Exhibit 99.2

018	Suncor Energy Inc.
	2006 Annual Report

Management’s discussion and analysis

February 28, 2007

This Management’s Discussion and Analysis (MD&A) contains forward-looking statements. These statements are based on certain estimates and assumptions and involve risks and uncertainties. Actual results may differ materially. See page 60 for additional information.

This MD&A should be read in conjunction with Suncor’s audited consolidated financial statements and the accompanying notes. All financial information is reported in Canadian dollars (Cdn$) and in accordance with Canadian generally accepted accounting principles (GAAP) unless noted otherwise. The financial measures cash flow from operations, return on capital employed (ROCE) and cash and total operating costs per barrel referred to in this MD&A are not prescribed by GAAP and are outlined and reconciled in Non-GAAP Financial Measures on page 58.

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

Barrels of oil equivalent (boe) may be misleading, particularly if used in isolation. A boe conversion ratio of six thousand cubic feet (mcf) of natural gas : one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead.

References to “we,” “our,” “us,” “Suncor” or “the company” mean Suncor Energy Inc., its subsidiaries, partnerships and joint venture investments, unless the context otherwise requires.

The tables and charts in this document form an integral part of this MD&A.

Additional information about Suncor filed with Canadian securities commissions and the United States Securities and Exchange Commission (SEC), including periodic quarterly and annual reports and the Annual Information Form (AIF) filed with the SEC under cover of Form 40-F, is available online at www.sedar.com, www.sec.gov and our website www.suncor.com. Information contained in or otherwise accessible through our website does not form a part of this MD&A. All such references are inactive, textual references only.

In order to provide shareholders with full disclosure relating to potential future capital expenditures, we have provided cost estimates for projects that, in some cases, are still in the early stages of development. These costs are preliminary estimates only. The actual amounts are expected to differ and these differences may be material. For a further discussion of our significant capital projects and the range of cost estimates associated with an “on-budget” project, see the “Significant Capital Project Update” on page 27.

Suncor Energy Inc.	019
2006 Annual Report

Suncor overview and strategic priorities

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate four businesses:

•Oil Sands, located near Fort McMurray, Alberta, produces bitumen recovered from oil sands through mining and in-situ technology and upgrades it into 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 internal natural gas consumption in our oil sands and downstream operations. This business also supports Suncor’s sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

•Energy Marketing and Refining – Canada (EM&R) operates a 70,000 barrel per day (bpd) capacity refinery and a 200 million litre per year ethanol plant, both in Sarnia, Ontario. As well, EM&R markets refined petroleum products to customers primarily in Ontario and Quebec. EM&R also manages our 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 the respective business segments.

•Refining and Marketing – U.S.A. (R&M) operates a 90,000 bpd capacity refinery in Commerce City, Colorado, as well as related pipeline assets. R&M markets refined petroleum products to customers throughout Colorado.

In addition to the operating segments outlined above, we also report a corporate segment that includes the activities not directly attributable to an operating segment, as well as those of our self-insurance entity.

Suncor’s strategic priorities are:

Operational:

•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, continued focus on operational excellence and worksite safety.

•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 reduce intensity of our water use, air and greenhouse gas emission and our impact on the land while also earning continued stakeholder support for our ongoing operations and growth plans.

•Maintaining a strong focus on worker, contractor and community health and safety.

Financial:

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

•Reducing risk associated with natural gas price volatility by producing natural gas volumes that offset purchases for internal consumption.

•Maintaining a strong balance sheet by closely managing debt and capital spending.

We expect our current growth to 350,000 bpd in 2008 to support an annual average 15% return on capital employed (ROCE) assuming a US$35 West Texas Intermediate (WTI) crude oil price and a Cdn$/US$ exchange rate of $0.80. Longer term, we are targeting a 15% ROCE at a sustainable long-term crude oil price. Estimates of ROCE are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs.

020	Suncor Energy Inc.
	2006 Annual Report

2006 Overview

•Combined oil sands and natural gas production in 2006 was 294,800 barrels of oil equivalent (boe) per day, compared to 206,100 boe per day in 2005. Oil sands production averaged 260,000 bpd in 2006 (253,800 bpd of synthetic crude oil and 6,200 bpd of bitumen sold directly to the market), compared to 171,300 bpd in 2005. Natural gas production averaged 191 million cubic feet (mmcf) per day, compared to an average 190 mmcf per day in 2005.

•Oil sands cash operating costs averaged $21.70 per barrel during 2006 compared to $24.55 per barrel in 2005. The decrease in 2006 was primarily due to fixed operating costs being spread over higher production volumes, as well as lower natural gas costs.

•Suncor continued to make progress on the addition of the coker unit to Upgrader 2. At year-end, construction was approximately 70% complete. The project remains on schedule and within budget.

•Average daily in-situ bitumen production from Suncor’s Firebag facilities increased to 33,700 bpd in 2006 from 19,100 bpd in 2005.

•Plans for Suncor’s next major stage of oil sands growth were also advanced in 2006 with receipt of regulatory approval for a planned third upgrader, a key component in the company’s Voyageur Strategy to increase production to 500,000 to 550,000 bpd in 2010 to 2012.

•In its U.S. downstream operations, Suncor completed modifications in June to the company’s Commerce City refining operation that enabled production of ultra low sulphur diesel fuel and the integration of up to 15,000 bpd of oil sands sour crude into the refinery’s feedstock.

•In Suncor’s Canadian downstream operations, modifications were completed in July to enable the company’s Sarnia refinery to meet ultra low sulphur diesel requirements. The second stage of this project, slated for completion in the fourth quarter of 2007, is planned to integrate up to 40,000 bpd of oil sands sour crude into the facility’s feedstock and to improve the economic performance of the refinery.

•While continuing to expand its integrated oil sands and downstream refining and marketing businesses, Suncor also made advances in its renewable energy strategy with the opening of Canada’s largest ethanol plant and the commissioning of its third wind farm. Further investment in ethanol-based biofuels and a fourth wind farm are planned for 2007.

•Maintaining a strong balance sheet remained a priority in 2006. Suncor’s net debt (short and long-term debt less cash and cash equivalents) at December 31, 2006, was $1.9 billion (approximately 0.4 times cash flow from operations). Year-end net debt in 2005 was $2.9 billion (approximately 1.2 times cash flow from operations).

•Suncor achieved a company-wide return on capital employed of 40.6% in 2006 (excluding capitalized costs for major projects in progress), compared to 19.7% in 2005. Including capitalized costs related to major projects in progress, return on capital employed was 30.4% in 2006, and 14.3% in 2005.

Suncor Energy Inc.	021
2006 Annual Report

Selected financial information

Annual Financial Data

Year ended December 31 ($ millions except per share data)	2006	2005	2004
Revenues	15 829	11 129	8 705
Net earnings	2 971	1 158	1 076
Total assets	18 781	15 149	11 774
Long-term debt	2 385	3 007	2 217
Dividends on common shares	127	102	97
Net earnings attributable to common shareholders per share – basic	6.47	2.54	2.38
Net earnings attributable to common shareholders per share – diluted	6.32	2.48	2.33
Cash dividends per share	0.30	0.24	0.23

Outstanding Share Data

As at December 31, 2006 (thousands)
Number of common shares	459 944
Number of common share options	19 809
Number of common share options – exercisable	8 627

Quarterly Financial Data

	2006				2005
	Quarter ended				Quarter ended
($ millions except per share)	Dec. 31	Sept. 30	June 30	Mar. 31	Dec. 31	Sept. 30	June 30	Mar. 31
Revenues	3 787	4 114	4 070	3 858	3 521	3 149	2 385	2 074
Net earnings	358	682	1 218	713	693	315	83	67
Net earnings attributable to common shareholders per share
Basic	0.78	1.48	2.65	1.56	1.52	0.69	0.18	0.15
Diluted	0.76	1.45	2.59	1.52	1.48	0.67	0.18	0.14

Net Earnings⁽¹⁾

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	2 824	976	970
Natural Gas	109	155	115
Energy Marketing and Refining – Canada	86	41	80
Refining and Marketing – U.S.A.(3)	168	142	34

Cash Flow from Operations⁽¹⁾

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	3 902	1 878	1 734
Natural Gas	281	412	319
Energy Marketing and Refining – Canada	217	152	188
Refining and Marketing – U.S.A.(3)	281	247	59

Capital Employed^{(1) (2)}

Year ended December 31,
($ millions)

	06	05	04
Oil Sands	5 092	4 472	4 105
Natural Gas	861	563	448
Energy Marketing and Refining – Canada	1 023	486	512
Refining and Marketing – U.S.A.(3)	831	327	232

(1)Excludes Corporate and Eliminations segment.

(2)Excludes major projects in progress.

(3)Refining and Marketing – U.S.A. 2006 and 2005 data includes results of the former Colorado Refining Company, acquired May 31, 2005.

022	Suncor Energy Inc.
	2006 Annual Report

Fluctuations in quarterly net earnings for 2006 and 2005 were due to a number of factors:

•Significantly higher Oil Sands production and sales volumes during 2006, following the September 2005 completion of recovery work to repair portions of the facilities damaged in the January 2005 fire, and the subsequent expansion of synthetic crude oil production capacity (to 260,000 bpd from 225,000 bpd).

•Changes in U.S. dollar denominated crude oil and natural gas prices. WTI averaged US$66.20 per barrel (bbl) in 2006 compared to US$56.55/bbl in 2005, and Henry Hub natural gas prices averaged US$7.25/mcf in 2006, compared to US$8.55/mcf in 2005.

•Cash operating costs varied due to variations in Oil Sands production levels, the timing and amount of maintenance activities, increased insurance expenses, and the price and volume of natural gas used for energy in Oil Sands operations.

•Alberta Oil Sands Crown royalties fluctuated as a result of changes in crude oil commodity prices and the extent and timing of annual capital and operating expenditures.

•Commodity and refined product prices fluctuated as a result of global and regional supply and demand, as well as seasonal demand variations. In our downstream operations, seasonal prices have historically reflected higher demand for vehicle fuels and asphalt in summer and heating fuels in winter, although 2006 saw these variations reduced significantly. Improved refining margins in 2006 compared to 2005 were partially offset by decreasing retail margins resulting from competitive market conditions.

•Realized commodity prices were unfavourably impacted by continued increases in the 2006 and 2005 average Cdn$/US$ exchange rates, which reduced the Canadian dollar revenues earned. The minimal increase in the year-end exchange rate resulted in no net foreign exchange gains for the U.S. dollar denominated debt in 2006, after a $37 million pretax gain in 2005.

•Reductions in both the federal and Alberta provincial corporate tax rates during the second quarter of 2006 increased 2006 net earnings by $419 million.

•The timing and amount of insurance receipts in both 2006 and 2005 related to the 2005 Oil Sands fire.

Consolidated Financial Analysis

This analysis provides an overview of our consolidated financial results for 2006 compared to 2005. For a detailed analysis, see the various business segment analyses.

Net Earnings

Our net earnings were $2.971 billion in 2006, compared with $1.158 billion in 2005 (2004 – $1.076 billion). The increase was primarily due to higher Oil Sands production coupled with increased U.S. dollar benchmark crude oil prices, strong refining margins in our downstream operations, and the substantive enactment of both federal and Alberta provincial income tax rate reductions in 2006. These positive impacts were partially offset by higher royalty expenses, increased maintenance and labour expenses, and additional third party insurance premium during 2006. The impact of a stronger Canadian dollar also reduced the sales value of Suncor’s U.S. dollar denominated products.

Net Earnings Components ⁽¹⁾

Year ended December 31 ($ millions, after-tax)	2006		2005		2004
Net earnings before the following items:	2 333		838		969
Firebag in-situ start-up costs	(13	)	(4	)	(14	)
Oil Sands fire accrued insurance proceeds (2)	232		293		—
Impact of income tax rate reductions on opening net future income tax liabilities	419		—		53
Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	—		31		68
Net earnings as reported	2 971		1 158		1 076

(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 consolidated financial statements and notes in accordance with Canadian GAAP.

(2)Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown royalties.

Suncor Energy Inc.	023
2006 Annual Report

Industry Indicators

(Average for the year unless otherwise noted)	2006		2005	2004
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	66.20		56.55	41.40
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	73.05		69.00	52.55
Light/heavy crude oil differential US$/barrel WTI at Cushing less Lloydminster Blend at Hardisty	21.85		20.90	13.55
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	7.25		8.55	6.20
Natural gas (Alberta spot) Cdn$/mcf at AECO	7.00		8.50	6.80
New York Harbour 3-2-1 crack US$/barrel (1)	9.80		9.50	6.90
Ontario refined product demand percentage change over prior year (2)	(1.6	)	0.1	4.3
Colorado light product demand percentage change over prior year (3)	2.2		2.5	7.2
Exchange rate: Cdn$/US$	0.88		0.83	0.77

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

(2)Figures for 2004 and 2005 are based on published government data. Figure for 2006 is an internal estimate based on preliminary government data.

