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EXHIBIT 99-1

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SUNCOR ENERGY INC.
FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008,
INCLUDING RECONCILIATION TO U.S. GAAP (NOTE 20)

MANAGEMENT'S STATEMENT
OF RESPONSIBILITY FOR FINANCIAL REPORTING

The management of Suncor Energy Inc. is responsible for the presentation and preparation of the accompanying consolidated financial statements of Suncor Energy Inc. on pages 47 to 86 and all related financial information contained in this Annual Report, including Management's Discussion and Analysis.

The consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles. They include certain amounts that are based on estimates and judgments relating to matters not concluded by year-end. Financial information presented elsewhere in this Annual Report is consistent with that contained in the consolidated financial statements.

In management's opinion, the consolidated financial statements have been properly prepared within reasonable limits of materiality and within the framework of the significant accounting policies adopted by management as summarized on pages 47 to 51. If alternate accounting methods exist, management has chosen those policies it deems the most appropriate in the circumstances. In discharging its responsibilities for the integrity and reliability of the financial statements, management maintains and relies upon a system of internal controls designed to ensure that transactions are properly authorized and recorded, assets are safeguarded against unauthorized use or disposition and liabilities are recognized. These controls include quality standards in hiring and training of employees, formalized policies and procedures, a corporate code of conduct and associated compliance program designed to establish and monitor conflicts of interest, the integrity of accounting records and financial information among others, and employee and management accountability for performance within appropriate and well-defined areas of responsibility.

The system of internal controls is further supported by the professional staff of an internal audit function who conduct periodic audits of the company's financial reporting.

The company retains independent petroleum consultants, GLJ Petroleum Consultants Ltd., to conduct independent evaluations of the company's oil and gas reserves and resources.

The Audit Committee of the Board of Directors, currently composed of five independent directors, reviews the effectiveness of the company's financial reporting systems, management information systems, internal control systems and internal auditors. It recommends to the Board of Directors the external auditors to be appointed by the shareholders at each annual meeting and reviews the independence and effectiveness of their work. In addition, it reviews with management and the external auditors any significant financial reporting issues, the presentation and impact of significant risks and uncertainties, and key estimates and judgments of management that may be material for financial reporting purposes. The Audit Committee appoints the independent petroleum consultants. The Audit Committee meets at least quarterly to review and approve interim financial statements prior to their release, as well as annually to review Suncor's annual financial statements and Management's Discussion and Analysis, Annual Information Form/Form 40-F, and annual reserves and resource estimates, and recommend their approval to the Board of Directors. The internal auditors and PricewaterhouseCoopers LLP have unrestricted access to the company, the Audit Committee and the Board of Directors.

Richard L. George	J. Kenneth Alley
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

February 25, 2009

SUNCOR ENERGY INC. 2008ANNUAL REPORT 43

The following report is provided by management in respect of the Company's internal control over financial reporting (as defined in Rule13a-15(f) under the U.S. Securities Exchange Act of 1934):

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

1.

Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting.

2.

Management has used the Committee of Sponsoring Organizations of the Treadway Commission (COSO) framework in Internal Control – Integrated Framework to evaluate the effectiveness of the Company's internal control over financial reporting.

3.

Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2008, and has concluded that such internal control over financial reporting was effective as of that date. Additionally, based on this assessment, management determined that there were no material weaknesses in internal control over financial reporting as of December 31, 2008. Because of inherent limitations, systems of internal control over financial reporting may not prevent or detect misstatements and even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation.

4.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2008 has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

Richard L. George	J. Kenneth Alley
President and Chief Executive Officer	Senior Vice President and Chief Financial Officer

February 25, 2009

44 SUNCOR ENERGY INC. 2008ANNUAL REPORT

INDEPENDENT AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have completed integrated audits of Suncor Energy Inc.'s 2008, 2007 and 2006 consolidated financial statements and of its internal control over financial reporting as at December 31, 2008. Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated balance sheets of Suncor Energy Inc. ("the company") as at December 31, 2008 and December 31, 2007, and the related consolidated statements of earnings and comprehensive income, of cash flows and of changes in shareholders' equity for each of the years in the three year period ended December 31, 2008. These financial statements are the responsibility of the company's management. Our responsibility is to express an opinion on these financial statements based on our audits.

We conducted our audits of the company's financial statements as at December 31, 2008 and 2007 and for each of the years in the three year period ended December 31, 2008 in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform an audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. A financial statement audit also includes assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.

In our opinion, the consolidated financial statements referred to above present fairly, in all material respects, the financial position of the company as at December 31, 2008 and December 31, 2007 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2008 in accordance with Canadian generally accepted accounting principles.

Internal control over financial reporting

We have also audited the company's internal control over financial reporting as at December 31, 2008, based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). The company's management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Management's Report on Internal Control over Financial Reporting. Our responsibility is to express an opinion on the company's internal control over financial reporting based on our audit.

We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

A company's internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company's internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company's assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 45

In our opinion, the company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2008 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 25, 2009

COMMENTS BY AUDITORS FOR U.S. READERS ON CANADA – U.S. REPORTING DIFFERENCES

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company's consolidated financial statements, such as the changes described in Summary of Significant Accounting Policies and in Note 1 to the consolidated financial statements. Our report to the shareholders dated February 25, 2009 is expressed in accordance with Canadian reporting standards, which do not require a reference to such a change in the Auditors' Report when the change is properly accounted for and adequately disclosed in the consolidated financial statements.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 25, 2009

46 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SUNCOR ENERGY INC.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

Suncor Energy Inc. is a Canadian integrated energy company comprised of three operating segments: oil sands, natural gas, and refining and marketing.

Oil sands includes the production of light sweet and light sour crude oil, diesel fuel and various custom blends from oil sands in the Athabasca region of northeastern Alberta, and the marketing of these products substantially in Canada and the United States.

Natural gas includes the exploration, acquisition, development, production, transportation and marketing of natural gas, natural gas liquids and crude oil in Canada and the United States.

Refining and marketing includes the manufacturing, transportation and marketing of petroleum, petrochemical and biofuel products from our Canadian and United States operations. Canadian activities are conducted primarily in Ontario and Quebec, while activities in the United States are primarily in Colorado.

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

The significant accounting policies of the company are summarized below:

(a) Principles of Consolidation and the Preparation of Financial Statements

These consolidated financial statements are prepared and reported in Canadian dollars in accordance with generally accepted accounting principles (GAAP) in Canada, which differ in some respects from GAAP in the United States. These differences are quantified and explained in note 20.

The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company's proportionate share of the assets, liabilities, equity, revenues, expenses and cash flows of its joint ventures. Subsidiaries are defined as entities in which the company holds a controlling interest, is the general partner or where it is subject to the majority of expected losses or gains.

The timely preparation of financial statements requires that management make estimates and assumptions, and use judgment regarding assets, liabilities, revenues and expenses. Such estimates primarily relate to unsettled transactions and events as of the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur.

Certain prior period comparative figures have been reclassified to conform to the current period presentation.

(b) Cash Equivalents and Investments

Cash equivalents consist primarily of term deposits, certificates of deposit and all other highly liquid investments with a maturity at the time of purchase of three months or less. Investments with maturities greater than three months and up to one year are classified as short-term investments, while those with maturities in excess of one year are classified as long-term investments.

(c) Revenues

Crude oil sales from upstream operations (oil sands and natural gas) to downstream operations (refining and marketing) are based on actual product shipments. On consolidation, revenues and purchases related to these sales transactions are eliminated from operating revenues and purchases of crude oil and products.

The company also uses its natural gas production to offset purchases for internal consumption at its oil sands plant and Sarnia refinery. On consolidation, revenues from these sales are eliminated from operating revenues, crude oil and products purchases, and operating, selling and general expenses.

Revenues associated with sales of crude oil, natural gas, petroleum and petrochemical products and all other items not eliminated on consolidation are recorded when title passes to the customer and delivery has taken place. Revenues from oil and natural gas production from properties in which the company has an interest with other producers are recognized on the basis of the company's net working interest.

(d) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 47

Expenditures to acquire and develop oil sands mining properties are capitalized. Development costs to expand the capacity of existing mines or to develop mine areas substantially in advance of current production are also capitalized. Drilling and related seismic costs for regulatory approved mining areas are capitalized when planned future development timelines do not exceed 10 years. All other mining exploration costs are expensed as incurred.

The company follows the successful efforts method of accounting for its conventional natural gas and in-situ oil sands operations. Under the successful efforts method, acquisition costs of proved and unproved properties are capitalized. Costs of unproved properties are transferred to proved properties when proved reserves are confirmed. Exploration costs, including geological and geophysical costs, are expensed as incurred. Exploratory drilling costs are initially capitalized. If it is determined that a specific well does not contain proved reserves, the related capitalized exploratory drilling costs are charged to expense, as dry hole costs, at that time. Related land costs are expensed through the amortization of unproved properties as covered under the natural gas section of the depreciation, depletion and amortization policy below.

Development costs, which include the costs of wellhead equipment, development drilling costs, gas plants and handling facilities, applicable geological and geophysical costs and the costs of acquiring or constructing support facilities and equipment are capitalized. Costs incurred to operate and maintain wells and equipment and to lift oil and gas to the surface are expensed as operating costs.

Costs incurred after the inception of operations are expensed.

Interest Capitalization

Interest costs relating to major capital projects in progress and to the portion of non-producing oil and gas properties expected to become producing are capitalized as part of property, plant and equipment. Capitalization of interest ceases when the capital asset is substantially complete and ready for its intended productive use.

Leases

Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as capital leases and classified as property, plant and equipment with offsetting long-term debt. All other leases are classified as operating leases under which leasing costs are expensed in the period incurred.

Depreciation, Depletion and Amortization

OIL SANDS Property, plant and equipment are depreciated over their useful lives on a straight-line basis, commencing when the assets are placed into service. Mine and mobile equipment is depreciated over periods ranging from three to 20 years and plant and other property and equipment, including leases in service, primarily over four to 40 years. Capitalized costs related to the in-progress phase of projects are not depreciated until the facilities are substantially complete and ready for their intended productive use.

NATURAL GAS Acquisition costs of unproved properties that are individually significant are evaluated for impairment by management. Impairment of unproved properties that are not individually significant is provided for through amortization over the average projected holding period for that portion of acquisition costs not expected to become producing. The average projected holding period of five years is based on historical experience.

Acquisition costs of proved properties are depleted using the unit of production method based on proved reserves. Capitalized exploratory drilling costs and development costs are depleted on the basis of proved developed reserves. For purposes of the depletion calculation, production and reserves volumes for oil and natural gas are converted to a common unit of measure on the basis of their approximate relative energy content. Gas plants, support facilities and equipment are depreciated on a straight-line basis over their useful lives, which average 12 years.

REFINING AND MARKETING Depreciation of property, plant and equipment is provided on a straight-line basis over the useful lives of assets. The Sarnia and Commerce City refineries and additions thereto are depreciated over an average of 30 years, service stations and related equipment over an average of 20 years and pipeline facilities and other equipment over three to 40 years.

Asset Retirement Obligations

A liability is recognized for future retirement obligations associated with the company's property, plant and equipment. The fair value of the Asset Retirement Obligation (ARO) is recorded on a discounted basis. This amount is capitalized as part of the cost of the related asset and amortized to expense over its useful life. The liability accretes until the company settles the obligation.

48 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Impairment

Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount, less future income taxes, may not be recoverable from estimated undiscounted future cash flows. If it is determined that the estimated net recoverable amount is less than the net carrying amount, a write-down to the asset's fair value is recognized during the period, with a charge to earnings.

Disposals

Gains or losses on disposals of non-oil and gas property, plant and equipment are recognized in earnings. For oil and gas property, plant and equipment, gains or losses are recognized in earnings for significant disposals or disposal of an entire property. However, the acquisition cost of a subsequently surrendered or abandoned unproved property that is not individually significant, or a partial abandonment of a proved property, is charged to accumulated depreciation, depletion and amortization.

(e) Deferred Charges and Other

The cost of major maintenance shutdowns is deferred and amortized on a straight-line basis over the period to the next shutdown, which varies from three to nine years. Normal maintenance and repair costs are charged to expense as incurred.

Deferred tax credits are government receivables, recognized when they are reasonably measurable and collectible, relating to eligible expenditures under various programs.

See also section (m) Recently Issued Accounting Standards.

(f) Employee Future Benefits

The company's employee future benefit programs consist of defined benefit and defined contribution pension plans, as well as other post-retirement benefits.

The estimated future cost of providing defined benefit pension and other post-retirement benefits is actuarially determined using management's best estimates of demographic and financial assumptions, and such cost is accrued proportionately from the date of hire of the employee to the date the employee becomes fully eligible to receive the benefits. The discount rate used to determine accrued benefit obligations is based on a year-end market rate of interest for high-quality debt instruments with cash flows that match the timing and amount of expected benefit payments. Company contributions to the defined contribution plan are expensed as incurred.

(g) Inventories

Inventories of crude oil and refined products are valued at the lower of cost (using the first-in, first-out (FIFO) method) and net realizable value.

Materials and supplies are valued at the lower of average cost and net realizable value.

Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location.

See also Note 1 – Changes in Accounting Policies.

(h) Financial Instruments

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 future income taxes), and long-term debt.

The estimated fair values of financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies based on industry accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

Derivative contracts 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. 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 uses these valuations to estimate the fair values of the underlying physical commodity contracts.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 49

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 outlined above. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. Gains or losses on our U.S. dollar denominated long-term debt resulting from changes in the exchange rate are recognized in the period in which they occur.

See also Note 1 – Changes in Accounting Policies.

(i) Foreign Currency Translation

Monetary assets and liabilities denominated in foreign currencies are translated to Canadian dollars at rates of exchange in effect at the end of the period. The resulting exchange gains and losses are included in earnings. Other assets and related depreciation, depletion and amortization, other liabilities, revenues and expenses are translated at rates of exchange in effect at the respective transaction dates. The resulting exchange gains and losses are included in earnings.

United States operations of our refining and marketing business, and our corporate self-insurance operations are classified as self-sustaining and are translated into Canadian dollars using the current rate method. Assets and liabilities are translated at the period-end exchange rate, while revenues and expenses are translated using average exchange rates during the period. Translation gains or losses are included in other comprehensive income in the Consolidated Statements of Earnings and Comprehensive Income.

(j) Stock-Based Compensation Plans

Under the company's common share option programs (see note 12), common share options are granted to executives, employees and non-employee directors.

Compensation expense is recorded in the Consolidated Statements of Earnings and Comprehensive Income as operating, selling and general expense for all common share options granted to employees and non-employee directors on or after January 1, 2003, with a corresponding increase recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders' Equity. The expense is based on the fair values of the option at the time of grant and is recognized in the Consolidated Statements of Earnings and Comprehensive Income over the estimated vesting periods of the respective options. For employees eligible to retire prior to the vesting date, the compensation expense is recognized over the shorter period. In instances where an employee is eligible to retire at the time of grant, the full expense is recognized immediately. Consideration paid to the company on exercise of options is credited to share capital.

