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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31,
2007, dated February 27, 2008

MANAGEMENT'S DISCUSSION AND ANALYSIS
February 27, 2008

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 48 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 46.

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 regulatory authorities 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 and is not incorporated by reference into this MD&A.

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, see the Significant Capital Project Update on page 18.

10 SUNCOR ENERGY INC. 2007ANNUAL REPORT

SUNCOR OVERVIEW AND STRATEGIC PRIORITIES

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. We operate three 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, located in western Canada, is a conventional exploration and development operation, focused primarily on the production of natural gas. Its natural gas production offsets Suncor's purchases for internal consumption at our oil sands operations.

•

Refining and marketing, Suncor's downstream operations located in Ontario and Colorado, produce and market the company's refined products to industrial, commercial and retail customers.

In addition to Suncor's integrated oil sands-focused business activities, the company is also investing in renewable energy opportunities. Suncor is a partner in four wind power projects and operates Canada's largest ethanol plant.

Suncor's strategic priorities are:

Operational:

•

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

•

Expanding oil sands mining, in-situ and upgrading facilities to increase crude oil production and improving reliability by providing flexible bitumen feed and upgrading options.

•

Integrating oil sands production into the North American energy market through Suncor's refineries and third-party refineries to reduce vulnerability to supply and demand imbalances.

•

Managing environmental and social performance by mitigating impact to air, water and 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.

•

Ensuring appropriate levels of debt and capital spending are in place to support growth in a fiscally responsible manner.

2007 Overview

•

Combined oil sands and natural gas production in 2007 was 271,400 barrels of oil equivalent (boe) per day, compared to 294,800 boe per day in 2006. Oil sands production averaged 235,600 barrels per day (bpd) in 2007, compared to 260,000 bpd in 2006. Oil sands cash operating costs averaged $27.80 per barrel during 2007, compared to $21.70 per barrel in 2006. Natural gas production averaged 215 million cubic feet equivalent (mmcfe) per day, compared to an average 209 mmcfe per day in 2006.

•

Suncor continued to make progress on plans to expand Upgrader 2 and increase production capacity to 350,000 bpd, with construction completion targeted in the second quarter of 2008 and ramp-up to full capacity expected in the fourth quarter. As of December 31, 2007, the project was 95% complete.

•

In July, Suncor filed a regulatory application for the Voyageur South mine extension. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility.

•

In Suncor's downstream operations, investments were made to integrate up to 40,000 bpd of oil sands sour crude into the company's Sarnia, Ontario refinery.

•

In September, Suncor commissioned its fourth wind farm. The 76-megawatt facility located near Ripley, Ontario is the company's largest wind power project.

•

Capital spending in 2007 totalled $5.4 billion. Net debt at year-end 2007 was $3.2 billion, compared to $1.8 billion at the end of 2006.

•

Suncor achieved a company-wide return on capital employed of 28.3% in 2007, compared to 40.7% in 2006 (excluding capitalized costs for major projects in progress).

SUNCOR ENERGY INC. 2007ANNUAL REPORT 11

SELECTED FINANCIAL INFORMATION

Annual Financial Data

Year ended December 31 ($ millions except per share)	2007	2006	2005
Revenues	17 933	15 829	11 129
Net earnings	2 832	2 971	1 158
Total assets	24 167	18 759	15 126
Long-term debt	3 811	2 363	2 984
Dividends on common shares	162	127	102
Net earnings attributable to common shareholders per share – basic	6.14	6.47	2.54
Net earnings attributable to common shareholders per share – diluted	6.02	6.32	2.48
Cash dividends per share	0.38	0.30	0.24

Outstanding Share Data

At December 31, 2007 (thousands)
Number of common shares	462 783
Number of common share options	27 000
Number of common share options – exercisable	7 276

Net Earnings  ⁽¹⁾
Year ended December 31
($ millions)

	07	06	05
•  Oil sands	2 434	2 783	957
•  Natural gas	25	106	155
•  Refining and marketing	345	235	174

Cash Flow
from Operations  ^(1),(2)
Year ended December 31
($ millions)

	07	06	05
•  Oil sands	3 092	3 917	1 916
•  Natural gas	248	281	412
•  Refining and marketing	580	443	363

Capital Employed  ^(1),(2),(3)
At December 31
($ millions)

	07	06	05
•  Oil sands	6 541	5 015	4 436
•  Natural gas	1 153	857	562
•  Refining and marketing	2 270	1 818	796

(1)	Excludes Corporate and Eliminations segment.
(2)	Non-GAAP measures.
(3)	Excludes major projects in progress.

12 SUNCOR ENERGY INC. 2007ANNUAL REPORT

CONSOLIDATED FINANCIAL ANALYSIS

This analysis provides an overview of our consolidated financial results for 2007 compared to 2006. For a detailed analysis, see the various business segment discussions.

Net Earnings

Our net earnings were $2.832 billion in 2007, compared with $2.971 billion in 2006 (2005 – $1.158 billion). Excluding the impacts of the reduction of federal and Alberta income tax rates, net insurance proceeds (relating to a January 2005 fire), unrealized foreign exchange gains on the company's U.S. dollar denominated long-term debt, and project start-up costs, earnings were $2.239 billion in 2007, compared to $2.350 billion in 2006 (2005 – $850 million). The decrease in net earnings primarily reflects the impact of scheduled and unscheduled maintenance that reduced crude oil production and increased operating expenses. The largest impacts on financial results were a scheduled 50-day maintenance shutdown to portions of Suncor's oil sands operation to tie in new facilities related to a planned expansion and a scheduled 120-day shutdown to portions of the Sarnia refinery to tie in new sour crude processing facilities. These impacts were partly offset by higher realized crude oil prices.

Net Earnings Components⁽¹⁾

Year ended December 31 ($ millions, after-tax)		2007		2006		2005
Net earnings before the following items:		2 239		2 350		850
	Impact of income tax rate reductions on opening future income tax liabilities	427		419		—
	Oil sands fire accrued insurance proceeds (2)	—		232		293
	Unrealized foreign exchange gains on U.S. dollar denominated long-term debt	215		—		31
	Project start-up costs	(49	)	(30	)	(16	)
Net earnings as reported		2 832		2 971		1 158

(1)

This table highlights 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.

Industry Indicators

(Average for the year)	2007	2006	2005
West Texas Intermediate (WTI) crude oil US$/barrel at Cushing	72.30	66.20	56.55
Canadian 0.3% par crude oil Cdn$/barrel at Edmonton	76.65	73.05	69.00
Light/heavy crude oil differential US$/barrel WTI at Cushing less Western Canadian Select at Hardisty	22.25	21.45	20.20
Natural gas US$/thousand cubic feet (mcf) at Henry Hub	6.90	7.25	8.55
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.60	7.00	8.50
New York Harbour 3-2-1 crack US$/barrel (1)	13.70	9.80	9.50
Exchange rate: US$/Cdn$	0.93	0.88	0.83

(1)

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

Revenues were $17.933 billion in 2007, compared with $15.829 billion in 2006 (2005 – $11.129 billion). The increase was primarily due to the following factors:

•

Energy marketing and trading revenues increased to $2.883 billion in 2007, compared to $1.582 billion in 2006. The increase is due primarily to a larger volume of crude oil traded and higher average crude oil prices.

•

A reduction in planned refinery maintenance in 2007 compared to 2006 led to increased refinery utilization and sales in our downstream operations. Downstream operations also benefited from stronger refining and retail margins reflecting supply constraints in the Ontario and U.S. Rocky Mountain regions.

•

Average crude oil prices were higher in 2007 than in 2006. A 9% increase in average U.S. dollar WTI benchmark prices increased the selling price of oil sands crude oil production. In addition, strengthening price realizations for our sweet and sour blends relative to WTI also increased our revenue.

Partially offsetting these increases were the following:

•

Oil sands production and sales volumes were lower during 2007, mainly as a result of the planned shutdown of Upgrader 2. The 50-day outage was

SUNCOR ENERGY INC. 2007ANNUAL REPORT 13

required to tie in new facilities related to our planned expansion of oil sands production capacity.

•

A 6% increase in the average US$/Cdn$ exchange rate negatively impacted realizations on our crude oil sales basket. Because crude oil is primarily sold based on U.S. dollar benchmark prices, a strengthening Canadian dollar produced a corresponding reduction in the Canadian dollar value of our products.

•

The absence of net insurance proceeds relating to a January 2005 fire at our oil sands operations (2006 – $436 million).

Overall, reduced production in our oil sands operations decreased revenues by approximately $634 million. Higher price realizations on our crude oil products increased total revenues by approximately $470 million.

The cost to purchase crude oil and crude oil products was $5.935 billion in 2007, compared to $4.678 billion in 2006 (2005 – $4.164 billion). The increase was primarily due to the following:

•

Higher benchmark crude oil prices. This had the largest impact on product purchases for our refining and marketing business, as WTI increased by more than US$6.00/bbl over the prior year.

•

Increased inputs of crude oil feedstock to meet higher demand from our refineries, and additional purchases of refined products to meet sales commitments during planned maintenance outages in our oil sands and downstream operations.

Operating, selling and general expenses were $3.375 billion in 2007 compared with $3.043 billion in 2006 (2005 – $2.437 billion). The primary reasons for the increase were:

•

An increase in the costs associated with maintenance activities.

•

Higher stock-based compensation expenses resulting from the launch of our new performance stock option plan in September 2007 and continued growth in our share price.

Transportation and other expenses were $198 million in 2007, compared to $212 million in 2006 (2005 – $152 million). The decrease in transportation costs was primarily due to reduced volumes shipped out of the Fort McMurray area.

Depreciation, depletion and amortization (DD&A) was $864 million in 2007, compared to $695 million in 2006 (2005 – $568 million). The increase primarily reflects the construction and commissioning of new operating units at both our oil sands operation and our Sarnia refinery.

Royalty expenses were $691 million in 2007, compared with $1,038 million in 2006 (2005 – $555 million). The decrease in 2007 was primarily due to an increase in capital expenditures incurred in our oil sands operations, lower sales volumes and also the absence of net insurance proceeds (relating to a January 2005 fire). These factors were partially offset by increased crude oil prices. For a discussion of Crown royalties, see pages 19 and 20.

Taxes other than income taxes were $648 million in 2007, compared to $595 million in 2006 (2005 – $529 million). The increase was primarily due to higher sales volumes subject to Canadian fuel excise taxes in our refining and marketing operations.

Financing income was $211 million in 2007, compared with expenses of $39 million in 2006 (2005 – income of $15 million). The increase in financing income was primarily due to the foreign exchange gains on our U.S. dollar denominated long-term debt. Although interest expense related to our long-term debt increased from the prior year due to additional debt issuance during 2007, it was all capitalized, resulting in no total interest expense in 2007, compared to $21 million in 2006. Capitalized interest was $189 million in 2007, compared to $129 million in 2006.