(3)Figures for 2004 and 2005 are based on public reporting by state and government agencies. The 2006 figure is based on consensus estimates by third party consultants.

Revenues were $15.8 billion in 2006, compared with $11.1 billion in 2005 (2004 – $8.7 billion). Excluding the impact of net insurance proceeds related to the January 2005 fire at our Oil Sands operations, the increase was primarily due to the following:

•Production and sales volumes increased significantly during 2006, reflecting the October 2005 production capacity expansion to 260,000 bpd from 225,000, and the completion of recovery work from damage caused by the January 2005 fire.

•Average crude oil prices were higher in 2006 than in 2005. A 17% increase in average U.S. dollar WTI benchmark prices increased the selling price of Oil Sands crude oil production. This was partially offset by a 5% widening of the average light/heavy crude oil differentials compared to the WTI benchmark index. A 6% increase in the average Cdn$/US$ exchange rate resulted in lower realizations on our crude oil sales basket. Because crude oil is primarily sold based on U.S. dollar benchmark prices, a narrowing of the exchange rate difference produced a corresponding reduction in the Canadian dollar value of our products.

•Refined product wholesale prices in both EM&R and R&M were higher due to higher crude oil benchmark prices. In addition, 2006 reflects a full year of refined product sales volumes in R&M attributable to our acquisition of the Colorado Refining Company in the second quarter of 2005.

•The absence of strategic crude oil hedging losses in 2006 increased revenues by $535 million. During 2005, we sold 36,000 bpd of our crude oil production at an average fixed price of US$23/bbl. These hedges expired at December 31, 2005.

•Energy marketing and trading revenues increased to $1,582 million in 2006 compared to $827 million in 2005. The increase is due primarily to increased physical trading activities and higher average commodity prices. The results of energy marketing and trading are evaluated net of energy marketing and trading expenses. For a discussion of these net results, see page 33.

Partially offsetting these increases were the following:

•Retail prices in both EM&R and R&M reflected increasingly competitive pricing markets in the Ontario and Colorado regions.

•Lower price realizations on natural gas. Realized natural gas prices were $7.15 per thousand cubic feet (mcf) in 2006 compared to $8.57 per mcf in 2005, reflecting lower benchmark commodity prices.

Overall, increased production in our Oil Sands operations increased revenues by approximately $2.2 billion; higher crude oil prices, net of the impact of the higher average Cdn$/US$ exchange rate, increased total revenues by approximately $745 million; and the absence of hedging losses increased revenues by approximately $535 million.

024	Suncor Energy Inc.
	2006 Annual Report

Purchases of crude oil and products were $4.7 billion in 2006 compared with $4.2 billion in 2005 (2004 – $2.9 billion). The increase was primarily due to the following:

•Higher benchmark crude oil prices. This had the largest impact on product purchases for EM&R and R&M as WTI increased 17% over the prior year.

•Increased purchases of crude oil feedstock and refined products to meet sales commitments during planned maintenance shutdowns in both EM&R and R&M, and to more fully utilize the additional refining capacity acquired by R&M in the second quarter of 2005.

•Additional purchases of crude oil and products to meet plant and customer demands associated with unplanned maintenance at our Oil Sands operations.

Operating, selling and general expenses were $3.0 billion in 2006 compared with $2.4 billion in 2005 (2004 – $2.0 billion). The primary reasons for the increase were:

•An increase in the costs associated with planned and unplanned maintenance activities and labour costs.

•Higher stock-based compensation expenses as a result of the increase in our share price.

Transportation and other costs were $212 million in 2006 compared to $152 million in 2005 (2004 – $132 million). The increase in transportation costs was primarily due to increased volumes shipped out of the Fort McMurray area, and the increased shipments of Oil Sands sour crude blends to the U.S. Gulf Coast market.

Depreciation, depletion and amortization (DD&A) was $695 million in 2006, compared to $568 million in 2005 (2004 – $514 million). DD&A at Oil Sands increased by $55 million, primarily due to the inclusion of newly commissioned upgrading facilities and Firebag Stage 2 operations in our depreciable cost base during the fourth quarter of 2005. The DD&A for EM&R and R&M increased by $21 million and $15 million respectively in 2006 as a result of the completion of capital projects during the year, and the inclusion of these costs in our depreciable cost base. The capital projects for both EM&R and R&M were facility upgrades to enable production of ultra low sulphur diesel, in addition to the new ethanol facility completed in EM&R.

Royalty expenses were $1,038 million in 2006 compared with $555 million in 2005 (2004 – $531 million). The increase in 2006 was primarily due to increased Oil Sands royalties reflecting higher sales volumes, and higher price realizations. For a discussion of Oil Sands Crown royalties, see page 29.

Taxes other than income taxes were $595 million in 2006 compared to $529 million in 2005 (2004 – $540 million). The increase was primarily due to higher sales volumes subject to fuel excise taxes in our Oil Sands operations.

Financing expenses were $39 million in 2006 compared with income of $15 million in 2005 (2004 – expenses of $24 million). The increase in financing expenses was primarily due to the absence of any offsetting foreign exchange gains on our U.S. dollar denominated long-term debt. Interest expense on long-term debt was consistent with the prior year, with the impact of higher interest rates offset by lower debt levels. Total interest expense, net of capitalized interest, was $21 million in 2006 compared to $32 million in 2005. Capitalized interest was $129 million in 2006 compared to $119 million in 2005.

Income tax expense was $835 million in 2006 (22% effective tax rate), compared to $694 million in 2005 (37% effective tax rate) and $526 million in 2004 (33% effective tax rate). Income tax expense in both 2006 and 2004 included the effects of reductions in federal and Alberta provincial tax rates that reduced opening future income tax liabilities as follows:

Impact of Tax Rate Changes on Segmented Earnings

			Energy
			Marketing
			& Refining			2006	2005	2004
($ millions, increase (decrease) in earnings)	Oil Sands	Natural Gas	– Canada	Corporate		Total	Total	Total
Federal	290	36	5	(39	)	292	—	—
Provincial	139	17	—	(29	)	127	—	53
	429	53	5	(68	)	419	—	53

Excluding these adjustments, income tax expense in 2006 was $1,254 million (33% effective tax rate) and $579 million in 2004 (36% effective tax rate).

Suncor Energy Inc.	025
2006 Annual Report

Corporate Expenses

After-tax net corporate expenses were $216 million in 2006 compared to $156 million in 2005 (2004 – $123 million). Excluding the impact of group elimination entries, actual after-tax net corporate expenses were $222 million in 2006 (2005 – $167 million; 2004 – $111 million). The increase in net expenses resulted primarily from additional future tax expense as a result of the revaluation of future income taxes, higher stock-based compensation expenses and an increase in DD&A relating to our new enterprise resource planning system implemented throughout 2006. These factors were partially offset by the elimination of the self-insurance entity premium expense (fully offset in our Oil Sands segment). Corporate had a net cash deficiency of $443 million in 2006, compared with $105 million in 2005 (2004 – $325 million). The additional deficiency in 2006 was primarily due to changes in working capital.

Breakdown of Net Corporate Expense

Year ended December 31,
($ millions)	2006		2005		2004
Corporate expenses	222		167		111
Group eliminations	(6	)	(11	)	12
Total	216		156		123

Consolidated Cash Flow from Operations

Cash flow from operations was $4.533 billion in 2006 compared to $2.476 billion in 2005 (2004 – $2.013 billion). The increase in cash flow from operations was primarily due to the same factors that impacted net earnings, with the exception of DD&A, foreign exchange gains on our U.S. dollar denominated long-term debt in 2005, and future income taxes, all of which are non-cash items.

Dividends

Total dividends paid during 2006 were $0.30 per share, compared with $0.24 per share in 2005 (2004 – $0.23 per share). Suncor’s Board of Directors periodically reviews the dividend policy, taking into consideration the company’s capital spending profile, financial position, financing requirements, cash flow and other relevant factors. In the second quarter of 2006, the Board approved an increase in the quarterly dividend to $0.08 per share from $0.06 per share.

Liquidity and Capital Resources

At December 31, 2006, our capital resources consisted primarily of cash flow from operations and available lines of credit. Our level of earnings and cash flow from operations depends on many factors, including commodity prices, production/sales levels, downstream margins, operating expenses, taxes, royalties, and Cdn$/US$ exchange rates.

At December 31, 2006, our net debt was approximately $1.9 billion compared to $2.9 billion at December 31, 2005. The decrease in debt levels was primarily a result of higher cash flow from operations.

In 2006, the following changes to our available credit facilities were completed:

•A $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five-year term maturing in June 2011. In addition, the credit limit was increased by $500 million to $2 billion total funds available.

•A $200 million credit facility agreement was renegotiated and the credit limit was increased by $100 million to $300 million total funds available.

•A $600 million credit facility agreement matured and was not renewed.

Our undrawn lines of credit at December 31, 2006, were approximately $1.8 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.

Interest expense on debt continues to be influenced by the composition of our debt portfolio, and we are benefiting from short-term floating interest rates continuing at low levels. To manage fixed versus floating rate exposure, we have 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 our growth plans. We believe a phased approach to existing and future growth projects should assist us in managing project costs and debt levels.

We believe we have the capital resources to fund our 2007 capital spending program of $5.3 billion and to meet current working capital requirements. If additional capital is required, we believe adequate additional financing is available at commercial terms and rates.

026	Suncor Energy Inc.
	2006 Annual Report

We anticipate our growth plan will be financed from internal cash flow, which is dependent on commodity prices and production levels, as well as debt. We plan to continue to evaluate strategic crude oil hedging opportunities to provide downside protection against adverse changes in commodity prices (See page 31 for a discussion of our crude oil hedging program). After 2006, to support our growth strategy and sustain operations, we are projecting an annual capital spending program of approximately $5 billion. Actual spending is subject to change due to such factors as internal and external approvals and capital availability. Refer to the discussion under Risk Factors Affecting Performance on page 30 for additional factors that can have an impact on our ability to generate funds to support investing activities.

During the fourth quarter of 2006, we received the final settlement of our property damage claim related to the January 2005 Oil Sands fire.

Effective May 15, 2006, our primary business interruption insurer discontinued operations. During the third quarter 2006, we recorded additional premium expenses related to losses incurred by this insurer primarily relating to hurricane activity in the Gulf of Mexico during the summer of 2005.

Aggregate Contractual Obligations and Off-balance Sheet Financing

	Payments Due by Period
($ millions)	Total	2007	2008-09	2010-11	Later Years
Fixed-term debt, commercial paper (1)	2 347	681	—	500	1 166
Capital leases	38	1	3	3	31
Interest payments on fixed-term debt, commercial paper and capital leases (1)	2 393	144	222	224	1 803
Employee future benefits (2)	565	40	90	104	331
Asset retirement obligations (3)	1 657	104	175	96	1 282
Non-cancellable capital spending commitments (4)	216	216	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	5 346	279	577	574	3 916
Total	12 562	1 465	1 067	1 501	8 529

In addition to the enforceable and legally binding obligations quantified in the above table, we have 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 resold shortly after purchase, are one example of excluded items.

(1)Includes $2,066 million of U.S. and Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2007 to 2034. Interest rates vary from 5.95% to 7.15%. We entered into various interest rate swap transactions maturing in 2007 and 2011 that resulted in an average effective interest rate in 2005 ranging from 5.2% to 6.0% on $600 million of our medium-term notes. Approximately $280 million of commercial paper with an effective interest rate of 4.3% was issued and outstanding at December 31, 2006.

(2)Represents the undiscounted expected funding by the company to its pension plans as well as benefit payments to retirees for other post-employment benefits.

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

(4)Non-cancellable capital commitments related to capital projects totalled approximately $216 million at the end of 2006. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2007, we anticipate spending approximately $900 million at our Oil Sands operations towards sustaining capital.

(5)Includes transportation service agreements for pipeline capacity, including 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.

We are subject to financial and operating covenants related to our public market and bank debt. Failure to meet the terms of one or more of these covenants may constitute an Event of Default as defined 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 our commodity purchase agreements, off-balance sheet arrangements (for a discussion of these arrangements see page 28) and derivative financial instrument agreements contain provisions linked to debt ratings that may result in settlement of the outstanding transactions should our debt ratings fall below investment grade status.

At December 31, 2006, we were in compliance with all covenants and our debt ratings were investment grade with a stable outlook. For more information, see page 25.

Suncor Energy Inc.	027
2006 Annual Report

Significant Capital Project Update

We spent $3.5 billion on capital investing activities in 2006 compared to $2.7 billion ($3.1 billion including the cost of the fire rebuild and capitalized interest) in 2005 (2004 – $1.7 billion). The projects listed below represent the significant individual capital projects underway to support both our growth and sustaining capital needs. For a discussion of our Oil Sands growth strategy, refer to page 46. All projects listed below have received Board of Directors approval.