For common share options granted prior to January 1, 2003 ("pre-2003 options"), compensation expense is not recognized in the Consolidated Statements of Earnings and Comprehensive Income. The company continues to disclose the pro forma earnings impact of related stock-based compensation expense for pre-2003 options.

Stock-based compensation awards that are to be settled in cash are measured using the fair value based method of accounting. The expense is based on the fair values of the award at the time of grant and the change in fair value from the time of grant. The expense is recognized in the Consolidated Statements of Earnings and Comprehensive Income over the estimated vesting periods of the respective award.

(k) Transportation Costs

Transportation costs billed to customers are classified as revenues with the related transportation costs classified as transportation and other costs in the Consolidated Statements of Earnings and Comprehensive Income.

(l) Income Taxes

Suncor follows the liability method of accounting for income taxes. Future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using enacted or substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with the adjustment being recognized in net earnings in the period that the change occurs. Investment tax credits are recorded as an offset to the related expenditures.

(m) Recently Issued Canadian Accounting Standards

Goodwill and Intangible Assets

In February 2008, the Canadian Institute of Chartered Accountants (CICA) approved Handbook section 3064 "Goodwill and Intangible Assets". Effective January 1, 2009, this new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs". The standard focuses on the criteria for asset recognition in the financial statements, including those internally developed. The new standard will not materially impact net earnings or financial position,

50 SUNCOR ENERGY INC. 2008ANNUAL REPORT

however will result in the reclassification and presentation of certain balances on the balance sheet. At December 31, 2008, $566 million of turnaround costs would have been reclassified as part of Property, Plant and equipment (December 31, 2007 – $296 million).

International Financial Reporting Standards

In February 2008, the Accounting Standards Board confirmed that International Financial Reporting Standards (IFRS) will replace Canadian GAAP in 2011 for publicly accountable enterprises. While IFRS uses a conceptual framework similar to Canadian GAAP there are significant differences in accounting policies that must be evaluated. More disclosures will be required under IFRS.

The company's IFRS conversion project began in 2008. A formal project plan, governance structure, and a project team, including an external advisor, have been established. The project philosophy is to align with current accounting practices and policies, where possible, to minimize the impact of any changes to the business. Regular reporting is provided to senior management and the Audit Committee of the Board of Directors. Specific changes resulting from implementation of IFRS have not been determined at this time.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 51

CONSOLIDATED STATEMENTS OF EARNINGS
AND COMPREHENSIVE INCOME

For the years ended December 31 ($ millions)		2008	2007 (restated) (note 1)		2006 (restated) (note 1)
Revenues
	Operating revenues (notes 7, 17 and 19)	18 336	15 020		13 798
	Energy marketing and trading activities (note 7d)	11 725	3 515		2 299
	Net insurance proceeds	—	—		436
	Interest	28	30		13
		30 089	18 565		16 546
Expenses
	Purchases of crude oil and products	7 184	5 817		4 670
	Operating, selling and general	4 044	3 340		3 066
	Energy marketing and trading activities (note 7d)	11 717	3 467		2 261
	Transportation and other costs	275	182		203
	Depreciation, depletion and amortization	1 049	864		695
	Accretion of asset retirement obligations	64	48		34
	Exploration (note 19)	90	95		104
	Royalties (note 5)	890	691		1 038
	Taxes other than income taxes (note 19)	679	648		595
	Loss (gain) on disposal of assets	13	7		(1	)
	Project start-up costs	35	68		45
	Financing expenses (income) (note 15)	917	(211	)	39
		26 957	15 016		12 749
Earnings Before Income Taxes		3 132	3 549		3 797
Provision for income taxes (note 11)
	Current	514	382		20
	Future	481	184		808
		995	566		828
Net Earnings		2 137	2 983		2 969
Other comprehensive income (loss) (notes 7 and 18)		350	(190	)	10
Comprehensive Income		2 487	2 793		2 979
Net Earnings Per Common Share (dollars) (note 14)
Net earnings attributable to common shareholders
	Basic	2.29	3.23		3.23
	Diluted	2.26	3.17		3.16
Cash dividends		0.20	0.19		0.15

See accompanying Summary of Significant Accounting Policies and Notes.

52 SUNCOR ENERGY INC. 2008ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)			2008	2007 (restated) (note 1)
Assets
	Current assets
		Cash and cash equivalents	660	569
		Accounts receivable (notes 7, 12 and 19)	1 580	1 438
		Inventories (notes 1 and 16)	909	1 012
		Income taxes receivable	67	95
		Future income taxes (note 11)	21	46
	Total current assets		3 237	3 160
	Property, plant and equipment, net (note 3)		28 316	20 945
	Deferred charges and other (note 4)		975	404
	Total assets		32 528	24 509
Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	11	6
		Accounts payable and accrued liabilities (notes 7, 9, 10 and 13)	3 229	2 797
		Taxes other than income taxes	97	72
		Income taxes payable	81	244
		Future income taxes	111	37
	Total current liabilities		3 529	3 156
	Long-term debt (note 6)		7 875	3 811
	Accrued liabilities and other (notes 7, 9, 10 and 13)		1 986	1 434
	Future income taxes (note 11)		4 615	4 212
	Total liabilities		18 005	12 613
	Commitments and contingencies (note 12)
	Shareholders' equity
		Share capital (note 13)	1 113	881
		Contributed surplus (note 13)	288	194
		Accumulated other comprehensive income (loss) (notes 7 and 18)	97	(253	)
		Retained earnings (note 1)	13 025	11 074
	Total shareholders' equity		14 523	11 896
	Total liabilities and shareholders' equity		32 528	24 509

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board of Directors:

Richard L. George	Brian A. Canfield
Director	Director

February 25, 2009

SUNCOR ENERGY INC. 2008ANNUAL REPORT 53

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions)		2008		2007 (restated) (note 1)		2006 (restated) (note 1)
Operating Activities
Cash flow from operations (a)		4 463		4 009		4 524
Decrease (increase) in operating working capital
	Accounts receivable	(134	)	(387	)	53
	Inventories	103		(223	)	(57	)
	Accounts payable and accrued liabilities	140		248		87
	Taxes payable/receivable	(110	)	246		(43	)
Cash flow from operating activities		4 462		3 893		4 564
Cash Used in Investing Activities (a)		(7 590	)	(5 362	)	(3 489	)
Net Cash (Deficiency) Surplus Before Financing Activities		(3 128	)	(1 469	)	1 075
Financing Activities
Decrease in short-term debt		(1	)	(4	)	(42	)
Proceeds from issuance of long-term debt		2 704		1 835		—
Net increase (decrease) in long-term debt		422		(171	)	(622	)
Issuance of common shares under stock option plans		190		62		45
Dividends paid on common shares		(180	)	(162	)	(127	)
Deferred revenue		—		4		27
Cash flow provided by (used in) financing activities		3 135		1 564		(719	)
Increase in Cash and Cash Equivalents		7		95		356
Effect of Foreign Exchange on Cash and Cash Equivalents		84		(47	)	—
Cash and Cash Equivalents at Beginning of Year		569		521		165
Cash and Cash Equivalents at End of Year		660		569		521

(a)

See Schedules of Segmented Data on pages 58 and 59.

See accompanying Summary of Significant Accounting Policies and Notes.

54 SUNCOR ENERGY INC. 2008ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS' EQUITY

For the years ended December 31 ($ millions)	Share Capital	Contributed Surplus		Accumulated Other Comprehensive Income (AOCI)		Retained Earnings
At December 31, 2005, as previously reported	732	50		(81	)	5 295
Retroactive adjustment for change in accounting policy, net of tax (note 1)	—	—		—		134
At December 31, 2005, as restated	732	50		(81	)	5 429
Net earnings	—	—		—		2 969
Dividends paid on common shares	—	—		—		(127	)
Issued for cash under stock option plans	52	(7	)	—		—
Issued under dividend reinvestment plan	10	—		—		(10	)
Stock-based compensation expense	—	53		—		—
Income tax benefit of stock option deductions in the U.S.	—	4		—		—
Change in AOCI related to foreign currency translation	—	—		10		—
At December 31, 2006, as restated	794	100		(71	)	8 261
Net earnings	—	—		—		2 983
Dividends paid on common shares	—	—		—		(162	)
Issued for cash under stock option plans	74	(12	)	—		—
Issued under dividend reinvestment plan	13	—		—		(13	)
Stock-based compensation expense	—	103		—		—
Income tax benefit of stock option deductions in the U.S.	—	3		—		—
Adjustment to opening retained earnings arising from ineffective portion of cash flow hedges at January 1, 2007	—	—		—		5
Adjustment to opening AOCI arising from effective portion of cash flow hedges at January 1, 2007	—	—		8		—
Change in AOCI related to foreign currency translation	—	—		(195	)	—
Change in AOCI related to derivative hedging activities	—	—		5		—
At December 31, 2007, as restated	881	194		(253	)	11 074
Net earnings	—	—		—		2 137
Dividends paid on common shares	—	—		—		(180	)
Issued for cash under stock option plans	226	(36	)	—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	120		—		—
Income tax benefit of stock option deductions in the U.S.	—	10		—		—
Change in AOCI related to foreign currency translation	—	—		350		—
Change in AOCI related to derivative hedging activities	—	—		—		—
At December 31, 2008	1 113	288		97		13 025

See accompanying Summary of Significant Accounting Policies and Notes.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 55

SCHEDULES OF SEGMENTED DATA ^(a)

	Oil Sands						Natural Gas						Refining and Marketing                      (note 2)
For the years ended December 31 ($ millions)	2008		2007		2006		2008		2007		2006		2008		2007		2006
EARNINGS
Revenues (b)
Operating revenues	8 077		6 195		6 259		696		541		554		9 543		8 278		6 981
Energy marketing and trading activities	—		—		—		—		—		—		11 827		3 522		2 324
Net insurance proceeds	—		—		436		—		—		—		—		—		—
Intersegment revenues (c)	1 309		580		712		58		12		23		—		—		—
Interest	—		—		—		—		—		1		1		5		5
	9 386		6 775		7 407		754		553		578		21 371		11 805		9 310
Expenses
Purchases of crude oil and products	574		157		89		—		—		—		8 074		6 250		5 297
Operating, selling and general (note 2)	3 124		2 384		2 212		155		151		119		715		693		669
Energy marketing and trading activities	—		—		—		—		—		—		11 725		3 473		2 292
Transportation and other costs	229		138		162		17		15		16		29		29		25
Depreciation, depletion and amortization	580		462		385		225		189		152		202		171		132
Accretion of asset retirement obligations	55		40		28		8		7		5		1		1		1
Exploration	17		13		22		73		82		82		—		—		—
Royalties (note 5)	715		565		911		175		126		127		—		—		—
Taxes other than income taxes	111		90		75		5		4		3		562		553		516
Loss (gain) on disposal of assets	36		1		—		(22	)	(1	)	(4	)	6		7		3
Project start-up costs	35		60		38		—		—		—		—		8		7
Financing expenses (income)	—		—		—		—		—		—		—		—		—
	5 476		3 910		3 922		636		573		500		21 314		11 185		8 942
Earnings (loss) before income taxes	3 910		2 865		3 485		118		(20	)	78		57		620		368
Income taxes	(1 035	)	(391	)	(710	)	(29	)	45		28		(6	)	(176	)	(124	)
Net earnings (loss)	2 875		2 474		2 775		89		25		106		51		444		244
As at December 31
TOTAL ASSETS	25 795		18 172		13 727		1 862		1 811		1 503		4 666		4 825		4 219

(a)

Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.

(b)

There were no customers that represented 10% or more of the company's 2008, 2007 or 2006 consolidated revenues.

(c)

Intersegment revenues are recorded at prevailing fair market prices and accounted for as if the sales were to third parties.

See accompanying Summary of Significant Accounting Policies and Notes.

56 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

	Corporate and                      Eliminations						Total
For the years ended December 31 ($ millions)	2008		2007		2006		2008		2007		2006
EARNINGS
Revenues (b)
Operating revenues	20		6		4		18 336		15 020		13 798
Energy marketing and trading activities	(102	)	(7	)	(25	)	11 725		3 515		2 299
Net insurance proceeds	—		—		—		—		—		436
Intersegment revenues (c)	(1 367	)	(592	)	(735	)	—		—		—
Interest	27		25		7		28		30		13
	(1 422	)	(568	)	(749	)	30 089		18 565		16 546
Expenses
Purchases of crude oil and products	(1 464	)	(590	)	(716	)	7 184		5 817		4 670
Operating, selling and general (note 2)	50		112		66		4 044		3 340		3 066
Energy marketing and trading activities	(8	)	(6	)	(31	)	11 717		3 467		2 261
Transportation and other costs	—		—		—		275		182		203
Depreciation, depletion and amortization	42		42		26		1 049		864		695
Accretion of asset retirement obligations	—		—		—		64		48		34
Exploration	—		—		—		90		95		104
Royalties (note 5)	—		—		—		890		691		1 038
Taxes other than income taxes	1		1		1		679		648		595
Loss (gain) on disposal of assets	(7	)	—		—		13		7		(1	)
Project start-up costs	—		—		—		35		68		45
Financing expenses (income)	917		(211	)	39		917		(211	)	39
	(469	)	(652	)	(615	)	26 957		15 016		12 749
Earnings (loss) before income taxes	(953	)	84		(134	)	3 132		3 549		3 797
Income taxes	75		(44	)	(22	)	(995	)	(566	)	(828	)
Net earnings (loss)	(878	)	40		(156	)	2 137		2 983		2 969
As at December 31
TOTAL ASSETS	205		(299	)	(490	)	32 528		24 509		18 959

SUNCOR ENERGY INC. 2008ANNUAL REPORT 57

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Oil Sands						Natural Gas						Refining and Marketing               (note 2)
For the years ended December 31 ($ millions)			2008		2007		2006		2008		2007		2006		2008		2007		2006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		2 875		2 474		2 775		89		25		106		51		444		244
	Exploration expenses		—		—		—		61		67		52		—		—		—
	Non-cash items included in earnings
		Depreciation, depletion and amortization	580		462		385		225		189		152		202		171		132
		Future income taxes	535		108		725		15		(43	)	(28	)	(7	)	77		69
		Loss (gain) on disposal of assets	36		1		—		(22	)	(1	)	(4	)	6		7		3
		Stock-based compensation expense	60		49		25		4		5		2		19		25		13
		Other	(54	)	1		14		(4	)	7		1		2		(5	)	(7	)
	Increase (decrease) in deferred credits and other		(194	)	48		(21	)	—		(1	)	—		5		(3	)	(3	)
Total cash flow from (used in) operations			3 838		3 143		3 903		368		248		281		278		716		451
Decrease (increase) in operating working capital			603		586		440		42		22		(27	)	(30	)	(254	)	(110	)
Total cash from (used in) operating activities			4 441		3 729		4 343		410		270		254		248		462		341
Cash from (used in) investing activities:
Capital and exploration expenditures			(7 051	)	(4 431	)	(2 463	)	(339	)	(531	)	(458	)	(172	)	(376	)	(665	)
Deferred maintenance shutdown expenditures			(340	)	(135	)	—		(3	)	(6	)	—		(54	)	(73	)	(80	)
Deferred outlays and other investments			(39	)	(18	)	(2	)	—		—		—		(11	)	—		7
Proceeds from disposals			—		3		2		26		5		15		—		1		4
Proceeds from property loss			—		—		36		—		—		—		—		—		—
Decrease (increase) in investing working capital			434		333		197		—		—		—		(19	)	(43	)	(53	)
Total cash (used in) investing activities			(6 996	)	(4 248	)	(2 230	)	(316	)	(532	)	(443	)	(256	)	(491	)	(787	)
Net cash surplus (deficiency) before financing activities			(2 555	)	(519	)	2 113		94		(262	)	(189	)	(8	)	(29	)	(446	)

(a)

Accounting policies for segments are the same as those described in the Summary of Significant Accounting Policies.