Income tax expense was $513 million in 2007 (15% effective tax rate), compared to $835 million in 2006 (21% effective tax rate) and $694 million in 2005 (37% effective tax rate). The decrease in the effective tax rate was primarily due to a decrease in statutory rates, an increase in the deductibility of Crown royalties, as well as an increase in the revaluation of opening future income tax liabilities due to the enactment of tax rate reductions. Income tax expense in both 2007 and 2006 included the effects of reductions in tax rates that reduced opening future income tax liabilities as follows:

14 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Impact of Tax Rate Changes on Segmented Earnings

	2007					2007	2006	2005
($ millions, increase (decrease) in earnings)	Oil Sands	Natural Gas	Refining and Marketing	Corporate and Eliminations		Total	Total	Total
Federal	413	39	17	(42	)	427	292	—
Alberta	—	—	—	—		—	127	—
	413	39	17	(42	)	427	419	—

Reflects fourth quarter 2007 federal rate reduction of 3.5%, second quarter 2007 federal rate reduction of 0.5%, second quarter 2006 federal rate reduction of 3.1% and second quarter 2006 Alberta rate reduction of 1.5%.

Excluding these adjustments, income tax expense in 2007 was $940 million (28% effective tax rate) and $1,254 million in 2006 (33% effective tax rate).

Corporate Earnings

After-tax net corporate earnings were $28 million in 2007, compared to expense of $153 million in 2006 (2005 – $128 million expense). Excluding the impact of group elimination entries, actual after-tax net corporate earnings were $31 million in 2007 (2006 – $147 million expense; 2005 – $139 million expense). The net earnings in the corporate segment in 2007, compared to net expense in 2006, were primarily due to the unrealized foreign exchange gains on our U.S. denominated long-term debt as a result of the stronger Canadian dollar. After-tax unrealized foreign exchange gains on our U.S. denominated long-term debt were $215 million in 2007, compared to nil in 2006 (2005 – gain of $31 million). In addition, the increase in future tax expense as a result of the revaluation of future income taxes was smaller in 2007 – an expense of $42 million in 2007, compared to an expense of $68 million in 2006. These factors were partially offset by an increase in stock-based compensation expense. Corporate had a net cash deficiency of $659 million in 2007, compared with $403 million in 2006 (2005 – $107 million). The additional deficiency in 2007 was primarily due to increases in working capital of $187 million.

Breakdown of Net Corporate Earnings (Expense)

Year ended December 31 ($ millions)	2007		2006		2005
Corporate earnings (expense)	31		(147	)	(139	)
Group eliminations	(3	)	(6	)	11
Total	28		(153	)	(128	)

Consolidated Cash Flow from Operations

Cash flow from operations was $3.805 billion in 2007, compared to $4.533 billion in 2006 (2005 – $2.476 billion). The decrease in cash flow from operations was primarily due to the same factors that impacted net earnings, as well as an increase in cash income taxes during 2007 compared to 2006.

Dividends

Total dividends paid during 2007 were $0.38 per share, compared with $0.30 per share in 2006 (2005 – $0.24 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 2007, the Board approved an increase in the quarterly dividend to $0.10 per share from $0.08 per share.

Quarterly Financial Data

		2007 Quarter ended				2006 Quarter ended
($ millions except per share)		Dec 31	Sept 30	June 30	Mar 31	Dec 31	Sept 30	June 30	Mar 31
Revenues		4 958	4 666	4 358	3 951	3 787	4 114	4 070	3 858
Net earnings		963	677	641	551	358	682	1 218	713
Net earnings attributable to common shareholders per share
	Basic	2.08	1.47	1.39	1.20	0.78	1.48	2.65	1.56
	Diluted	2.04	1.43	1.36	1.17	0.76	1.45	2.59	1.52

SUNCOR ENERGY INC. 2007ANNUAL REPORT 15

Variations in quarterly net earnings during 2007 and 2006 were due to a number of factors:

•

Oil sands production and sales volumes decrease during periods of planned and unplanned maintenance.

•

Changes in benchmark commodity prices throughout 2006 and 2007. WTI averaged US$72.30 per barrel (bbl) in 2007, compared to US$66.20/bbl in 2006.

•

Cash operating costs varied due to changes in oil sands production levels, the timing and amount of maintenance activities, and the price and volume of natural gas used for energy in oil sands operations.

•

Reductions in federal corporate tax rates during the second and fourth quarters of 2007 increased net earnings by $67 million and $360 million, respectively, and reductions in both the federal and Alberta corporate tax rates during the second quarter of 2006 increased 2006 net earnings by $419 million.

•

Insurance proceeds were received in the second and fourth quarters of 2006 of $205 million and $27 million after tax, respectively, related to a January 2005 fire at our oil sands operations.

•

Oil sands Crown royalties varied as a result of changes in crude oil commodity prices and the extent and timing of eligible capital and operating expenditures.

•

The continued strengthening of the Canadian dollar through 2007 unfavourably impacted the realized commodity prices on our products sold in U.S. dollars, reducing the Canadian dollar revenues earned. Changes in the exchange rate also led to unrealized gains on our U.S. dollar denominated long-term debt in 2007.

•

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 fluctuations have historically reflected higher demand for vehicle fuels and asphalt in summer and heating fuels in winter. Refining and retail margins strengthened in 2007, compared to 2006 as a result of tighter supply of refined products in both the Ontario and U.S. Rocky Mountain markets.

LIQUIDITY AND CAPITAL RESOURCES

Our capital resources consist 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 US$/Cdn$ exchange rates.

At December 31, 2007, our net debt (short and long-term debt less cash and cash equivalents) was $3.248 billion, compared to $1.849 billion at December 31, 2006. The increase in debt levels was primarily a result of increased capital spending to fulfill our growth strategies.

During the first quarter of 2007, the company repaid maturing $250 million of 6.80% Medium Term Notes using commercial paper borrowings. Also during the first quarter, the company issued 5.39% Medium Term Notes with a principal amount of $600 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on March 26, 2037. The net proceeds received were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

During the second quarter of 2007, the company issued 6.50% Notes with a principal amount of US$750 million under an outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds received were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

Also during the second quarter, the company's $300 million bilateral credit facility was amended and extended by one year to 2008 and the credit limit was increased by $30 million to $330 million total funds available. A $2 billion syndicated credit facility was renegotiated and extended by one year to have a five-year term expiring in June 2012 and the company's commercial paper program limit was increased by $300 million to $1.5 billion from $1.2 billion. Additionally, a $15 million revolving demand credit facility was renegotiated and increased by $15 million to $30 million.

16 SUNCOR ENERGY INC. 2007ANNUAL REPORT

During the third quarter of 2007, the company repaid $150 million of maturing 6.10% Medium Term Notes using commercial paper borrowings. Also during the third quarter, the company issued additional 6.50% Notes with a principal amount of US$400 million under our outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds received were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

Undrawn lines of credit at December 31, 2007 were approximately $1.6 billion. Suncor's current long-term senior debt ratings are A-, with a stable trend by Standard & Poor's; A(low), Under Review – Developing by Dominion Bond Rating Service; and A3, with a stable trend by Moody's Investors Service.

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 remaining at low levels. To manage fixed versus floating rate exposure, we have entered into interest rate swaps with investment grade counterparties. At December 31, 2007, we had $200 million of fixed-rate to variable-rate interest swaps (December 31, 2006 – $600 million).

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 maintaining our ability to manage project costs and debt levels.

We believe we will have the capital resources to fund our 2008 capital spending program of $7.5 billion and to meet current working capital requirements. If additional capital is required, we believe adequate additional financing will be available at commercial terms and rates. Suncor expects similar levels of company-wide capital spending over the next several years. (Actual spending is subject to change due to such factors as internal and external approvals and capital availability.)

We anticipate our growth plan will be financed through cash flow from operations, credit facilities and access to debt capital markets. Refer to the discussion under Risk Factors Affecting Performance on page 21 for additional factors that may have an impact on our ability to generate funds to support investing activities.

Aggregate Contractual Obligations

	Payments Due by Period
($ millions)	Total	2008	2009-2010 (aggregate)	2011-2012 (aggregate)	Later Years
Fixed-term debt and commercial paper (1)	3 747	522	—	500	2 725
Interest payments on fixed-term debt and commercial paper (1)	5 022	233	409	397	3 983
Capital leases	324	9	18	20	277
Employee future benefits (2)	612	43	99	113	357
Asset retirement obligations (3)	2 231	190	269	93	1 679
Non-cancellable capital spending commitments (4)	446	446	—	—	—
Operating lease agreements, pipeline capacity and energy services commitments (5)	7 310	330	770	792	5 418
Total	19 692	1 773	1 565	1 915	14 439

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 re-sold shortly after purchase, are one example of excluded items.

(1)

Includes $3,225 million of U.S. and Canadian dollar denominated debt that is redeemable at our option. Maturities range from 2011 to 2038. Interest rates vary from 5.39% to 7.15%. We entered into various interest rate swap transactions maturing in 2011 that resulted in an average effective interest rate in 2007 of 5.7% on $200 million of our Medium Term Notes. Approximately $522 million of commercial paper with an effective interest rate of 4.8% was issued and outstanding at December 31, 2007.

(2)

Represents the undiscounted expected funding by the company to its pension plans as well as benefit payments to retirees for other post-retirement 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 $446 million at the end of 2007. In addition to capital projects, we spend maintenance capital to sustain our current operations. In 2008, we anticipate spending approximately $1.5 billion 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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 17

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 19) 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, 2007, we were in compliance with all covenants and our debt ratings were investment grade.

Significant Capital Project Update

We spent $5.4 billion on capital and exploration expenditures in 2007, compared to $3.6 billion in 2006 (2005 – $3.2 billion). A summary of the progress on our significant projects under construction to support both our growth and sustaining needs is provided below. All projects listed below have received Board of Directors approval.

							Estimated % Complete
Project		Plan	Cost Estimate $ millions(1)	Estimate % Accuracy	Spent to Date		Engineering	Construction	Target Completion Date
Coker unit		Expected to increase production capacity by 90,000 bpd	2 100	+13/-7	2 120		100	95	Q2 2008
Steepbank extraction plant		Location and new technologies aimed at improving operational performance	850	+10/-10	320		96	25	2009
Naphtha unit		Increases sweet product mix	650	+10/-10	345		95	20	2009
North Steepbank mine expansion		Expected to generate about 180,000 bpd of bitumen	400	+10/-10	60		50	10	2009
Firebag sulphur plant(2)		Supports emission abatement plan at Firebag; capacity to support Stages 1-6	340	+10/-10	80		65	5	2009
Voyageur program:
	Firebag	Expansion of Firebag 3-6 is expected to increase bitumen supply.	9 000	+18/-13	1 440	(3)
		– Stage 3					75	20	2009
		– Stage 4(2)					25	—	2010
		– Stage 5(2)					10	—	2011
		– Stage 6(2)					—	—	2011
Voyageur program:
	Upgrader 3	Expected to increase production capacity by 200,000 bpd	11 600	+12/-8	1 075	(3)	20	1	2011 (4)

(1)

Excludes commissioning and start-up costs.

