oil and Gas and Mining Disclosure, Suncor reported no proved reserves from Firebag in-situ leases. The disclosure in the table above reports proved reserves from these leases and differs in the following three ways. Reserves from Firebag in-situ leases are:

(a) disclosed in this table on a gross basis versus a net basis;

(b) converted from barrels of bitumen to barrels of synthetic crude oil in this table for comparability purposes only; and

(c) evaluated based on Annual Average Differential Pricing assumptions versus point-in-time Constant Cost and Pricing assumptions as at December 31. Accordingly, Firebag in-situ reserve estimates under Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves and Firebag in-situ proved reserve estimates in this table differ materially.

(4) U.S. companies do not disclose probable reserves for non-mining properties. Suncor voluntarily discloses its probable reserves for Firebag in-situ leases as it believe this information is useful to investors, and allows the company to aggregate its mining and in-situ reserves into a consolidated total for its Oil Sands business. As a result, Suncor’s Firebag in-situ estimates are not comparable to those made by U.S. companies.

Suncor Energy Inc. 2004 Annual Report

Employee Future Benefits

The company provides a range of benefits to its employees and retired employees, including pensions and other post-retirement health care and life insurance benefits. 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. Management continually reviews these assumptions in light of actual experience and expectations for the future. Changes in assumptions are accounted for on a prospective basis. Employee future benefit costs are reported as part of operating, selling and general expenses in the company’s Consolidated Statements of Earnings and Schedules of Segmented Data. The accrued benefit liability is reported as part of “accrued liabilities and other” in the Consolidated Balance Sheets.

The assumed rate of return on plan assets considers the current level of expected returns on the fixed income portion of the plan assets portfolio, the historical level of risk premium associated with other asset classes in the portfolio and the expected future returns on each asset class. The discount rate assumption is based on the year end interest rate on high quality bonds with maturity terms equivalent to the benefit obligations. The rate of compensation increases is based on management’s judgment. 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. A 1% change in the assumptions at which pension benefits and other post-retirement benefit liabilities could be effectively settled is as noted below.

	Rate of Return on Plan Assets			Discount Rate			Rate of Compensation Increase
($ millions)	1% Increase		1% Decrease	1% Increase		1% Decrease	1% Increase	1% Decrease
Increase (decrease) to net periodic benefit cost	(4	)	4	(11	)	12	6	(5	)
Increase (decrease) to benefit obligation	—		—	(99	)	115	30	(27	)

Health care costs comprise a significant element of Suncor’s post-employment benefit obligation and an area where there is increasing cost pressure due to an aging North American society. Suncor has assumed an 11.5% annual rate of increase in the per capita cost of covered health care benefits for 2004, with an assumption that this rate will decrease by 0.5% annually, to 5% by 2017, and remain at that level thereafter.

A 1% change in the assumed health care cost trend rate would have the following effect:

($ millions)	1% Increase	1% Decrease
Increase (decrease) to total of service and interest cost components of net periodic post-retirement health care benefit cost	2	(1	)
Increase (decrease) to the health care component of the accumulated post-retirement benefit obligation	13	(11	)

Control Environment

Based on their evaluation as of December 31, 2004, Suncor’s chief executive officer and chief financial officer concluded that Suncor’s disclosure controls and procedures (as defined in Rules 13(a)-15(e) and 15(d)-15(e) under the United States Securities Exchange Act of 1934 (the Exchange Act)) are effective to ensure that information required to be disclosed by Suncor in reports that it files or submits under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the United States Securities and Exchange Commission rules and forms. In addition, other than as described below, as of December 31, 2004, there were no changes in Suncor’s internal controls over financial reporting that occurred during 2004 that have materially affected, or are reasonably likely to materially affect its internal controls over financial reporting. Suncor will continue to periodically evaluate its disclosure controls and procedures and internal controls over financial reporting and will make any modifications from time to time as deemed necessary.

Suncor Energy Inc. 2004 Annual Report

The company is in the process of implementing an ERP system in all of its businesses to support the company’s growth plan. The phased implementation is currently planned to be complete by 2006. Implementing an ERP system on a widespread basis involves significant changes in business processes and extensive organizational training. The company currently believes a phased-in approach reduces the risks associated with making these changes. Suncor believes it is taking the necessary steps to monitor and maintain appropriate internal controls during this transition period. These steps include deploying resources to mitigate internal control risks and performing additional verifications and testing to ensure data integrity.

The company has undertaken a comprehensive review of the effectiveness of its internal control over financial reporting as part of the reporting, certification and attestation requirements of Section 404 of the U.S. Sarbanes-Oxley Act of 2002. For the year ended December 31, 2004, the company’s internal controls were found to be operating free of any material weaknesses. In connection with the continued implementation of its ERP system, the company expects there will be a significant redesign of its business processes during 2005, some of which relate to internal control over financial reporting and disclosure controls and procedures.

Change In Accounting Policies

Asset Retirement Obligations (ARO)

On January 1, 2004, the company retroactively adopted the new Canadian accounting standard related to “Asset Retirement Obligations”. Under the new standard a liability is recognized for the future retirement obligations associated with the company’s property, plant and equipment. The fair value of the ARO is recorded on a discounted basis. This amount is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the company settles the obligation.

Recently Issued Canadian Accounting Standards

Variable Interest Entities

In 2003, Canadian Accounting Guideline 15 (AcG 15), “Consolidation of Variable Interest Entities” (VIEs) was issued. Effective January 1, 2005, AcG 15 requires consolidation of a VIE where the company will absorb a majority of a VIE’s losses, receive a majority of its returns, or both. The company will be required to consolidate the VIE related to the sale of equipment as described on page 23. The company does not expect a significant impact on net earnings upon consolidation of the equipment VIE. The impact on the balance sheet will be an increase to property, plant and equipment of $14 million, an increase to inventory of $8 million, and an increase to long-term debt of $22 million. The company’s accounts receivable securitization program described on page 23, as currently structured, does not meet the AcG 15 criteria for consolidation by Suncor.