See accompanying Summary of Significant Accounting Policies and Notes.

58 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Corporate and                      Eliminations						Total
For the years ended December 31 ($ millions)			2008		2007		2006		2008		2007		2006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		(878	)	40		(156	)	2 137		2 983		2 969
	Exploration expenses		—		—		—		61		67		52
	Non-cash items included in earnings
		Depreciation, depletion and amortization	42		42		26		1 049		864		695
		Future income taxes	(62	)	42		42		481		184		808
		Loss (gain) on disposal of assets	(7	)	—		—		13		7		(1	)
		Stock-based compensation expense	37		24		13		120		103		53
		Other	824		(236	)	(22	)	768		(233	)	(14	)
	Increase (decrease) in deferred credits and other		23		(10	)	(14	)	(166	)	34		(38	)
Total cash flow from (used in) operations			(21	)	(98	)	(111	)	4 463		4 009		4 524
Decrease (increase) in operating working capital			(616	)	(470	)	(263	)	(1	)	(116	)	40
Total cash from (used in) operating activities			(637	)	(568	)	(374	)	4 462		3 893		4 564
Cash from (used in) investing activities:
Capital and exploration expenditures			(28	)	(77	)	(27	)	(7 590	)	(5 415	)	(3 613	)
Deferred maintenance shutdown expenditures			—		—		—		(397	)	(214	)	(80	)
Deferred outlays and other investments			(1	)	(14	)	(2	)	(51	)	(32	)	3
Proceeds from disposals			7		—		—		33		9		21
Proceeds from property loss			—		—		—		—		—		36
Decrease (increase) in investing working capital			—		—		—		415		290		144
Total cash (used in) investing activities			(22	)	(91	)	(29	)	(7 590	)	(5 362	)	(3 489	)
Net cash surplus (deficiency) before financing activities			(659	)	(659	)	(403	)	(3 128	)	(1 469	)	1 075

SUNCOR ENERGY INC. 2008ANNUAL REPORT 59

SUNCOR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGES IN ACCOUNTING POLICIES

(a)   Inventories

On January 1, 2008 the company retroactively adopted the Canadian Institute of Chartered Accountants (CICA) Handbook section 3031 "Inventories". Under the new standard, the use of a LIFO (last-in, first-out) based valuation approach for inventory has been eliminated. 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. The company adopted a FIFO (first-in, first-out) based valuation approach for inventory effective January 1, 2008. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets

($ millions, increase/(decrease))	As at December 31 2008	As at December 31 2007
Inventories	110	404
Total assets	110	404
Future income taxes	30	121
Retained earnings	80	283
Total liabilities and shareholders' equity	110	404

Change in Consolidated Statements of Earnings (Loss) and Comprehensive Income

	Twelve months ended December 31
($ millions, increase/(decrease))	2008		2007		2006
Purchases of crude oil and products	270		(153	)	(5	)
Operating, selling and general	24		(51	)	14
Future income taxes	(91	)	53		(7	)
Net earnings (loss)	(203	)	151		(2	)
Per common share – basic (dollars)	(0.22	)	0.16		—
Per common share – diluted (dollars)	(0.22	)	0.16		—

(b)   Capital Disclosure

On January 1, 2008, the company adopted CICA Handbook section 1535 "Capital Disclosures". This section establishes disclosure requirements for management's policies and processes in defining and managing its capital. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard. See note 8 for disclosure of the new section.

(c)    Financial Instruments – Disclosures and Presentation

On January 1, 2008, the company adopted CICA Handbook sections 3862 "Financial Instruments – Disclosures" and 3863 "Financial Instruments – Presentation", which enhance existing disclosures for financial instruments. In particular, section 3862 focuses on the identification of risk exposures and the company's approach to management of these risks. There was no financial impact to previously reported financial statements as a result of the implementation of this new standard. See note 7 for disclosure of new sections.

2. CHANGE IN SEGMENTED DISCLOSURES

Consistent with the company's organizational restructuring during the first quarter of 2007, results from our Canadian and U.S. downstream refining and marketing 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. The results of company-wide energy marketing and trading activities will continue to be included in this segment. The financial results relating to the sales of oil sands and

60 SUNCOR ENERGY INC. 2008ANNUAL REPORT

natural gas production will continue to be reported in their respective business segments. There was no impact to consolidated net earnings as a result of the restructuring.

Effective January 1, 2007, the company began allocating stock-based compensation expense to each of the reportable business segments. Comparative figures have been reclassified to reflect the allocation of stock-based compensation. There was no impact to consolidated net earnings as a result of the allocation.

3. PROPERTY, PLANT AND EQUIPMENT

		2008		2007
($ millions)		Cost	Accumulated Provision	Cost	Accumulated Provision
Oil sands
	Plant	15 229	2 282	11 049	1 962
	Mine and mobile equipment	1 777	469	1 423	388
	In-situ properties	2 881	301	2 566	222
	Pipeline	149	40	149	35
	Capital leases	102	10	102	6
	Major projects in progress (1)	6 582	—	3 830	—
		26 720	3 102	19 119	2 613
Natural gas
	Proved properties	2 542	1 239	2 213	1 042
	Unproved properties	146	30	139	32
	Other support facilities and equipment	102	38	92	30
	Wells in progress	211	—	291	—
		3 001	1 307	2 735	1 104
Refining and marketing
	Refinery	2 973	754	2 699	628
	Marketing	844	330	783	304
	Pipeline	87	7	53	4
		3 904	1 091	3 535	936
Corporate		329	138	305	96
		33 954	5 638	25 694	4 749
Net property, plant and equipment			28 316		20 945

(1)

This balance only includes certain major projects in progress. Total assets under construction not being depreciated at December 31, 2008 is $11.1 billion (2007 – $6.3 billion).

4. DEFERRED CHARGES AND OTHER

($ millions)	2008	2007
Deferred maintenance shutdown costs	566	296
Deferred government tax credits	35	36
Unrealized mark to market gains	273	6
Other	101	66
Total deferred charges and other	975	404

5. ROYALTIES

The company's current estimation of Alberta Crown royalties is based on regulations that were in effect until the end of 2008. Alberta Crown royalties for each oil sands project require payments to the Government of Alberta based on annual gross revenues less related allowable transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. Royalty expense for the company's oil sands operations for the year ended December 31, 2008, was $715 million (2007 – $565 million, 2006 – $911 million). The balance of the consolidated royalty expense is in respect of natural gas royalties of $175 million (2007 – $126 million, 2006 – $127 million).

The New Royalty Framework changes enacted by the Government of Alberta will increase royalty rates, effective January 1, 2009 to a sliding scale of 25% – 40% of R-C, subject to a minimum royalty of 1%-9% depending on oil price. In both cases, the

SUNCOR ENERGY INC. 2008ANNUAL REPORT 61

sliding scale royalty would move with increases in WTI prices from the minimum rates at Cdn $55 to the maximum rates at a WTI price of Cdn $120.

The New Royalty Framework changes and the new sliding scale royalty rates outlined above apply to our Firebag in-situ project effective January 1, 2009.

In January 2008, the company entered into a Royalty Amending Agreement with the government of Alberta to transition our base oil sands mining operations to the New Royalty Framework rates in the New Royalty Framework. Commencing January 1, 2010 until December 31, 2015, the new royalty rates will apply to the bitumen royalty for current production levels, subject to a cap of 30% of R-C, and a minimum royalty of 1% to 1.2% of R. In addition, the Suncor Royalty Amending Agreement provides the company with a level of certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind, and certain taxes. In 2016 and subsequent years, the limitations on royalty rates and other matters will no longer apply and our base mine operations will be subject to royalty under the terms of the New Royalty Framework, unless it is amended or superseded prior to that time.

6. LONG-TERM DEBT

A.    Fixed-term debt, redeemable at the option of the company

($ millions)	2008		2007
6.85% Notes, denominated in U.S. dollars, due in 2039 (US$750) (i)	918		—
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150) (iii)	1 408		1 137
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	612		494
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	612		494
6.10% Notes, denominated in U.S. dollars, due in 2018 (US$1250) (i)	1 531		—
5.39% Series 4 Medium Term Notes, due in 2037 (iv)	600		600
5.80% Series 4 Medium Term Notes, due in 2018 (ii)	700		—
6.70% Series 2 Medium Term Notes, due in 2011 (v)	500		500
	6 881		3 225
Revolving-term debt, with interest at variable rates (see B. Credit facilities)
Commercial Paper (interest at December 31, 2008 – 2.2%, 2007 – 4.8%) (vi)	934		522
Total unsecured long-term debt	7 815		3 747
Secured long-term debt	13		1
Capital leases (vii), (viii)	103		102
Fair values of interest swaps	16		6
Deferred financing costs	(72	)	(45	)
Total long-term debt	7 875		3 811

(i)

In June 2008, the company issued 6.10% Notes with a principal amount of US$1.25 billion and 6.85% Notes with a principal amount of US$750 million under an amended US$3.65 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 1, 2018, and June 1, 2039, respectively. The net proceeds received were added to our general funds, which were used for our working capital needs, sustaining capital expenditures, growth capital expenditures and to repay outstanding commercial paper borrowings.

(ii)

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on May 22, 2018. The net proceeds received were added to our general funds to repay outstanding commercial paper, which originally funded our working capital needs, sustaining capital expenditures and growth capital expenditures.

(iii)

During the third quarter of 2007, the company issued additional 6.50% Notes with a principal amount of US$400 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 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 were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

(iv)

During the first quarter of 2007, 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 were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

(v)

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

	Principal Swapped		Effective Interest Rate
Description of Swap Transaction	($ millions)	Swap Maturity	2008	2007
Swap of 6.70% Medium Term Notes to floating rates	200	2011	4.8%	5.7%

62 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(vi)

The company is authorized to issue commercial paper to a maximum of $1,500 million having a term not to exceed 365 days. Commercial paper is supported by unutilized credit facilities (see B. Credit facilities).

(vii)

Equipment leases with interest rates between 6.5% and 13.4% and maturity dates ranging from 2009 to 2037.

(viii)

Future minimum amounts payable under capital leases and other long-term debt are as follows:

($ millions)	Capital Leases	Other Long-term Debt
2009	9	963 (a)
2010	9	—
2011	10	500
2012	10	—
2013	9	—
Later years	265	6 309
Total minimum payments	312	7 772
Less amount representing imputed interest	209
Present value of obligation under capital leases	103

(a)

Long-term debt due in the next year will be refinanced with available credit facilities

Long-term Debt (per cent)

	2008	2007
Variable rate	15	19
Fixed rate	85	81

B. Credit facilities

During 2008, the company's $330 million bilateral credit facility was amended and extended by one year to 2009 and the credit limit was increased by $150 million to $480 million total funds available. The company's $2 billion syndicated credit facility was renegotiated and extended by one year to have a five year term expiring in March 2013 and the credit limit was increased to $3.75 billion. Additionally, an $8 million demand credit facility was negotiated. At December 31, 2008, the company had available credit facilities of $4,283 million, of which $3,030 million was undrawn as follows:

($ millions)	2008
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2009	480
Facility that is fully revolving for a period of five years and expires in 2013	3 750
Facilities that can be terminated at any time at the option of the lenders	53
Total available credit facilities	4 283
Credit facilities supporting outstanding commercial paper	934
Credit facilities supporting standby letters of credit	319
Total undrawn credit facilities	3 030

7. FINANCIAL INSTRUMENTS AND FINANCIAL RISK FACTORS

Derivatives are financial instruments that either imitate or counter the price movements of stocks, bonds, currencies, commodities and interest rates. Suncor uses derivatives to reduce (hedge) its exposure to fluctuations in commodity prices and foreign currency exchange rates and to manage interest rate or currency-sensitive assets and liabilities. Suncor also uses derivatives for trading purposes. When used in a trading activity, the company is attempting to realize a gain on the fluctuations in the market value of the derivative.

Forwards and futures are contracts to purchase or sell a specific item at a specified date and price. When used as hedges, forwards and futures help to manage the exposure to losses that could result if commodity prices, foreign currency exchange rates, or interest rates change adversely.

An option is a contract where its holder, for a fee, has purchased the right (but not the obligation) to buy or sell a specified item at a fixed price during a specified period. Options used as hedges help to protect against adverse changes in commodity prices, interest rates, or foreign currency exchange rates.

A costless collar is a combination of two option contracts that limit the holder's exposure to changes in prices to within a specific range. The "costless" nature of this derivative is achieved by buying a put option (the right to sell) for consideration equal to the premium received from selling a call option (the right to purchase).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 63

A swap is a contract where two parties exchange commodity, currency, interest or other payments in order to alter the nature of the payments. For example, fixed interest rate payments on debt may be converted to payments based on a floating interest rate.

Hedge accounting is a method for recognizing the gains, losses, revenues and expenses associated with the items in a hedging relationship at the time when the underlying transaction impacts earnings. Suncor has elected to use hedge accounting on certain derivatives linked to future commodity and financial transactions.

See below for more technical details and amounts.

Financial Instruments

(a)   Balance Sheet Financial Instruments

The company's financial instruments in the Consolidated Balance Sheets 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 future income taxes), 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 recognized financial instruments have been determined based on the company's assessment of available market information and appropriate valuation methodologies based on industry accepted third-party models; however, these estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

The company's fixed-term debt is accounted for under the amortized cost method. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. Gains or losses on our U.S. dollar denominated long-term debt resulting from changes in the exchange rate are recognized in the period in which they occur. At December 31, 2008, the carrying value of our fixed-term debt accounted for under the amortized cost method was $6.7 billion (December 31, 2007 – $3.0 billion) and the fair value at December 31, 2008 was $5.4 billion (December 31, 2007 – $3.1 billion).