(2)

Pending regulatory approval.

(3)

Spending to date includes procurement of major project components. For Firebag Stage 3, procurement at year-end 2007 was 70% complete; for Stage 4, 45% complete; and for Stage 5, 2% complete. For Upgrader 3, procurement was 20% complete.

(4)

Construction completion targeted in 2011 with ramp-up to full capacity during 2012.

18 SUNCOR ENERGY INC. 2007ANNUAL REPORT

The previous table contains forward-looking information and users of this information are cautioned that the actual timing, amount of the final capital expenditures and expected results for each of these projects may vary from the plans disclosed in the table. The target completion dates and cost estimates are based on information and assumptions from the procurement, design and engineering phases of the projects. The more preliminary the project, the greater the range of uncertainty that is projected in connection with the project.

For a list of the material risk factors that could cause actual timing, amount of the final capital expenditures and expected results to differ materially from those contained in the previous table, please see pages 21 to 26. 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.

Guarantees, Variable Interest Entities and Off-Balance Sheet Arrangements

At December 31, 2007, we had various indemnification agreements with third parties, as described below.

We have a multiple-party securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million (2006 – $170 million) of accounts receivable having a maturity of 45 days or less. At December 31, 2007, no outstanding accounts receivable had been sold under the program (2006 – $170 million). Under the recourse provisions, we indemnify certain counterparties against credit losses, and in 2007 such indemnification did not exceed $42 million. A contingent liability has not 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, 2007, were $170 million and approximately $1,530 million, respectively. We recorded an after-tax loss of approximately $4 million on the securitization program in 2007 (2006 – $2 million; 2005 – $4 million).

We have agreed to indemnify holders of our outstanding U.S. dollar denominated debt securities 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.

In 1999, we entered into an equipment sale and leaseback arrangement with a Variable Interest Entity (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 January 1, 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. At December 31, 2007, the VIE did not have any assets or liabilities.

Oil Sands Crown Royalties

Under the current Province of Alberta generic oil sands royalty regime (the "Generic Regime"), Alberta Crown royalties for oil sands projects are currently 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 1% of R. The Alberta government has classified Suncor's current oil sands operations as two distinct "projects" for royalty purposes.

Royalties on our current Firebag in-situ project are under the Generic Regime, and assessed based on bitumen value. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will increase royalty rates under the Generic Regime to a sliding scale royalty of 25% – 40% of R-C, subject to minimum royalty of 1% – 9% of R, depending on oil price. In both cases, the sliding scale royalty would move with increases in WTI prices from Cdn$55 to the maximum rate at a WTI price of Cdn$120.

Royalties on our base oil sands mining and associated upgrading operations (the "base operations") are assessed on the R-C calculation as follows:

•

Continues to be based on upgraded product values until December 31, 2008 with the rates at 25% of R-C, subject to the 1% minimum royalty of R.

•

Commencing January 1, 2009, a bitumen-based royalty will apply from Suncor's 1997 option to transition to the Generic Regime. The royalty rates will remain the same, but will apply to a revised R-C, where R will be based on bitumen value and C would exclude substantially all upgrading costs.

•

Commencing January 1, 2010, pursuant to the Suncor Royalty Amending Agreement we entered into with the government of Alberta in January 2008, the new royalty rates in the Generic Regime described above will apply to the bitumen royalty for current production levels,

SUNCOR ENERGY INC. 2007ANNUAL REPORT 19

subject to a cap of 30% of R-C, and a minimum royalty of up to 1.2% of R (assuming the government enacts their proposed framework). In addition, the Suncor Royalty Amending Agreement provides Suncor with certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes, generally until 2016.

•

In 2016 and subsequent years, the royalty rates for all of our oil sands operations (our base operation and our Firebag in-situ project) will be the rates prescribed under the Generic Regime.

Anticipated Oil Sands Royalty Expense Based on Certain Assumptions

The table below shows the potential royalty payment at various WTI crude prices, for both mining and in-situ operations, as a percentage of gross revenues.

Oil Sands Mining and In-Situ Royalties

WTI Price/bbl US$	70	80	90
Natural gas (Alberta spot) Cdn$/mcf at AECO	6.71	6.98	7.22
Light/heavy oil differential of WTI at Cushing less Maya at the U.S. Gulf Coast US$	15.89	18.72	20.86
US$/Cdn$ exchange rate	0.95	1.00	1.05
Crown Royalty Expense (based on percentage of total oil sands revenue) %
2008 – Mining synthetic crude oil, in-situ bitumen (25% and 1% min)	9-10	9-10	10-11
2009 – Bitumen (mining old rates – 25% and 1% min; in-situ new rates)	7-8	8-9	9-10
2010 to 2012 – Bitumen (new rates – cap 30% for mining)	8-10	9-11	9-11

The foregoing table contains forward-looking information and users of this information are cautioned that actual Crown royalty expense may vary from the percentages or ranges disclosed in the table. The royalty percentages or ranges disclosed in the table were developed using the following assumptions: current agreements with the government of Alberta, royalty rates proposed by the government of Alberta, current forecasts of production, capital and operating costs, and the commodity prices and exchange rates described in the table. If WTI prices rise beyond $90, Suncor anticipates Firebag in-situ royalties may be higher than disclosed in the table.

The following material risk factors could cause actual royalty rates to differ materially from the rates contained in the foregoing table:

(i)

Pursuant to the new royalty framework, the government intends to establish a permanent generic "bitumen valuation methodology" (BVM) for determining the "R" related to bitumen. The Crown is consulting with stakeholders and independent advisors with a decision on the methodology anticipated by June 30, 2008. Final determination of that methodology may have an impact on royalties payable to the Crown;

(ii)

The government also announced its intention to assess and recommend improvements in its systems, structures and resources supporting the collection, verification and reporting of provincial royalties. This assessment is expected to be completed by March 31, 2008. Steps taken by the government thereafter may affect the calculation of royalties; and

(iii)

Changes in crude oil and natural gas pricing, production volumes, foreign exchange rates, and capital and operating costs for each oil sands project; changes to the Generic Regime by the government of Alberta; changes in other legislation and the occurrence of unexpected events all have the potential to have an impact on royalties payable to the Crown.

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.

Natural Gas Crown Royalties

Royalty rates on natural gas production are currently capped at 30% for gas discovered in 1974 or later and 35% for gas discovered prior to 1974. These rates are subject to reduction if gas prices drop below $3.70/Gigajoule ($3.89/mcf), a gas well qualifies for a deep gas royalty holiday incentive, or a gas well qualifies as a low productivity well. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will change royalty rates beginning in 2009. The announced framework is a sliding scale that is dependent on the production rate, depth of the well, and the market price for natural gas, up to a maximum royalty rate of 50%. If enacted as proposed, the new royalty framework would

20 SUNCOR ENERGY INC. 2007ANNUAL REPORT

negatively impact the economics of deep gas wells in the Alberta Foothills which may cause management to reduce drilling activity in this area.

Cash Income Taxes

The 2007 federal budget proposes to phase out the accelerated capital cost allowance that was originally intended to offset some of the risk associated with the large capital investment required to bring oil sands projects to production. The accelerated capital cost allowance will continue to be available for assets acquired before 2012 on major projects where major construction commenced before March 19, 2007. We believe Suncor's Voyageur expansion, targeted for completion in 2012, will fall under the current accelerated capital cost allowance provisions. If not, the accelerated capital cost allowance will be gradually phased out between 2011 and 2015.

Cash income taxes are sensitive to crude oil and natural gas commodity price volatility and the timing of recognition of capital expenditures for income tax purposes. Based on current forecasts of production, capital and operating costs, and the commodity prices and exchange rates described in the table "Oil Sands Mining and In-situ Royalties" on page 20, we anticipate our effective income tax rate to be within 2% of the statutory income tax rate for each respective year beyond 2007. Based on the enacted tax rates and assuming that there are no further changes to the current income tax regime, we estimate we will have cash income taxes of 30-50% of our effective tax rate during 2008 to 2010 inclusive. Thereafter, we do not anticipate any significant cash income tax until the middle of the next decade. Our outlook on cash income tax is a forward looking statement and users of this information are cautioned that actual cash income taxes may vary from our outlook.

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, credit market conditions, stakeholder support for growth plans, extreme weather, regional labour issues and other issues discussed within Risk Factors Affecting Performance 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 (AIF)/Form 40-F, filed with securities regulatory authorities. We are continually working to mitigate the impact of potential risks to our stakeholders. This process includes an entity wide-risk review. The internal review is completed annually to ensure all significant risks are identified and appropriately managed.

Commodity Prices and Exchange Rates

Our future financial performance remains closely linked to hydrocarbon commodity prices, which may be influenced by many factors including global and regional supply and demand, seasonality, worldwide political events and weather. These factors, among others, may result in a high degree of price volatility. For example, from 2005 to 2007 the monthly average price for benchmark WTI crude oil ranged from a low of US$46.85/bbl to a high of US$94.63/bbl. During the same three-year period, the natural gas AECO benchmark monthly average price ranged from a low of $4.45/mcf to a high of $12.74/mcf.

Crude oil prices are based on U.S. dollar benchmarks that result in our realized prices being influenced by the US$/Cdn$ 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 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.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 21

SENSITIVITY ANALYSIS ⁽¹⁾

						Approximate Change in
			2007 Average		Change	Cash Flow from Operations ($ millions)	After-Tax Earnings ($ millions)
Oil Sands
	Price of crude oil ($/barrel)(2)		74.01	US$	1.00	69	50
	Sweet/sour differential ($/barrel)		10.13	US$	1.00	30	22
	Sales (bpd)		234 700		1 000	13	9
Natural Gas
	Price of natural gas ($/mcf)(2)		6.32		0.10	5	4
	Sales (mmcf/d)		196		10	13	3
Consolidated
	Exchange rate: US$/Cdn$		0.93		0.01
		Effect on oil sands operations				51	36
		Effect on U.S. denominated long-term debt					(15	)
	Total exchange rate impact					51	21

(1)

The sensitivity analysis shows the main factors affecting Suncor's annual cash flow from operations and earnings based on actual 2007 operations. The table illustrates the potential financial impact of these factors applied to Suncor's 2007 results. A change in any one factor could compound or offset other factors.

(2)

Includes the impact of hedging activities.

Derivative Financial Instruments

Effective January 1, 2007, new accounting standards were implemented relating to financial instruments. For a more detailed discussion, see Change in Accounting Policies on page 32. Adoption of these changes did not significantly impact earnings.

We periodically enter into derivative contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. We also use physical and financial energy contracts, including swaps, forwards and options, to earn trading and marketing revenues.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Upon initial recognition, each financial asset and financial liability instrument is recorded at fair value, adjusted for any transaction costs.

Derivative contracts, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge each period, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings. If the derivative is designated as a cash flow hedge each period, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the related hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash flow hedges.