	Cost		Spent		Total Spent
	Estimate		in 2006		to Date
Description	($ millions)	(1)	($ millions)		($ millions)		Status (1)
Oil Sands
Coker unit (2)	2 100		665		1 590		Project is on schedule and on budget.
Millennium naphtha unit (3)	650		80		85		Project is on schedule and on budget.
Steepbank extraction plant (4)	880		55		65		Project is on schedule and on budget.
Firebag cogeneration and expansion	400		190		315		Project is on schedule and on budget.
EM&R
Diesel desulphurization
and oil sands integration	960		320		800		Project is on schedule; and cost estimate has been revised from the April 2005 estimate of $800 million. (5)
R&M
Diesel desulphurization	540		115		530
and oil sands integration	(US$445	)	(US$95	)	(US$435	)	Project complete. (6)

(1)Estimating and budgeting for major capital projects is a process that involves uncertainties and that evolves in stages, each with progressively more refined data and a correspondingly narrower range of uncertainty. At very early stages, when broad engineering design specifications are developed, the level of uncertainty can result in price ranges with -30%/+50% (or similar) levels of uncertainty. As project engineering progresses, vendor bids are studied, goods and materials ordered and we move closer to the build stage, the level of uncertainty narrows. Generally, when projects receive final approval from our Board of Directors, our cost estimates have a range of uncertainty that has narrowed to the -10%/+10% or similar range. The projects noted in the above table have cost estimates within this range of uncertainty. These ranges establish an expected high and low capital cost estimate for a project. When we say that a project is “on budget,” we mean that we still expect the final project capital cost to fall within the current range of uncertainty for the project. Even at this stage, the uncertainties in the estimating process and the impact of future events, can and will cause actual results to differ, in some cases materially, from our estimates.

(2)Excludes costs associated with bitumen feed.

(3)The Millennium naphtha unit project is expected to enhance the product mix of our oil sands production.

(4)The Steepbank extraction plant will replace and enhance existing base plant extraction facilities.

(5)See page 52 for discussion.

(6)In the first quarter of 2006, the project budget was increased to a final expected cost of US$445 million from then-current estimates of US$390 million. The original cost estimate was US$300 million.

The addition of a third upgrader has not yet been approved by Suncor’s Board of Directors. Suncor has not yet announced firm capital cost estimates for this project as the cost estimate, together with the final configuration of the project, is still under development. However, preliminary figures including those in Suncor’s regulatory approval application are under upward pressure. Detailed engineering is expected in 2007, at which time final approval to proceed with the project will be considered by Suncor’s Board of Directors. Subject to Board approval, the project will be included in the above table at that time.

To date approximately $900 million has been approved for planning and scoping initiatives related to project design for the third upgrader.

Suncor’s Firebag Stage 3 project is expected to be submitted for final Board of Director’s approval in 2007. To date approximately $550 million has been approved for planning and scoping initiatives related to project design.

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Variable Interest Entities and Guarantees and Off-balance Sheet Arrangements

At December 31, 2006, we had off-balance sheet arrangements with Variable Interest Entities (VIEs), and indemnification agreements with other third parties, as described below.

We have a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million (2005 – $340 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, 2006, $170 million (2005 – $340 million) in outstanding accounts receivable had been sold under the program. Although the company does not believe it has any significant exposure to credit losses, under the recourse provisions, we provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $72 million in 2006 and no contingent liability or earnings impact have been recorded for this indemnification as we believe we have no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2006, were $170 million and approximately $623 million, respectively. We recorded an after-tax loss of approximately $2 million on the securitization program in 2006 (2005 – $4 million; 2004 – $2 million).

In 1999, we entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE’s sole asset was the equipment sold to it and leased back by Suncor. The VIE was consolidated effective January1, 2005. The initial lease term covered a period of seven years, and had been accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2006, the VIE did not have any assets or liabilities.

We have agreed to indemnify holders of the 7.15% fixed-term U.S. dollar notes, the 5.95% fixed-term U.S. dollar notes and our credit facility lenders for added costs related 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. We are unable to determine the maximum potential amount payable as government regulations and legislation are subject to change without notice. Under these agreements, we have the option to redeem or terminate these contracts if additional costs are incurred.

Outlook

During 2007, management will focus on the following operational priorities:

•Achieve annual oil sands production (including bitumen sold directly to the market) of 260,000 to 270,000 bpd with a cash operating cost average of $21.50 to $22.50 per barrel. Steady and reliable production will help us manage cash operating costs.

•Increase natural gas production (including natural gas liquids and crude oil) to an average 215 to 220 mmcf equivalent per day. We expect to bring several existing wells into production and will continue to focus on high-volume deep gas prospects in 2007.

•Advance plans for increased bitumen supply. Launch the regulatory, consultation and engineering work required to determine mine development potential for Voyageur South (Lease 23), receive Board of Director approval for our Firebag Stage 3 in-situ development, including cost estimates.

•Safely complete all planned expansion tie ins. Complete a 50-day shutdown on Upgrader 2 to perform planned maintenance and tie in expanded facilities that are expected to increase production to 350,000 bpd in 2008. At the Sarnia refinery, complete a
65-day shutdown to tie in new and modified equipment to allow the processing of up to 40,000 bpd of oil sands sour crude.

•Advance plans for increased upgrader capacity. Complete the Engineering Design Study (EDS) phase, which is necessary to seek Board of Directors approval to proceed with construction of our planned third oil sands upgrader, a key component of achieving more than half a million bpd by 2010 to 2012.

•Continue to improve safety performance.

•Focus on enterprise-wide efficiency. For example, improved operational reliability is the goal of establishing a single-vendor, performance-based maintenance contract for all Canadian facilities.

•Maintain a strong balance sheet. With capital spending plans of more than $5 billion, a strong balance sheet will be critical. Suncor is targeting debt at a maximum of two times cash flow.

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•Continue to pursue energy efficiencies, greenhouse gas offsets and new, renewable energy projects. We plan to continue investment in biofuels and to commission our fourth – and largest yet – joint venture wind power project in 2007. Complete the stakeholder consultation and preliminary engineering needed to determine feasibility of expanding the St. Clair Ethanol facility.

Oil Sands Crown Royalties and Cash Income Taxes

Under the current Province of Alberta oil sands royalty regime, Alberta Crown royalties for oil sands projects are payable at the rate of 25% of the difference between a project’s annual gross revenues net of related transportation costs (R), less allowable costs including allowable capital expenditures (the R-C Royalty), subject to a minimum royalty, currently at 1% of R. The Alberta government has classified Suncor’s current Oil Sands operations as two distinct “projects” for royalty purposes: Suncor’s 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 under the government’s generic bitumen-based royalty regime for oil sands projects.

In 1997, Suncor was granted an option by the government to transition our base operations on January 1, 2009, to the generic bitumen-based royalty regime, subject to finalizing certain terms of transition. Suncor and the government reached agreement on the terms and conditions of our option in the third quarter of 2005. In November 2006, we exercised our option to convert to the bitumen-based royalty. As a result, starting January 1, 2009, we expect to pay a royalty in respect of our base operations of 25% of R-C, with “R” based on bitumen rather than upgraded product values, and “C” excluding substantially all of the upgrading costs.

In 2006, the Department of Energy proposed a new methodology for determining the “R” related to bitumen using an synthetic crude oil (SCO) value less an upgrading processing cost of service charge. This methodology would generally result in higher attributed bitumen values than those used under the current formula. The Crown is consulting with industry, with a decision on the methodology anticipated by January1, 2008.

A new bitumen pricing methodology is not expected to affect base operation royalties until our transition to the bitumen-based regime effective January 1, 2009. However, for our Firebag operations the pricing methodology could be retroactively applied to November 1, 2003, when Firebag commenced production. The outcome of this review is uncertain, and future royalties payable as well as the determination of net reserves may be affected.

In addition, the Government of Alberta has announced a review of its Crown royalties, to be completed by the summer of 2007.

Assuming anticipated levels of operating expenses and capital expenditures for each project remain relatively constant, and there are no changes to the current Government of Alberta oil sands royalty regime or the government’s application of the applicable rules (including no changes to the bitumen pricing methodology), and no other unanticipated events occur, we believe future variability in Oil Sands royalty expense will primarily be a function of changes in annual Oil Sands revenue. On that basis, we would generally expect Alberta Crown royalty expense for Oil Sands to range as set forth in the following chart. For years after 2008, this percentage range may decline as anticipated new in-situ production attracts royalties based on bitumen values at 1% until project payout. Although we have assumed there will be no change in the methodology for determining the price of bitumen used to determine “R,” the methodology is not likely to be finalized until 2008, and as a result, the potential impacts are not currently known but may be material.

Anticipated Royalty Expense Based on Certain Assumptions

For the period from 2007-2012
WTI Price/bbl (US$)	40	50	60
Natural gas price per mcf at Henry Hub (US$)	6.75	8.25	10.00
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast (US$)	9.60	12.60	15.10
Cdn$/US$ exchange rate	0.80	0.85	0.90
Crown Royalty Expense % (based on percentage of total Oil Sands revenue)
2007-2008 (all cases 2007 @ $50)	7-8	7-10	7-12
2009-2012 (1)	4-5	5-7	6-8

(1) During 2006, we exercised our option to transition our base operations in 2009 to the generic bitumen-based royalty regime.

The federal opposition parties and others have requested an elimination of the oil sands accelerated depreciation of capital costs incurred; however, to date no changes have been made. Assuming there are no changes to the current

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income tax regime for 2007, we estimate we will have partial cash taxes in the range of 70-100% of expected effective tax rates, based on current prices, and current forecasts of production, capital and operating costs for 2007. Any cash tax in 2007 would be due in February 2008. Assuming there are no changes to the current income tax regime, we do not expect any significant cash tax in subsequent years until the next decade, primarily due to the company’s investment in the expansion of its oil sands operations to 500,000 to 550,000 bpd. In any particular year, our Oil Sands and Natural Gas operations may be subject to some cash income tax due to sensitivity to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for income tax purposes.

Alberta Crown royalties and cash taxes are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project. In addition, all aspects of the current Alberta oil sands royalty regime, including royalty rates and the royalty base, are subject to alteration by the Government of Alberta. Accordingly, in light of these uncertainties and the potential for unanticipated events to occur, we strongly caution that it is impossible to predict even a range of annualized royalty expense as a percentage of revenues or the impact royalties may have on our financial results, and actual differences may be material. The forward-looking information in the preceding paragraphs and table should not be taken as an estimate, forecast or prediction of future events or circumstances.

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

Climate Change

Our effort to reduce greenhouse gas emissions is reflected in our pursuit of greater internal energy efficiency, investment in renewable energy including wind power, carbon capture research and development, and emissions offsets.

We continue to consult with governments about the impact of the Kyoto Protocol and we plan to continue to actively manage our greenhouse gas emissions. As the announced Clean Air Act by the Conservative Government has been referred to a special committee for review and revision, the ultimate regulatory outcome is unknown. In the meantime, Suncor will continue to actively manage its air emissions, including greenhouse gases, and to advance opportunities such as carbon capture and geological sequestration, and renewable and alternate forms of energy such as wind power and biofuels.

Risk Factors Affecting Performance

Our financial and operational performance is potentially affected by a number of factors including, but not limited to, commodity prices and exchange rates, environmental regulations, changes to royalty and income tax legislation and application of such legislation, stakeholder support for growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors for each of our business segments. As a company we identify risks in four principal categories: 1) Operational; 2) Financial; 3) Legal and Regulatory; and 4) Strategic. A more detailed discussion of our risk factors is presented in our most recent Annual Information Form/Form 40-F, filed with securities regulatory authorities. We are continually working to mitigate the impact of potential risks to our businesses. This process includes an entity wide risk review. The internal review is completed annually to ensure that all significant risks are identified and appropriately managed.

Commodity Prices, Refined Product Margins and Exchange Rates

Our 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 2004 to 2006 the monthly average price for benchmark WTI crude oil ranged from a low of US$34.22/bbl to a high of US$74.46/bbl. During the same three-year period, the natural gas Henry Hub benchmark monthly average price ranged from a low of US$4.40/mcf to a high of US$14.07/mcf. We believe commodity price volatility will continue.

Crude oil and natural gas prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the Cdn$/US$ currency exchange rate, thereby creating an element of uncertainty. Should the Canadian dollar strengthen compared to the U.S. dollar, the resulting negative effect on net earnings would be partially offset by foreign exchange gains on our U.S. dollar

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denominated debt. The opposite would occur should the Canadian dollar weaken compared to the U.S. dollar. Cash flow from operations is not impacted by the effects of currency fluctuations on our 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 debt at the end of 2006, a $0.01 change in the Cdn$/US$ exchange rate would change net earnings by approximately $11 million after-tax.

Future U.S. capital projects may be partially funded from Canadian operations. A weaker Canadian dollar would result in a higher funding requirement for these projects.