(b)   Hedges – Documented as Part of a Qualifying Hedge Relationship

Fair Value Hedges

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage its exposure to benchmark interest rate fluctuations. The interest rate swap contracts involve an exchange of floating rate versus fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in earnings as an adjustment to interest expense. The fair value of the underlying debt is adjusted by the fair value change in the derivative financial instrument with the offset to interest expense. At December 31, 2008, the company had interest rate swaps classified as fair value hedges outstanding for up to three years relating to fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the twelve month period ended December 31, 2008 (no ineffectiveness during the twelve month period ended December 31, 2007). The fair value of interest rate swap contracts outstanding at December 31, 2008 is detailed in note 6, Long-term debt.

The company periodically enters into derivative contracts to hedge risks specific to individual transactions. The differentials between the fair value of the hedged transactions and the fair value of the derivative contracts are recognized in earnings as an adjustment to operating revenues. The earnings impact associated with hedge ineffectiveness on derivative contracts to hedge risks specific to individual transactions during the twelve month period ended December 31, 2008 was a loss of $4 million, net of income taxes of $2 million (2007 – gain of $4 million, net of income taxes of $2 million).

Cash Flow Hedges

The company operates in a global industry where the market price of its petroleum and natural gas products is largely determined based on floating benchmark indices. The company periodically enters into derivative financial instrument 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. Specifically, the company manages crude sales price variability by entering into West Texas Intermediate (WTI) derivative transactions, and manages variability in market interest rates and foreign exchange rates during periods of debt issuance through the use of interest rate locks and foreign exchange forward contracts.

64 SUNCOR ENERGY INC. 2008ANNUAL REPORT

At December 31, 2008, the company had hedged a portion of its forecasted cash flows subject to natural gas price risk for the first quarter of 2009 related to our refinery natural gas consumption.

There was no earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the twelve month period ended December 31, 2008 (2007 – loss of $5 million, net of income taxes of $2 million).

Certain derivative contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company's sales revenues or crude oil purchase costs. For collars, if market rates are not different than, or are within the range of contract prices, the options contracts making up the collar will expire with no exchange of cash.

Contracts outstanding at December 31, were as follows:

Revenue Hedges

Strategic Crude Oil	Quantity (bpd)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007
Costless collars	10 000	59.85 – 101.06	216 – 365	2008
As at December 31, 2006
Costless collars	60 000	51.64 – 93.26	1 318 – 2 380	2007
Costless collars	10 000	59.85 – 101.06	255 – 431	2008

Natural Gas	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007	—	—	—	—
As at December 31, 2006
Swaps	4 000	6.11	9	2007

Consumption Hedges	Quantity (MMBtu/day)	Average Price (US$/MMBtu)	Consumption Hedged (Cdn$ millions) (b)	Hedge Period (c)
As at December 31, 2008
Natural Gas – fixed price purchases	25 000	6.92	19	2009	(d)
As at December 31, 2007	—	—	—	—
As at December 31, 2006	—	—	—	—

Foreign Currency Hedges	Notional (Euro Millions)	Average Forward Rate	Dollars Hedged (Cdn$ millions)	Hedge Period (c)
As at December 31, 2008	—	—	—	—
As at December 31, 2007	—	—	—	—
As at December 31, 2006
Euro/Cdn forward	20.6	1.41	29.0	2007	(e)

(a)

Average price for crude costless collars is US$ WTI per barrel at Cushing, Oklahoma.

(b)

The revenue and consumption hedged is translated to Cdn$ at the respective year-end exchange rate for convenience purposes.

(c)

Original hedge term is for the full year unless otherwise noted.

(d)

For the period January to March 2009, inclusive.

(e)

Settlement for applicable forwards occurring within the period April to September 2007.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 65

Fair Value of Hedging Derivative Financial Instruments

The fair value of hedging derivative financial instruments as recorded, is the estimated amount that the company would receive (pay) to terminate the hedging derivative contracts. Such amounts, which also represent the unrealized gain (loss) on the contracts, were as follows:

($ millions)	December 31 2008		December 31 2007
Revenue and consumption hedges	(2	)	(11	)
Fixed to floating interest rate swaps	24		8
Specific hedges of individual transactions	(11	)	12
Fair value of outstanding hedging derivative financial instruments	11		9

Accumulated Other Comprehensive Income (AOCI)

A reconciliation of changes in AOCI attributable to derivative hedging activities for the twelve month period ending December 31 is as follows:

($ millions)	2008		2007
AOCI attributable to derivative hedging activities, beginning of the period, net of income taxes of $4 (2007 – $5)	13		8
Current year net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1)	(7	)	8
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $3 (2007 – $2)	7		(3	)
AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2007 – $4)	13		13

(c)    Hedges – Not Documented as Part of a Qualifying Hedge Relationship

The company also periodically enters into derivative financial instruments such as options, basis swaps, and heat rate swaps that either do not qualify for hedge accounting treatment or hedges that the company has not elected to document as part of a qualifying hedge relationship. These financial instruments are accounted for using the mark-to-market method and, as such, these derivative instruments are recorded at fair value at each balance sheet date. The earnings impact associated with these contracts for the twelve month period ended December 31, 2008, was a gain of $348 million, net of income taxes of $142 million (2007 – a loss of $3 million, net of income taxes of $1 million).

Significant contracts outstanding at December 31, 2008 were as follows:

Crude Oil (d)	Quantity (bpd)	Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Purchased puts	55 000	60.00	1 475	2009
Purchased puts	55 000	60.00	1 475	2010

(a)

Price for crude puts is US$ WTI per barrel at Cushing, Oklahoma.

(b)

The revenue hedged is translated to Cdn$ at the December 31, 2008 exchange rate for convenience purposes.

(c)

Original hedge term is for the full year.

(d)

Premiums paid was US$59 million.

For information on significant contracts entered into subsequent to December 31, 2008, see page 77.

(d)   Energy Marketing and Trading Activities

In addition to the financial derivatives used for hedging activities, the company uses physical and financial energy contracts, including swaps, forwards and options to earn trading and marketing revenues. These energy contracts are comprised of crude oil, natural gas and refined products contracts. Financial energy trading activities are accounted for using the mark-to-market method. Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. The results of these activities are reported as revenue and as energy marketing and trading expenses in the

66 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Consolidated Statements of Earnings and Comprehensive Income. Net pretax earnings (loss) for the twelve month period ended December 31 for our energy and trading activities in our refining and marketing segment were as follows:

Net Pretax Earnings (Loss)

($ millions)	2008		2007		2006
Physical energy contracts trading activity	100		57		38
Financial energy contracts trading activity	7		(4	)	(3	)
General and administrative costs	(5	)	(4	)	(3	)
Total	102		49		32

(e)   Fair Value of Non-Designated Derivative Financial Instruments

The fair value of unsettled (unrealized) energy derivative assets and liabilities, which includes all financial contracts referenced in section (c) & (d) above are as follows:

($ millions)	December 31 2008	December 31 2007
Energy trading assets(a)	635	18
Energy trading liabilities(b)	14	21
Net energy trading assets (liabilities)	621	(3	)

(a)

As at December 31, 2008, $376 million is recorded in accounts receivable (2007 – $18 million) and $259 million is recorded in deferred charges and other (2007 – nil) in the Consolidated Balance Sheets.

(b)

As at December 31, 2008, $14 million is recorded in accrued liabilities and other (2007 – $21 million) in the Consolidated Balance Sheets.

Change in fair value of net assets

($ millions)	2008
Fair value of contracts at December 31, 2007	(3	)
Fair value of contracts realized during the period	(53	)
Fair value of contracts entered into during the period	673
Changes in fair value during the period	4
Fair value of contracts outstanding at December 31, 2008	621

Financial Risk Factors

The company is exposed to a number of different financial risks arising from normal course business exposures, as well as the company's use of financial instruments. These risk factors include market risks relating to commodity prices, foreign currency risk and interest rate risk, as well as liquidity risk and credit risk.

The company maintains a formal governance process to manage its financial risks. Our Risk Management Committee (RMC) is charged with the oversight of the company's risk management for trading risk management activities which are defined as strategic hedging, optimization trading, marketing and speculative trading. The RMC, acting under board authority, meets regularly to monitor limits on risk exposures, review policy compliance and validate risk-related methodologies and procedures. All risk management activity is carried out by specialist teams that have the appropriate skills, experience and supervision with the appropriate financial and management controls, and is unchanged from the prior year.

1) Market Risk

Market risk is the risk or uncertainty arising from possible market price movements and their impact on the future performance of the business. The market price movements that could adversely affect the value of the company's financial assets, liabilities and expected future cash flows include commodity price risk (crude oil, natural gas and electricity price), foreign currency exchange risk and interest rate risk.

(a)   Commodity Price Risk

The company's financial performance is closely linked to crude oil prices (including pricing differentials for various product types), and to a lesser extent, natural gas and electricity prices. The company's policies permit the use of various financial instruments in managing these price exposures. Our strategic crude oil hedging program gives management approval to fix a price or range of

SUNCOR ENERGY INC. 2008ANNUAL REPORT 67

prices for portions of the total crude oil planned production for specified periods of time. Historically, the company has leveraged hedging instruments to stabilize cash flows during periods of growth and expansion. The company will consider additional strategic hedging opportunities as they become available.

A key component of our overall business strategy is to produce sufficient natural gas to meet or exceed internal demands for natural gas purchased for consumption in our oil sands operation, thus creating a price hedge which reduces our exposure to natural gas price volatility. In addition, existing corporate policies also permit the hedging of natural gas exposures to manage regional price differentials and pricing indexes as identified.

Changes in commodity prices on our financial contracts would have the following impact on our net earnings and other comprehensive income for the twelve months ended December 31, 2008:

Sensitivity Analysis

($ millions)		December 31, 2008 (1)	Change	Net Earnings		Other Comprehensive Income
Crude Oil		US$63.38/barrel
	Price increase		US$1.00/barrel	(32	)	—
	Price decrease		US$1.00/barrel	32		—
Natural Gas		US$6.22/mcf
	Price increase		US$0.10/mcf	(1	)	—
	Price decrease		US$0.10/mcf	1		—

(1)

Prices represent the average of the forward strip prices at December 31, 2008.

(b)   Foreign Currency Exchange Risk

The company is exposed to changes in foreign exchange rates as revenues, capital expenditures, or financial instruments may fluctuate due to changing rates. As crude oil, the company's primary product, is priced in U.S. dollars, fluctuations in US$/Cdn$ exchange rates may have a significant impact on revenues. The company's exposure is partially offset through the issuance of U.S. dollar denominated long-term debt (refer to note 6) and by sourcing capital projects in U.S. dollars. The company does not currently hedge foreign currency risk on estimated revenues. The effect of a $0.01 change in the US$/Cdn$ exchange rate on our U.S. dollar denominated long-term debt would change after-tax earnings by approximately $55 million for the twelve months ended December 31, 2008.

Where an operating unit has substantial exposure to capital expenditures in currencies other than the U.S. dollar, the company may hedge these risks through a combination of forward and option instruments. Transactions in the applicable financial market are executed consistent with established risk management policies.

(c)    Interest Rate Risk

The company is exposed to interest rate risk as changes in interest rates may affect future cash flows and the fair values of its financial instruments. The primary exposure is related to notes and commercial paper. The company seeks to optimize this risk through the use of interest rate swaps by swapping fixed rates of interest for variable rates (see – fair value hedges) and other derivative instruments.

To optimize the company's position with respect to interest expense, the company targets 30% to 50% of total debt to be exposed to floating interest rates. Over time this floating/fixed rate mix will fluctuate based on prevailing market conditions and management's assessment of overall risk.

The proportion of floating interest rate exposure inclusive of interest rate swaps at December 31, 2008 was 15% of total debt outstanding (December 31, 2007 was 19% of total debt outstanding). The weighted average interest rate on total debt for the year ending December 31, 2008 was 5.9% (December 31, 2007 – 6.1%).

The company's cash flows are sensitive to changes in interest rates on the floating rate portion of the company's debt. Given our current growth and expansion plans, all interest is currently being capitalized and therefore there is no earnings impact. If the interest rates applicable to floating rate instruments were to have increased by 1%, it is estimated that the company's cash flow for the twelve months ended December 31, 2008 would decrease by approximately $11 million. This assumes that the amount and mix of fixed and floating rate debt remains unchanged from December 31, 2008, and that the change in interest rates is effective from the beginning of the period.

68 SUNCOR ENERGY INC. 2008ANNUAL REPORT

2) Liquidity Risk

Liquidity risk is the risk that an entity will encounter difficulty in meeting obligations associated with financial liabilities. The company believes that it has access to sufficient capital through internally generated cash flows and external sources (bank credit markets and debt capital markets), and to undrawn committed borrowing facilities to meet current spending forecasts.

Surplus cash is invested into a range of short-dated money market securities and the company seeks to ensure the security and liquidity of those investments. Investments are only permitted in high credit quality government or corporate securities. Diversification of these investments is supported through maintaining counterparty credit limits.

The following table shows the timing of cash outflows relating to trade and other payables and finance debt.

	December 31, 2008		December 31, 2007
($ millions)	Trade and other payables (1)	Finance debt (2)	Trade and other payables (1)	Finance debt (2)
Within one year	3 181	1 378	2 843	764
1 to 3 years	335	1 377	347	427
3 to 5 years	—	822	—	917
Over 5 years	16	13 387	19	6 985
Total	3 532	16 964	3 209	9 093

(1)

These balances exclude non-financial liabilities (pension liabilities, asset retirement obligation, future income taxes and derivative financial instruments) totaling $1,972 million and $1,375 million at December 31, 2008 and December 31, 2007 respectively.

(2)

Finance debt includes long-term debt, capital leases and interest payments on fixed-term debt and commercial paper.

3) Credit Risk

Credit risk is the risk that a customer or counterparty will fail to perform an obligation or fail to pay amounts due causing a financial loss. We have a credit policy that is designed to ensure there is a standard credit practice throughout the company to measure and monitor credit risk. The policy outlines delegation of authority, the due diligence process required to approve a new customer or counterparty and the maximum amount of credit exposure per single entity. Before transactions begin with a new customer or counterparty, its creditworthiness is assessed, a credit rating is assigned and a maximum credit limit is allocated. The assessment process is outlined in the credit policy and considers both quantitative and qualitative factors. The company constantly monitors the exposure to any single customer or counterparty along with the financial position of the customer or counterparty. If it is deemed that a customer or counterparty has become materially weaker, the company will work to reduce the credit exposure and lower the credit limit allocated. Regular reports are generated to monitor credit risk and the Credit Committee meets quarterly to ensure compliance with the credit policy and review the exposures.

A substantial portion of the company's accounts receivable are with customers in the oil and gas industry and are subject to normal industry credit risk. At December 31, 2008 and December 31, 2007, substantially all of the company's trade receivables were current, and there were no counterparties that individually constituted more than 10% of the outstanding balance.