Commodity Hedging Activities To provide an element of stability to future earnings and cash flow, we have Board of Director approval to fix a price or range of prices for up to approximately 30% of our total planned production of crude oil for specified periods of time. 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.

Settlement of 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. 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. Cash received or paid offsets corresponding decreases or increases in our sales revenues or product purchase costs. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions in the Consolidated Statements of Earnings and Comprehensive Income. In 2007, there was a $3 million decrease in net earnings due to the settlement of crude oil hedges, compared to no impact in 2006 (2005 – decrease of $337 million).

22 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Crude oil hedge contracts outstanding at December 31, 2007 were as follows:

	Quantity (bpd)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Costless collars	10 000	59.85 - 101.06	216 - 365	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 US$/Cdn$ exchange rate fluctuates during the hedge period.

(c)

Original hedge term is for the full year.

In addition to our strategic crude oil hedging program, the company also uses derivative contracts to hedge risks related to sales of natural gas and refined products, and to hedge risks specific to individual transactions.

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.

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. We had the following interest rate swap transactions during 2007.

Description of Swap Transaction	Principal Swapped ($ millions)	Swap Maturity	2007 Effective Interest Rate	2006 Effective Interest Rate
Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.7%	5.2%
Swap of 6.80% Medium Term Notes to floating rates	250	2007	6.0%	6.0%
Swap of 6.10% Medium Term Notes to floating rates	150	2007	4.7%	5.3%

In 2007, these interest rate swap transactions reduced pretax financing expense by $4 million, compared to a reduction of $6 million in 2006 (2005 – $14 million reduction).

In addition to our interest rate swap contracts, the company also manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate swaps and foreign exchange forward contracts.

The net pretax loss associated with hedge ineffectiveness in 2007 was $1 million.

Fair Value of Hedging Derivative Financial Instruments The fair value of hedging derivative financial 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 unrealized gain (loss) on the contracts, were as follows at December 31:

($ millions)	2007		2006
Revenue hedge swaps and collars	(11	)	22
Fixed to floating interest rate swaps	8		16
Specific hedges of individual transactions	12		(4	)
Fair value of outstanding hedging derivative financial instruments	9		34

Energy Marketing and Trading Activities In addition to derivative contracts used for hedging activities, the company uses physical and financial energy derivatives to earn trading and marketing revenues. These trading activities are accounted for using the mark-to-market method, with the results reported as revenue and as energy marketing and trading expenses in the Consolidated Statements of Earnings and Comprehensive Income.

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

Net Pretax Earnings (Loss) ($ millions)	2007		2006
Physical energy contracts trading activity	21		41
Financial energy contracts trading activity	(3	)	(3	)
General and administrative costs	(4	)	(3	)
Total	14		35

SUNCOR ENERGY INC. 2007ANNUAL REPORT 23

The fair value of unsettled energy marketing and trading 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 unrealized gain (loss) on the contracts, were as follows at December 31:

($ millions)	2007		2006
Energy trading assets	18		16
Energy trading liabilities	21		13
Net energy trading assets (liabilities)	(3	)	3

The change in fair value of energy marketing and trading net assets during 2007 was as follows:

($ millions)	2007
Fair value of contracts at December 31, 2006	3
Fair value of contracts realized during 2007	29
Fair value of contracts entered into during the year	(56	)
Changes in values attributable to market price and other market changes	21
Fair value of contracts outstanding at December 31, 2007	(3	)

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 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:

($ millions)	2007	2006
Derivative contracts not accounted for as hedges	18	16
Derivative contracts accounted for as hedges	20	35
Total	38	51

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 of petroleum products and petrochemicals. Environmental assessments and regulatory approvals are required before initiating most new projects or undertaking significant changes to existing operations. We were issued a new 10-year operating approval in connection with our oil sands base operations in August 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 province;

•

manufacture, import, storage, treatment and disposal of hazardous or industrial waste and substances;

•

the need to reduce or stabilize various emissions to air and withdrawals of, 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; and

•

U.S. implementation of regulation or policy to limit its purchases of oil to oil produced from conventional sources.

Changes in environmental regulation could have a potentially adverse effect on our financial results 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

24 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 clean up costs and damages and the loss of important permits and licenses.

On March 8, 2007, the Alberta government introduced the Climate Change and Emissions Management Amendment Act, which places intensity (emissions per unit of production) limits on facilities emitting more than 100,000 tonnes of carbon dioxide equivalent per year. Suncor's oil sands operations are subject to this legislation. The act calls for intensity reductions of 12% commencing July 1, 2007.

In compliance with this new legislation, Suncor filed applications in December 2007 to establish baseline intensities for our oil sands facility. In March 2008, Suncor must file compliance reports that show what actions the company took during the year to offset intensities. Mitigation options available to Suncor include internal emission reductions, utilizing offset projects or contributing to a government climate change emission management fund.

For the compliance period of July 1, 2007 to December 31, 2007, the compliance costs to Suncor are estimated at between $3 million and $5 million. Final costs will be determined with the company's March 2008 compliance report filing to the province.

The Ontario provincial and Colorado state governments are also in various stages of developing greenhouse gas management legislation and regulation. At this time, no such legislation has been tabled in any of these jurisdictions and any potential impacts are unknown.

In April 2007, the Canadian federal government introduced the Clean Air regulatory framework, which is expected to regulate both greenhouse gas emissions and air pollutants from industrial emitters. Suncor has been engaging in the ongoing consultations on this framework. In support of developing regulation, the federal government has required the submission of production, operations and emissions information for each of Suncor's operations by May 31, 2008. The financial impact of this proposed legislation will be dependent on the details of Clean Air Act regulations.

There remains uncertainty around the outcome and impacts of climate change and other environmental regulations. We continue to actively work to mitigate our environmental impact, including taking action to reduce greenhouse gas emissions, investing in renewable and alternate forms of energy such as wind power and biofuels, accelerating land reclamation, the installation of new emission abatement equipment and pursuing other opportunities such as carbon capture and sequestration.

Regulatory Requirements at Oil Sands Suncor is working to decrease emissions at our oil sands operations. At our in-situ operation, high emissions resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. Until regulators can be assured emissions are stable at compliant levels, production at the in-situ operation has been capped at approximately 42,000 barrels of bitumen per day. As a result, commissioning of units to increase the bitumen production capacity of Firebag Stages 1 and 2 by about 35% have been delayed. Suncor's production outlook for 2008 reflects this constraint. Suncor's planned $340 million Firebag sulphur plant is expected to play a role in managing sulphur emissions for existing and planned in-situ developments.

At Suncor's base plant we are taking steps to comply with an environmental protection order issued by Alberta Environment. The order relates to emissions at Suncor's oil sands plant that have exceeded air quality standards and which are resulting in increased odours from the operation. To correct the problem, Suncor is upgrading its emission control equipment and reducing discharges to the tailings ponds. The company has also introduced processing changes and is undertaking a more comprehensive air monitoring program.

Any additional regulatory requirements placed on us due to these, or other, matters could have a material effect on our business and results of operations.

Tailings Management Another area of risk for Suncor 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 our 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 the Millennium, Steepbank, and North Steepbank Extension mines, we have posted irrevocable letters of credit equal to approximately $227 million with Alberta Environment, representing security for the maximum reclamation liability in the period April 1, 2007 through March 31, 2008. 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 security for the estimated cost of our reclamation activity. This letter of

SUNCOR ENERGY INC. 2007ANNUAL REPORT 25

credit equalled $14 million at December 31, 2007 (2006 – $14 million). For more information about our reclamation and environmental remediation obligations, refer to Asset Retirement Obligations in the Critical Accounting Estimates section on page 30.

A new Mine Liability Management Program (MLMP) is under review by the Province of Alberta. The MLMP would involve increased reporting of progressive reclamation, measurement of MLMP assets against MLMP liabilities and measurement of reserve life. 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 involves stakeholder consultation, environmental impact assessments and public hearings, among other factors. Failure to obtain regulatory approvals, or failure to obtain them on a timely basis, could result in delays, abandonment, or restructuring of projects and increased costs, all of which could negatively impact future earnings and cash flow.

CRITICAL ACCOUNTING ESTIMATES

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. The following are the critical accounting estimates used in the preparation of our consolidated financial statements.

Reserves Estimates

As a Canadian issuer, we are subject to the reporting requirements of Canadian securities regulatory authorities, including the reporting of our reserves in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities ("NI 51-101"). 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 78.5% for proven reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proven reserves reflects historical operational levels. The 80% proved plus probable reserves yield rate reflects anticipated yield levels once operational performance issues have been addressed.

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 value of Alberta Crown, overriding, and freehold royalty burdens under constant December 31 pricing and our exercise of the option electing to transfer to a bitumen-based Crown royalty effective at 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 Crown royalty based on bitumen, rather than synthetic, crude oil. As there is currently no legislated methodology for determining bitumen value for Alberta Crown royalty purposes, bitumen value for determining royalties has been assumed to correspond to Firebag bitumen sales to our upgrader. However, determination of bitumen value for royalty purposes is currently under review by the Government of Alberta.

In October 2007, the Government of Alberta proposed changes to the royalty regime. In January 2008, Suncor entered into a Royalty Amending Agreement to transition to the new royalty framework assuming the government enacts their proposed changes. Neither the government's proposed changes nor our Royalty Amending Agreement have been reflected in the following reserve estimates. For a full discussion of our Crown royalties, see Oil Sands Crown Royalties and Natural Gas Crown Royalties on pages 19 and 20.

26 SUNCOR ENERGY INC. 2007ANNUAL REPORT

In addition to reporting our reserves in accordance with U.S. disclosure requirements, the exemption issued by Canadian securities regulatory authorities permits us to provide voluntary additional disclosure. We provide this additional voluntary disclosure to show aggregate proved and probable oil sands reserves, including both mining reserves and Firebag reserves. In our voluntary disclosure we report our aggregate reserves on the following basis:

•

Gross and net proved and probable mining reserves are consistent with required US mining disclosures, however the voluntary disclosure reflects normalized constant dollar cost and pricing assumptions. These assumptions use a posted benchmark oil price as at December 31, but apply a differential generally intended to represent a normalized annual average for the year ("Annual Average Differential Pricing"), rather than a point in time differential, in accordance with CSA Staff Notice 51-315 (reported as barrels of synthetic crude oil based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves and 80% for proved plus probable reserves); and

•

Gross and net proved and probable bitumen reserves from Firebag in-situ leases, evaluated based on Annual Average Differential Pricing. 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% for proved and proved plus probable reserves.

Accordingly, our voluntary disclosures of reserves from our Firebag in-situ leases will differ from our required U.S. disclosure in four 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;

(c)

include proved plus probable reserves, rather than proved reserves only under U.S. disclosure requirements; and

(d)

are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

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 significant for 2005 and 2007 reporting given the considerably lower constant price assumptions. At December 31, 2006, there was no difference arising from pricing. Refer to Voluntary Oil Sands Reserves and Resources Disclosure – Estimated Gross and Net Proved and Probable Oil Sands Reserves Reconciliations.