Sensitivity Analysis ⁽¹⁾

			Approximate Change in
			Cash Flow
			from	After-tax
	2006		Operations	Earnings
	Average	Change	($ millions)	($ millions)
Oil Sands
Price of crude oil ($/barrel) (2)	$68.03	US$1.00	82	55
Sweet/sour differential ($/barrel)	$8.84	US$1.00	37	25
Sales (bpd)	263 100	1 000	13	9
Natural Gas
Price of natural gas ($/mcf) (2)	$7.15	0.10	5	4
Production/sales of natural gas (mmcf/d)	191	10	16	7
Consolidated
Exchange rate: Cdn$/US$	0.88	0.01	43	29

(1)The sensitivity analysis shows the main factors affecting Suncor’s annual cash flow from operations and earnings based on actual 2006 operations. The table illustrates the potential financial impact of these factors applied to Suncor’s 2006 results. A change in any one factor could compound or offset other factors.

(2)Includes the impact of hedging activities.

Derivative Financial Instruments

We periodically enter into commodity-based derivative financial instruments such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to variations in underlying commodity indices. In addition, we periodically enter into derivative financial instrument contracts such as interest rate swaps and foreign currency contracts as part of our risk management strategy to manage exposure to interest rate and foreign exchange fluctuations.

We also use energy derivatives, including physical and financial swaps, forwards and options to earn trading revenues. These trading activities are accounted for at fair value in our 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. See page 42 for a discussion of changes to the accounting for hedges effective January 1, 2007.

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 Our crude oil hedging program is subject to periodic management reviews to determine appropriate hedge requirements in light of our tolerance for exposure to market volatility as well as the need for stable cash flow to finance future growth.

To provide an element of stability to future earnings and cash flow, we resumed our strategic crude oil hedging program in the third quarter of 2005, receiving Board approval to fix a price or range of prices for up to approximately 30% of our total production of crude oil for specified periods of time. At December 31, 2006, we had entered into US$ WTI costless collar agreements covering 60,000 bpd of crude oil beginning January 1, 2007 and ending December 31, 2007, and 10,000 bpd from

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January 1, 2008 to December 31, 2008. Prices for these barrels are fixed within a range from an average of US$51.64/bbl up to an average of US$101.06/bbl.

For collars, if market rates are within the range of the hedged contract prices, the option contracts making up the collar will expire with no exchange of cash. On settlement of swap agreements, our hedging contracts result in cash receipts or payments for the difference between the derivative contract and market rates for the applicable volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in our 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 Segmented Statements of Earnings. In 2006, there was no net earnings impact due to crude oil hedging, compared to a decrease of $337 million in 2005 (2004 – decrease of $397 million).

Crude oil hedge contracts outstanding at December 31, 2006, were as follows:

Swap Transactions

		Average		Revenue
	Quantity	Price		Hedged		Hedge
	(bpd)	(US$/bbl)	(a)	(Cdn$ millions)	(b)	Period	(c)
Costless collars	60 000	51.64 – 93.26		1 318 – 2 380		2007
Costless collars	10 000	59.85 – 101.06		255 – 431		2008

(a)Average price of crude oil costless collars is WTI per barrel at Cushing, Oklahoma.

(b)The revenue hedged is translated to Cdn$ at the year-end exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(c)Original hedge term is for the full year.

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

We have entered into various interest rate swap transactions at December 31, 2006. 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.

	Principal Swapped	Swap	2006 Effective
Description of swap transaction	($ millions)	Maturity	Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.2	%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	6.0	%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	5.3	%

In 2006, these interest rate swap transactions reduced pretax financing expense by $6 million compared to a pretax reduction of $14 million in 2005 (2004 – $17 million pretax).

At December 31, 2006, we had also hedged €20.6 million in 2007 Euro exposure created by the anticipated purchase of equipment during the year.

Fair Value of Strategic Derivative Hedging Instruments

The fair value of derivative hedging instruments is the estimated amount, based on broker quotes and/or internal valuation models, that we 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:

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Fair Value of Hedging Derivative Financial Instruments

($ millions)	2006		2005
Revenue hedge swaps and collars	22		(4	)
Margin hedge swaps	—		1
Interest rate and cross-currency interest rate swaps	16		22
Specific cash flow hedges of individual transactions	(4	)	5
Total	34		24

Energy Marketing and Trading Activities In addition to the financial derivatives used for hedging activities, the company uses physical and financial energy contracts, including swaps, forwards and options to earn trading and marketing revenues. The financial trading activities are accounted for using the mark-to-market method and as such all financial instruments are recorded at fair value at each balance sheet date. Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. The results of these activities are reported as revenue and as energy trading and marketing expenses in the Consolidated Statements of Earnings.

The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss)

($ millions)	2006		2005
Physical energy contracts trading activity	41		15
Financial energy contracts trading activity	(3	)	5
General and administrative costs	(3	)	(3	)
Total	35		17

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

Fair Value of Unsettled Financial Energy Trading Assets and Liabilities

($ millions)	2006	2005
Energy trading assets	16	82
Energy trading liabilities	13	70
Net energy trading assets	3	12

Change in Fair Value of Net Assets

($ millions)	2006
Fair value of contracts outstanding at December 31, 2005	12
Fair value of contracts realized during 2006	(6	)
Fair value of contracts entered into during the period	2
Changes in values attributable to market price and other market changes	(5	)
Fair value of contracts outstanding at December 31, 2006	3

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

Counterparty Credit Risk We may be exposed to certain losses in the event that the counterparties to derivative financial instruments are unable to meet the terms of the contracts. Our exposure is limited to those counterparties holding derivative contracts with net positive fair values at the reporting date. We minimize this risk by entering into agreements primarily with investment grade counterparties. Risk is also minimized through regular management review of the potential exposure to and credit ratings of such counterparties.

At December 31, the company had exposure to credit risk with counterparties as follows:

Counterparty Credit Risk

($ millions)	2006	2005
Derivative contracts not accounted for as hedges	16	82
Unrecognized derivative contracts accounted for as hedges	35	30
Total	51	112

Environmental Regulation and Risk

Environmental regulation affects nearly all aspects of our operations. These regulatory regimes are laws of general application that apply to us in the same manner as they apply to other companies and enterprises in the energy industry. The regulatory regimes require us to obtain operating licenses and permits in order to operate, and impose certain standards and controls on activities relating to mining, oil and gas exploration, development and production, and the refining, distribution and marketing

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of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new major projects or undertaking significant changes to existing operations. Suncor’s Oil Sands operating licence was temporarily extended in 2006 and we anticipate receipt of a new operating licence in 2007. In addition to these specific, known requirements, we expect future changes to environmental legislation, including anticipated legislation for air pollution (Criteria Air Contaminants (CACs) and Greenhouse Gases (GHGs)), will impose further requirements on companies operating in the energy industry.

Some of the issues that are or may in future be subject to environmental regulation include:

•The possible cumulative impacts of oil sands development in the Athabasca region

•Storage, treatment, and disposal of hazardous or industrial waste

•The need to reduce or stabilize various emissions to air and withdrawals and discharges to water

•Issues relating to global climate change, land reclamation and restoration

•Water use and water disposal

•Reformulated gasoline to support lower vehicle emissions.

Changes in environmental regulation could have a potentially adverse effect on us from the standpoint of product demand, product reformulation and quality, methods of production and distribution and costs. For example, requirements for cleaner-burning fuels could cause additional costs to be incurred, which may or may not be recoverable in the marketplace. The complexity and breadth of these issues make it extremely difficult to predict their future impact on us. 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. Compliance with environmental regulation can require significant expenditures and failure to comply with environmental regulation may result in the imposition of fines and penalties, liability for cleanup costs and damages and the loss of important permits and licenses.

Another area of risk for Suncor and the oil sands industry is the reclamation of tailings ponds, which contain water, clay and residual bitumen produced through the extraction process. To reclaim tailings ponds, we are using a process referred to as consolidated tailings (CT) technology. At this time, no ponds have been fully reclaimed using this technology. The success of the CT technology and time to reclaim the tailings ponds could increase or decrease the current asset retirement cost estimates. We continue to monitor and assess other possible technologies and/or modifications to the CT process now being used.

For Suncor’s Oil Sands Mining Leases 86 and 17, we are required to and have posted annually with Alberta Environment an irrevocable letter of credit equal to $0.03 per bbl of crude oil produced as of December 31, 2005 ($14 million as at December 31, 2005) as security for the estimated cost of our reclamation activity. Since there has been no production from Leases 86/17 in 2006, the amount of security remained unchanged.

For the Millennium and Steepbank mines, we have posted irrevocable letters of credit equal to approximately $163 million, representing security for the maximum reclamation liability in the period March 31, 2006 through March 31, 2007. For more information about our reclamation and environmental remediation obligations, refer to “Asset Retirement Obligations” under “Critical Accounting Estimates” in the “Suncor Overview and Strategic Priorities” section of our MD&A.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta, and is currently planned for implementation June 30, 2007. The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement of reserve life. As currently proposed, initial security deposits for oil sands mining would be reduced. Partial security could be required if reclamation targets are not met and full security may eventually be required.

Regulatory Approvals

Before proceeding with most major projects, we 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.

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Critical Accounting Estimates

Critical accounting estimates are defined as estimates that are important to the portrayal of our financial position and operations, and require management to make judgments based on underlying assumptions about future events and their effects. These underlying assumptions are based on historical experience and other factors that management believes to be reasonable under the circumstances, and are subject to change as new events occur, as more industry experience is acquired, as additional information is obtained and as our operating environment changes. Critical accounting estimates are reviewed annually by the Audit Committee of the Board of Directors. We believe the following are the most critical accounting estimates used in the preparation of our consolidated financial statements.

Reserves Estimates

We are a Canadian issuer subject to Canadian reporting requirements, including rules in connection with the reporting of our reserves. However, we have received an exemption from Canadian securities administrators permitting us to report our reserves in accordance with U.S. disclosure requirements. Pursuant to U.S. disclosure requirements, we disclose net proved conventional oil and gas reserves, including natural gas reserves and bitumen reserves from our 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, 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”). Reserves from our 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, we also disclose gross and net proved and probable mining reserves. The estimates of our gross and net mining reserves are based in part on the current mine plan and estimates of extraction recovery and upgrading yields. We report mining reserves as barrels of synthetic crude oil based on a net coker, or synthetic crude oil yield from bitumen of 80%. During 2005, we reached an agreement with the Government of Alberta finalizing the terms of our option to transition to the generic bitumen-based royalty regime commencing in 2009, allowing us to prepare an estimate of our net mining reserves. The estimate of our net mining reserves reflects the relative value of Alberta Crown and freehold royalty burdens under constant December 31 bitumen pricing and our exercise of the option to transfer to a bitumen-based Crown royalty effective the beginning of 2009 (See “Required U.S. Oil and Gas and Mining Disclosure – Proved and Probable Oil Sands Mining Reserves” for both gross and net, proved and probable mining reserves). Our Firebag in-situ leases are subject to Alberta Crown royalty based on bitumen, rather than synthetic crude oil (for a full discussion of our oil sands Crown royalties, see “Oil Sands Crown Royalties and Cash Income Taxes” on page 29).

In addition to required disclosure, our exemption issued by Canadian securities administrators permits us to provide further disclosure voluntarily. We provide this additional voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and reserves from our Firebag in-situ leases. In our voluntary disclosure we report our aggregate reserves on the following basis:

•Gross and net 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 upon a net coker, or synthetic crude oil yield from bitumen of 80%); and

•Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on normalized constant dollar cost and pricing assumptions. Bitumen reserves estimated on this basis are subsequently converted, for aggregation purposes only, to barrels of synthetic crude oil based on a net coker or synthetic crude oil yield from bitumen of 80%.

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Accordingly, our voluntary disclosures of reserves from our Firebag in-situ leases will differ from our required U.S. disclosure in three ways. Reserves from our Firebag in-situ leases under our voluntary disclosure:

(a)are disclosed on a gross basis as well as the required net basis under U.S. disclosure requirements;

(b)are converted from barrels of bitumen under U.S. disclosure requirements to barrels of synthetic crude oil for aggregation purposes only; and

(c)include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements.

Under the U.S. disclosure requirements described above, our Firebag in-situ reserves were determined to be entirely uneconomic at December 31, 2004. In 2005, Constant Cost and Pricing assumptions were again applied to assess economic viability of our in-situ reserves. This assessment resulted in the rebooking of proved reserves at December 31, 2005. At December 31, 2006, pricing assumptions were again considered economically viable and our proved reserves disclosures reflect this. (See “Required U.S. Oil and Gas and Mining Disclosure – Proved Conventional Oil and Gas Reserves”).

Under our voluntary disclosure, the year-end 2006 bitumen price determined pursuant to SEC pricing methodology was not materially different than the price determined pursuant to CSA Staff Notice 51-315. Consequently, for 2006 only one constant price scenario was used for year end disclosures. Refer to “Voluntary Oil Sands Reserves Disclosure - Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations.”

Comparisons of reserve estimates under required U.S. Oil and Gas Mining Disclosure and Voluntary Oil Sands Reserve Disclosure may show material differences based on the pricing assumptions used, whether the reserves are reported as barrels of bitumen or barrels of synthetic crude oil, whether probable reserves are included, and whether the reserves are reported on a gross or net basis. These differences were more significant during 2004 and 2005 with considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing.