Liabilities and Equity

In 2003, the Canadian Accounting Standards Board approved an amendment to Handbook Section 3860 “Financial Instruments – Disclosure and Presentation” requiring certain obligations that must or could be settled with an entity’s own equity instruments to be presented as liabilities. The amendment, effective for the company’s 2005 fiscal year and applied on a retroactive basis will affect the company’s current presentation of preferred securities as equity. The reclassification of the preferred securities from equity to long-term debt is expected to increase property, plant and equipment by $37 million, and increase 2005 DD&A by $1 million.

Suncor Energy Inc. 2004 Annual Report

oil sands

Located near Fort McMurray, Alberta, Suncor’s Oil Sands business forms the foundation of Suncor’s growth strategy and represents the most significant portion of the company’s assets. The Oil Sands business unit recovers bitumen through mining and in-situ development and upgrades it into refinery feedstock, diesel fuel and byproducts.

Oil Sands strategy focuses on:

• Acquiring long-life mineral leases with substantial bitumen resources in place.

• Sourcing low-cost bitumen supply through mining, in-situ development and third-party supply agreements, and upgrading this bitumen supply into high value crude oil products that meet market demand.

• Increasing production capacity and improving reliability through staged expansion of Oil Sands upgrading facilities.

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

highlights

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2004	2003	2002
Revenue	3 596	3 061	2 616
Production (thousands of bpd)	226.5	216.6	205.8
Average sales price ($/barrel)	42.28	37.19	33.65
Net earnings	995	888	782
Cash flow from operations	1 752	1 803	1 475
Total assets	9 032	7 934	7 186
Cash used in investing activities	1 086	1 055	630
Net cash surplus	737	799	729
ROCE (%) (1)	22.9	20.8	16.7
ROCE (%) (2)	18.8	17.4	15.6

(1) Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for Suncor’s operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non GAAP Financial Measures. See page 51.

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

Significant Developments in 2004 and Subsequent Event

• The start-up phase of stage one of Suncor’s Firebag in-situ operation was completed and commercial operations commenced in the second quarter of 2004. Production in 2004 averaged 10,900 barrels per day (bpd) of bitumen, and is expected to reach its full production capacity of 35,000 bpd of bitumen in 2006.

• Cash operating costs from Oil Sands base operations averaged $11.95 per barrel during 2004 at an average natural gas price of US$6.20 per thousand cubic feet (mcf).

• Work to expand Oil Sands production capacity to 260,000 bpd by the end of 2005 continued on schedule and on budget.

• Oil Sands began construction on an estimated $3.6 billion project that, when complete in 2008, is expected to increase production capacity to 350,000 bpd.

• On January 4, 2005, a fire occurred in Upgrader 2, primarily affecting a coker fractionator. As a result, base plant production capacity at Oil Sands has been temporarily reduced to about 110,000 bpd from about 225,000 bpd. Based on a preliminary assessment of the damage, Suncor estimates that production should return to full rates of approximately 225,000 bpd sometime during the third quarter, 2005.

Analysis of Net Earnings

Net earnings were $995 million in 2004 compared to $888 million in 2003. The increase was largely driven by higher benchmark commodity prices (net of the effect of widening light/heavy crude oil differentials), higher sales volumes related to higher overall production, and reductions in year-over-year non-cash income tax expenses due to changes in tax rates and resource allowance deductions. These positive factors were largely offset by increased hedging losses, higher Oil Sands Alberta Crown royalties, and the impact of a stronger Canadian dollar.

Oil Sands average production was 226,500 bpd in 2004, compared to 216,600 bpd in 2003. The increase in 2004 was largely due to new in-situ bitumen production

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of 10,900 bpd. Base plant production in 2004 was lower than expected due to unplanned upgrader maintenance. In addition, 2004 in-situ bitumen production was lower than anticipated due to unscheduled water treatment system maintenance in the third quarter. Production volumes in 2003 were from base operations only, and reflect the impact of a 30-day maintenance shutdown of Upgrader 1.

Sales volumes in 2004 averaged 226,300 bpd compared with 218,300 bpd in 2003. Higher sales volumes increased 2004 net earnings by $78 million.

Sales prices averaged $42.28 per barrel in 2004 (including the impact of pretax hedging losses of $621 million) compared with $37.19 per barrel in 2003 (including the impact of pretax hedging losses of $239 million). The average price realization was favourably impacted by the strengthening of U.S. dollar West Texas Intermediate (WTI) benchmark crude oil prices (net of widening light/heavy crude oil differentials), partially offset by the continued strengthening of the Canadian dollar from an average exchange rate of US$0.72 in 2003 to US$0.77 in 2004. Because crude oil is sold based on U.S. dollar benchmark prices, the narrowing exchange rate decreased the Canadian dollar value of crude oil products.

The net impact of the above pricing factors increased earnings by $265 million in 2004.

Cash Expenses

Cash expenses increased to $1.17 billion from $1.03 billion in 2003. Expenses were higher year-over-year due to the following factors:

• Purchases of crude oil and products increased to $75 million in 2004 from $12 million in 2003. The increase is primarily due to the repurchase of crude oil originally sold to a Variable Interest Entity (VIE) in 1999.

• The first year of in-situ operations increased cash expenses by $64 million in 2004, including natural gas purchases of $39 million.

• Upgrading costs increased by $26 million primarily due to unscheduled maintenance.

These higher expenses were partially offset by lower transportation costs and other costs of $13 million. Overall, increases in cash expenses reduced 2004 net earnings by $49 million.

Royalties

Oil Sands Alberta Crown royalties increased by $374 million to $407 million in 2004 compared to $33 million in 2003. Increased royalties reduced net earnings by approximately $240 million. For a further discussion on Crown royalties, see page 24.

Start-up Expenses

Project start-up expenses increased by $16 million ($10 million after tax) in 2004, due to commissioning and start-up expenses for in-situ operations during the first quarter of 2004.