In addition to our required and voluntary reserves disclosures, we have also elected to disclose our best estimate remaining recoverable resources for both mining and in-situ at December 31, 2007. These disclosures follow the requirements in NI 51-101.

All of our reserves and resources have been evaluated as at December 31, 2007, by independent petroleum consultants, GLJ Petroleum Consultants Ltd. (GLJ). In reports dated February 19, 2008, for oil sands mining, and February 11, 2008, for oil sands in-situ (collectively referred to herein as "GLJ Oil Sands Reports"), GLJ evaluated our resources and our proved and probable reserves on our oil sands mining and Firebag in-situ leases pursuant to 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 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, project implementation commitments 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 3D seismic control (or 40-acre spacing without 3D 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 under way but have not yet received final approval from our Board.

In a report dated January 10, 2008 ("GLJ NG Report"), GLJ also evaluated our proved reserves of natural gas, natural gas liquids and crude oil (other than reserves from our

SUNCOR ENERGY INC. 2007ANNUAL REPORT 27

mining leases and the Firebag in-situ reserves) as at December 31, 2007.

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 undivided percentage 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, 2007, 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.

Required U.S. Oil and Gas and Mining Disclosure

Proved and Probable Oil Sands Mining Reserves

	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, 2006	1 709		1 507		634	564	2 343		2 071
Revisions of previous estimates	(1	)	103		106	149	105		252
Extensions and discoveries	–		–		–	–	–		–
Production	(74	)	(66	)	–	–	(74	)	(66	)
December 31, 2007	1 634		1 544		740	713	2 374		2 257

(1)

Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proved reserves, and 80% for proved plus probable reserves. The lower yield rate applied to proved reserves reflects historical operational levels that have fallen below management expectations. The 80% proved plus probable reserves yield rate reflects a return to management's target levels once operational performance issues have been addressed.

(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, freehold and overriding royalty burdens under constant December 31 pricing and incorporates our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009. Neither the current proposed Alberta royalty regime changes nor our Royalty Amending Agreement have been incorporated. If enacted, at current oil prices we expect our future royalty payments to increase and our net reserves to decrease. Refer to the Alberta Crown Royalties risk, as outlined in the Risk Factors section of our AIF.

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. 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

Constant cost and pricing as at December 31	Oil sands business: Firebag – crude oil (millions of barrels of bitumen) (2) (3)		Natural gas business: crude oil and natural gas liquids (millions of barrels)		Total (millions of barrels)		Natural gas business: natural gas (billions of cubic feet)
December 31, 2006	903		7		910		426
Revisions on previous estimates (4)	68		–		68		4
Improved recovery(5)	99		–		99		–
Purchases of minerals in place	–		–		–		19
Extensions and discoveries	–		–		–		33
Production	(13	)	(1	)	(14	)	(53	)
Sales of minerals in place	–		–		–		(1	)
December 31, 2007	1 057		6		1 063		428

(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. See Reliance on Exemptive Relief in our AIF.

(3)

We have the option of selling the bitumen production from these leases or upgrading the bitumen to synthetic crude oil.

(4)

Natural gas infill drilling included in total revisions for 2007 was 16 billion cubic feet (bcf), (2006 – 11 bcf; 2005 – 23 bcf).

(5)

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

28 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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, 2006, to December 31, 2007, based on the GLJ Oil Sands Reports.

Estimated Gross Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases (1), (2)					Firebag In-Situ Leases (1), (3)						Total Mining and In-Situ (3)
Millions of barrels of synthetic crude oil (1)	Proved		Probable	Proved & Probable		Proved		Probable		Proved & Probable		Proved & Probable
December 31, 2006	1 709		634	2 343		803		1 907		2 710		5 053
Revisions of previous estimates	(1	)	106	105		(17	)	(5	)	(22	)	83
Improved recovery	–		–	–		80		(66	)	14		14
Extensions and discoveries	–		–	–		–		–		–		–
Production	(74	)	–	(74	)	(11	)	–		(11	)	(85	)
December 31, 2007	1 634		740	2 374		855		1 836		2 691		5 065

Estimated Net Proved and Probable Oil Sands Reserves Reconciliation

	Oil Sands Mining Leases (1), (2)					Firebag In-Situ Leases (1), (3)						Total Mining and In-Situ (3)
Millions of barrels of synthetic crude oil (1)	Proved		Probable	Proved & Probable		Proved		Probable		Proved & Probable		Proved & Probable
December 31, 2006	1 507		564	2 071		722		1 639		2 361		4 432
Revisions of previous estimates	11		108	119		(15	)	(7	)	(22	)	97
Improved recovery	–		–	–		72		(60	)	12		12
Extensions and discoveries	–		–	–		–		–		–		–
Production	(66	)	–	(66	)	(11	)	–		(11	)	(77	)
December 31, 2007	1 452		672	2 124		768		1 572		2 340		4 464

(1)

Synthetic crude oil reserves are based upon a net coker, or synthetic crude oil, yield from bitumen of 78.5% for proven reserves, and 80% for proved plus probable reserves under oil sands mining leases and 80% for both proved reserves and proved plus probable reserves for Firebag in-situ leases. Virtually all of our bitumen from the oil sands mining leases is upgraded into synthetic crude oil. However, we have the option of selling the bitumen produced from our Firebag in-situ leases directly to the market where strategic opportunities exist. Accordingly, these bitumen reserves are converted to synthetic crude oil for aggregation purposes.

(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 based on 2007 Annual Average Differential Pricing assumptions in accordance with CSA Staff Notice 51-315 and reflects our exercised option to elect to transfer to a bitumen-based Crown royalty effective at the beginning of 2009. Neither the current proposed Alberta royalty regime changes, nor our Royalty Amending Agreement have been incorporated.

(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 four 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 to barrels of synthetic crude oil in this table for aggregation purposes only;

(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 Firebag in-situ leases as we believe this information is useful to investors, and allows us to aggregate our mining and our 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.

(d)

are evaluated based on 2007 Annual Average Differential Pricing assumptions, in accordance with CSA Staff Notice 51-315, versus Constant Cost and Pricing assumptions pursuant to U.S. disclosure requirements.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 29

Remaining Recoverable Resources ^(1)(2)(3)(4)

Suncor holds a 100% interest in its oil sands leases, all located near Fort McMurray in the Athabasca region of Alberta. Based upon independent evaluations conducted by GLJ effective December 31, 2007, our best estimate of remaining recoverable synthetic crude oil resources are as follows:

(1)

As U.S. companies are prohibited from disclosing estimates of probable reserves for non-mining properties and resources for oil and gas or mining properties, Suncor's resource estimates will not be comparable to those made by U.S. companies.

(2)

Remaining Recoverable Resources are the sum of reserves and contingent resources.

(3)

Contingent Resources are those quantities of petroleum estimated, as of a given date, to be potentially recoverable from known accumulations using established technology or technology under development, but which are not currently considered to be commercially recoverable due to one or more contingencies.

(4)

Best Estimate Resources is considered to be the best estimate of the quantity of resources that will actually be recovered. It is equally likely that the actual remaining quantities recovered will be greater or less than the best estimate. The best estimate of potentially recoverable volumes is generally prepared independent of the risks associated with achieving commercial production.

The contingent resources are not classified as reserves due to the absence of a commercial development plan that includes a firm intent to develop within a reasonable timeframe, and in some cases due to higher uncertainty as a result of lower core-hole drilling density. Our Voyageur South development area, for which we submitted a regulatory application in 2007, is part of our mining contingent resources. Significant mining contingent resources are also associated with our Audet leases, located north of our Firebag leases and immediately adjacent to leases proposed for mining development by other operators. All of our in-situ leases are associated with our Firebag leases. While we consider the contingent resources to be potentially recoverable under reasonable economic and operating conditions, there is no certainty that it will be commercially viable to produce any portion of them.

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 every year-end, and incremental increases are discounted to present value using a credit-adjusted risk-free discount rate (2007 – 6.0%; 2006 – 5.5%). 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 and Comprehensive Income 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 30 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 ARO during 2007, we increased our estimated undiscounted total obligation to $2.231 billion from the previous estimate of $1.657 billion. The increase was primarily due to a change in the oil sands estimate to $1.941 billion from $1.473 billion, primarily reflecting increased estimated costs related to pond reclamation. The majority of the costs in oil sands are projected to occur over a time horizon extending to approximately 2060. In 2008, these changes in the ARO estimate are anticipated to result in additional after-tax expenses of approximately $24 million. The discounted amount of our ARO liability was $1.072 billion at December 31, 2007, compared to $808 million at December 31, 2006.

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

30 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 Comprehensive Income. The accrued benefit liability is reported as part of accrued liabilities and other in the Consolidated Balance Sheets.

The assumed rate of return on plan assets considers the current level of expected returns on the fixed income portion of the plan assets portfolio, the historical level of risk premium associated with other asset classes in the portfolio and the expected future returns on each asset class. The discount rate assumption is based on the year-end interest rate on high-quality bonds with maturity terms equivalent to the benefit obligations. The rate of compensation increases is based on management's judgment. The accrued benefit obligation and net periodic benefit cost for both pensions and other post-retirement benefits may differ significantly if different assumptions are used. The impact of a 1% change in the assumptions at which pension benefits and other post-retirement benefit liabilities could be effectively settled is disclosed in note 9 to the consolidated financial statements on page 75.

Property, Plant and Equipment

We account for our in-situ and natural gas 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 exploration expenses in the Consolidated Statements of Earnings and Comprehensive Income. 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. 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 properties are assessed by management to be fully or partially impaired, the book value of the properties is reduced to fair value and either completely removed ("written off") or partially removed ("written down") in our records and reported as part of depreciation, depletion and amortization expenses in the Consolidated Statements of Earnings and Comprehensive Income.

Negative revisions in natural gas and in-situ reserves estimates will result in an increase in depletion expenses.

Control Environment

Based on their evaluation as of December 31, 2007, 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 Securities and Exchange Commission rules and forms. In addition, as of December 31, 2007, there were no changes in our internal control over financial reporting that occurred during 2007 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.

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, 2007, the company's internal controls were found to be operating free of any material weaknesses.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 31

CHANGE IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007, the company adopted The Canadian Institute of Chartered Accountants (CICA) Handbook section 3855 "Financial Instruments, Recognition and Measurement", section 3865 "Hedging", section 1530 "Comprehensive Income" and section 3251 "Equity".

Sections 3855 and 3865 establish accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. Section 1530 establishes standards for reporting and disclosure of comprehensive income, where comprehensive income refers to all changes in equity (net assets) during a reporting period except those resulting from investments by owners and distributions to owners, and section 3251 establishes standards for the presentation of equity and changes in equity during the reporting period.

The company's financial instruments consist of cash and cash equivalents, accounts receivable, derivative contracts, substantially all current liabilities (except for the current portions of asset retirement and pension obligations), and long-term debt. Unless otherwise noted, carrying values reflect the current fair value of the company's financial instruments.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and/or appropriate valuation methodologies; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. Upon initial recognition, each financial asset and financial liability instrument is recorded at fair value, adjusted for any transaction costs.