The company may be exposed to certain losses in the event that counterparties to derivative financial instruments are unable to meet the terms of the contracts. The company's exposure is limited to those counterparties holding derivative contracts with positive fair values at the reporting date. At December 31, 2008, the company's exposure was $659 million (December 31, 2007 – $38 million).

8. CAPITAL STRUCTURE FINANCIAL POLICIES

The company's primary capital management objective is to maintain a solid investment-grade credit rating profile. This objective affords the company the financial flexibility and access to the capital it requires to execute on its growth objectives.

The company monitors capital through two key ratios: net debt to cash flow from operations and total debt to total debt plus shareholders' equity.

Net debt to cash flow from operations is calculated as short-term debt plus long-term debt less cash and cash equivalents divided by cash flow from operations for the year then ended.

Total debt to total debt plus shareholders' equity is calculated as short-term debt plus long-term debt divided by short-term debt plus long-term debt plus shareholders' equity.

The company's strategy during 2008, which was unchanged from 2007, was to maintain the measures set out in the following schedule. The company believes that maintaining our capital targets helps to provide the company access to capital at a

SUNCOR ENERGY INC. 2008ANNUAL REPORT 69

reasonable cost by maintaining solid investment-grade credit ratings. The company operates in a cyclical business environment and manages this through the business cycle.

At December 31, ($ millions)			Capital Measure Target	2008		2007
Components of ratios
	Short-term debt			11		6
	Long-term debt			7 875		3 811
		Total debt		7 886		3 817
	Cash and equivalents			660		569
		Net debt		7 226		3 248
	Shareholders' equity			14 523		11 896
	Total capitalization (total debt + shareholders' equity)			22 409		15 713
	Cash flow from operations			4 463		4 009
Net debt/cash flow from operations			<2.0 times	1.6		0.8
Total debt/total debt plus shareholders' equity				35	%	24 %

9. ACCRUED LIABILITIES AND OTHER

($ millions)	2008	2007
Asset retirement obligations (a)	1 444	882
Employee future benefits liability (see note 10)	191	176
Employee and director incentive plans (b)	67	173
Deferred revenue	161	164
Environmental remediation costs (c)	7	11
Other	116	28
Total	1 986	1 434

(a)   Asset Retirement Obligations (ARO)

The following table presents the reconciliation of the beginning and ending aggregate carrying amount of the total obligations associated with the retirement of property, plant and equipment.

($ millions)	2008		2007
Asset retirement obligations, beginning of year	1 072		808
Liabilities incurred	598		275
Liabilities settled	(134	)	(59	)
Accretion of asset retirement obligations	64		48
Asset retirement obligations, end of year	1 600		1 072

The portion of the ARO expected to be paid within one year is shown within current liabilities and amounts to an additional $156 million (2007 – $190 million).

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2008, was approximately $3.5 billion (2007 – $2.2 billion). The liability recognized in 2008 was discounted using the company's credit-adjusted risk-free rate of 9.0% (2007 – 6.0%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 30 years.

A significant portion of the company's assets, including the upgrading facilities at the oil sands operation and the two downstream refineries located in Sarnia and Commerce City, have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.

(b)   Employee and Director Incentive Plans

The portion of the employee and director incentive plans expected to be paid within one year is shown within current liabilities and amounts to an additional $8 million (2007 – $50 million).

70 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(c)    Environmental Remediation Costs

The portion of the environmental remediation costs expected to be paid within one year is shown within current liabilities and amounts to an additional $16 million (2007 – $19 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

10. EMPLOYEE FUTURE BENEFITS LIABILITY

Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire. The related Benefit Obligation or commitment that Suncor has to employees and retirees at December 31, 2008, was $955 million (2007 – $1,063 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of the pension obligations. The company funds its unregistered supplementary pension plan and supplementary senior executive retirement plan on a voluntary basis. The amount and timing of future funding for these supplementary plans is subject to capital availability and is at the company's discretion. At the end of December 2008, Plan Assets to meet the Benefit Obligation were $613 million (2007 – $684 million).

The excess of the Benefit Obligation over Plan Assets of $342 million (2007 – $379 million) represents the Net Unfunded Obligation.

See below for more technical details and amounts.

Defined Benefit Pension Plans and Other Post-Retirement Benefits

The company's defined benefit pension plans provide non-indexed pension benefits at retirement based on years of service and final average earnings. These obligations are met through funded registered retirement plans and through unregistered supplementary pensions and senior executive retirement plans that are voluntarily funded through retirement compensation arrangements, and/or paid directly to recipients. Company contributions to the funded plans are deposited with independent trustees who act as custodians of the plans' assets, as well as the disbursing agents of the benefits to recipients. Plan assets are managed by a pension committee on behalf of beneficiaries. The committee retains independent managers and advisors.

Funding of the registered retirement plans complies with applicable regulations that require actuarial valuations of the pension funds at least once every three years in Canada, depending on funding status, and every year in the United States. The most recent valuation for the Canadian plan was performed as at December 31, 2006.

The company's other post-retirement benefits programs are unfunded and include certain health care and life insurance benefits provided to retired employees and eligible surviving dependants.

The expense and obligations for both funded and unfunded benefits are determined in accordance with Canadian GAAP and actuarial principles. Obligations are based on the projected benefit method of valuation that includes employee service to date and present pay levels, as well as a projection of salaries and service to retirement.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 71

Obligations and Funded Status

The following table presents information about obligations recognized in the Consolidated Balance Sheets and the funded status of the plans at December 31:

		Pension Benefits				Other                      Post-Retirement                      Benefits
($ millions)		2008		2007		2008		2007
Change in benefit obligation
	Benefit obligation at beginning of year	901		866		162		158
	Service costs	56		51		4		4
	Interest costs	49		45		9		8
	Plan participants' contributions	9		5		—		—
	Foreign exchange	8		(5	)	4		(2	)
	Actuarial (gain) loss	(168	)	(28	)	(27	)	(3	)
	Benefits paid	(49	)	(33	)	(3	)	(3	)
Benefit obligation at end of year (a)(d)		806		901		149		162
Change in plan assets (b)
	Fair value of plan assets at beginning of year	684		616		—		—
	Actual return (loss) on plan assets	(107	)	7		—		—
	Employer contributions	69		88		—		—
	Foreign exchange	4		(2	)	—		—
	Plan participants' contributions	9		5		—		—
	Benefits paid	(46	)	(30	)	—		—
Fair value of plan assets at end of year (d)		613		684		—		—
Net unfunded obligation		(193	)	(217	)	(149	)	(162	)
Items not yet recognized in earnings:
	Unamortized net actuarial loss (c)	123		158		12		43
	Unamortized past service costs	—		—		(17	)	(20	)
Accrued benefit liability		(70	)	(59	)	(154	)	(139	)
	Current liability	(37	)	(41	)	(3	)	(3	)
	Long-term liability	(40	)	(40	)	(151	)	(136	)
	Long-term asset	7		22		—		—
Total accrued benefit liability		(70	)	(59	)	(154	)	(139	)

(a)

Obligations are based on the following assumptions:

	Pension Benefit               Obligations		Other Post-Retirement               Benefits Obligations
(percent)	2008	2007	2008	2007
Discount rate	6.50	5.25	6.50	5.25
Rate of compensation increase	5.00	5.00	4.75	4.75

A one percent change in the assumptions at which pension benefits and other post-retirement benefits liabilities could be effectively settled is as follows:

	Rate of Return        on Plan Assets			Discount Rate			Rate of Compensation        Increase
($ millions)	1% increase		1% decrease	1% increase		1% decrease	1% increase	1% decrease
Increase (decrease) to net periodic benefit cost	(6	)	6	(23	)	27	11	(9	)
Increase (decrease) to benefit obligation	—		—	(127	)	150	32	(29	)

In order to measure the expected cost of other post-retirement benefits, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2008 (2007 – 9%; 2006 – 9.5%). It is assumed that this rate will remain constant in 2009 and will decrease by 0.5% annually, to 5% by 2017, and remain at that level thereafter.

Assumed health care cost trend rates may have a significant effect on the amounts reported for other post-retirement benefit obligations. A one percent change in assumed health care cost trend rates would have the following effects:

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

72 SUNCOR ENERGY INC. 2008ANNUAL REPORT

(b)

Pension plan assets are not the company's assets and therefore are not included in the Consolidated Balance Sheets.

(c)

The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 11 years for pension benefits (2007 – 11 years; 2006 – 11 years), and over the expected average future service life to full eligibility age of 11 years for other post-retirement benefits (2007 – 12 years; 2006 – 10 years).

(d)

The company uses a measurement date of December 31 to value the plan assets and accrued benefit obligation.

The above benefit obligation at year-end includes partially funded and unfunded plans, as follows:

	Pension Benefits		Other                      Post-Retirement                      Benefits
($ millions)	2008	2007	2008	2007
Partially funded plans	806	901	—	—
Unfunded plans	—	—	149	162
Benefit obligation at end of year	806	901	149	162

Components of Net Periodic Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other                      Post-Retirement Benefits
($ millions)	2008		2007		2006		2008	2007	2006
Current service costs	56		51		44		4	4	5
Interest costs	49		45		40		9	8	8
Expected return on plan assets (ii)	(45	)	(42	)	(32	)	—	—	—
Amortization of net actuarial loss	22		25		28		3	3	1
Net periodic benefit cost recognized (iii)	82		79		80		16	15	14

Components of Net Incurred Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other                      Post-Retirement Benefits
($ millions)	2008		2007		2006		2008		2007		2006
Current service costs	56		51		44		4		4		5
Interest costs	49		45		40		9		8		8
Actual (return) loss on plan assets (ii)	107		(7	)	(60	)	—		—		—
Actuarial (gain) loss	(168	)	(28	)	67		(27	)	(4	)	5
Net incurred benefit cost	44		61		91		(14	)	8		18

(i)

The net periodic benefit cost includes certain accounting adjustments made to allocate costs to the periods in which employee services are rendered, consistent with the long-term nature of the benefits. Costs actually incurred in the period (arising from actual returns on plan assets and actuarial gains and losses in the period) differ from allocated costs recognized.

(ii)

The expected return on plan assets is the expected long-term rate of return on plan assets for the year. It is based on plan assets at the beginning of the year that have been adjusted on a weighted-average basis for contributions and benefit payments expected for the year. The expected return on plan assets is included in the net periodic benefit cost for the year to which it relates, while the difference between it and the actual return realized on plan assets in the same year is amortized over the expected average remaining service life of employees of 11 years for pension benefits.

To estimate the expected long-term rate of return on plan assets, the company considered the current level of expected returns on the fixed income portion of the portfolio, the historical level of the risk premium associated with other asset classes in which the portfolio is invested and the expectation for future returns on each asset class. The expected return for each asset class was weighted based on the policy asset mix to develop an expected long-term rate of return on asset assumption for the portfolio.

(iii)

Pension expense is based on the following assumptions:

	Pension               Benefit Expense			Other Post-Retirement               Benefits Expense
(percent)	2008	2007	2006	2008	2007	2006
Discount rate	5.25	5.00	5.00	5.25	5.00	5.00
Expected return on plan assets	6.50	6.50	6.50	N/A	N/A	N/A
Rate of compensation increase	5.00	5.00	4.50	4.75	4.75	4.25

SUNCOR ENERGY INC. 2008ANNUAL REPORT 73

Plan Assets and Investment Objectives

The company's long-term investment objective is to secure the defined pension benefits while managing the variability and level of its contributions. The portfolio is rebalanced periodically as required, while ensuring that the maximum equity content is 65% at any time. Plan assets are restricted to those permitted by legislation, where applicable. Investments are made through pooled, mutual, segregated or exchange traded funds.

The company's weighted-average pension plan asset allocation based on market values as at December 31, 2008 and 2007, and the target allocation for 2009, are as follows:

	Target Allocation %	Plan Assets %
Asset Category	2009	2008	2007
Equities	60	57	58
Fixed income	40	43	42
Total	100	100	100

Equity securities do not include any direct investments in Suncor shares.

Cash Flows

The company expects that contributions to its pension plans in 2009 will be $76 million, including approximately $10 million for the company's supplemental executive and supplemental retirement plans. Expected benefit payments from all of the plans are as follows:

	Pension Benefits	Other Post-Retirement Benefits
2009	42	6
2010	45	6
2011	47	7
2012	50	8
2013	54	9
2014 – 2018	318	51
Total	556	87

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and a U.S. 401(k) savings plan, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $15 million in 2008 (2007 – $13 million; 2006 – $11 million).

74 SUNCOR ENERGY INC. 2008ANNUAL REPORT

11. INCOME TAXES

The assets and liabilities shown on Suncor's balance sheets are calculated in accordance with Canadian GAAP. Suncor's income taxes are calculated according to government tax laws and regulations, which results in different values for certain assets and liabilities for income tax purposes. These differences are known as temporary differences, because eventually these differences will reverse.

The amount shown on the balance sheets as future income taxes represent income taxes that will eventually be payable or recoverable in future years when these temporary differences reverse.

See below for more technical details and amounts.

The provision for income taxes reflects an effective tax rate that differs from the statutory tax rate. A reconciliation of the provision for income taxes is as follows:

		2008		2007		2006
($ millions)		Amount		Amount		Amount
Federal tax rate		924		1 119		1 253
Provincial abatement		(313	)	(308	)	(380	)
Federal surtax		—		34		43
Provincial tax rates		314		325		394
Statutory tax		925		1 170		1 310
Adjustment of statutory rate for future rate reductions		(101	)	(151	)	(150	)
		824		1 019		1 160
Add (deduct) the tax effect of:
	Capital gains and losses	136		(40	)	—
	Stock-based compensation	36		33		18
	Other	47		(18	)	16
	Assessments and adjustments	(48	)	(1	)	(9	)
	Tax rate changes on opening future income taxes (a)	—		(427	)	(419	)
	Crown royalties	—		—		125
	Large corporations tax	—		—		2
	Attributed Canadian royalty income	—		—		(23	)
	Resource allowance (b)	—		—		(42	)
Total provision for income taxes		995		566		828
Effective Rate		32	%	16	%	22	%

(a)

During 2007, the federal government enacted tax rate reductions totalling $427 million. During the fourth quarter of 2007 the federal government substantively enacted a 3.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $360 million related to the revaluation of its opening future income tax balances. During the second quarter of 2007 the federal government substantively enacted a 0.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $67 million related to the revaluation of its opening future income tax balances.

During 2006, there were both federal and provincial government rate reductions totalling $419 million. During the second quarter of 2006 the federal government substantively enacted a 3.1% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $292 million related to the revaluation of its opening future income tax balances. As well, the provincial government of Alberta substantively enacted a 1.5% reduction to its provincial corporate tax rates during the second quarter of 2006. Accordingly, the company recognized a reduction in future income tax expense of $127 million related to the revaluation of its opening future income tax balances.

(b)

The resource allowance was a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by GAAP in Canada, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate. Resource allowance has been phased out effective January 1, 2007.