All of our reserves have been evaluated as at December 31, 2006, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (GLJ). In reports dated February 9, 2007 (“GLJ Oil Sands Reports”), GLJ evaluated our proved and probable reserves on our oil sands mining and Firebag in-situ leases pursuant to both U.S. disclosure requirements using Constant Cost and Pricing assumptions.

Estimates in the GLJ Oil Sands Reports consider recovery from leases for which regulatory applications have been submitted and no anticipated impediment to the receipt of regulatory approval is expected. 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 our regulatory approval or likely impediments to the receipt of pending regulatory approval, project implementation commitments, detailed design estimates, detailed reservoir studies, demonstrated commercial success of analogous commercial projects and drill density. Our proved reserves are delineated to within 80 acre spacing with 3-D seismic control (or 40 acre spacing without 3-D seismic control) while our probable reserves are delineated to within 160 acre spacing without 3D seismic control. The major facility expenditures to develop our proved undeveloped reserves have been approved by our Board. Plans to develop our probable undeveloped reserves in subsequent phases are underway but have not yet received final approval from our Board.

In a report dated February 9, 2007 (“GLJ NG Report”), GLJ also evaluated our proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from our mining leases and the Firebag in-situ reserves) as at December 31, 2006.

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

Net reserves represent Suncor’s working interest in total reserves after deducting Crown Royalties, freehold and overriding royalty interests. Reserve estimates are based on assumptions about future prices, production levels, operating costs, capital expenditures, and the current Government of Alberta Royalty regime. These assumptions reflect market and regulatory conditions, as required, at December 31, 2006, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

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Required U.S. Oil and Gas and Mining Disclosure

Proved and Probable Oil Sands Mining Reserves

	Oil Sands Mining Leases
	Proved				Probable				Proved & Probable
Millions of barrels of synthetic crude oil (1)	Gross	(2)	Net	(3)	Gross	(2)	Net	(3)	Gross	(2)	Net	(3)
December 31, 2005	1 528		1 440		896		862		2 424		2 302
Revisions of previous estimates	266		140		(262	)	(298	)	4		(158	)
Extensions and discoveries	—		—		—		—		—		—
Production	(85	)	(73	)	—		—		(85	)	(73	)
December 31, 2006	1 709		1 507		634		564		2 343		2 071

(1)Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil yield from bitumen of 80% (2005 – 80%).

(2)Our gross mining reserves are based in part on our 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.

(3)Net mining reserves reflect the value of Crown royalty burdens under constant December 31st pricing and incorporates our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.

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 our Oil Sands mining activities are excluded, while in-situ Firebag reserves are included.

Net Proved Reserves ⁽¹⁾

Crude Oil, Natural Gas Liquids and Natural Gas

			Natural Gas
	Oil Sands business:		business: crude
	Firebag – crude		oil and natural				Natural Gas
	oil (millions		gas liquids		Total		business: natural
	of barrels		(millions		(millions		gas (billions
Constant Cost and Pricing as at December 31	of bitumen)	(2) (3) (4)	of barrels)		of barrels)		of cubic feet)
December 31, 2005	632	(3)	7		639		449
Revisions on previous estimates (5)	(57	)	—		(57	)	5
Improved recovery (6)	340		—		340		—
Purchases of minerals in place	—		—		—		—
Extensions and discoveries	—		1		1		26
Production	(12	)	(1	)	(13	)	(53	)
Sales of minerals in place	—		—		—		(1	)
December 31, 2006	903		7		910		426

(1)   Our undivided percentage interest in reserves, after deducting Crown royalties, freehold royalties and overriding royalty interests. Our Firebag leases are only subject to Crown royalties.

(2)   Although we are subject to Canadian disclosure rules in connection with the reporting of our reserves, we have received exemptive relief from Canadian securities administrators permitting us to report our proved reserves in accordance with U.S. disclosure practices.

(3)   Estimates of proved reserves from our Firebag in-situ leases are based on Constant Cost and Pricing assumptions as at December 31. In 2004, due to unusually low year-end posted benchmark oil prices and unusually high year-end diluent prices, our proved reserves were determined to be uneconomic. Under 2005 Constant Cost and Pricing assumptions, we have rebooked our proved reserves, and these continue to be economically viable in 2006.

(4)   We have the option of selling the bitumen production from these leases or upgrading the bitumen to synthetic crude oil. With the completion of upgrading expansion projects during 2005, all bitumen is expected to be processed into synthetic crude oil in the future, unless strategic market conditions exist.

(5)   Natural gas infill drilling included in total revisions for 2006 was 11 billion cubic feet (bcf).

(6)   Improved recovery recognizes a portion of our Firebag Stage 3 expansion project.

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Voluntary Oil Sands Reserves Disclosure

Oil Sands Mining and Firebag In-situ Reserves Reconciliation

The following tables set out, on a gross and net basis, a reconciliation of our proved and probable reserves of synthetic crude oil from our Oil Sands mining leases and bitumen, converted to synthetic crude oil for comparison purposes only, from our in-situ Firebag leases, from December 31, 2005, to December 31, 2006, based on the GLJ Oil Sands Reports.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

													Total Mining
	Oil Sands Mining Leases (1) (2)						Firebag In-situ Leases (1) (3)						and In-situ (3)
					Proved						Proved		Proved
Millions of barrels of synthetic crude oil (1)	Proved		Probable		& Probable		Proved		Probable		& Probable		& Probable
December 31, 2005	1 528		896		2 424		561		2 137		2 698		5 122
Revisions of previous estimates	266		(262	)	4		—		22		22		26
Improved recovery	—		—		—		252		(252	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(85	)	—		(85	)	(10	)	—		(10	)	(95	)
December 31, 2006	1 709		634		2 343		803		1 907		2 710		5 053

Estimated Net Proved and Probable Oil Sands Reserves Reconciliation

													Total Mining
	Oil Sands Mining Leases (1) (2)						Firebag In-situ Leases (1) (3)						and In-situ (3)
					Proved						Proved		Proved
Millions of barrels of synthetic crude oil (1)	Proved		Probable		& Probable		Proved		Probable		& Probable		& Probable
December 31, 2005	1 440		862		2 302		556		2 029		2 585		4 887
Revisions of previous estimates	140		(298	)	(158	)	(50	)	(164	)	(214	)	(372	)
Improved recovery	—		—		—		226		(226	)	—		—
Extensions and discoveries	—		—		—		—		—		—		—
Production	(73	)	—		(73	)	(10	)	—		(10	)	(83	)
December 31, 2006	1 507		564		2 071		722		1 639		2 361		4 432

(1)   Synthetic crude oil reserves are based on a net coker, or synthetic crude oil yield from bitumen of 80% for reserves under Oil Sands Mining and under Firebag in-situ Leases. Although virtually all of our bitumen from the Oil Sands mining leases is upgraded into synthetic crude oil, we have the option of selling the bitumen produced from our Firebag in-situ leases and/or upgrading this bitumen into synthetic crude oil. Accordingly, these bitumen reserves are converted to synthetic crude oil for comparison purposes only.

(2)   Our 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. Net mining reserves reflect the relative value of Crown, freehold and overriding royalty burdens under constant December 31st pricing and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009.

(3)   Under “Required U.S. Oil and Gas and Mining Disclosure,” we reported proved reserves from our 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 under our voluntary disclosure:

(a)    are disclosed on a gross basis as well as the required net basis under required U.S. disclosure requirements;

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

(c)    include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements. U.S. companies do not disclose probable reserves for non-mining properties. We voluntarily disclose our probable reserves for our Firebag in-situ leases as we believe this information is useful to investors, and allows us to aggregate our mining and in-situ reserves into a consolidated total for our Oil Sands business. As a result, our Firebag in-situ estimates in the above tables are not comparable to those made by U.S. companies.

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2006 Annual Report

Asset Retirement Obligations (ARO)

We are required to recognize a liability for the future retirement obligations associated with our property, plant and equipment. An ARO is only recognized to the extent there is a legal obligation associated with the retirement of a tangible long-lived asset that we are required to settle as a result of an existing or enacted law, statute, ordinance, 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 our total ARO amount. These individual assumptions can be subject to change based on experience.

The ARO is measured at fair value and discounted to present value using a credit-adjusted risk-free discount rate of 5.5% (2005 – 5.6%). The ARO accretes over time until we settle the obligation, the effect of which is included in a separate line in the Consolidated Statements of Earnings entitled “Accretion of asset retirement obligations.” 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 is adjusted as 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 and third party reviews of Oil Sands and NG completed in the fourth quarter of 2006, we increased our estimated undiscounted total obligation to approximately $1.66 billion from the previous estimate of $1.22 billion. The increase was primarily due to a change in the Oil Sands estimate from $1.08 billion to $1.47 billion, primarily reflecting increased estimated costs related to tailings projects and increased land reclamation. The majority of the costs in Oil Sands are projected to occur over a time horizon extending to approximately 2060. In 2007, these changes in the ARO estimate are anticipated to result in additional after-tax expenses of approximately $19 million. The discounted amount of our ARO liability was $808 million at December 31, 2006, compared to $543 million at December 31, 2005.

The greatest area of judgment and uncertainty with respect to our asset retirement obligations relates to our Oil Sands mining leases where there is a requirement to provide for land productivity equivalent to pre-disturbed conditions. To reclaim tailings ponds, we are using a process referred to as consolidated tailings technology. At this time, no ponds have been fully reclaimed using this technology, although work is underway. 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.

Employee Future Benefits

We provide a range of benefits to our employees and retired employees, including pensions and other post-retirement benefits. The determination of obligations under our 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 our 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

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	2006 Annual Report

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.

Employee Future Benefits Liability – Sensitivity Analysis

	Rate of Return						Rate of
	on Plan Assets			Discount Rate			Compensation Increase
	1%		1%	1%		1%	1%	1%
($ millions)	Increase		Decrease	Increase		Decrease	Increase	Decrease
Increase (decrease) to net periodic benefit cost	(5	)	5	(18	)	21	9	(8	)
Increase (decrease) to benefit obligation	—		—	(136	)	161	35	(31	)

Health care costs comprise a significant element of our post-retirement benefit obligation and is an area where there is increasing cost pressure due to an aging North American population. We have assumed a 9.5% annual rate of increase in the per capita cost of covered health care benefits for 2006, with an assumption that this rate will decrease by 0.5% annually, to 5% by 2015, and remain at that level thereafter.

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

	1%	1%
($ millions)	Increase	Decrease
Increase (decrease) to total of service and interest cost components of net periodic post-retirement health care benefit cost	1	(1	)
Increase (decrease) to the health care component of the accumulated post-retirement benefit obligation	16	(13	)

Property, Plant and Equipment

We account for our Oil Sands in-situ and NG exploration and production activities using the “successful efforts” method. This policy was selected over the alternative of the full-cost method because we believe it provides more timely accounting of the success or failure of exploration and production activities.

The application of the successful efforts method of accounting requires management to determine the proper classification of activities designated as developmental or exploratory, which then 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 (“written off”) or partially removed (“written down”) in our records and reported as part of Oil Sands and NG DD&A expenses in the Consolidated Statements of Earnings.

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

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The remainder of our plant and equipment are depreciated on a straight-line basis over the estimated useful life of the assets. 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 our Oil Sands base operations and our Firebag operations are not based on recorded reserves as we have access to other undeveloped properties, and bitumen feedstock from third parties, as well as the ability to provide processing services for other producers’ bitumen. Firebag and NG property costs are depleted on a unit of production (UOP) basis. UOP amortization is used where that method better matches the asset utilization with the production associated with the asset. 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.

We determine 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 our 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 of our business segments with the majority of the impact being in Oil Sands.

We also continuously look at ways to further utilize technological advancements and opportunities for future growth. The classification of research and development costs as either capital or expense is dependent upon specific criteria, including production feasibility, available resources and management commitment.

Control Environment

Based on their evaluation as of December 31, 2006, our Chief Executive Officer and Chief Financial Officer concluded that our 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 us in reports that we file or submit under the Exchange Act is recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms. In addition, other than as described below, as of December 31, 2006, there were no changes in our internal control over financial reporting that occurred during 2006 that have materially affected, or are reasonably likely to materially affect, our internal control over financial reporting. We will continue to periodically evaluate our disclosure controls and procedures and internal control over financial reporting and will make any modifications from time to time as deemed necessary.

During 2006, we largely completed the implementation of an enterprise resource planning (ERP) system in all of our businesses to facilitate our growth plan. We believe we took the necessary steps to monitor and maintain appropriate internal control over financial reporting during this transition period. These steps included 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, 2006, the company’s internal control over financial reporting was found to be operating free of any material weaknesses.