Derivative contracts, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings each period. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash flow hedges.

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations.

The company's fixed-term debt is accounted for under the amortized cost method with the exception of the portion of debt that has related financial hedges which is accounted for under the fair value hedge methodology. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized.

The company's equity section will now contain a new caption "Accumulated Other Comprehensive Income". In addition to containing the effective portions of the gains/losses on our cash flow hedges, accumulated other comprehensive income will also contain the cumulative foreign currency translation adjustment of our foreign operations.

Upon implementation and initial measurement under the new standards at January 1, 2007, the following increases (decreases), net of income taxes, were recorded to the Consolidated Balance Sheet:

($ millions)
Financial Assets (1)	42
Financial Liabilities (1)	29
Retained Earnings (2)	5
Cumulative Foreign Currency Translation (3)	71
Accumulated Other Comprehensive Loss (4)	(63	)

(1)

Recognition of fair value of derivative financial instruments designated as cash flow hedges and fair value hedges, and the related income tax impacts.

(2)

Impact on adoption of the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges.

(3)

Restatement of foreign currency translation adjustment to accumulated other comprehensive loss.

(4)

Recognition of accumulated other comprehensive loss arising from the restatement of foreign currency translation adjustment, offset by accumulated other comprehensive income arising from the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges.

The comparative consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

32 SUNCOR ENERGY INC. 2007ANNUAL REPORT

RECENTLY ISSUED CANADIAN ACCOUNTING STANDARDS

Inventories

In June 2007, the CICA approved Handbook section 3031 "Inventories". Effective January 1, 2008, this standard eliminates the use of a LIFO (last-in-first-out) based valuation approach for inventory. The standard also requires any impairment to net realizable value of inventory to be written down at each reporting period, with subsequent reversals when applicable. This standard can be applied prospectively with an initial adjustment to retained earnings or applied retrospectively with restatement of comparative balances.

The company currently uses a LIFO methodology for crude oil and refined product inventory and will be transitioning to a FIFO (first-in-first-out) methodology beginning January 1, 2008. Retrospective application with restatement will increase the following financial statement balances upon transition:

($ millions)
Inventory	404
Future Income Tax Liability	121
Retained Earnings	283

Capital Disclosures

In December 2006, the CICA approved Handbook section 1535 "Capital Disclosures". Effective January 1, 2008 this standard outlines required disclosure of specific information about an entity's objectives, policies and processes for managing capital. The new standard will not impact net earnings or financial position.

Financial Instruments

In December 2006, the CICA approved Handbook section 3862 "Financial Instruments Disclosure" and section 3863 "Financial Instruments Presentation". Effective January 1, 2008, these standards provide a complete set of disclosure and presentation requirements for financial instruments. The standards have increased emphasis on simplifying disclosures, while enhancing risk identification and discussion of how these risks are managed in relation to both recognized and unrecognized financial instruments. The new standard will not impact net earnings or financial position.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 33

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 sales of bitumen when market conditions are favourable or when operating conditions warrant.

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.

•

Increasing production capacity and improving reliability through staged expansion, continued focus on operational excellence and worksite 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)	2007		2006	2005
Revenue	6 775		7 407	3 965
Production (thousands of bpd)	235.6		260.0	171.3
Average sales price ($/barrel)	74.01		68.03	53.81
Net earnings	2 434		2 783	957
Cash flow from operations (1)	3 092		3 917	1 916
Total assets	18 108		13 692	11 648
Cash used in investing activities	4 248		2 230	1 882
Net cash surplus (deficiency)	(519	)	2 113	(236	)
Sales mix (light/heavy mix)	54/46		53/47	54/46
Cash operating costs ($/barrel) (1)	27.80		21.70	24.55
ROCE (%) (2)	42.6		53.5	22.4
ROCE (%) (3)	27.6		40.1	16.0

(1)

Non-GAAP measure. See page 46.

(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 46.

(3)

Includes capitalized costs related to major projects in progress. See page 46.

2007 Overview

•

Oil sands production averaged 235,600 bpd in 2007, compared to 260,000 bpd in 2006. Production was down year-over-year primarily as the result of planned and unplanned maintenance including a planned 50-day outage of Upgrader 2.

•

Oil sands cash operating costs averaged $27.80 per barrel during 2007, compared to $21.70 per barrel in 2006. The increase in 2007 was primarily due to fixed costs being spread over lower production, as well as higher maintenance costs related to planned and unplanned maintenance.

34 SUNCOR ENERGY INC. 2007ANNUAL REPORT

•

The oil sands business made considerable progress on a variety of projects that are expected to benefit operational reliability, production and sales. At December 31, 2007, the addition of a new set of cokers to our upgrading complex was approximately 95% complete. This expansion is expected to increase production capacity to 350,000 bpd, with construction completion targeted in the second quarter of 2008 and ramp-up to full capacity expected in the fourth quarter. Other work included construction of a naphtha unit (which is intended to enhance product mix) which was approximately 20% complete at year-end, and the Steepbank extraction plant which was approximately 25% complete at year-end.

•

Significant progress was also made on components of the Voyageur program to increase production capacity to 550,000 bpd in 2012. Engineering, procurement and field construction on these projects was advanced to a point sufficient for Suncor's Board of Directors to provide final project approval in early 2008.

•

In July, Suncor filed a regulatory application for the Voyageur South mine extension. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility.

•

In August, Alberta Environment issued a new 10-year operating approval for Suncor's base oil sands operations.

•

At our in-situ operation, high emissions resulted in intervention by both Alberta Environment and the Alberta Energy and Utilities Board. See page 25 for further discussion.

Analysis of Net Earnings

Net earnings were $2,434 million in 2007, compared to $2,783 million in 2006 (2005 – $957 million). Excluding the impacts of income tax rate revaluations, net insurance proceeds (relating to the January 2005 fire) and project start-up costs, earnings were $2,063 million in 2007, compared to $2,148 million in 2006 (2005 – $680 million).

The decrease in earnings primarily reflects the impact of scheduled and unscheduled maintenance that reduced crude oil production and increased operating expenses.

Oil sands average production was 235,600 bpd in 2007, compared to 260,000 bpd in 2006. Sales volumes in 2007 averaged 234,700 bpd, compared with 263,100 bpd in 2006. Lower sales volumes decreased 2007 net earnings by $427 million. Production and sales volumes were significantly lower in 2007 due mainly to the planned shutdown of Upgrader 2 during the summer. The 50-day outage was required to tie-in new facilities related to our planned expansion of oil sands production capacity. Unplanned outages throughout the year have also had a negative impact on our 2007 production volumes.

Sales price realizations averaged $74.01 per barrel in 2007 (including the impact of pretax hedging losses of $5 million), compared with $68.03 per barrel in 2006 (with no pretax hedging gains). The average sales price realization was favourably impacted by stronger WTI benchmark crude oil prices and strengthening differentials on our sweet and sour crude blends relative to WTI, partially offset by a higher average US$/Cdn$ exchange rate. As crude oil is sold based on U.S. dollar benchmark prices, the increased average US$/Cdn$ exchange rate decreased the Canadian dollar value of crude oil products.

The net impact of the above sales mix and pricing factors increased net earnings by $297 million in 2007.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 35

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, were $2,833 million in 2007, compared to $2,546 million in 2006 (2005 – $1,652 million). Expenses increased year-over-year primarily due to higher maintenance expenditures, in addition to diesel fuel purchases made in order to satisfy customer commitments during the Upgrader 2 shutdown.

Overall, increased cash expenses, which include Firebag operating expenses, reduced net earnings by $194 million.

Royalties

Alberta oil sands Crown royalties decreased to $565 million in 2007, compared to $911 million in 2006 (2005 – $406 million). The lower royalty expense is due primarily to increased capital expenditures incurred, lower sales volumes and the absence of net insurance proceeds (relating to a January 2005 fire). These factors were partially offset by higher crude oil prices. Alberta oil sands Crown royalties are subject to completion of audits for 2007 and prior years. 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 19.

Non-Cash Expenses

Non-cash depreciation, depletion and amortization (DD&A) expense increased to $462 million from $385 million in 2006 (2005 – $330 million). The increase primarily resulted from continued growth in the depreciable cost base after the commissioning of new assets throughout the year. Higher non-cash expenses decreased net earnings by $61 million.

Revaluation of Future Income Taxes

Reductions to the federal income tax rate in the second and fourth quarters of 2007 resulted in a total decrease of $413 million in the oil sands opening future income tax (FIT) liability balance, and a corresponding increase in the net earnings of the oil sands segment. In the second quarter of 2006, reductions to both the federal and the Alberta provincial income tax rates resulted in a $429 million revaluation of the oil sands future income tax liability balance, with a corresponding increase in net earnings (2005 – nil).

Cash Operating Costs

Cash operating costs increased to $2,391 million in 2007, compared to $2,057 million in 2006. On a per barrel basis, these costs increased to $27.80 per barrel from $21.70 per barrel in 2006. The increase in cash operating costs per barrel is a result of increased operating expenses and lower production. Refer to page 46 for further details on cash operating costs as a non-GAAP financial measure, including the calculation and reconciliation to GAAP measures.

Net Cash Surplus (Deficiency) Analysis

Cash flow from operations was $3,092 million in 2007, compared to $3,917 million in 2006 (2005 – $1,916 million). The decrease was primarily due to the same factors that impacted net earnings, excluding the impact of depreciation, depletion and amortization. In addition, cash flows were reduced by cash income taxes that were not present in 2006.

Cash flow used in investing activities increased to $4,248 million in 2007 from $2,230 million in 2006 (2005 – $1,882 million). During 2007, capital spending related primarily to continued progress on the current coker unit expansion, future Voyageur strategy expansion, Steepbank extraction plant and naphtha unit projects.

Combined, the above factors resulted in a net cash deficiency of $519 million in 2007, compared with a surplus of $2,113 million in 2006 (2005 – $236 million deficiency).

36 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Future Expansion

In 2001, Suncor announced plans to pursue a multi-phased growth strategy to increase production capacity at its oil sands plant from 225,000 barrels per day (bpd) to 550,000 bpd in 2012.

The first step in that plan was completed in 2005 when Suncor increased production by 35,000 bpd (bringing the total production capacity to 260,000 bpd). In the second half of 2008, Suncor expects to complete an expansion to increase production capacity by 90,000 bpd (bringing the total production capacity to 350,000 bpd).

Suncor's Board of Directors approved the final phase of this multi-staged growth strategy in January 2008. An investment estimated at $20.6 billion for our Voyageur program is expected to increase production capacity by 200,000 bpd, enabling production capacity of 550,000 bpd in 2012. Of the $20.6 billion, $9 billion is planned for expansion of bitumen supply at our in-situ operation, while $11.6 billion is targeted for construction of a third upgrader. For further details, see the Significant Capital Projects table on page 18.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, 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 16.