In 2008, net income tax payments totalled $638 million (2007 – $152 million; 2006 – $36 million).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 75

At December 31, future income taxes were comprised of the following:

($ millions)		2008		2007
Future income tax liabilities:
	Excess of book values of assets over tax values	4 987		4 467
	Risk management	149		—
	Other	48		86
Future income tax assets:
	Asset retirement obligations	(400	)	(269	)
	Employee future benefits	(72	)	(118	)
	Inventories	(7	)	37
Net Future income tax liabilities		4 705		4 203
Less: Current portion of future income tax assets & liabilities		90		(9	)
Future income tax liabilities		4 615		4 212

12. COMMITMENTS, CONTINGENCIES, VARIABLE INTEREST ENTITIES, GUARANTEES AND SUBSEQUENT EVENT

(a)   Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2008, future minimum amounts payable under these leases and agreements are as follows:

($ millions)	Pipeline Capacity and Energy Services (1)	Operating Leases
2009	327	56
2010	341	49
2011	421	39
2012	409	28
2013	412	24
Later years	5 826	176
Total	7 736	372

(1)

Includes annual tolls payable under transportation service agreements with major pipeline companies to use a portion of their pipeline capacity and tankage, as applicable, for transportation of product within Canada and the USA.

Suncor has commitments under long-term energy agreements to obtain a portion of the power and the steam generated by certain cogeneration facilities owned by a major third-party energy company. Since October 1999, this third-party has also managed the operations of Suncor's existing energy services facility at its oil sands operations.

At December 31, 2008, Suncor had purchase commitments relating to crude oil predominately for refinery supply and natural gas for physical trading. Crude oil commitments consisted of market price evergreen contracts for a total volume of 148,000 barrels per day of crude oil (2007 – 148,000 bbls/day), of which most have industry standard 30-day cancellation clauses. Natural gas commitments consist of fixed price contracts with a total volume of 8 million GJ (2007 – 14 million) within a price range of Cdn $5.80 – $9.47 per GJ (2007 – $6.00-$7.67 per GJ) and having terms extending to December 2009 (2007 – December 2008), as well as market price contracts for a total volume of 17 million GJ (2007 – 40 million GJ) with terms extending to October 2009 (2007 – April 2009).

(b)   Contingencies

The company is subject to various regulatory and statutory requirements relating to the protection of the environment. These requirements, in addition to contractual agreements and management decisions, result in the recognition of estimated asset retirement obligations. Estimates of asset retirement obligation costs can change significantly based on such factors as operating experience and changes in legislation and regulations.

The company carries both property damage and business interruption insurance policies with a combined coverage limit of up to US$1.6 billion, net of deductible amounts or waiting periods. The primary property loss policy of US$250 million has a deductible of US$10 million per incident. Suncor has 100% ownership interest in Fort Insurance Limited, an insurance company which provides coverage to Suncor including business interruption coverage for oil sands with a limit of US$150 million and a deductible of the greater of 30 days or US$50 million. The excess coverage of US$1.2 billion can be used for either property damage or business interruption coverage for oil sands operations. Excess business interruption coverage begins the greater of

76 SUNCOR ENERGY INC. 2008ANNUAL REPORT

90 days from the date of the incident or US$250 million in gross earnings lost. For the purposes of determining loss for business interruption claims, the excess coverage has a ceiling of US$50 WTI and a lost production maximum of 150,000 barrels per day.

The company is defendant and plaintiff in a number of legal actions that arise in the normal course of business. The company believes that any liabilities that might arise pertaining to such matters would not have a material effect on its consolidated financial position.

Costs attributable to these commitments and contingencies are expected to be incurred over an extended period of time and to be funded from the company's cash flow from operating activities. Although the ultimate impact of these matters on net earnings cannot be determined at this time, the impact may be material.

(c)    Guarantees, Variable Interest Entities (VIE), and Off-Balance Sheet Arrangements

At December 31, 2008, the company had various indemnification agreements with third parties as described below.

The company had a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2007 – $170 million) having a maturity of 45 days or less, to a third party. The third party was a multiple party securitization vehicle that provided funding for numerous asset pools. As at December 31, 2008, no outstanding accounts receivable had been sold under the program (2007 – nil) and the program had been allowed to expire. Although the company does not believe it had any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $57 million in 2008 and no contingent liability or earnings impact were recorded for this indemnification as the company believes it had 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, 2008, were $170 million and approximately $510 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2008 (2007 – $4 million; 2006 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE's sole asset is the equipment sold to it and leased back by the company. 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. As at December 31, 2008 and 2007, the VIE did not have any assets or liabilities.

The company has agreed to indemnify holders of the 6.10% notes, 6.85% notes, 6.50% notes, 7.15% notes, and the 5.95% notes and the company's credit facility lenders (see note 6) for added costs relating to taxes, assessments or other government charges or conditions, including any required withholding amounts. Similar indemnity terms apply to certain facility and equipment leases.

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

(d)   Subsequent Event

Subsequent to December 31, 2008, the company entered into crude oil hedges for approximately 125,000 barrels per day (bpd) of production from February 1 through December 31, 2009. These volumes are in addition to previously reported options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00 per barrel from January 1 to December 31, 2009. The combination of the previous options and new fixed-price hedges provide Suncor with an equivalent WTI floor price of about US$53.50 for approximately 180,000 bpd of production in 2009.

For the full year 2010, we have entered into crude oil hedges for approximately 50,000 bpd at an equivalent WTI floor price of US$50.00 per barrel and a ceiling price of approximately US$68.00 per barrel. This program replaces previously reported 2010 options to sell 55,000 bpd at an equivalent WTI floor price of US$60.00, which was effectively exited by selling similar contracts for gross proceeds to Suncor of approximately $250 million before tax.

13. SHARE CAPITAL

Stock Split

In May 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares. Information related to common shares, stock-based compensation, and earnings per share has been restated to reflect the impact of the company's two-for-one stock split.

Authorized

Common Shares

The company is authorized to issue an unlimited number of common shares without nominal or par value.

Preferred Shares

The company is authorized to issue an unlimited number of preferred shares in series, without nominal or par value.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 77

Issued

	Common Shares
	Number (thousands)	Amount ($ millions)
Balance as at December 31, 2005	915 330	732
Issued for cash under stock option plans	4 294	52
Issued under dividend reinvestment plan	264	10
Balance as at December 31, 2006	919 888	794
Issued for cash under stock option plans	5 388	74
Issued under dividend reinvestment plan	290	13
Balance as at December 31, 2007	925 566	881
Issued for cash under stock options plan	9 823	226
Issued under dividend reinvestment plan	135	6
Balance as at December 31, 2008	935 524	1 113

Stock-Based Compensation

A common share option gives the holder the right, but not the obligation, to purchase common shares at a predetermined price over a specified period of time.

After the date of grant, employees and non-employee directors that hold options must earn the right to exercise them. This is done by the holder by fulfilling a time requirement for service to the company, and with respect to certain options, subject to accelerated vesting should the company meet predetermined performance criterion. Once this right has been earned, these options are considered vested.

The predetermined price at which an option can be exercised is equal to or greater than the market price of the common shares on the date the options are granted.

A performance vesting share unit is an award entitling employees to receive cash to varying degrees contingent upon Suncor's shareholder return relative to a peer group of companies.

A restricted share unit is a time-vested award with a three-year term entitling employees to receive cash.

See below for more technical details and amounts on the company's stock option plans:

(a)   Stock Option Plans

(i)    SunShare 2012 Performance Stock Option Plan

The company granted 2,637,000 options in 2008 (2007 – 15,686,000, 2006 – nil) to all eligible permanent full-time and part-time employees, both executive and non-executive, under its new employee stock option incentive plan ("SunShare 2012"). During the second quarter 2008, in connection with the achievement of a predetermined performance criterion, 25% of the outstanding options vested under the SunShare 2012 plan and will become exercisable on January 1, 2010. The remaining 75% of outstanding options may vest on January 1, 2013 if further specified performance targets are met. All unvested options at January 1, 2013, which have not previously expired or been cancelled will automatically expire.

(ii)   SunShare Performance Stock Option Plan

Granting of options under the company's previous employee stock option incentive plan ("SunShare") ended in December 2007 (the company granted 2,090,000 options during 2007 and 3,274,000 options during 2006). Final vesting of all unvested SunShare options occurred on April 30, 2008.

(iii)  Executive Stock Plan

Under this plan, the company granted 895,000 common share options in 2008 (2007 – 958,000; 2006 – 1,076,000) to non-employee directors and certain executives and other senior employees of the company. Options granted have a 10-year life and vest annually over a three-year period.

(iv)  Key Contributor Stock Option Plan

Under this plan, the company granted 2,375,000 common share options in 2008 (2007 – 2,370,000; 2006 – 2,100,000) to non-insider senior managers and key employees. Options granted have a 10-year life and vest annually over a three-year period.

78 SUNCOR ENERGY INC. 2008ANNUAL REPORT

The following tables cover all common share options granted by the company for the years indicated:

		Number (thousands)		Range of Exercise Prices Per Share ($)	Weighted-Average Exercise Price Per Share ($)
Outstanding, December 31, 2005		38 406		2.61 – 35.57	14.06
	Granted	6 448		36.68 – 50.90	44.98
	Exercised	(4 294	)	2.61 – 30.96	10.50
	Cancelled	(942	)	12.50 – 48.05	23.33
Outstanding, December 31, 2006		39 618		3.89 – 50.90	19.24
	Granted	21 104		35.28 – 53.51	46.68
	Exercised	(5 388	)	3.89 – 46.06	11.38
	Cancelled	(1 334	)	12.66 – 50.87	32.84
Outstanding, December 31, 2007		54 000		5.06 – 53.51	30.31
	Granted	5 907		23.30 – 69.97	50.78
	Exercised	(9 823	)	5.06 – 50.86	19.69
	Cancelled	(3 682	)	12.31 – 67.58	41.72
Outstanding, December 31, 2008		46 402		5.06 – 69.97	34.55
Exercisable, December 31, 2008		24 933		5.06 – 50.86	22.55

Common shares authorized for issuance by the Board of Directors that remain available for the granting of future options, at December 31:

(thousands of common shares)	2008	2007	2006
	12 345	14 570	15 940

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2008:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)
5.06 – 8.72	1 723	2	8.29	1 723	8.29
10.67 – 14.46	11 523	3	13.48	11 523	13.48
15.64 – 34.86	5 439	5	20.60	5 417	20.59
35.26 – 46.84	8 127	6	44.34	5 506	44.31
47.02 – 47.91	16 136	6	47.54	345	47.43
48.05 – 83.58	3 454	6	56.22	419	49.59
Total	46 402	5	34.55	24 933	22.55

Fair Value of Options Granted

The fair values of all common share options granted during the period are estimated as at the grant date using a Monte Carlo simulation approach for the SunShare 2012 option plan and the Black-Scholes option-pricing model for all other option plans. The weighted-average fair values of the options granted during the various periods and the weighted-average assumptions used in their determination are as noted below:

	2008	2007	2006
Annual dividend per share	$0.20	$0.19	$0.15
Risk-free interest rate	3.35%	4.22%	4.08%
Expected life	6 years	6 years	5 years
Expected volatility	30%	30%	29%
Weighted-average fair value per option	$13.86	$14.89	$14.59

Stock-based compensation expense recognized for the year ended December 31, 2008 related to stock option plans was $120 million (2007 – $103 million; 2006 – $53 million).

SUNCOR ENERGY INC. 2008ANNUAL REPORT 79

Common share options granted prior to January 1, 2003 are not recognized as compensation expense in the Consolidated Statement of Earnings and Comprehensive Income. The company's reported net earnings attributable to common shareholders and earnings per share prepared in accordance with the fair value method of accounting for stock-based compensation would have been reduced for all common share options granted prior to 2003 to the pro forma amounts stated below:

($ millions, except per share amounts)		2008	2007	2006
Net earnings attributable to common shareholders – as reported		2 137	2 983	2 969
Less: compensation cost under the fair value method for pre-2003 options		4	8	15
Pro forma net earnings attributable to common shareholders for pre-2003 options		2 133	2 975	2 954
Basic earnings per share
	As reported	2.29	3.23	3.23
	Pro forma	2.29	3.23	3.22
Diluted earnings per share
	As reported	2.26	3.17	3.16
	Pro forma	2.26	3.16	3.14

(b)   Deferred Share Units (DSUs)

The company had 1,903,000 DSUs outstanding at December 31, 2008 (2,336,000 at December 31, 2007). DSUs were granted to certain executives under the company's former employee long-term incentive program. Members of the Board of Directors receive one-half, or at their option, all of their compensation in the form of DSUs. DSUs are only redeemable at the time a unitholder ceases employment or Board membership, as applicable.

In 2008, 473,000 DSUs were redeemed for cash consideration of $30 million (2007 – 40,000 redeemed for cash consideration of $2 million; 2006 – 118,000 redeemed for cash consideration of $5 million). Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments. Final DSU redemption amounts are subject to change depending on the company's share price at the time of exercise. Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period. As at December 31, 2008, the total liability related to the DSUs was $45 million (2007 – $126 million), of which $8 million (2007 – $5 million) was classified as current.

During 2008, total pretax compensation expense related to DSUs was a recovery of $51 million (2007 – $21 million; 2006 – $25 million).

(c)    Performance Share Units (PSUs)

During 2008, the company issued 795,000 PSUs (2007 – 830,000; 2006 – 794,000) under its Performance Share Unit Compensation Plan. PSUs granted replace the remuneration value of reduced grants under the company's stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor's performance (performance factor). Performance is measured by reference to the company's total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the anticipated performance factor. This expense is recognized on a straight-line basis over the term of the grant. Pretax recovery recognized for PSUs during 2008 was $30 million (2007 – expense of $60 million; 2006 – expense of $42 million).

(d)   SunShare 2012 Restricted Share Units (RSUs)

In 2008, the company issued 1,078,000 RSUs under the share unit portion of its new employee stock-based compensation plan ("SunShare 2012"). Expense recognized for the year ended December 31, 2008 was $8 million.

80 SUNCOR ENERGY INC. 2008ANNUAL REPORT

14. EARNINGS PER COMMON SHARE

The following is a reconciliation of basic and diluted net earnings per common share:

($ millions)		2008	2007	2006
Net earnings attributable to common shareholders		2 137	2 983	2 969
(millions of common shares)
Weighted-average number of common shares		932	922	918
Dilutive securities:
	Shares issued under stock-based compensation plans	13	20	22
Weighted-average number of diluted common shares		945	942	940
(dollars per common share)
Basic earnings per share (a)		2.29	3.23	3.23
Diluted earnings per share (b)		2.26	3.17	3.16

Note: An option will have a dilutive effect under the treasury stock method only when the average market price of the common stock during the period exceeds the exercise price of the option.

(a)

Basic earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of common shares.

(b)

Diluted earnings per share is the net earnings attributable to common shareholders divided by the weighted-average number of diluted common shares.