Non-cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense, including overburden amortization expense, increased to $503 million from $458 million in 2003. The increase was primarily due to first-time DD&A expenses from in-situ operations of $20 million, higher overburden amortization of $16 million, and higher maintenance shutdown and catalyst amortization. Higher non-cash expenses decreased net earnings by $28 million.

In 2004, Oil Sands average overburden removal stripping ratio was 0.52 cubic metres of overburden for every tonne of ore mined, compared to 0.46 cubic metres per tonne in 2003. The increased stripping ratio year-over-year was primarily due to higher proportionate levels of mining activity from the Millennium mine, which has a higher stripping ratio than the Steepbank mine, as well as updated drilling results that provided more detailed information. Overburden amortization increased to $224 million in 2004 compared with $208 million in 2003.

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Stripping ratios are expected to continue to increase until 2006 as proportionately more mining activity is conducted at the company’s Millennium mine. From 2006 to 2010 it is expected that all mining production will come from the Millennium mine and the stripping ratio will stabilize. (For a discussion of overburden stripping ratios see page 29.)

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 significant.

Tax Adjustments

In 2004, non-cash income tax expense was reduced by $53 million relating to reductions in the Alberta provincial tax rate. In 2003, non-cash income tax expense increased by $93 million primarily related to the impact of changes in the federal government’s taxation policies for the resource sector, and an increase in Alberta and Ontario provincial tax rates. Including other minor differences, changes in effective tax rates increased net earnings by $132 million in 2004 compared to 2003.

Operating Costs

With the start of Firebag in-situ operations, Suncor reported cash operating costs from mining and upgrading production from the mine (base operations) separately from cash costs from in-situ operations. Cash operating costs for base operations increased to $949 million ($11.95 per barrel) in 2004 compared to $907 million ($11.45 per barrel) in 2003, primarily as a result of higher maintenance costs, offset by lower natural gas costs.

Natural gas purchases for base operations averaged approximately 65 million cubic feet per day (mmcf/d) in 2004, consistent with the prior year. Oil Sands natural gas costs declined to $6.74 per mcf in 2004 from $6.95 per mcf in 2003, reducing cash costs by approximately $0.15 per barrel.

Net Cash Surplus Analysis

Cash flow from operations was $1.75 billion in 2004, a slight decrease from $1.8 billion in 2003. Excluding the impact of non-cash income tax adjustments, the decrease was due to the same factors that increased net earnings, offset by higher cash overburden and reclamation spending, and higher pension funding requirements.

Net working capital decreased by $71 million in 2004 compared to a decrease of $51 million in 2003. Higher accounts receivable due to higher sales volumes and higher price realizations in the final month of 2004 compared to 2003 was more than offset by increased accounts payable and accrued liabilities related to increased capital spending in the fourth quarter and higher accrued royalties payable.

Cash flow used in investing activities increased slightly to $1.09 billion in 2004 compared to $1.06 billion in 2003. During 2004, capital spending related primarily to construction of Firebag stage two, the Millennium vacuum unit, and engineering and preliminary construction of the Millennium Coker Unit. During 2003, capital spending primarily related to construction of Firebag stage one, and engineering and preliminary construction of the Millennium Vacuum Unit, as well as spending on the planned maintenance shutdown of Upgrader 1.

Combined, the above factors resulted in a net cash surplus of $737 million in 2004, compared with a surplus of $799 million in 2003.

Subsequent Event

A fire on January 4, 2005, caused significant damage to Oil Sands Upgrader 2, reducing upgraded crude oil production capacity from base operations to about 110,000 bpd. Repair work is under way and Oil Sands expects to return to full production capacity of 225,000 bpd in the third quarter of 2005.

The timeline for recovery work is preliminary and subject to change. Further inspection of the damaged equipment will occur as the repairs progress. Any new information could modify the timetable for returning to full production.

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To mitigate the impact of reduced production during the recovery period, Oil Sands plans to bring forward as many maintenance projects as possible, including all, or significant portions of, a maintenance shutdown previously planned for the fall.

Suncor’s preliminary investigation into the cause of the fire suggests the issue was an isolated case.

Outlook

As a result of the January fire, specific targets for Oil Sands production, sales mix and cash operating costs are not available. Fire recovery efforts are not expected to impact expansion efforts and work to continue specific growth targets continues.

Expansion to 260,000 bpd

Work is proceeding on schedule to increase production capacity to 260,000 bpd by the end of 2005. To achieve this goal, Oil Sands must complete construction of the Millennium vacuum unit, tie in bitumen feed infrastructure and commission the new facility. The project is on budget to meet its estimated cost of $425 million.

Expansion to 350,000 bpd

The next stage of growth, expected to increase production capacity to 350,000 bpd, is also proceeding on schedule and on budget. This project is expected to reach several milestones with fabrication and transport of major vessels for the coker unit expansion scheduled to be completed during 2005.

The total cost of this project is estimated at $3.6 billion, including approximately $2.1 billion to expand Upgrader 2 and $1.5 billion to increase bitumen supply.

Incremental bitumen to feed expanded upgrading capacity is also expected to be provided under a processing agreement between Suncor and Petro-Canada, slated to take effect in 2008. Under the agreement, Oil Sands will process at least 27,000 bpd of Petro-Canada bitumen on a fee-for-service basis. Petro-Canada will retain ownership of the bitumen and resulting sour crude oil production of about 22,000 bpd. In addition, Suncor will sell an additional 26,000 bpd of Suncor proprietary sour crude oil production to Petro-Canada. Both the processing and sales components of the agreement will be for a minimum 10-year term.

Expansion to 500,000 bpd to 550,000 bpd

In planning for expansion beyond 2008, Suncor expects to file regulatory applications in 2005 to construct a third upgrader and expand its mining/extraction and in-situ operations, key steps to increasing production capacity to 500,000 to 550,000 bpd in the 2010 to 2012 time frame. Cost estimates for this project, known as Voyageur, are not yet available. Approval by regulators and Suncor’s Board of Directors is required before the project can proceed.

Production Plan

Description	Regulatory Approval	Board of Directors Approval	Cost Estimate (1)	Production Capacity (bpd)	Status
Millennium vacuum unit	Yes	Yes	$425 million	260 000	Millennium vacuum unit under construction. Project is on schedule and on budget.