•

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 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 an increased focus on preventative maintenance.

•

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.

•

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 2,100 oil sands employees. The current collective agreement with the union expires on April 30, 2010.

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Also refer to Risk Factors Affecting Performance on page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 37

NATURAL GAS

Suncor's natural gas business, operating primarily in western Canada, acts as a price hedge against the company's purchases for internal consumption at our oil sands operations. This business also supports Suncor's sustainability goals by managing investment in wind energy projects and developing strategies to reduce greenhouse gas emissions.

Natural gas strategy 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.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)	2007		2006		2005
Revenue	553		578		679
Natural gas production (mmcf/d)	196		191		190
Average natural gas sales price ($/mcf)	6.32		7.15		8.57
Net earnings	25		106		155
Cash flow from operations (1)	248		281		412
Total assets	1 811		1 503		1 307
Cash used in investing activities	532		443		344
Net cash surplus (deficit)	(262	)	(189	)	63
ROCE (%) (2)	2.5		14.9		30.7

(1)

Non-GAAP Measure. See Page 46.

(2)

ROCE for Suncor operating segments is calculated in a manner consistent with consolidated ROCE as reconciled in Non-GAAP Financial Measures. See page 46.

2007 Overview

•

Total production averaged 215 million cubic feet equivalent per day (mmcfe/d) in 2007, compared to 209 mmcfe/d in 2006. Production during 2007 was comprised of 91% natural gas and 9% natural gas liquids and crude oil.

•

Company-wide purchases of natural gas for internal consumption were approximately 184 million cubic feet per day (mmcf/d) during 2007, compared to natural gas production of 196 mmcf/d in 2007.

•

In September, Suncor commissioned its fourth wind power project. The 76-megawatt facility located near Ripley, Ontario is the company's largest wind power project.

•

During the first quarter of 2007, Suncor acquired developed and undeveloped lands in British Columbia for approximately $160 million.

38 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Analysis of Net Earnings

Natural gas net earnings were $25 million in 2007, compared to $106 million in 2006 (2005 – $155 million). Excluding the impact of income tax rate reductions on the opening future income tax liability, the net loss for 2007 was $14 million, compared to net earnings of $53 million in 2006 (2005 – $155 million). The decrease in net earnings was due primarily to lower natural gas price realizations and higher depreciation, depletion and amortization, operating costs, and transportation expenses.

The average realized price for natural gas was $6.32 per thousand cubic feet (mcf) in 2007, compared to an average of $7.15 per mcf in 2006, reflecting lower benchmark natural gas prices. This was partially offset by the increase in price realizations for crude oil and natural gas liquids that resulted from the higher benchmark prices for those products. The net impact of the price variance was a reduction in net earnings of $38 million.

Natural gas total production was 215 mmcfe/d in 2007, compared to 209 mmcfe/d in the prior year. The increase in 2007 production was primarily due to increased volumes from the Grizzly Valley area as a result of new wells added during the period and improved access to processing facilities. Increased production volumes positively impacted 2007 net earnings by $11 million.

Cash Expenses

Operating costs, including general and administrative expenses, were $135 million in 2007, compared to $110 million in 2006 (2005 – $93 million). The increase in operating costs was mainly due to higher lifting costs resulting from third-party processing fees and industry cost pressures, including higher labour costs.

Exploration expenses were $82 million in 2007, unchanged from 2006 (2005 – $46 million). A $15 million increase in dry hole costs recognized during the year was offset by a reduction in seismic expenditures.

Non-Cash expenses

DD&A expense was $189 million in 2007, compared to $152 million in 2006 (2005 – $130 million). The increase was due to higher production and an increase in the capitalized costs, including the impact of developmental dry holes.

Royalties

Royalties on production of natural gas and liquids were $126 million ($1.61 per thousand cubic feet equivalent (mcfe)) in 2007, comparable to the $127 million royalty expense ($1.67 per mcfe) in 2006 (2005 – $149 million; $1.95 per mcfe). Higher production was offset by lower sales price realizations. In October 2007, the government of Alberta announced a new royalty framework which, if enacted by the government, will change royalty rates beginning in 2009. For a further discussion on Crown royalties, see page 20.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 39

Net Cash Deficiency Analysis

Natural gas net cash deficiency was $262 million in 2007, compared with a $189 million deficiency in 2006 (2005 – $63 million surplus). Cash flow from operations decreased to $248 million compared with $281 million in the prior year (2005 – $412 million), mainly due to decreased revenues and higher operating costs.

Cash used in investing activities increased to $532 million, compared with $443 million in 2006 (2005 – $344 million) primarily due to the acquisition of developed and undeveloped lands in British Columbia for approximately $160 million.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but not limited to, the following:

•

Consistently and competitively finding and developing reserves that can be brought on stream economically.

•

The impact of market demand for land. Market demand also influences the cost and available opportunities for acquisitions.

•

The impact of market demand for labour and equipment, which in a heated exploration and development market, could increase costs and/or cause delays to projects for natural gas and its competitors.

•

Risks and uncertainties associated with consulting with stakeholders and obtaining regulatory approval for exploration and development activities in our operating areas. These risks could increase costs and/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, which may result in increased costs and/or reduced production.

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Refer to Risk Factors Affecting Performance on page 21.

40 SUNCOR ENERGY INC. 2007ANNUAL REPORT

REFINING AND MARKETING

Consistent with the company's organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream marketing and refining operations have been combined into a single business segment – refining and marketing. Comparative figures have been reclassified to reflect the combination of the previously disclosed Energy Marketing & Refining – Canada (EM&R) and Refining & Marketing – U.S.A. (R&M) segments. There was no impact to previously reported net earnings as a result of the combination. The results of company-wide energy marketing and trading will continue to be included in this segment. The financial results relating to the sales of oil sands and natural gas production will continue to be reported in their respective business segments.

Refining and marketing operates a 70,000 barrel per day (bpd) capacity refinery in Sarnia, Ontario and a 90,000 bpd capacity refining complex in Commerce City, Colorado, and markets refined products to industrial, wholesale and commercial customers primarily in Ontario, Quebec and Colorado. Through a combination of joint venture-operated and company-owned retail stations, we market products to retail customers in Ontario and the Denver area. Assets also include a 200-million litre per year ethanol plant in St. Clair, Ontario, the 480-kilometre Rocky Mountain pipeline system, the 140-kilometre Centennial pipeline system, two product terminals in Ontario, and two product terminals in Grand Junction, Colorado.

The refining and marketing business also encompasses third-party energy marketing and trading activities, as well as providing marketing services for the sale of crude oil and natural gas from the oil sands and natural gas segments.

Refining and marketing'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, an increased focus on reliability through carefully managed maintenance scheduling, strategic alliances with key suppliers and customers and continuous improvement of operations.

•

Increasing the profitability and efficiency of our retail networks.

HIGHLIGHTS

Summary of Results

Year ended December 31 ($ millions unless otherwise noted)		2007		2006		2005
Revenue		11 173		8 593		6 984
Refined product sales (millions of litres)
	Gasoline	6 132		5 804		5 585
	Total	12 228		10 803		10 574
Net earnings breakdown:
	Total earnings excluding energy, marketing and trading activities	335		213		163
	Energy marketing and trading activities	10		22		11
	Total net earnings	345		235		174
Cash flow from operations (1)		580		443		363
Total assets		4 519		4 037		3 172
Cash used in investing activities		(491	)	(787	)	(818	)
Net cash deficiency		(29	)	(446	)	(485	)
ROCE (%) (2)		16.8		20.4		22.2
ROCE (%) (3)		14.5		12.5		13.8

(1)

Non-GAAP measure. See page 46.

(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 46.

(3)

Includes capitalized costs related to major projects in progress. See page 46.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 41

2007 Overview

•

The final phase of a three-year, $1 billion investment project in the Sarnia refinery is now complete. This investment was made to improve the refinery's environmental performance, enable the production of ultra low sulphur diesel fuel and increase the refinery's sour synthetic processing capacity. The upgrades to enable the production of ultra low sulphur diesel fuel were completed in 2006. The final phase of this multi-phased project was a 120-day shutdown of the refinery hydrocracker unit to complete the tie-in of new facilities to the existing refinery.

•

During commissioning of the new facilities, operational difficulties were encountered resulting in a lengthier than planned start-up period. As a result, full production from the new facilities had not yet been achieved by year end.

•

Refinery utilization levels increased as there were fewer scheduled shutdowns during 2007, compared to the prior year and the Commerce City refinery had improved reliability during the year.

•

Both our Canadian and U.S. downstream operations benefited from high refining and retail margins due to tighter supply of refined products in the Ontario and U.S. Rocky Mountain markets during the first half of the year. Partially offsetting this was increased purchases of refined products to meet customer commitments during planned refinery shutdowns, which reduced overall fuel margins.

Analysis of Net Earnings

Refining and marketing results include the impact of our third-party energy marketing and trading activities that are discussed separately on page 43.

Refining and marketing's net earnings increased to $345 million in 2007 from $235 million in 2006 (2005 – $174 million). This increase was primarily due to higher sales volumes, offset by increased operating expenses.

Volumes

Total sales volumes averaged 33.5 10³m³/d (thousands of cubic metres per day), compared to 29.5 10³m³/d in 2006. The increase in sales was the result of the higher refinery utilization levels and higher purchases for resale. Total gasoline sales volumes through our Sunoco and Phillips 66® branded retail network were comparable to the prior year, with 1,900 million litres in 2007, slightly down from 1,935 million litres in 2006.

Fuel Margins

Refining and marketing benefited from stronger margins in both Canada and the U.S. Rocky Mountain regions during the first half of the year as tighter supply of refined products resulted in higher light oil product margins. This was mostly offset in the second half of the year by lower margins on heavy fuel oil sales and lower margins from finished products purchased for re-sale. Crude and product purchases were $6,351 million in 2007, compared to $5,308 million in 2006 (2005 – $4,613 million). The increase was a result of higher crude oil prices, higher crude oil purchases due to higher refinery utilization levels and an increase in refined product purchases to meet customer commitments during the planned outage at our Sarnia refinery.

Refinery Utilization

Overall crude refinery utilization averaged 98% in 2007, compared with 85% in 2006. The increase in refinery utilization was primarily the result of a reduction in overall planned maintenance shutdowns occurring during 2007 compared to 2006, in addition to improved reliability at the Commerce City refinery.

Cash and Non-Cash Expenses

Overall, cash and non-cash operating expenses increased by $72 million after-tax in 2007. Cash expenses increased by $44 million after-tax in 2007, primarily due to an increase in Canadian federal excise tax paid as a result of increased sales volumes in 2007. Non-cash expenses increased by $28 million after-tax in 2007, due to increased depreciation, depletion and amortization expense mainly resulting from a full year's depreciation being taken on the Commerce City and Sarnia refinery diesel desulphurization projects and the St. Clair ethanol project that were completed in 2006.