15. FINANCING EXPENSES (INCOME)

($ millions)		2008		2007		2006
Interest expense on debt		352		189		150
Capitalized interest		(352	)	(189	)	(129	)
	Net interest expense	—		—		21
	Foreign exchange loss (gain) on long-term debt	919		(252	)	—
	Other foreign exchange (gain) loss	(2	)	41		18
Total financing expenses (income)		917		(211	)	39

Cash interest payments in 2008 totaled $328 million (2007 – $183 million; 2006 – $146 million).

16. INVENTORIES

($ millions)	2008	2007
Crude oil	459	542
Refined products	247	320
Materials, supplies and merchandise	203	150
Total	909	1 012

During 2008, inventories of $15.7 billion (2007 – $8.0 billion) were expensed which includes write-downs of inventories totaling $39.9 million (2007 – $15.2 million). No reversals of write-downs were recorded for the twelve month periods ending December 31, 2008 and 2007.

17. RELATED PARTY TRANSACTIONS

The following table summarizes the company's related party transactions after eliminations for the year. These transactions are in the normal course of operations and have been carried out on the same terms as would apply with unrelated parties.

($ millions)			2008	2007	2006
Operating revenues
	Sales to refining and marketing segment joint ventures:
		Refined products	368	329	294
		Petrochemicals	188	163	136

The company has supply agreements with two refining and marketing segment joint ventures for the sale of refined products. The company also has a supply agreement with a refining and marketing segment joint venture for the sale of petrochemicals.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 81

At December 31, 2008, amounts due from refining and marketing segment joint ventures were $13 million (2007 – $17 million).

Sales to and balances with refining and marketing segment joint ventures are established and agreed to by the various parties and approximate fair value.

18. ACCUMULATED OTHER COMPREHENSIVE INCOME

The components of accumulated other comprehensive income (loss), net of income taxes, are as follows:

As at December 31 ($ millions)	2008	2007
Unrealized foreign currency translation adjustment	84	(266	)
Unrealized gains and losses on derivative hedging activities	13	13
Total	97	(253	)

19. SUPPLEMENTAL INFORMATION

($ millions)			2008	2007	2006
Geographic areas
	Revenues
		Canada	25 043	14 365	12 930
		U.S.	4 945	4 091	3 532
		Other	101	109	84
			30 089	18 565	16 546
	Total assets
		Canada	29 178	21 615	16 227
		U.S.	2 840	2 556	2 439
		Other	510	338	293
			32 528	24 509	18 959
Export sales (a)			761	876	810
Exploration expenses
	Geological and geophysical		29	26	51
	Other		—	—	1
	Cash costs		29	26	52
	Dry hole costs		61	69	52
	Cash and dry hole costs (b)		90	95	104
	Leasehold impairment (c)		—	—	2
			90	95	106
Taxes other than income taxes
	Excise taxes (d)		570	568	538
	Production, property and other taxes		109	80	57
			679	648	595
Allowance for doubtful accounts			4	3	4

(a)

Sales of crude oil, natural gas and refined products from Canada to customers in the United States and sales of petrochemicals to customers in the United States and Europe.

(b)

Included in the Consolidated Statements of Earnings and Comprehensive Income as exploration expenses.

(c)

Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings and Comprehensive Income.

(d)

Included in operating revenues in the Consolidated Statements of Earnings and Comprehensive Income.

82 SUNCOR ENERGY INC. 2008ANNUAL REPORT

20. DIFFERENCES BETWEEN CANADIAN AND U.S. GENERALLY ACCEPTED ACCOUNTING PRINCIPLES

The consolidated financial statements have been prepared in accordance with Canadian GAAP. The application of United States GAAP (U.S. GAAP) would have the following effects on earnings and comprehensive income as reported:

($ millions)		Notes	2008		2007		2006
Net earnings as reported, Canadian GAAP			2 137		2 983		2 969
Adjustments
	Derivatives and hedging activities	(a)	—		—		11
	Stock-based compensation expense	(b)	(7	)	15		(19	)
	Research and development costs	(g)	(1	)	(34	)	—
	Income tax expense		1		4		(3	)
Net earnings from continuing operations, U.S. GAAP			2 130		2 968		2 958
	Cumulative effect of change in accounting principles, net of income taxes of $nil (2007 – $nil; 2006 – $2)	(b)	—		—		(4	)
Net earnings, U.S. GAAP			2 130		2 968		2 954
Derivatives and hedging activities, net of income taxes of $nil (2007 – $nil; 2006 – $3)		(a)	—		5		6
Minimum pension liability, net of income taxes of $nil (2007 – $nil; 2006 – $20)		(c)	—		—		39
Pension and Post-retirement obligation, net of income taxes of $20 (2007 – $8)		(c)	43		17		—
Foreign currency translation adjustment			350		(195	)	10
Comprehensive income, U.S. GAAP			2 523		2 795		3 009

Per common share (dollars)		2008	2007	2006
Net earnings per share from continuing operations, U.S. GAAP
	Basic	2.29	3.22	3.22
	Diluted	2.25	3.15	3.14
Net earnings per share, U.S. GAAP
	Basic	2.29	3.22	3.22
	Diluted	2.25	3.15	3.14

The application of U.S. GAAP would have the following effects on the consolidated balance sheets as reported:

				December 31, 2008		December 31, 2007
		Notes		As Reported	U.S. GAAP	As Reported		U.S. GAAP
Current assets				3 237	3 237	3 160		3 160
Property, plant and equipment, net		(g	)	28 316	28 281	20 945		20 911
Deferred charges and other		(i	)	975	1 047	404		449
	Total assets			35 528	32 565	24 509		24 520
Current liabilities				3 529	3 529	3 156		3 156
Long-term borrowings		(i	)	7 875	7 947	3 811		3 856
Accrued liabilities and other		(b,c	)	1 986	2 094	1 434		1 602
Future income taxes		(b,c,g	)	4 615	4 569	4 212		4 147
Share capital		(b	)	1 113	1 201	881		944
Contributed surplus		(b	)	288	313	194		240
Retained earnings		(b,g	)	13 025	12 894	11 074		10 950
Accumulated other comprehensive income (loss)		(c	)	97	18	(253	)	(375	)
	Total liabilities and shareholders' equity			35 528	32 565	24 509		24 520

The application of U.S. GAAP would have no material impact on statements of cash flow as reported.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 83

(a)   Derivative Financial Instruments

The adoption of CICA Handbook section 1530 "Comprehensive Income", section 3251 "Equity", section 3855 "Financial Instruments, Recognition and Measurement", and section 3865 "Hedging" on January 1, 2007 substantially aligned Canadian GAAP with U.S. GAAP for the treatment of the company's derivative financial instruments. As a result, there were no differences between Canadian and U.S. GAAP for the years ended December 31, 2008 and December 31, 2007. For comparative balances for the year ended December 31, 2006 disclosed under U.S. GAAP, the company accounted for its derivative financial instruments under the same method as described in note 7.

Under U.S. GAAP, for the year ended December 31, 2006, the company would have recognized $5 million of hedging gains relating to forecasted cash flows in 2007 and 2008. The net earnings impact of this ineffectiveness was recognized for Canadian GAAP purposes on January 1, 2007 as an adjustment to opening retained earnings.

Accumulated Other Comprehensive Earnings (AOCI) and U.S. GAAP Net Earnings Impacts

A reconciliation of changes in AOCI attributable to derivative hedging activities for the years ended December 31 is as follows:

($ millions)	2008		2007
AOCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $4 (2007 – $4)	13		8
Current period net changes arising from cash flow hedges, net of income taxes of $2 (2007 – $1)	(7	)	8
Net unrealized hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $3 (2007 – $2)	7		(3	)
AOCI attributable to derivatives and hedging activities, end of period, net of income taxes of $5 (2007 – $4)	13		13

For the year ended December 31, 2006, U.S. GAAP net earnings increased by $7 million, net of income taxes of $4 million to reflect the impact of ineffectiveness on derivative contracts classified as cash flow hedges.

(b)   Stock-Based Compensation

Following U.S. Financial Accounting Standards Board (FASB) Statement 123(R), "Share-Based Payment", using the modified-prospective approach, the company expenses common share options issued after January 1, 2003 in a manner consistent with Canadian GAAP. The statement requires the recognition of an expense for employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The cost is to be recognized over the period for which an employee is required to provide the service in exchange for the award. In addition, the statement requires recognition of compensation expense for the portion of outstanding unvested awards granted prior to the effective date.

Under Canadian GAAP, the company's Performance Share Units (PSUs) are measured using an intrinsic approach, a fair-value technique not permitted under U.S. GAAP. For U.S. GAAP, our PSUs have been measured using a Monte Carlo Simulation approach to determine fair value. The impact on net earnings for the year ended December 31, 2008 is an expense of $2 million, net of income taxes of $1 million (2007 – recovery of previously recognized stock-based compensation expense of $17 million expense, net of income taxes of $6 million; 2006 – $3 million expense, net of income taxes of $1 million).

Under Canadian GAAP, compensation expense related to common share options granted prior to January 1, 2003 ("pre-2003 options") is not recognized in the Consolidated Statements of Earnings and Comprehensive Income. FAS 123(R) requires the recognition of expense related to the company's pre-2003 options. This resulted in an increase to stock-based compensation expense of $4 million (2007 – $8 million; 2006 – $15 million). There was no impact on income taxes.

(c)    Accounting for Defined Benefit Pension and Other Post-Retirement Plans

On December 31, 2006, the Company adopted FAS 158, "Employers Accounting for Defined Benefit and Other Post Retirement Plans", requiring the recognition of the over funded or under funded status of a defined benefit post-retirement plan as an asset or liability on the balance sheet, with changes to funded status in the year recorded through comprehensive income, net of income taxes. The standard was applied prospectively effective December 31, 2006, as retrospective application was not permitted.

84 SUNCOR ENERGY INC. 2008ANNUAL REPORT

Prior to the adoption of FAS 158, recognition of an additional minimum pension liability was required when the accumulated benefit obligation exceeded the fair value of plan assets to the extent that such excess was greater than accrued pension costs otherwise recorded. For the year ended December 31, 2006, the company would have recognized an increase in other comprehensive income of $39 million, net of income taxes of $20 million. No such adjustment was required under Canadian GAAP.

As required under FAS 158, the minimum pension liability adjustment recorded prior to December 31, 2006 was eliminated upon adoption.

Accumulated Other Comprehensive Income (AOCI) and U.S. GAAP Net Earnings Impacts

($ millions)	2008		2007
AOCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $59 million (2007 – $67 million)	(122	)	(139	)
Amortization of net actuarial loss, net of income taxes of $9 million (2007 – $10 million)	19		21
Amortization of past service costs, net of income taxes of $1 million (2007 – $1 million)	(2	)	(2	)
Adjustments to unamortized net actuarial loss, net of income taxes of $12 million (2007 – $2 million)	26		(2	)
AOCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $39 million (2007 – $59 million)	(79	)	(122	)

Total amount included in AOCI expected to be recognized as components of net periodic benefit cost during 2009 are as follows:

Amortization of net actuarial loss	$25 million
Amortization of past service costs	$(3) million

(d)   Cumulative Foreign Currency Translation

Prior to the adoption of CICA Section 1530 "Comprehensive Income" on January 1, 2007, under Canadian GAAP, foreign currency gains and losses arising on translation of the company's U.S. based foreign operations were recorded directly to shareholders' equity. Under the new Canadian standard, these foreign currency translation gains and losses are treated as they have been under U.S. GAAP, and included as a component of comprehensive income.

(e)   Suspended Exploratory Well Costs

Under U.S. GAAP, the company is permitted to continue the capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project.

The table below provides details of the changes in the balance of suspended exploratory well costs as well as an aging summary of those costs.

Change in capitalized suspended exploratory well costs

($ millions)		2008		2007		2006
Balance, beginning of year		21		23		15
	Additions pending determination of proved reserves	35		14		21
	Charged to dry hole expense	(15	)	(6	)	—
	Reclassifications to proved properties	—		(10	)	(13	)
Balance, end of year		41		21		23
Capitalized for a period greater than one year ($ millions)		6		7		2
Number of projects that have exploratory well costs capitalized for a period greater than 12 months		2		3		3

(f)    Accounting for Purchases and Sales Inventory with the Same Counterparty

Emerging Issues Task Force (EITF) Abstract No. 04-13, "Accounting for Purchases and Sales of Inventory with the Same Counterparty" addresses when it is appropriate to measure purchases and sales of inventory with the same counterparty at fair value and record them in revenues and cost of sales and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold (reported net versus gross). The EITF is effective for transactions entered into subsequent to April 1, 2006.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 85

As required by EITF 04-13, we record certain crude oil, natural gas, petroleum product and chemical purchases and sales entered into contemporaneously with the same counterparty on a net basis within the "purchases of crude oil and products" line in the Consolidated Statements of Earnings and Comprehensive Income. These transactions are undertaken to ensure that the appropriate crude oil is at the appropriate refineries when required and that the appropriate products are available to meet customer demands. These transactions take place in the oil sands and refining and marketing operating segments.

In addition, until 2006, the refining and marketing segment sold finished product and bought coker gas oil as a raw material to be used in the refining process from the same counterparty under terms specified in a single contract. These sales and purchases, as noted in the table below, were recorded at fair value in "revenue" and "purchases of crude oil and products" in the Consolidated Statements of Earnings and Comprehensive Income in accordance with the consensus for Issue 2 in EITF 04-13.

The purchase/sale of contract amounts included in revenue for 2008, 2007 and 2006 are shown below.

($ millions)	2008	2007	2006
Consolidated revenues	30 089	18 565	16 546
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	—	—	5

(1)

Associated costs are in "purchases of crude oil and products".

(g)   Research and Development Costs

Under Canadian GAAP, development expenditures are eligible to be capitalized when specific criteria are met. Under FAS 2, "Accounting for Research and Development Costs", development costs are required to be charged to expense when incurred. As a result, $1 million would have been charged to income during 2008 (2007 – $24 million, net of income taxes of $10 million; 2006 – nil).

(h)   Accounting for Uncertainties in Income Taxes

Effective January 1, 2007, the company adopted the FASB Interpretation No. 48 "Accounting for Uncertainty in Income Taxes" (FIN 48). FIN 48 is an interpretation of FASB Statement 109 "Accounting for Income Taxes" and outlines the recognition and related disclosure requirements of uncertain tax positions determined to be more likely than not, defined as greater than 50%, to be sustained on audit.

The adoption of FIN 48 had no impact on net earnings or financial position.

(i)    Deferred Financing Costs

Effective January 1, 2007, under Canadian GAAP, deferred financing costs on long-term debt are included in the carrying value of the related debt. Under U.S. GAAP, these costs are recorded as a deferred charge. As a result, $72 million would have been reclassified from long-term debt to deferred charges and other at December 31, 2008 (December 31, 2007 – $45 million).