Coker unit expansion and expanded mining and in-situ operations	Yes	Firebag stage 2 and coker unit expansion approved. Additional Firebag stages and mining/extraction subject to approval.	$3.6 billion	350 000 in 2008	Construction under way. Project is on schedule and on budget.

Potential third upgrader – asset configuration still to be determined	No	No	Not available	500 000 to 550 000 in 2010 to 2012	Regulatory application expected to be filed in 2005.

(1) These cost estimates are based on preliminary engineering. Actual amounts will differ and the differences may be material.

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Mine Extension

As part of its regulatory filing for Voyageur, Oil Sands also intends to file for approval to construct and operate an extension of the Steepbank mine. The proposed development would replace ore production that is expected to be depleted prior to the end of the decade. Currently, capital development costs are estimated at $350 million. Approval by regulators and Suncor’s Board of Directors

is required before construction can proceed.

To support the company’s mine development plan, in January 2005, Oil Sands submitted a regulatory application to build a new primary extraction plant in closer proximity to mining operations. The cost of constructing the new extraction facility and decommissioning the existing plant has been estimated at $320 million.

Operating Licence Renewal

During 2005, Oil Sands will be required to update its 10-year operating licence by filing a renewal application with regulators. Management does not expect the operating licence renewal to affect its growth plans.

Risk/Success Factors Affecting Performance

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

• Final amount and timing of the settlement and payment of insurance proceeds related to fire damage and interruption of business at Oil Sands.

• Additional maintenance or updated maintenance schedules related to returning Oil Sands to full production as well as delay or extension of work to tie in major vessels required to expand operations.

• Suncor’s ability to finance Oil Sands growth in a volatile commodity pricing environment. Also refer to Suncor Overview, Liquidity and Capital Resources on page 21.

• The ability to complete future 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 infrastructure (housing, roads, schools, etc.), or higher prices for the products and services required to operate and maintain the operations. 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 maintaining a strong focus on engineering, procurement and project management.

• Potential changes in the demand for refinery feedstock and diesel fuel. Suncor’s strategy is to reduce the impact of this issue by entering into long-term supply agreements with major customers, expanding its customer base and offering a variety of 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.

• Suncor’s relationship with its trade unions. Work disruptions have the potential to adversely affect Oil Sands operations and growth projects.

These factors and estimates are subject to certain risks, assumptions and uncertainties discussed on page 53 under Forward-looking Statements. Also refer to Suncor Overview, Risk/Success Factors Affecting Performance on page 25.

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natural gas

Suncor’s Natural Gas (NG) business primarily produces conventional natural gas in Western Canada. NG’s production serves as a price hedge that provides the company with a degree of protection from volatile market prices of natural gas purchased for internal consumption.

NG’s strategy is focused on:

• Building competitive operating areas.

• Improving base business efficiency.

• Creating new, low-capital business opportunities.

NG’s long-term goal is to achieve a sustainable return on capital employed (ROCE) of 12% at mid-cycle prices of US$4.00 to US$4.50 per thousand cubic feet (mcf). To ensure natural gas production keeps pace with company-wide natural gas purchases, NG is targeting production increases of 3% to 5% per year.

highlights

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2004	2003	2002
Revenue	567	512	339
Natural gas production (mmcf/d)	200	187	179
Average natural gas sales price ($/mcf)	6.70	6.42	3.91
Net earnings	115	120	34
Cash flow from operations	319	298	164
Total assets	965	763	793
Cash used in investing activities	251	166	158
Net cash surplus	67	143	28
ROCE (%) (1)	27.1	29.2	9.5

(1) ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non GAAP Financial Measures. See page 51.

Significant Developments During 2004

• Natural gas production increased 7% to 200 million cubic feet per day (mmcf/d) in 2004 compared to purchases of approximately 120 to 130 mmcf/d. Favourable drilling results in the Foothills and Northern operating areas were a major factor in delivering volume additions.

• Higher revenues due to increased production and higher commodity prices were offset by higher royalties and higher depreciation, depletion and amortization (DD&A).

• The divestment of 62.5% of NG’s interest in Suncor’s Simonette gas plant yielded a $13 million after-tax gain.

(2) For details on barrels of oil equivalent (boe), see page 14.

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Net Cash Surplus Analysis

NG’s net cash surplus was $67 million in 2004 compared with $143 million in 2003. Cash flow from operations increased to $319 million compared with $298 million in the prior year, largely due to increased production and higher commodity prices, partially offset by the Enron settlement and higher royalties. Changes in net working capital in 2004 resulted in a use of cash of $1 million, compared with a source of cash of $11 million in 2003, due primarily to an increase in accounts receivable.

Cash used in investing activities increased to $251 million compared with $166 million in 2003 as a result of an asset acquisition and higher capital and exploration costs, partially offset by proceeds from disposal of the Simonette gas plant. On December 29, 2004, NG acquired assets in eastern British Columbia for $33 million. These assets generate approximately 6 mmcf/d of production and consist of developed and undeveloped land.

Outlook

NG’s long-term financial goal is to achieve a sustainable ROCE of 12% at mid-cycle natural gas prices (US$4.00 to US$4.50/mcf). To meet this goal, management plans to continue to build competitive operating areas, grow natural gas production, improve base business efficiency and focus on strict cost control.

NG continues to work towards an operational target of increasing production by 3% to 5% per year to keep pace with the company’s growing internal natural gas demands. To meet this goal, in 2005 NG is targeting average production of 205 to 210 mmcf/d and approximately 3,300 bpd of crude oil and natural gas liquids.

NG will continue to leverage its expertise and existing assets to bring reserves into production in Western Canada. However, increasing production will likely require expansion through farm-ins(1), joint-ventures or additional property acquisitions, which could expand the size and number of operating areas, or could involve new operating areas outside of Western Canada.

To support these goals, the company has budgeted $260 million in capital spending for exploration and development in 2005.