42 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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 Canadian GAAP. Refining and marketing 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)			2007	2006	2005
Operating revenues
	Sales to refining and marketing joint ventures:
		Refined products	329	294	327
		Petrochemicals	163	136	279

At December 31, 2007, amounts due from refining and marketing joint ventures were $17 million, compared to $20 million at December 31, 2006.

Energy Marketing and Trading Activities

Energy marketing and 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 $10 million in 2007 compared to net earnings of $22 million in 2006 (2005 – $11 million). The higher earnings in 2006 compared to 2007 were the result of very strong crude trading margins in the prior year. For further details on our energy marketing and trading activities, see page 23.

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.

Net Cash Deficiency Analysis

Refining and marketing's net cash deficiency was $29 million in 2007 compared to a net cash deficiency of $446 million in 2006 (2005 – $485 million). Cash flow from operations was $580 million in 2007 compared to $443 million in 2006 (2005 – $363 million). The increase was primarily due to the same factors that impacted net earnings.

Cash used in investing activities was $491 million in 2007 compared to $787 million in 2006 (2005 – $818 million). Capital expenditures in 2007 were significantly lower than the previous year, as the majority of the work related to the diesel desulphurization and oil sands integration projects was completed in 2006. Capital spending in 2007 related mainly to completion of this work at Sarnia, including a planned refinery shutdown to allow the tie-in of the new facilities.

Risk Factors Affecting Performance

Our financial and operating performance is potentially affected by a number of factors, including, but 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, the new facilities for reducing sulphur in on-road diesel fuel should also allow the company to meet the requirements for reducing sulphur in off-road diesel and light fuel oil.

Additional risks, assumptions and uncertainties are discussed on page 48 under Forward-Looking Information. Refer to Risk Factors Affecting Performance on page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 43

OUTLOOK

During 2008, management will focus on the following priorities:

•

Achieve annual oil sands production of 275,000 to 300,000 bpd at a cash operating cost average of $25 to $27 per barrel. Planned production increases with the commissioning of an expansion to Upgrader 2 and a strong focus on production reliability are key to managing operating costs.

•

Maintain production from our natural gas business (including natural gas liquids and crude oil) at an average 205 to 215 mmcf equivalent per day. We expect to bring several new wells into production and will continue to focus on high-volume deep gas prospects in 2008.

•

Advance plans for increased bitumen supply. Meet regulatory requirements to allow ramp up of expansion to Firebag Stages 1 and 2, commence construction of Stage 3 and seek regulatory approval to proceed with Stages 4 to 6. New third-party bitumen supplies are also expected in 2008.

•

Advance plans for increasing crude oil production. Fully commission expanded units to enable production capacity of 350,000 bpd by year end. With Board of Director's approval given in January 2008, accelerate work on a $20.6 billion expansion of bitumen feed and upgrader capacity to generate 550,000 bpd capacity in 2012.

•

Fulfill regulatory requirements. Construct and commission emission abatement equipment and reduce diluent discharges to the tailings ponds to meet specific regulatory requirements.

•

Continue to focus on safety. Increase focus on identifying and reducing potential process hazards.

•

Focus on efficiency. Safely complete planned modifications to Upgrader 2 aimed at ensuring reliable full capacity production. A planned maintenance shutdown to Upgrader 1, part of $1.5 billion in maintenance capital spending in 2008, is also expected to improve reliability going forward.

•

Maintain a strong balance sheet. While net debt is expected to rise with capital spending of $7.5 billion in 2008, plan to maintain a strong debt to cash flow ratio and protect future cash flow with strategic crude oil hedging of up to 30% of planned production.

•

Continue efforts to reduce environmental impact intensity. Investments planned to reduce sulphur emissions at oil sands facilities and reduce water use intensity.

•

Continue to pursue energy efficiencies, greenhouse gas offsets and new, renewable energy projects. In oil sands operations, advance work on more efficient extraction technology. Advance renewable energy portfolio.

44 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Suncor's outlook provides management's targets for 2008 in certain key areas of the company's business. Users of this information are cautioned that the actual events in 2008 may vary from the priorities disclosed.

		2008 Full-Year Outlook
Oil Sands
Production		275,000 bpd to 300,000 bpd
	Diesel	11%
	Sweet	36%
	Sour	49%
	Bitumen	2%
	Third-party processing	2%
Realization on crude sales basket		WTI @ Cushing less Cdn$4.25 to Cdn$5.25 per barrel
Cash operating costs (1)		$25.00 to $27.00 per barrel
Natural Gas
Production (2) (mmcf equivalent per day)		205 to 215
	Natural gas	93%
	Liquids	7%

(1)

Cash operating cost estimates are based on the following assumptions: i) production volumes and sales mix as described in the table above; and ii) a natural gas price of $6.70 per gigajoule at AECO. This goal also includes costs incurred for third-party bitumen processing. Cash operating costs per barrel are not prescribed by Canadian generally accepted accounting principles (GAAP). This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Suncor includes this non-GAAP financial measure because investors may use this information to analyze operating performance. This information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See Non-GAAP Financial Measures on page 46.

(2)

Production target includes natural gas liquids (NGL) and crude oil converted into mmcf equivalent at a ratio of one barrel of NGL/crude oil: six thousand cubic feet of natural gas. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This mmcf equivalent may be misleading, particularly if used in isolation.

Factors that could potentially impact Suncor's 2008 financial performance include:

•

Planned maintenance at oil sands. Upgrader 1 is expected to be shut down for approximately 30 days in the second quarter for scheduled maintenance. Although this shutdown is reflected in operational targets for the year, production estimates could be impacted if unplanned work is identified, or the schedule is impacted by labour or material supply issues. During the outage, Upgrader 2 is expected to continue producing approximately 200,000 bpd.

•

Completion and commissioning of an expansion to Upgrader 2 during the second quarter to enable production capacity of 350,000 bpd. Production rates during the ramp-up period are difficult to predict and can be impacted by bitumen supply, as well as planned and unplanned maintenance. However, Suncor expects to move towards the 350,000 bpd capacity in the fourth quarter.

•

Regulatory requirements at the company's oil sands base plant and in-situ operation. Suncor plans to incur maintenance and capital expenditures to construct and commission emission abatement equipment. The timing and scope of this work could impact 2008 results.

•

Bitumen supply. If Suncor encounters unexpected issues in meeting regulatory requirements aimed at controlling emissions at both base plant and the in-situ operation, or if there are unexpected issues related to third-party supplies, there may be bitumen supply restrictions that could impact 2008 production targets.

•

Production volumes at the Sarnia refinery. Suncor is lining-out new facilities at the refinery and this work could impact production in the first few months of 2008.

•

Crude oil hedges. Consistent with the approval received from the Board of Directors, Suncor may fix a price or range of prices for up to approximately 30% of our planned production of crude oil for specified periods of time. At December 31, 2007, Suncor had hedging agreements in place for 10,000 bpd in 2008. These costless collar hedges have an average floor of US$59.85 per barrel with an average ceiling of US$101.06 per barrel in 2008.

For additional information on risk factors that could cause actual results to differ, please see page 21.

SUNCOR ENERGY INC. 2007ANNUAL REPORT 45

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		2007	2006	2005
Cash flow from operations ($ millions)	A	3 805	4 533	2 476
Weighted average number of common shares outstanding – basic (millions of shares)	B	461	459	456
Cash flow from operations – basic ($ per share)	A/B	8.25	9.87	5.43

ROCE

For the year ended December 31 ($ millions, except ROCE)		2007		2006	2005
Adjusted net earnings
Net earnings		2 832		2 971	1 158
Add: after-tax financing expenses (income)		(179	)	26	(16	)
	D	2 653		2 997	1 142
Capital employed – beginning of year
Short-term and long-term debt, less cash and cash equivalents		1 849		2 868	2 134
Shareholders' equity		8 952		5 996	4 874
	E	10 801		8 864	7 008
Capital employed – end of year
Short-term and long-term debt, less cash and cash equivalents		3 248		1 849	2 868
Shareholders' equity		11 613		8 952	5 996
	F	14 861		10 801	8 864
Average capital employed	(E+F)/2=G	12 831		9 832	7 936
Average capitalized costs related to major projects in progress	H	3 454		2 476	2 175
ROCE (%)	D/(G-H)	28.3		40.7	19.8

46 SUNCOR ENERGY INC. 2007ANNUAL REPORT

Oil Sands Operating Costs – Total Operations

			2007			2006			2005
(unaudited)			$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses			2 435			2 198			1 455
	Less: natural gas costs, inventory changes and stock-based compensation		(353	)		(361	)		(281	)
	Less: non-monetary transactions		(102	)		(126	)		—
Accretion of asset retirement obligations			41			28			24
Taxes other than income taxes			55			36			29
Cash costs			2 076		24.15	1 775		18.70	1 227		19.60
Natural gas			307		3.55	276		2.90	307		4.90
Imported bitumen (net of other reported product purchases)			8		0.10	6		0.10	2		0.05
Cash operating costs		A	2 391		27.80	2 057		21.70	1 536		24.55
Project start-up costs		B	60		0.95	38		0.40	25		0.40
Total cash operating costs		A+B	2 451		28.75	2 095		22.10	1 561		24.95
Depreciation, depletion and amortization			462		5.40	385		4.05	330		5.30
Total operating costs			2 913		34.15	2 480		26.15	1 891		30.25
Production (thousands of barrels per day)					235.6			260.0			171.3

Oil Sands Operating Costs – In-Situ Bitumen Production Only

		2007			2006			2005
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		273			209			155
Less: natural gas costs and inventory changes		(134	)		(103	)		(91	)
Taxes other than income taxes		7			4			—
Cash costs		146		10.85	110		8.95	64		9.15
Natural gas		134		9.90	103		8.35	91		13.05
Cash operating costs	A	280		20.75	213		17.30	155		22.20
In-situ (Firebag) start-up costs	B	—		—	21		1.70	7		1.00
Total cash operating costs	A+B	280		20.75	234		19.00	162		23.20
Depreciation, depletion and amortization		83		6.20	68		5.55	34		4.90
Total operating costs		363		26.95	302		24.55	196		28.10
Production (thousands of barrels per day)				36.9			33.7			19.1

SUNCOR ENERGY INC. 2007ANNUAL REPORT 47

Legal Notice – Forward-Looking Information

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 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," 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, interest rates 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 Voyageur project, including our Firebag in-situ development) and regulatory projects (for example, the emissions reduction modifications at our Firebag in-situ development); 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; the cost of compliance with current and 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 and from companies that provide alternative sources of energy; labour and material shortages; 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 unintended consequences of the proposed 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 fires, blowouts, freeze-ups, equipment failures and other similar events affecting Suncor or other parties whose operations or assets directly or indirectly affect Suncor. These 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.

48 SUNCOR ENERGY INC. 2007ANNUAL REPORT

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EXHIBIT 99-2

Management's Discussion and Analysis for the fiscal year ended December 31, 2007, dated February 27, 2008