Change In Accounting Policies

Non-monetary Transactions

On January 1, 2006, the company prospectively adopted The Canadian Institute of Chartered Accountants (CICA) Handbook section 3831 “Non-monetary Transactions.” The standard requires all non-monetary transactions to be measured at fair value (if determinable) unless future cash flows are not expected to change significantly as a result of a transaction or the transaction is an exchange of a product held for sale in the ordinary course of business. The company was required to record the effects of an existing contract at Oil Sands that exchanges off-gas produced as a by-product of the upgrading operations for natural gas. An equal amount of revenues for the sale of the off-gas and purchases of crude oil and products for the purchase of the natural gas are recorded. The amount of the gross up of revenues and purchases of crude oil and products for the year ended December 31, 2006 was $126 million.

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Overburden Removal Costs

On January 1, 2006, the company retroactively adopted Emerging Issues Committee abstract (EIC 160) “Stripping Costs Incurred in the Production Phase of a Mining Operation.” Under the new standard, overburden removal costs should be deferred and amortized only in instances where the activity benefits future periods, otherwise the costs should be charged to earnings in the period incurred. At Suncor, overburden removal precedes mining of the oil sands deposit within the normal operating cycle, and is related to current production. In accordance with the new standard, overburden removal costs are treated as variable production costs and expensed as incurred. Previously, overburden removal was deferred and amortized on a life-of-mine approach.

Recently Issued Canadian Accounting Standards

Financial Instruments/Other Comprehensive Income/Hedges

In 2005, the CICA approved Handbook section 3855 “Financial Instruments – Recognition and Measurement,” section 1530 “Comprehensive Income” and section 3865 “Hedges.” Effective January 1, 2007, these standards require the presentation of financial instruments at fair value on the balance sheet. These standards must be applied prospectively with an initial recognition adjustment to retained earnings and accumulated other comprehensive income.

For specific transactions identified as hedges, changes in fair value are recognized in net earnings or other comprehensive income based on the type and effectiveness of the individual instruments. Upon adoption of these standards the company’s presentation will be more aligned with the current U.S. GAAP reporting as outlined in note 18 to the consolidated financial statements.

Other comprehensive income will represent the foreign currency translation of self-sustaining subsidiaries, the fair value gains/losses of specific financial investments (available for sale) and the effective portion of gains/losses of cash flow hedges. Presentation of other comprehensive income will require a change in the presentation of the Consolidated Statements of Earnings, and result in a new Statement of Comprehensive Income.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following adjustments will be recorded to the balance sheet:

Financial assets	$26 million
Financial liabilities	$13 million
Retained earnings	$5 million
Cumulative foreign currency translation	$71 million
Accumulated other comprehensive loss	$63 million

No restatement of comparative balances is permitted.

The CICA has approved additional financial instrument and capital disclosure requirements. These new requirements will become effective on January 1, 2008.

Accounting Changes

In 2006, the CICA approved revisions to Handbook section 1506 “Accounting Changes.” Effective January 1, 2007, accounting policy changes are permitted only in the event a change is made within a primary source of GAAP, or where a change is warranted to provide more relevant and reliable information. All accounting policy changes are to be applied retrospectively, unless impracticable. Any prior period errors identified also require retrospective application. The revised standards will not impact net earnings or financial position.

Stock-based Compensation

On July 6, 2006, the Emerging Issues Committee of the CICA approved an abstract (EIC 162) addressing the recognition of stock-based compensation expenses for employees eligible to retire prior to the vesting date of any award(s) issued. The abstract requires that the compensation expense be recognized over the term until the employee is eligible to retire, when earlier than the award vesting date. If the employee is eligible to retire at the time of grant, the award is to be expensed immediately. The abstract was applied retrospectively, effective December 31, 2006. No material adjustment was required in applying this standard.

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2006 Annual Report

Oil Sands

Located near Fort McMurray, Alberta, our Oil Sands business forms the foundation of our growth strategy and represents the most significant portion of our assets. The Oil Sands business recovers bitumen through mining and in-situ development and upgrades it into refinery feedstock, diesel fuel and byproducts. Our marketing plan also allows for strategic sales of bitumen when market conditions are favourable.

Oil Sands strategy focuses on:

•Acquiring long-life 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, continued focus on operational excellence and work site safety.

•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.

•Pursuing new technology applications to increase production, mitigate costs and reduce environmental impacts.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2006	2005		2004
Revenue	7 407	3 965		3 640
Production (thousands of bpd)	260.0	171.3		226.5
Average sales price ($/barrel)	68.03	53.81		42.28
Net earnings	2 824	976		970
Cash flow from operations (1)	3 902	1 878		1 734
Total assets	13 692	11 648		9 000
Cash used in investing activities	2 230	1 882		1 039
Net cash surplus (deficiency)	2 098	(274	)	719
Sales mix (light/heavy mix)	53/47	54/46		63/37
Cash operating costs ($/barrel) (1)	21.70	24.55		15.15
ROCE (%) (2)	53.7	22.7		22.6
ROCE (%) (3)	40.4	16.3		18.5

(1)Non-GAAP measure. See page 58.

(2)Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 58.

(3)Includes capitalized costs related to major projects in progress. See page 58.

2006 Overview

•Oil Sands recorded significantly higher production and sales volumes during 2006, following the September 2005 completion of recovery work to repair portions of the facilities damaged in a January 2005 fire, and the subsequent expansion of synthetic crude oil production capacity (to 260,000 bpd from 225,000 bpd).

•In November, the Alberta Energy and Utilities Board (EUB) approved Suncor’s application to build a third oil sands upgrader, designed to increase our production to 500,000 to 550,000 bpd in the 2010 to 2012 time frame. The EUB also conditionally approved our application to proceed with our proposed North Steepbank mine extension.

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	2006 Annual Report

•Construction continued on the estimated $2.1 billion project that, when complete in 2008, is expected to increase upgrading capacity to 350,000 bpd. The centrepiece of this expansion is the addition of a third coker to Upgrader 2. The project remains on schedule and within budget projections. See page 27.

•Commercial operations for Stage 2 of our Firebag in-situ operations commenced as expected during the first quarter of 2006.

•In January 2007, Suncor commissioned new cogeneration facilities at its in-situ operations. A related expansion of in-situ production capacity is expected to be completed in 2007.

Analysis of Net Earnings

Net earnings were $2,824 million in 2006 compared to $976 million in 2005 (2004 – $970 million). The increase in net earnings was mainly the result of increased production and sales volumes reflecting the October 2005 production capacity expansion to 260,000 bpd and reduced production in 2005 as a result of the fire in January of that year, coupled with higher benchmark WTI prices in 2006. Net earnings also increased during 2006 as a result of the reduction of federal and Alberta provincial income tax rates. These positive impacts were partially offset by higher royalty expense resulting from higher net sales volumes and commodity prices, higher operating expenses, and increased insurance premium expense (a portion of which was paid to our self-insurance entity and is fully offset in the corporate segment with no impact on consolidated results).

Oil Sands average production was 260,000 bpd in 2006, compared to 171,300 bpd in 2005 (including bitumen sold to third parties). Sales volumes in 2006 averaged 263,100bpd compared with 165,300 bpd in 2005. Higher sales volumes increased 2006 net earnings by $1,461 million. Production and sales volumes were significantly higher in 2006 due largely to the completion of recovery work relating to the January 2005 fire, and the production capacity expansion to 260,000 bpd.

Sales volume mix of high value diesel fuel and sweet crude products remained relatively consistent year over year (2006 – 53%; 2005 – 54%). Operating issues, plant maintenance activities and the sale of minor amounts of bitumen directly to market have impacted this mix.

Sales price realizations averaged $68.03 per barrel in 2006 (with no pretax hedging losses) compared with $53.81 per barrel in 2005 (including the impact of pretax hedging losses of $535 million). The average sales price realization was favourably impacted by the absence of hedging losses and stronger WTI benchmark crude oil prices, partially offset by widening differentials for synthetic crude oil, negative impacts on sour crude oil prices due to sales of more sour crude blends at the U.S. Gulf Coast, and by a higher average Cdn$/US$ exchange rate. As crude oil is sold based on U.S. dollar benchmark prices, the increased average Cdn$/US$ exchange rate decreased the Canadian dollar value of crude oil products.

The net impact of the above pricing factors increased net earnings by $955 million in 2006.

Bridge Analysis of Net Earnings

($ millions)

Net Fire Proceeds

In 2006, we recognized $436 million in insurance proceeds (2005 – $572 million), net of the write-off of damaged assets and related expenses. During 2006, we reached final settlement on all our insurance claims relating to the January 2005 fire. This included $92 million (2005 – $115 million) from our property loss policy and $385 million

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2006 Annual Report

Production

Year ended December 31 (thousands of bpd)	02	03	04	05	06
	205.8	216.6	226.5	171.3	260.0

(2005 – $594 million) in proceeds from our Business Interruption policies. For further discussion of our insurance activities during the year, see page 26.

Cash Expenses

Cash expenses, which include purchases of crude oil and products, operating, selling and general expenses, transportation and other costs, exploration expenses, and taxes other than income taxes, increased to $2,497 million from $1,629 million in 2005 (2004 - $1,431 million). Expenses were higher year over year due to the following factors:

•Higher total production and sales levels.

•Higher costs associated with unplanned maintenance, including an increase in the purchases of crude oil and products to meet plant and customer demands during maintenance outages.

•Increased transportation costs primarily due to increased volumes shipped out of the Fort McMurray area, and the increased shipments of Oil Sands sour crude blends to the U.S. Gulf Coast market.

•Higher labour costs, including costs associated with maintenance as well as contract labour costs related to managing operations to minimize impacts of the global shortage of heavy vehicle tires.

Overall, increased cash expenses reduced net earnings by $552 million.

Royalties

Oil Sands Alberta Crown royalties increased to $911 million in 2006 compared to $406 million in 2005 (2004 – $407 million). The higher royalty expense reflects the impact of higher sales volumes and commodity prices during 2006. Alberta Oil Sands Crown royalties are subject to change as policies arising from the government’s position are finalized and audits of 2006 and prior years are completed. Changes to the estimated amounts previously recorded will be reflected in our financial statements on a prospective basis and may be significant. For a further discussion on Crown royalties, see page 29.

Non-cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $385 million from $330 million in 2005 (2004 – $299 million). The increase was primarily due to the inclusion of newly commissioned upgrading facilities and Firebag Stage 2 operations in our depreciable cost base, during the fourth quarter of 2005. Higher non-cash expenses decreased net earnings by $40 million.

A change in accounting policy for certain non-monetary transactions (see page 41) resulted in certain natural gas costs and offsetting revenues, previously not recorded, being recorded in 2006. The amounts reflected in revenue and expense for 2006 totaled $126 million. There was no impact to net earnings or cash flow from operations.

Tax Adjustments

In the second quarter of 2006, reductions to the federal and Alberta provincial income tax rates resulted in a $429 million increase in the net earnings of the Oil Sands segment. These adjustments reduced Oil Sands opening future income tax balances.

Cash Operating Costs per Barrel

Effective January 1, 2006, cash operating costs per barrel, before commissioning and start-up costs, reflect a change in accounting policy to expense overburden costs as incurred (see page 42), as well as the inclusion of research and development costs. The change in accounting policy for overburden resulted in higher cash costs and lower non-cash costs. Therefore, recorded cash operating costs per barrel have increased, but total operating costs were not significantly impacted. Cash operating costs per barrel now reflect total Oil Sands operations including mining and in-situ production costs. In the past, operating costs per barrel for base (mining and upgrading) operations and in-situ operations were disclosed separately. All comparative balances have been retroactively restated for these changes in all 2006 Reports to Shareholders.

Cash operating costs increased to $2,057 million in 2006 from $1,536 million in 2005, as a result of higher maintenance activities, increased labour expenses and insurance related expenses. However, due to these costs being applied to significantly more barrels of production, cash operating costs on a per barrel basis decreased to $21.70 in 2006 from $24.55 in 2005. Refer to page 58 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

046	Suncor Energy Inc.
	2006 Annual Report

Bridge Analysis of Net Cash Surplus (Deficiency)

($ millions)

Net Cash Surplus (Deficiency) Analysis

Cash flow from operations was $3,902 million in 2006 compared to $1,878 million in 2005 (2004 – $1,734 million). The increase was primarily due to the same factors that impacted net earnings, excluding the impact of depreciation, depletion and amortization, and the revaluation of future tax balances resulting from the reduction of federal and Alberta provincial income tax rates.

Cash flow used in investing activities increased to $2,230 million in 2006 from $1,882 million in 2005 (2004 – $1,039 million). During 2006, capital spending related primarily to continued progress on the Coker Unit, Firebag in-situ, and Voyageur projects (see “Expansion to 500,000 bpd to 550,000 bpd” below). In addition, during the fourth quarter of 2006 we acquired two separate gross overriding royalty interests relating to a specific land lease, for cash consideration totaling approximately $174 million.

Outlook

Our Oil Sands operations continue to be the focus of our business strategy. In 2007, we anticipate Oil Sands production will average 260,000 to 270,000 bpd from our existing upgrading assets including bitumen sold directly to the market. Our future plans for Oil Sands remain focused on activities and investments anticipated to increase production, identify cost improvements and improve environment, health and safety performance.