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 costs. Market demand and the availability of opportunities also influences the cost of acquisitions and the willingness of competitors to allow farm-ins on prospects.

• Risks and uncertainties associated with obtaining regulatory approval for exploration and development activities in Canada and the United States. 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 53 under Forward-looking Statements. Refer to the Suncor Overview, Risk/Success Factors Affecting Performance on page 25.

(1) 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.

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energy marketing and refining – canada

Energy Marketing and Refining – Canada (EM&R) operates a 70,000 barrel per day (bpd) (approximately 11,100 cubic metres per day) capacity refinery in Sarnia, Ontario and markets refined products to industrial, wholesale and commercial customers primarily in Ontario and Quebec. Through its Sunoco-branded and joint-venture operated service networks, the business unit markets products to retail customers in Ontario. EM&R’s business also encompasses third-party energy marketing and trading activities, as well as providing marketing services for the sale of crude oil and natural gas from the Oil Sands and NG operations.

EM&R’s 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, including crude oil streams from Oil Sands operations.

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

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

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

As a marketing channel for Suncor’s refined products, EM&R’s Ontario retail networks generated approximately 58% of EM&R’s total 2004 sales volumes of 97,000 bpd. EM&R’s retail networks are comprised of 278 Sunoco-branded retail service stations, 23 Sunoco-branded Fleet Fuel Cardlock sites, and two 50% retail joint-venture(1) businesses that operate 147 Pioneer-branded retail service stations, 52 UPI-branded retail service stations and 14 UPI bulk distribution facilities for rural and farm fuels. Wholesale and industrial sales were responsible for approximately 37% of EM&R’s refined product sales in 2004. Sun Petrochemicals Company (SPC), a 50% joint-venture between a Suncor subsidiary and a Toledo, Ohio-based refinery, generated the remaining 5% of sales.

highlights

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2004		2003		2002
Revenue	3 460		2 936		2 508
Refined product sales
(millions of litres)
Sunoco retail gasoline	1 665		1 599		1 642
Total	5 643		5 477		5 286
Net earnings (loss) breakdown:
Total earnings excluding energy, marketing and trading activities	68		67		23
Energy marketing and trading activities	12		(2	)	3
Gain on sale of retail natural gas marketing business	—		—		35
Tax adjustments	—		(12	)	—
Total net earnings	80		53		61
Cash flow from operations	188		164		112
Cash used in investing activities	259		135		34
Net cash surplus (deficiency)	(21	)	29		63
ROCE (%)(1)	14.6		10.3		12.0
ROCE (%)(2)	13.6		10.3		12.0

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

Significant Developments During 2004

• EM&R started construction on the diesel desulphurization unit at the Sarnia refinery. This project will allow the company to meet federal low-sulphur diesel fuel regulations that take effect in 2006. The project, which is estimated to cost $800 million, is also expected to enable it to process approximately 40,000 bpd of Oil Sands sour crude blends.

(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 cooperative.

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• Pre-development engineering, formal public consultation, preliminary project planning and regulatory approval applications were completed for a planned ethanol plant in the Sarnia region. In February 2004, Suncor received approval by Natural Resources Canada’s(NRCan) Ethanol Expansion Program on its proposal for funding on the project. Subject to final approvals, NRCan would contribute $22 million towards Suncor’s construction of the $120 million ethanol production facility. During the year, Suncor finalized the site location for the plant.

• EM&R completed its interior store renewal program and also started an exterior re-imaging program of all convenience stores. Same site convenience store sales increased 20% over 2003, while same site convenience store royalties increased more than 10%.

Analysis of Net Earnings

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

Effective for 2004, EM&R’s Rack Back and Rack Forward organizational structures were consolidated into one unit for the purposes of external segmented reporting. Prior year amounts have been reclassified to conform to the current year’s presentation. EM&R’s external results continue to be measured and analysed on a margin basis.

EM&R results also include the impact of Suncor’s third-party energy marketing and trading activities that are discussed separately on page 46.

EM&R’s net earnings increased to $80 million in 2004 from $53 million in 2003. This increase was primarily due to higher refining margins, higher sales volumes, improved refinery utilization, mark-to-market gains on inventory related derivatives, and the impact of 2003 tax adjustments. These positive impacts were partially offset by higher product purchase costs, higher cash and non-cash refinery operating expenses, and lower joint-venture earnings.

Margins

After-tax refined product margins increased by $27 million in 2004 compared to 2003, due to higher refining margins in gasoline, chemicals, diesel and jet fuel, partially offset by reduced refining margins in other products such as fuel oil and propane and decreases in retail gasoline margins. Refining margins on Suncor’s proprietary refined products averaged 8.0 cents per litre (cpl) in 2004, compared to 6.5 cpl in 2003. The 23% increase was largely a result of strong refined product demand and tight North American inventory supply. Sunoco-branded retail gasoline margins averaged 4.4 cpl in 2004, compared with 6.6 cpl in 2003. The decrease was primarily due to higher crude prices and intense price competition in Ontario markets. Price competition also contributed to a decrease of $6 million in joint-venture net earnings in 2004.

Volumes

Total sales volumes averaged 97,000 bpd (15,400 cubic metres per day) in 2004, up from 94,400 bpd (15,000 cubic metres per day) in 2003, resulting in an increase in net earnings of $12 million. Higher sales of gasoline, jet and diesel fuel were partially offset by lower sales of propane and heavy fuel oils. Total gasoline sales volumes in the Sunoco-branded retail network increased to 1,665 million litres in 2004 from 1,599 million litres in 2003. Average Sunoco-branded service station site throughput was 6.2 million litres per site in 2004 compared to 5.9 million litres per site in 2003. Site throughput is an important indicator of network efficiency. EM&R’s Ontario retail gasoline market share, including all Sunoco and joint-venture operated retail sites was 19%, unchanged from 2003. Approximately 94% of EM&R’s refined products were sold to the Ontario market in 2004.

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Refinery Utilization

Overall refinery utilization averaged 100% in 2004, compared with 95% in 2003. The impact of scheduled and unscheduled maintenance shutdowns to portions of the refinery in the second quarter of 2004 was more than offset by above capacity utilization during the rest of the year. In 2003, utilization was below capacity primarily due to the impacts of a widespread power outage in the northeastern United States and southern Ontario during August, as well as a planned 32-day maintenance shutdown on a portion of the refinery.

Product Purchase Costs

The favourable impacts of improved refined product margins, higher volumes and higher refinery utilization were partially offset by higher third-party refined product purchase costs in 2004 compared to 2003. Refined product purchase costs increased primarily due to higher commodity prices for both purchased refined products and feedstock, partially offset by lower required purchased volumes of refined products to meet customer needs. Purchased volumes were higher in 2003 due to the power outage noted above. In total, increased purchase costs reduced 2004 net earnings by $22 million.

Cash and Non-cash Operating Expenses

Overall, cash and non-cash operating expenses increased by $10 million in 2004 compared to 2003. Cash expenses increased by $9 million in 2004, due to higher energy and freight costs, partially offset by lower salaries and benefits and lower refinery maintenance expenses. Non-cash expenses increased by $9 million in 2004, due to increased depreciation as a result of a higher asset base. These increases were partially offset by higher mark-to-market gains of $8 million on inventory-related derivatives.

Related Party Transactions

The Pioneer, UPI and SPC joint-ventures are considered to be related parties to Suncor for GAAP purposes. EM&R supplies refined petroleum products to the Pioneer and UPI joint-ventures, and petrochemical products to SPC. Suncor has a separate supply agreement with each of Pioneer, UPI and SPC. These supply agreements are evergreen, subject to termination only in accordance with the various agreements between the parties.

The following table summarizes the company’s related party transactions with Pioneer, UPI and SPC, after eliminations, for the year. These transactions are in the normal course of operations and have been conducted on the same terms as would apply with unrelated parties.

($ millions)	2004	2003	2002
Operating revenues
Sales to EM&R joint-ventures:
Refined products	320	301	321
Petrochemicals	272	187	142

At December 31, 2004, amounts due from EM&R joint-ventures were $17 million, compared to $36 million at December 31, 2003.

Sales to, and balances with, EM&R joint-ventures are established and agreed to by the related parties and approximate fair value.

Energy Marketing and Trading Activities

Third-party energy marketing and energy trading activities consist of both third-party crude oil marketing and financial and physical derivatives trading activities. These activities resulted in net earnings of $12 million in 2004 compared to a net loss of $2 million in 2003.

Energy trading activities, by their nature, can result in volatile and large positive or negative fluctuations in earnings. A separate risk management function reviews and monitors practices and policies and provides independent verification and valuation of these activities.

Tax Adjustments

In 2003, EM&R net earnings included a $12 million future income tax charge due to the repeal of previously announced reductions in income tax rates by the Ontario government.

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Net Cash Deficiency Analysis

EM&R’s net cash deficiency was $21 million in 2004 compared to a net cash surplus of $29 million in 2003. Cash flow from operations increased to $188 million in 2004 from $164 million in 2003 due to the same factors impacting net earnings. Net working capital decreased by $50 million in 2004, compared to no change in 2003. The decrease in net working capital is a result of increased accounts payable related to capital expenditures on the desulphurization project and higher purchased crude payables resulting from higher commodity prices.

The favourable impacts of the increased cash flow from operations and working capital were more than offset by an increase in cash used in investing activities, which increased to $259 million in 2004 from $135 million in 2003. The increase was primarily due to higher capital expenditures associated with the diesel desulphurization project at the Sarnia refinery, as well as increased refinery capital maintenance expenditures.

Outlook

In 2004, Suncor started construction on a diesel desulphurization project at the company’s Sarnia refinery to meet current and anticipated federal sulphur regulations. Under the terms of an agreement with Shell Canada Products (Shell), the project facilities will also be used to process high-sulphur diesel from Shell’s Sarnia refinery into low-sulphur diesel on a fee-for-service basis. The project will also include capital expenditures to expand the refinery’s throughput capacity and enable it to process approximately 40,000 bpd of Oil Sands sour crude blends. When all components are completed in 2007, Suncor expects this project will cost a total of approximately $800 million.

Construction of a planned ethanol plant is expected to begin in 2005 and be completed by 2006, subject to regulatory approvals. This facility is expected to produce ethanol at a capacity of 200 million litres per year for blending into Sunoco-branded and Suncor joint-venture retail gasolines. The total project is expected to cost $120 million.

EM&R expects total capital spending to be approximately $400 million in 2005, with the majority directed towards meeting regulations for diesel desulphurization at the Sarnia refinery.

As a result of a fire at Oil Sands, during 2005, EM&R may be required to purchase additional synthetic crude oil feedstock to meet customer demand, resulting in higher purchased product costs.

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:

• Management expects that fluctuations in demandand supply for refined products, margin and price volatility, and market competition, including potential new market entrants, will continue to impact the business environment.

• There are certain risks associated with the execution of capital projects, including the risk of cost overruns. The diesel desulphurization project must be completed prior to June 1, 2006, to ensure compliance with legislative requirements. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period.

• Environment Canada is expected to finalize regulations reducing sulphur in off-road diesel fuel and light fuel oil to take effect later in the decade. Suncor believes that if the regulations are finalized as currently proposed, the new facilities for reducing sulphur in on-road diesel fuel should also allow the company to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

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refining and marketing – u.s.a.

In August 2003, Suncor acquired downstream assets based in Denver, Colorado, to create a U.S. Refining and Marketing business unit (R&M). The business operates a 60,000 barrel per day (bpd) (approximately 9,500 cubic metres per day) capacity refinery located in the Denver, Colorado area that markets refined products to customers primarily in Colorado, including retail marketing through 43 Phillips 66-branded retail stations in the Denver area. Assets also include a 100% interest in the 480-kilometre Rocky Mountain pipeline system and a 65% interest in the 140-kilometre Centennial pipeline system.