For 2007, we have budgeted capital spending of approximately $4.4 billion, of which $900 million is slated for sustaining projects with the remainder earmarked for growth. Approximately $1 billion is allotted to project spending towards the goal of increasing production to 350,000 bpd in 2008, with the remaining $2.5 billion directed toward projects to support the Company’s goal of producing more than half a million barrels per day in the 2010 to 2012 time frame.

Expansion to 350,000 bpd

Work to increase production capacity to 350,000 bpd in 2008 continues, and these efforts are proceeding on schedule. During 2007, construction is planned to continue on the Coker Unit and Firebag expansion projects. As a result of this ongoing construction, a 50 day shutdown of Upgrader 2 is planned for 2007 to enable key tie ins for the project. The company intends to take advantage of this planned shutdown to perform necessary maintenance activities. Upgrader 1 is expected to continue to operate at normal capacity during the shutdown. For an update on the progress of these significant capital projects, see page 27.

In addition to our plans to expand our proprietary sources of bitumen supply, incremental bitumen to feed expanded upgrading capacity is also expected to be provided under a processing agreement between Suncor and Petro-Canada, expected to take effect in 2008. Under the agreement, Oil Sands will process a minimum of 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, we will sell an additional 26,000 bpd of our proprietary sour crude oil production to Petro-Canada. Both the processing and sales components of the agreement are for a minimum 10-year term.

Expansion to 500,000 bpd to 550,000 bpd

In November 2006, the EUB approved our application to construct a third oil sands upgrader, a critical component of our Voyageur strategy, which targets a further expansion of Oil Sands production to 500,000 to 550,000 bpd in 2010 to 2012. The EUB has also conditionally approved our application to develop the North Steepbank mine extension, which is expected to replace bitumen supply from depleted mining leases. Both projects are expected to advance development plans and cost estimates to a level appropriate to seek Board of Directors approval in 2007.

Suncor Energy Inc.	047
2006 Annual Report

In addition to the planned third upgrader and extension of the Steepbank mine, Suncor’s Voyageur strategy also includes the development of Stages 3 to 6 of in-situ bitumen supply from our Firebag leases and infrastructure related to the expansion including an overpass connecting planned facilities on the west side of Highway 63 to existing assets on the east side of the road. As Suncor continues to develop its in-situ projects, we expect to seek Board of Directors approval for Firebag Stage 3 in 2007.

Suncor expects to apply in 2007 for permission to build and extend its mining area to Lease 23 (Voyageur South), west of our existing operations. Pending regulatory and Board of Directors’ approval, construction could begin as early as 2009 with mining operations starting in 2011. In addition to pursuing future bitumen supply, Suncor is in the initial stages of investigating future expansion of upgrading capacity. As part of this investigation, we have secured land options northeast of Edmonton, Alberta. There are no firm plans to develop this land, nor are there firm plans about the configuration of any potential future upgrading expansion.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect performance including, but not limited to, the following:

•Our ability to finance Oil Sands growth in a volatile commodity pricing environment. Also refer to “Liquidity and Capital Resources” on page 25.

•Our 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 (including housing, roads, services and schools), or higher prices for the products and services required to operate and maintain the operations. We continue 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.

•Ability to manage production operating costs. Operating costs could be impacted by inflationary pressures on labour, volatile pricing for natural gas used as an energy source in oil sands processes and planned and unplanned maintenance. We continue to address these risks through such strategies as application of technologies that help manage operational workforce demand, offsetting natural gas purchases through internal production, investigation of technologies that mitigate reliance on natural gas as an energy source, and carefully managed maintenance scheduling.

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

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

•Logistical constraints and variability in market demand, which can impact crude movements. These factors can be difficult to predict and control.

•Changes to royalty and tax legislation that could impact our business. While fiscal regimes in Alberta and Canada are generally stable relative to many global jurisdictions, royalty and tax treatments are subject to periodic review, the outcome of which is not predictable and could result in changes to the company’s planned investments, and rates of return on existing investments. (See page 29 for a discussion of anticipated changes).

•Our relationship with our trade unions. Work disruptions have the potential to adversely affect Oil Sands operations and growth projects. The Communications, Energy and Paperworkers Union Local 707 represents approximately 2,000 Oil Sands employees. The current collective agreement with the union expires on May 1, 2007.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Also refer to Suncor Overview, Risk Factors Affecting Performance on page 30.

048	Suncor Energy Inc.
	2006 Annual Report

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 us with a degree of protection from volatile market prices of natural gas purchased for internal consumption in our Oil Sands and downstream operations.

NG’s stragtegy focuses on:

•Building competitive operating areas.

•Improving base business efficiency, with a focus on operational excellence and work site safety.

•Developing new, low-capital business opportunities.

NG’s long-term goal is to achieve a sustainable return on capital employed (ROCE) ⁽²⁾ of 12% to 15% at mid-cycle prices. To offset 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)	2006		2005	2004
Revenue	578		679	567
Natural gas production (mmcf/day)	191		190	200
Average natural gas sales price ($/mcf)	7.15		8.57	6.70
Net earnings	109		155	115
Cash flow from operations (1)	281		412	319
Total assets	1 503		1 307	967
Cash used in investing activities	443		344	251
Net cash surplus (deficiency)	(189	)	63	67
ROCE (%) (2)	15.3		30.7	27.1

(1)	Non-GAAP measure. See page 58.
(2)	ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 58.

2006 Overview

•Natural gas production averaged 191 million cubic feet (mmcf) per day in 2006 compared to 190 mmcf/day in 2005. Company-wide purchases for internal consumption were approximately 170 mmcf/day during 2006. Production in 2006 was below initial targets due to shut-in production as a result of pipeline and processing facility constraints, delays in bringing new production on stream, and an increase in exploratory dry holes compared to 2005.

•During the first quarter of 2006, Suncor sold a 15% interest in the South Rosevear gas plant for proceeds of $12 million. We currently retain a 60.4% interest and continue to operate the plant.

Total Net	02	03	04	05	06
Proved Reserves
Year ended December 31
(millions of boe) (3)
Natural gas liquids and crude oil	10	8	8	7	7
Natural gas	86	76	74	75	71
Total	96	84	82	82	78
Production	02	03	04	05	06
Year ended December 31
(thousands of boe/d) (3)
Natural gas liquids and crude oil	3.9	3.7	3.5	3.2	3.0
Natural gas	29.8	31.2	33.3	31.6	31.8
Total	33.7	34.9	36.8	34.8	34.8

(3) For details on barrels of oil equivalent (boe), see page 18.

Suncor Energy Inc.	049
2006 Annual Report

Analysis of Net Earnings

NG net earnings were $109 million in 2006, compared to $155 million in 2005 (2004 – $115 million). The decrease in net earnings was due primarily to lower price realizations, higher seismic and dry hole costs, higher operational costs resulting from an inflationary marketplace, and higher depreciation, depletion and amortization (DD&A). The average realized price for natural gas was $7.15 per mcf in 2006, compared to an average of $8.57 per mcf in 2005. These negative factors were partially offset by the reduction in federal and Alberta provincial income tax rates that resulted in a $53 million increase in net earnings during 2006.

NG’s total 2006 production was 209 million cubic feet equivalent per day (mmcfe/d) in 2006, unchanged from the prior year.

Bridge Anaylsis of Net Earnings
($ millions)

Expenses

Royalties on NG production were $127 million ($10.00 per boe) in 2006, compared to $149 million ($11.72 per boe) in 2005 (2004 - $124 million; $9.22 per boe). The decrease was due to lower sales price realizations, reflecting lower benchmark commodity prices.

Operating costs were $107 million in 2006 compared to $93 million in 2005 (2004 - $100 million). The increased operating expenses were mainly a result of higher selling, general & administrative costs as well as higher lifting costs caused by the inflationary environment affecting the oil and gas industry in Alberta.

Exploration expenses increased to $82 million in 2006 from $46 million in 2005 (2004 – $38 million). Dry hole costs recognized in the year totaled $52 million, compared to $33 million in 2005. Seismic expenditures increased to $30 million during 2006, compared to $13 million in 2005.

DD&A expense was $152 million in 2006 compared to $130 million in 2005 (2004 - $115 million). The Increase was due to higher depletion rates associated with increased finding and development costs.

In total, the above noted items reduced net earnings by $35 million.

Lifting and	02	03	04	05	06
Administration Costs
Year ended December 31
($/boe) (1)
Administration	2.34	2.35	2.39	2.52	3.37
Lifting	3.15	3.48	3.84	4.95	5.08
Total	5.49	5.83	6.23	7.47	8.45

(1) For details on barrels of oil equivalent (boe), see page 18.

050	Suncor Energy Inc.
	2006 Annual Report

Net Cash Surplus (Deficiency) Analysis

NG’s net cash deficit was $189 million in 2006 compared with $63 million surplus in 2005 (2004 – $67 million surplus). Cash flow from operations decreased to $281million compared with $412 million in the prior year (2004 – $319 million), largely due to the same factors impacting earnings.

Cash used in investing activities increased to $443 million compared with $344 million in 2005 (2004 – $251 million) as a result of increased drilling and exploration activities offset by reduced expenditures on pipeline and facility construction.

Bridge Analysis of Net Cash Surplus (Deficiency)
($ millions)

Outlook

NG targets increased production of natural gas, natural gas liquids and crude oil from 209 mmcfe/d in 2006 to 215 to 220mmcfe/d in 2007 to offset our internal natural gas demands, maintain existing operations and support the company’s goal of expanding production by 3% to 5% per year.

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

To support these goals, we have budgeted $350 million in capital spending primarily for exploration and development in 2007.

Natural Gas Production vs. Purchases

Year ended December 31 (mmcf/d)

Risk Factors Affecting Performance

There are certain issues that we strive to manage that may affect performance of the NG business including, but 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 influence the cost of acquisitions and the willingness of competitors to allow farm-ins on prospects.

•The impact of market demand for labour and equipment, which in a heated exploration and development market could add to cost or cause delays to projects for NG and its competitors.

•Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in Canada and in the United States. These risks could add to costs or cause delays to or cancellation of projects.

•Risks and uncertainties associated with weather conditions, which can shorten the winter drilling season and impact the spring and summer drilling program with increased costs or reduced production.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

(1)Acquisition 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.

Suncor Energy Inc.	051
2006 Annual Report

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 our Sunoco-branded and joint venture operated service networks, we market products to retail customers in Ontario. The EM&R 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 our Oil Sands and Natural Gas operations. In 2006, EM&R completed construction of Canada’s largest ethanol production plant.

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.

•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.

•Increasing the profitability and efficiency of retail networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2006		2005		2004
Revenue	5 465		4 363		3 500
Refined product sales (millions of litres) Sunoco retail gasoline	1 678		1 656		1 665
Total	5 547		5 570		5 643
Net earnings breakdown:
Total earnings excluding energy, marketing and trading activities	54		30		68
Energy marketing and trading activities	22		11		12
Tax adjustments	10		—		—
Total net earnings	86		41		80
Cash flow from operations (1)	217		152		188
Total assets	2 829		1 955		1 321
Cash used in investing activities	512		433		198
Net cash deficiency	(382	)	(328	)	(21	)
ROCE (%) (2)	12.5		8.1		14.6
ROCE (%) (3)	7.4		5.2		13.6

(1) Non-GAAP measure. See page 58.

(2) Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 58.

(3) Includes capitalized costs related to major projects in progress. See page 58.

052	Suncor Energy Inc.
	2006 Annual Report

2006 Overview

•The first phase of our diesel desulphurization and oil sands integration project was completed in July 2006. This phase of the project enables us to produce ultra low sulphur diesel to meet the new regulatory requirements that came into effect June 30, 2006. Phase two of the project, modifications to allow integration of oil sands sour crude feedstocks, is targeted for completion in 2007. Labour shortages and material supply issues have put upward cost pressures on the overall project. The cost estimate for this project has been increased to $960 million, from $800 million.

•A significant planned shutdown at our Sarnia refinery was completed December 22, 2006. Additional capital work that was not included in the original shutdown plan resulted in an extension to completion timelines and higher than anticipated costs.

•On July 1, 2006, Suncor’s new ethanol facility began production. The facility, the largest of its kind in Canada, is expected to produce approximately 200 million litres of ethanol annually. The ethanol produced will be used for blending purposes in specific refined products and for sales to third parties.

Analysis of Net Earnings

EM&R results include the impact of Suncor’s third party energy marketing and trading activities that are discussed separately on page 53.

Bridge Analysis of Net Earnings
($ millions)

EM&R’s net earnings increased to $86 million in 2006 from $41 million in 2005 (2004 – $80 million). This increase was primarily due to higher refining margins, offset by lower refinery utilization resulting from the major planned shutdown during the fourth quarter of 2006 and lower retail margins. Net earnings also increased by $5 million as a result of reductions to EM&R’s opening future income tax balances (FIT) due to reductions in the federal and Alberta provincial income tax rates during 2006.

Volumes

Total sales volumes averaged 95,000 bpd (15,100 cubic metres per day) in 2006, comparable to the 96,000 bpd (15,200 cubic metres per day) in 2005. Total gasoline sales volumes in the Sunoco-branded retail network increased to 1,678 million litres in 2006 from 1,656 million litres in 2005. Average Sunoco-branded service station site throughput was unchanged from 2005, at approximately 6million litres per site in 2006. 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 18% in 2006 (2005 – 19%). Approximately 90% of EM&R’s refined products were sold to the Ontario market in 2006.

Refinery Utilization

Overall refinery utilization averaged 78% in 2006, compared with 95% in 2005. The reduction in refinery utilization was primarily due to specific operational issues and the extensive planned maintenance activities during 2006.

Suncor Energy Inc.	053
2006 Annual Report

Product Purchase Costs

Refined product purchase costs were higher in 2006 as a result of higher purchased volumes of refined products to meet requirements due to operational issues and the maintenance shutdown, along with higher refined product prices. Increased third party purchase costs decreased 2006 net earnings by $53 million.

Cash and Non-cash Operating Expenses

Overall, cash and non-cash operating expenses increased by $36 million after-tax in 2006 compared to 2005. Cash expenses increased by $19 million after-tax in 2006, primarily due to higher administrative costs. Non-cash expenses increased by $17 million after-tax in 2006, due to increased depreciation as a result of a higher depreciable asset base, following the completion of the diesel desulphurization and ethanol projects during the year.

Related Party Transactions

The Pioneer and UPI retail facilities joint ventures and the Sun Petrochemicals Company (SPC) joint venture are considered to be related parties to Suncor under GAAP. 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.

The following table summarizes our 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 third parties.

($ millions)	2006	2005	2004
Operating revenues
Sales to EM&R joint ventures:
Refined products	294	327	320
Petrochemicals	136	279	272

At December 31, 2006, amounts due from EM&R joint ventures were $20 million, compared to $22 million at December 31, 2005.

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 after-tax of $22 million in 2006 compared to net earnings of $11 million in 2005 (2004 – $12 million).

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. See page 33.

Net Cash Deficiency Analysis

EM&R’s net cash deficiency was $382 million in 2006 compared to a net cash deficiency of $328 million in 2005 (2004 – net cash deficiency of $21 million). Cash flow from operations was $217 million in 2006 compared to $152 million in 2005 (2004 – $188 million). The increase was due to the same factors impacting net earnings, excluding the revaluation of opening future tax balances resulting from the reduction in federal income tax rates in 2006. Net working capital increased by $87 million in 2006, compared to an increase of $47 million in 2005. The increase in net working capital is a result of a decrease in accounts payable liabilities and an increase to our refined product inventory.

Cash used in investing activities was $512 million in 2006 compared to $433 million in 2005 (2004 – $198 million). Capital expenditures in 2006 were mainly associated with the ongoing diesel desulphurization and oil sands integration project, and the completion of the new ethanol facility. Refinery capital maintenance expenditures also increased during 2006 consistent with the planned maintenance shutdown.

Bridge Analysis of Net Cash Deficiency
($ millions)

054	Suncor Energy Inc.
	2006 Annual Report

Outlook

Completion of the oil sands integration project at the Sarnia refinery, planned for the fourth quarter of 2007, is expected to enable us to process up to 40,000 bpd of oil sands sour crude blends. Tie in of new and modified equipment is expected to require a 65 day shutdown of portions of the facility.

Capital spending, including the completion of the oil sands integration project, is expected to be approximately $300 million in 2007.

Suncor is also investigating a potential expansion of our ethanol plant, near Sarnia. Public consultation began in late 2006. No capital costs or firm plans have yet been defined.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect the performance of the EM&R business that include, but are not limited to, the following:

•Management expects that fluctuations in demand and 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. 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. We believe that if the regulations are finalized as currently proposed, our new facilities for reducing sulphur in on-road diesel fuel should also allow us to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

Suncor Energy Inc.	055
2006 Annual Report

Refining and Marketing – U.S.A.

Refining and Marketing – U.S.A. (R&M) operates a 90,000 barrel per day (bpd) (approximately 14,300 cubic metre per day) capacity refinery in Commerce City, Colorado, and markets refined products to customers primarily in Colorado, including retail marketing through 43 company owned Phillips 66^®-branded retail stations in the Denver area. Assets also include a 100% interest in the 480-kilometre Rocky Mountain pipeline system, a 65% interest in the 140-kilometre Centennial pipeline system and a 100% interest in a products terminal in Grand Junction, Colorado.

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 our Oil Sands operations.

•Creating additional downstream market opportunities in the United States 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.

•Increasing the profitability and efficiency of our retail network.

HIGHLIGHTS

Summary of Results

Year ended December 31
(Cdn$ millions unless otherwise noted)	2006		2005		2004
Revenue	3 128		2 621		1 495
Refined product sales (millions of litres) Gasoline	2 727		2 517		1 627
Total	5 256		5 004		3 504
Net earnings	168		142		34
Cash flow from operations (1)	281		247		59
Total assets	1 379		1 235		518
Cash used in investing activities	275		385		171
Net cash deficiency	(9	)	(121	)	(71	)
ROCE (%) (2)	34.2		49.4		12.2
ROCE (%) (3)	22.6		28.9		11.1

(1) Non-GAAP measure. See page 58.

(2) Excludes capitalized costs related to major projects in progress. Return on capital employed (ROCE) for our operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 58.

(3) Includes capitalized costs related to major projects in progress. See page 58.

2006 Overview

•R&M’s diesel desulphurization project was completed in June 2006. This project enabled production of ultra low sulphur diesel to meet the new regulatory requirements that came into effect June 1, 2006. In addition to improving the refinery’s environmental performance, the project modifications enable the refining facility to process up to 15,000 bpd of oil sands sour synthetic crude oil.

056	Suncor Energy Inc.
	2006 Annual Report

Analysis of Net Earnings

R&M’s net earnings were $168 million in 2006 compared to $142 million in 2005 (2004 – $34 million). Earnings increased due to higher refining margins, higher sales volumes due in part to expansion through the acquisition and integration of our second Commerce City refinery in May 2005, and a stronger sales mix of higher value diesel fuel. These positive impacts were partially offset by increased depreciation, depletion and amortization (DD&A) costs after the completion of our diesel desulphurization and oil sands integration project during 2006.

Volumes and Refinery Utilization

Sales volumes increased in 2006 compared to 2005, primarily as a result of the May 2005 acquisition of our second Commerce City refinery (the Colorado Refining Company), which increased throughput capacity of our Commerce City refining facility to 90,000 bpd from 60,000bpd. This was offset by lower refinery utilization rates resulting from the planned maintenance shutdown in the first quarter of 2006. Refinery utilization was 92% in 2006 compared to 98% in 2005. After the planned maintenance was completed in the first quarter of 2006, utilization rates were comparable with the prior year.

Increased product purchases reduced net earnings by $45million. The higher volume of purchased refined products was primarily due to purchases of additional finished products to meet customer demands.

Bridge Analysis of Net Earnings
($ millions)

Cash and Non-cash Expenses

Increases in refinery cash expenses and non-cash expenses were primarily due to incremental costs associated with the acquisition and operation of the additional refinery capacity throughout 2006. As well, depreciation, depletion and amortization costs increased during 2006 following the completion of our diesel desulphurization and oil sands integration project that increased our depreciable cost base.

Net Cash Deficiency Analysis

R&M’s net cash deficiency was $9 million in 2006, compared to a deficiency of $121 million in 2005 (2004 – $71 million deficiency). The increase in cash flow from operations to $281 million in 2006 from $247 million in 2005 (2004 – $59 million) was impacted by the same factors that affected net earnings. Net working capital increased $15 million in 2006, compared to a decrease of $17 million in 2005 (2004 – $41 million decrease). The increase in 2006 was primarily due to an increase in our refined product inventory.

Cash used in investing activities was $275 million in 2006, compared to $385 million in 2005 (2004 – $171 million). Investing activities in 2006 were primarily related to costs associated with the diesel desulphurization and oil sands integration project.

Bridge Analysis of Net Cash Deficiency
($ millions)

Suncor Energy Inc.	057
2006 Annual Report

Outlook

R&M estimates capital spending of approximately $100 million (approximately US$85 million) in 2007, with planned maintenance shutdowns in progress in February and planned in October.

Risk Factors Affecting Performance

There are certain issues we strive to manage that may affect the performance of the R&M business including, but not limited to, the following:

•Continuing fluctuations in demand for refined products, margin and price volatility and market competitiveness, including potential new market entrants.

•There are certain risks associated with the execution of capital projects, including the risk of cost overruns. 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.

Additional risks, assumptions and uncertainties are discussed on page 60 under Forward-looking Statements. Refer to the Suncor Overview, Risk Factors Affecting Performance on page 30.

058	Suncor Energy Inc.
	2006 Annual Report

Non-GAAP Financial Measures

Certain financial measures referred to in this MD&A are not prescribed by Canadian 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. We include 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 Canadian 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 our consolidated financial statements.

For the year ended December 31			2006	2005		2004
Cash flow from operations ($ millions)	A		4 533	2 476		2 013
Weighted average number of common shares outstanding (millions of shares)	B		459	456		453
Cash flow from operations (per share)	A/B		9.87	5.43		4.44
ROCE
For the year ended December 31 ($ millions, except ROCE)			2006	2005		2004
Adjusted net earnings
Net earnings			2 971	1 158		1 076
Add: after-tax financing expenses (income)			26	(16	)	1
	D		2 997	1 142		1 077
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents			2 891	2 159		2 577
Shareholders’ equity			5 996	4 874		3 858
	E		8 887	7 033		6 435
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents			1 871	2 891		2 159
Shareholders’ equity			8 952	5 996		4 874
	F		10 823	8 887		7 033
Average capital employed	(E+F)/2=G		9 855	7 960		6 734
Average capitalized costs related to major projects in progress	H		2 476	2 175		1 030
ROCE (%)	D/(G-H	)	40.6	19.7		18.9

Suncor Energy Inc.	059
2006 Annual Report

Oil Sands Operating Costs – Total Operations

		2006			2005			2004
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		2 149			1 432			1 179
Less: natural gas costs and inventory changes		(312	)		(258	)		(181	)
Less: non-monetary transactions		(126	)		—			—
Accretion of asset retirement obligations		28			24			21
Taxes other than income taxes		36			29			28
Cash costs		1 775		18.70	1 227		19.60	1 047		12.60
Natural gas		276		2.90	307		4.90	197		2.40
Imported bitumen (net of other reported product purchases)		6		0.10	2		0.05	13		0.15
Total cash operating costs	A	2 057		21.70	1 536		24.55	1 257		15.15
In-situ (Firebag) start-up costs	B	21		0.20	7		0.10	24		0.30
Total cash operating costs after start-up costs	A+B	2 078		21.90	1 543		24.65	1 281		15.45
Depreciation, depletion and amortization		385		4.05	330		5.30	299		3.60
Total operating costs		2 463		25.95	1 873		29.95	1 580		19.05
Production (thousands of barrels per day)		260.0			171.3			226.5

Oil Sands Operating Costs – In-situ Bitumen Production Only (excluding upgrading costs)

		2006			2005 (1)			2004 (1)
(unaudited)		$ millions		$ /barrel	$ millions		$ /barrel	$ millions		$ /barrel
Operating, selling and general expenses		209			155			77
Less: natural gas costs and inventory changes		(103	)		(91	)		(39	)
Taxes other than income taxes		4			—			—
Cash costs		110		8.95	64		9.15	38		10.85
Natural gas		103		8.35	91		13.05	39		11.20
Total cash operating costs	A	213		17.30	155		22.20	77		22.05
In-situ (Firebag) start-up costs	B	21		1.70	7		1.00	24		6.85
Total cash operating costs after start-up costs	A+B	234		19.00	162		23.20	101		28.90
Depreciation, depletion and amortization		68		5.55	34		4.90	21		6.00
Total operating costs		302		24.55	196		28.10	122		34.90
Production (thousands of barrels per day)		33.7			19.1			12.7

(1)Firebag start-up costs have not been separately identified in past Annual Reports. We have segregated these costs for comparable information purposes to provide additional detail to the individual components of cash costs.

060	Suncor Energy Inc.
	2006 Annual Report

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,” “scheduled,” “intends,” “believes,” “projects,” “indicates,” “could,” “focus,” “vision,” “goal,” “proposed,” “target,” “objective,” “leap,” “strategic,” “slated,” “may,” “laying the groundwork,” “investigating,” “continue,” “hopes,” “strive,” 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; 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 and increase the 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; 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 (for example, the Government of Alberta’s current review of the Crown Royalty regime, and the Government of Canada’s current review of greenhouse gas emission regulations); the ability and willingness of parties with whom we have material relationships to perform their obligations to us; and the occurrence of unexpected events such as 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 at www.sedar.com and the United States Securities and Exchange Commission (SEC) at www.sec.gov. 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.