This acquisition is part of an integration strategy aimed at improving access to the North American energy markets through acquisitions, long-term contracts and possible joint-ventures.

R&M’s strategy is focused on:

• Enhancing the profitability of refining operations by improving reliability, product yields and operational flexibility to process a variety of feedstocks, including crude oil streams from Oil Sands operations.

• Increasing the profitability and efficiency of its retail network.

• Creating additional downstream market opportunities in the United States to capture greater long-term value from Oil Sands production.

The following analysis has been prepared on the basis of a comparison of an entire year of operations in 2004 compared to five months in 2003. This has the impact of increasing measures related to earnings, margins, volumes and expenses in 2004 compared to 2003.

highlights

Summary of Results

Year ended December 31 (Cdn$ millions unless otherwise noted)	2004		2003(1)
Revenue	1 495		515
Refined product sales (millions of litres)
Gasoline	1 627		636
Total	3 504		1 384
Net earnings	34		18
Cash flow from operations	59		34
Investing activities	198		300
Net cash surplus (deficiency)	(71	)	(220	)
ROCE (%)(2)	12.2		—
ROCE (%)(3)	11.0		—

(1) Refining and Marketing – U.S.A. reflects the results of operations since acquisition on August 1, 2003.

(2) Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for Suncor’s operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non GAAP Financial Measures. See page 51. For 2003, represents five months of operations since acquisition August 1, therefore no annual ROCE was calculated.

(3) Includes capitalized costs related to major projects in progress.

Significant Developments During 2004

• R&M started construction on a project to modify the Denver refinery to allow the company to meet regulations that take effect on June 1, 2006, requiring lower sulphur diesel fuel. It is also expected that modifications will enable R&M to process 10,000 bpd to 15,000 bpd of Oil Sands sour crude while also increasing the refinery’s ability to process a broader slate of bitumen-based crude oil. The capital budget for this project is approximately $360 million (approximately US$300 million).

• A scheduled maintenance shutdown on certain refinery units was successfully completed in the second quarter of 2004.

• Approximately 6% of feedstock processed at the Denver refinery was supplied from Oil Sands operations, a significant step forward in Suncor’s integration strategy.

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Analysis of Net Earnings

R&M’s external results are measured and analysed on a net margin basis.

R&M’s net earnings were $34 million in 2004 compared to $18 million in 2003. In addition to the positive impact of an entire year of operations in 2004 compared to five months of operations in 2003, the increase was due to higher average refining margins and higher average sales volumes. These positive impacts were partially offset by higher product purchase costs, higher cash and non-cash refinery operating expenses, and lower refinery utilization during the first two quarters of 2004.

Margins

Average refining margins were 6.8 cents per litre (cpl) in 2004 compared to 5.9 cpl in 2003 reflecting significantly higher gasoline and diesel margins, partially offset by lower net realizations on asphalt and other heavy product sales. Higher refined product margins in 2004 increased earnings by $13 million. Retail margins were 5.4 cpl in 2004, compared to 5.6 cpl in 2003, reflecting weaker retail gasoline prices during the second and third quarters of 2004.

Volumes and Refinery Utilization

Sales volumes increased in 2004 due to seven more months of operations in 2004 compared to 2003. In addition, sales volumes increased by 5,800 bpd (900 cubic metres) in the last five months of 2004 as compared to the same period in 2003, primarily due to higher refinery utilization rates and decreases in refined inventory levels due to strong customer demand. Overall, the higher volumes resulted in an increase in net earnings of $17 million.

Refinery utilization in the first half of 2004 was negatively impacted by a planned 19-day maintenance shutdown on certain refinery units during the second quarter, as well as first quarter operating difficulties that were rectified during the shutdown.

Partially offsetting the positive impacts of higher margins and volumes, increased refined product purchases reduced net earnings by $21 million. The higher volume of purchased refined products was primarily due to meeting customer demand during the maintenance shutdown.

Cash and Non-cash Expenses

Increases in refinery cash expenses and non-cash depletion, depreciation and amortization were proportionately higher than 2003 due to 12 months of operations in 2004 compared to five months of operations in 2003.

Net Cash Deficiency Analysis

R&M’s cash deficiency of $71 million in 2004 compared to a deficiency of $220 million in 2003. The increase in cash flow from operations to $59 million in 2004 from $34 million in 2003 was impacted by the same factors that affected net earnings. Net working capital decreased $68 million in 2004, compared to a decrease of $46 million in 2003. The decrease in 2004 was due primarily to an increase in accounts payable related to capital expenditures on the refinery modifications.

Cash used in investing activities was $198 million in 2004, compared to $300 million in 2003. Investing activities in 2004 were primarily related to costs associated with the refinery modification project. In 2003, investing activities were substantially all related to the acquisition of the Denver refinery and related assets on August 1 of that year.

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Outlook

R&M estimates that it will spend approximately $260 million (approximately US$195 million) on new capital project work in 2005. Most of this investment will enable continuation of modifications that began at the Denver refinery during 2004. The project, which is expected to cost a total of approximately $360 million (approximately US$300 million), is expected to be substantially completed in early 2006.

R&M expects to spend an additional $29 million (US$24 million) by 2006 to meet existing obligations between the refinery and the United States Environmental Protection Agency and the State of Colorado. The expenditures, intended to improve environmental performance, are expected to be primarily capital.

The refinery runs a mixture of heavy and light crude oil feedstock from both Canadian and U.S. sources. In 2004, approximately 6% of R&M’s crude slate came from Oil Sands. Suncor is currently assessing plans for potential additional refinery modifications post-2006 in order to have the potential to integrate up to an additional 30,000 bpd of Oil Sands crude oil. Cost estimates for this project are not yet available.

During the fourth quarter of 2005, scheduled maintenance is planned for pipeline and refinery equipment. During this estimated 42-day maintenance period, customer requirements are expected to be met from existing inventory and third-party purchases and exchanges.

During 2004, R&M was able to enter into firm sales commitments with new and existing customers to sell all of its excess refinery production. R&M also plans to improve overall profitability by seeking to optimize refining margins through a combination of branded and unbranded sales.

R&M’s existing four-year contract with the local Paper, Allied-Industrial Chemical and Energy Workers International Union, which applies to hourly wage employees at the refinery, will expire in January 2006.

Risk/Success Factors Affecting Performance

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

• Management expects continuing fluctuations in demand for refined products, margin and price volatility and market competitiveness, including potential new market entrants, will continue to impact the business.

• There are certain risks associated with the execution of the fuels desulphurization project, including ensuring construction and commissioning is completed in time to comply with June 1, 2006 legislative requirements. Numerous risks and uncertainties can affect construction schedules, including the availability of labour and other impacts of competing projects drawing on the same resources during the same time period. As well, Suncor’s U.S. capital projects are expected to be partially funded from Canadian operations. A weaker Canadian dollar would result in a higher funding requirement for U.S. capital programs.

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non gaap financial measures

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

Cash Flow from Operations per Common Share

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the Schedules of Segmented Data, which are an integral part of Suncor’s Consolidated Financial Statements.

For the year ended December 31		2004	2003	2002
Cash flow from operations ($ millions)	A	2 021	2 079	1 440
Dividends paid on preferred securities ($ millions, pretax)	B	9	45	48
Weighted average number of common shares outstanding (millions of shares)	C	453	450	448
Cash flow from operations (per share)	A/C	4.46	4.62	3.22
Dividends paid on preferred securities (pretax, per share)	B/C	0.02	0.10	0.11
Cash flow from operations after deducting dividends paid on preferred securities (per share)	(A-B)/C	4.44	4.52	3.11

ROCE

For the year ended December 31 ($ millions, except ROCE)		2004		2003		2002
Adjusted net earnings
Net earnings		1 100		1 075		749
Add: after-tax financing expenses (income)		(10	)	(75	)	72
	D	1 090		1 000		821
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents		2 091		2 671		3 143
Shareholders’ equity		4 355		3 397		2 731
	E	6 446		6 068		5 874
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents		2 159		2 091		2 671
Shareholders’ equity		4 897		4 355		3 397
	F	7 056		6 446		6 068
Average capital employed	(E+F)/2=G	6 751		6 257		5 971
Average capitalized costs related to major projects in progress (1)	H	1 030		817		345
ROCE (%)	D/(G-H)	19.1		18.4		14.6

(1) Prior to 2004, average capital employed was calculated using a simple average of opening and closing major projects in progress. In 2004, the company has used a quarterly average.

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Oil Sands Operating Costs – Base Operations

		2004 (1)			2003			2002
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		871			865			790
Less: natural gas costs and inventory changes		(142	)		(176	)		(116	)
Accretion of asset retirement obligations		21			21			19
Taxes other than income taxes		28			24			23
Cash costs		778		9.80	734		9.25	716		9.55
Natural gas		158		2.00	169		2.15	119		1.55
Imported bitumen (net of other reported product purchases)		13		0.15	4		0.05	3		0.05
Cash operating costs – mining	A	949		11.95	907		11.45	838		11.15
Start-up costs		26			10			3
Add: in-situ inventory changes		2			—			—
Less: pre-start-up commissioning costs		(4	)		(10	)		(3	)
In-situ (Firebag) start-up costs	B	24		0.30	—		—	—		—
Total cash operating costs	A+B	973		12.25	907		11.45	838		11.15
Depreciation, depletion and amortization		482		6.10	458		5.80	458		6.10
Total operating costs		1 455		18.35	1 365		17.25	1 296		17.25
Production (thousands of barrels per day)		217.0			216.6			205.8

Oil Sands Operating Costs – Firebag In-situ Bitumen Production

	2004 (1)
	$ millions		$/barrel
Operating, selling and general expenses	68
Less: natural gas costs and inventory changes	(39	)
Accretion of asset retirement obligations	—
Taxes other than income taxes	—
Cash costs	29		8.30
Natural gas	39		11.20
Cash operating costs	68		19.50
Depreciation, depletion and amortization	21		6.00
Total operating costs	89		25.50
Production (thousands of barrels per day)	12.7

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

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forward-looking statements

This Management’s Discussion and Analysis contains certain Forward-looking Statements that are based on Suncor’s current expectations, estimates, projections and assumptions that were made by the company in light of its experience and its perception of historical trends.

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

The risks, uncertainties and other factors that could influence actual results include but are not limited to: changes in the general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products, commodity prices and currency exchange rates; Suncor’s ability to respond to changing markets and to receive timely regulatory approvals; the successful and timely implementation of capital projects including growth projects (for example the Firebag in-situ development and Voyageur) and regulatory projects (for example, the clean fuels refinery modifications projects in Suncor’s downstream businesses); the accuracy of cost estimates, some of which are provided at the conceptual or other preliminary stage of projects and prior to commencement or conception of the detailed engineering needed to reduce the margin of error or level of accuracy; the integrity and reliability of Suncor’s capital assets; the cumulative impact of other resource development; future environmental laws; the accuracy of Suncor’s reserve, resource and future production estimates and its success at exploration and development drilling and related activities; the maintenance of satisfactory relationships with unions, employee associations and joint-venture partners; competitive actions of other companies, including increased competition from other oil and gas companies or from companies that provide alternative sources of energy; the uncertainties resulting from the January 2005 fire at the Oil Sands facility and other uncertainties resulting from potential delays or changes in plans with respect to projects or capital expenditures; actions by governmental authorities including the imposition of taxes or changes to fees and royalties; changes in environmental and other regulations; the ability and willingness of parties with whom Suncor has material relationships to perform their obligations to Suncor; and the occurrence of unexpected events such as the January 2005 fire, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. The foregoing important factors are not exhaustive. Many of these risk factors are discussed in further detail throughout this Management’s Discussion and Analysis and in the company’s Annual Information Form/Form 40-F on file with Canadian securities commissions and the United States Securities and Exchange Commission (SEC). Readers are also referred to the risk factors described in other documents that Suncor files from time to time with securities regulatory authorities. Copies of these documents are available without charge from the company.

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