(j)    Inventory

Effective January 1, 2008, the company retroactively adopt a FIFO (first-in, first-out) based valuation approach for inventory under Canadian GAAP. We have retroactively adopted the same FIFO valuation approach for U.S. GAAP. As such, there continues to be no impact to net earnings or financial position.

Recently Adopted Accounting Standards

Effective January 1, 2008, the company adopted FAS 157 "Fair Value Measurements" and FAS 159 "The Fair Value Option for Financial Assets and Financial Liabilities". Retrospective application was not permitted. The adoption of these standards had no impact on net earnings or financial position.

Recently Issued Accounting Standards

In December 2007, FASB issued FAS 141(revised), "Business Combinations". The standard, effective January 1, 2009, establishes principles and requirements of the acquisition method for business combinations and the related disclosures. The revisions are to be applied with prospective application, where early adoption is prohibited. No impact to net earnings or financial position is anticipated.

In December 2007, FASB issued FAS 160, "Non-Controlling Interests in Consolidated Financial Statements". The standard is effective January 1, 2009. This interpretation of ARB No. 51 outlines that a non-controlling interest in a subsidiary represents an interest in the consolidated entity, which should be reported as equity in the financial statements. The new standard is to be applied with prospective application, where early adoption is prohibited. No impact to net earnings or financial position is anticipated.

86 SUNCOR ENERGY INC. 2008ANNUAL REPORT

QUARTERLY SUMMARY (unaudited)

FINANCIAL DATA

		For the Quarter Ended								Total Year		For the Quarter Ended								Total Year
($ millions, except per share amounts)		Mar 31 2008		June 30 2008		Sept 30 2008		Dec 31 2008		2008		Mar 31 2007		June 30 2007		Sept 30 2007		Dec 31 2007		2007
Revenues		5 988		7 959		8 946		7 196		30 089		4 053		4 525		4 802		5 185		18 565
Net earnings (loss)
Oil Sands		695		751		854		575		2 875		468		476		494		1 036		2 474
Natural Gas		19		52		18		—		89		4		(4	)	—		25		25
Refining and Marketing		95		91		46		(181	)	51		106		238		69		31		444
Corporate and eliminations		(101	)	(65	)	(103	)	(609	)	(878	)	(2	)	28		64		(50	)	40
		708		829		815		(215	)	2 137		576		738		627		1 042		2 983
Per common share
Net earnings (loss) attributable to common shareholders
	– basic	0.77		0.89		0.87		(0.24	)	2.29		0.63		0.80		0.68		1.12		3.23
	– diluted	0.75		0.87		0.86		(0.24	)	2.26		0.61		0.78		0.66		1.10		3.17
Cash dividends		0.05		0.05		0.05		0.05		0.20		0.04		0.05		0.05		0.05		0.19
Cash flow from (used in) operations
Oil Sands		910		1 174		1 109		645		3 838		600		657		829		1 057		3 143
Natural Gas		82		119		103		64		368		64		70		47		67		248
Refining and Marketing		190		210		85		(207	)	278		180		342		126		68		716
Corporate and eliminations		(21	)	(98	)	49		49		(21	)	(19	)	(42	)	(45	)	8		(98	)
		1 161		1 405		1 346		551		4 463		825		1 027		957		1 200		4 009
OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
	Total production	248.0		174.6		245.6		243.8		228.0		248.2		202.3		239.1		252.5		235.6
	Firebag	34.6		34.7		40.4		39.7		37.4		35.3		36.2		35.8		40.4		36.9
Sales
	Light sweet crude oil	96.2		68.2		48.1		95.7		77.0		105.5		100.0		99.3		102.2		101.7
	Diesel	28.0		21.2		10.9		19.1		19.8		29.5		20.3		23.9		26.0		25.0
	Light sour crude oil	120.8		91.8		157.4		144.2		128.7		112.7		84.2		94.1		118.2		102.3
	Bitumen	0.1		0.3		2.6		3.1		1.5		6.8		3.8		6.6		5.4		5.7
Total sales		245.1		181.5		219.0		262.1		227.0		254.5		208.3		223.9		251.8		234.7

SUNCOR ENERGY INC. 2008ANNUAL REPORT 87

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

		For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008	Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
	Light sweet crude oil	100.93	122.12	121.96	64.58	97.54	68.63	75.64	81.00	87.34	78.03
	Other (diesel, light sour crude oil and bitumen)	93.09	120.52	114.74	59.77	95.15	63.62	66.74	73.76	78.48	70.86
	Total	96.16	121.12	116.32	61.53	95.96	65.70	71.01	76.97	82.07	74.01
	Total (a)	96.22	122.39	117.14	61.20	96.33	65.61	71.01	76.97	82.36	74.07
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		25.10	40.10	27.80	35.35	31.45	21.75	28.40	23.00	24.10	24.15
Natural gas		5.00	8.75	4.30	4.05	5.25	4.50	4.20	2.10	3.60	3.55
Imported bitumen		1.45	2.00	1.90	1.90	1.80	0.05	0.10	—	0.20	0.10
Cash operating costs (3)		31.55	50.85	34.00	41.30	38.50	26.30	32.70	25.10	27.90	27.80
Project start-up costs		0.30	0.90	0.35	0.30	0.40	0.10	1.15	1.10	0.55	0.95
Total cash operating costs (4)		31.85	51.75	34.35	41.60	38.90	26.40	33.85	26.20	28.45	28.75
Depreciation, depletion and amortization		5.75	8.30	6.70	7.50	6.95	4.45	5.85	5.70	5.60	5.40
Total operating costs (5)		37.60	60.05	41.05	49.10	45.85	30.85	39.70	31.90	34.05	34.15
Cash operating costs and total operating costs – In-situ Bitumen Production Only
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		14.60	10.10	10.75	16.55	13.00	11.05	10.60	11.85	9.95	10.85
Natural gas		14.10	14.55	11.30	9.65	12.30	11.05	10.60	9.10	9.15	9.90
Cash operating costs (6)		28.70	24.65	22.05	26.20	25.30	22.10	21.20	20.95	19.10	20.75
Firebag start-up costs		0.35	1.65	0.80	—	0.65	—	—	—	—	—
Total cash operating costs (7)		29.05	26.30	22.85	26.20	25.95	22.10	21.20	20.95	19.10	20.75
Depreciation, depletion and amortization		6.75	6.70	5.40	6.55	6.35	5.35	5.75	6.70	6.80	6.20
Total operating costs (8)		35.80	33.00	28.25	32.75	32.30	27.45	26.95	27.65	25.90	26.95

88 SUNCOR ENERGY INC. 2008ANNUAL REPORT

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

	For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)	Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008	Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007
NATURAL GAS
Gross production (b)
— Natural gas (millions of cubic feet per day)	209	205	197	195	202	191	191	193	210	196
— Natural gas liquids and crude oil (thousands of barrels per day)	3.3	3.4	2.6	3.1	3.1	3.1	3.0	3.1	3.2	3.1
— Total gross production (thousands of barrels of oil equivalent per day)	38.2	37.7	35.4	35.6	36.7	34.9	34.9	35.2	38.2	35.8
— Total gross production (millions of cubic feet equivalent per day)	229	226	213	213	220	209	209	211	229	215
Average sales price (2)
— Natural gas (dollars per thousand cubic feet)	7.30	9.62	9.10	6.90	8.23	7.01	6.85	5.39	6.08	6.32
— Natural gas(a) (dollars per thousand cubic feet)	7.31	9.68	9.14	6.84	8.25	7.14	6.83	5.14	6.02	6.27
— Natural gas liquids and crude oil – conventional (dollars per barrel)	64.14	86.14	96.88	39.31	70.89	56.69	51.21	58.11	60.31	56.64
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)	30.5	33.1	32.0	31.5	31.5	31.6	34.6	35.1	32.8	33.5
Utilization of refining capacity (%)	90	102	99	98	97	97	108	102	87	98

(a)

Excludes the impact of hedging activities.

(b)

Currently Natural Gas production is located in the Western Canada Sedimentary Basin.

Definitions

(1)

Total operations production – Total operations production includes total production from both mining and in-situ operations.

(2)

Average sales price – This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).

(3)

Cash operating costs – Total operations – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non GAAP financial measure see Management's Discussion and Analysis.

(4)

Total cash operating costs – Total operations – Include cash operating costs – Total operations as defined above and cash start-up costs. Per barrel amounts are based on total production volumes.

(5)

Total operating costs – Total operations – Include total cash operating costs – Total operations as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes.

(6)

Cash operating costs – In-situ bitumen production – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes only.

(7)

Total cash operating costs – In-situ bitumen production – Include cash operating costs – In-situ bitumen production as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on in-situ production volumes only.

(8)

Total operating costs – In-situ bitumen production – Include total cash operating costs – In-situ bitumen production as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes only.

Metric conversion

Crude oil, refined products, etc. – 1m³ (cubic metre) = approximately 6.29 barrels
Natural gas – 1m³ (cubic metre) = approximately 35.49 cubic feet

SUNCOR ENERGY INC. 2008ANNUAL REPORT 89

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions, except for ratios)	2008		2007		2006		2005		2004
Revenues
Oil Sands	9 386		6 775		7 407		3 965		3 640
Natural Gas	754		553		578		679		567
Refining and Marketing	21 371		11 805		9 310		7 636		5 317
Corporate and eliminations	(1 422	)	(568	)	(749	)	(499	)	(497	)
	30 089		18 565		16 546		11 781		9 027
Net earnings (loss)
Oil Sands	2 875		2 474		2 775		986		957
Natural Gas	89		25		106		155		114
Refining and Marketing	51		444		244		237		138
Corporate and eliminations	(878	)	40		(156	)	(124	)	(105	)
	2 137		2 983		2 969		1 254		1 104
Cash flow from (used in) operations
Oil Sands	3 838		3 143		3 903		1 961		1 718
Natural Gas	368		248		281		412		314
Refining and Marketing	278		716		451		463		251
Corporate and eliminations	(21	)	(98	)	(111	)	(209	)	(228	)
	4 463		4 009		4 524		2 627		2 055
Capital and exploration expenditures
Oil Sands	7 051		4 431		2 463		1 948		1 119
Natural Gas	339		531		458		363		279
Refining and Marketing	172		376		665		779		418
Corporate	28		77		27		63		31
	7 590		5 415		3 613		3 153		1 847
Total assets	32 528		24 509		18 959		15 335		11 807
Ending capital employed(a)
Short-term and long-term debt, less cash and cash equivalents	7 226		3 248		1 849		2 868		2 109
Shareholders' equity	14 523		11 896		9 084		6 130		4 912
	21 749		15 144		10 933		8 998		7 021
Less capitalized costs related to major projects in progress	(6 583	)	(4 148	)	(2 649	)	(2 938	)	(1 467	)
	15 166		10 996		8 284		6 060		5 554
Total Suncor employees (number at year-end)	6 798		6 465		5 766		5 152		4 605

90 SUNCOR ENERGY INC. 2008ANNUAL REPORT

FIVE-YEAR FINANCIAL SUMMARY (unaudited) (continued)

($ millions, except for ratios)		2008	2007	2006	2005	2004
Dollars per common share
	Net earnings attributable to common shareholders	2.29	3.23	3.23	1.37	1.22
	Cash dividends	0.20	0.19	0.15	0.12	0.115
	Cash flow from operations	4.79	4.35	4.93	2.88	2.27
Ratios
Return on capital employed (%) (a), (b)		22.5	29.3	40.0	21.2	19.4
Return on capital employed (%) (c)		16.3	21.5	30.1	15.4	16.4
Return on shareholders' equity (%) (d)		16.2	28.4	39.0	22.7	25.1
Debt to debt plus shareholders' equity (%) (e)		35.2	24.3	20.7	33.1	30.9
Net debt to cash flow from operations (times) (f)		1.6	0.8	0.4	1.1	1.0
Interest coverage – cash flow basis (times) (g)		14.1	23.2	30.4	17.9	14.9
Interest coverage – net earnings basis (times) (h)		8.9	18.8	25.5	13.5	11.7

(a)

Capital employed – the sum of shareholders' equity plus short-term debt and long-term debt less cash and cash equivalents, less capitalized costs related to major projects in progress (as applicable).

(b)

Net earnings adjusted for after-tax financing expenses (income) for the twelve month period ended; divided by average capital employed. Average capital employed is the sum of shareholders' equity and short-term debt plus long-term debt less cash and cash equivalents, at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non-GAAP financial measure see page 40 of MD&A.

(c)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(d)

Net earnings as a percentage of average shareholders' equity. Average shareholders' equity is the sum of total shareholders' equity at the beginning and end of the year divided by two.

(e)

Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders' equity.

(f)

Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.

(g)

Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

(h)

Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 91

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2008	2007	2006	2005	2004
OIL SANDS
Production (thousands of barrels per day)	228.0	235.6	260.0	171.3	226.5
Sales(thousands of barrels per day)
Light sweet crude oil	77.0	101.7	110.5	73.3	114.9
Diesel	19.8	25.0	28.2	15.6	27.9
Light sour crude oil	128.7	102.3	118.2	59.8	75.1
Bitumen	1.5	5.7	6.2	16.6	8.4
	227.0	234.7	263.1	165.3	226.3
Average sales price (dollars per barrel)
Light sweet crude oil	97.54	78.03	71.98	49.93	45.60
Other (diesel, light sour crude oil and bitumen)	95.15	70.86	65.17	56.90	39.13
Total	95.96	74.01	68.03	53.81	42.28
Total (a)	96.33	74.07	68.03	62.68	49.78
Cash operating costs – total operations (b)	38.50	27.80	21.70	24.55	15.15
Total cash operating costs – total operations (b)	38.90	28.75	22.10	24.65	15.45
Total operating costs – total operations (b)	45.85	34.15	26.15	29.95	19.05
Cash operating costs – In-situ bitumen production (b), (e)	25.30	20.75	17.30	22.20	22.05
Total cash operating costs – In-situ bitumen production (b), (e)	25.95	20.75	19.00	23.20	28.90
Total operating costs – In-situ bitumen production (b), (e)	32.30	26.95	24.55	28.10	34.90
Ending capital employed excluding major projects in progress	9 352	6 605	5 039	4 468	4 091
Return on capital employed (%) (c)	35.5	43.0	53.1	23.0	22.3
Return on capital employed (%) (d)	21.8	27.9	39.8	16.5	18.3

(a)

Excludes the impact of hedging activities.

(b)

Dollars per barrel rounded to the nearest $0.05. See definitions on page 89.

(c)

See definitions on page 91.

(d)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(e)

In-situ bitumen production commenced commercial operations on April 1, 2004.

92 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

			2008	2007	2006	2005	2004
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
	Gross		202	196	191	190	200
	Net (a)		154	153	141	137	147
Natural gas liquids and crude oil (thousands of barrels per day)
	Gross		3.1	3.1	3.0	3.2	3.5
	Net (a)		2.3	2.4	2.3	2.6	2.6
Total (thousands of boe (b) per day)
	Gross		36.7	35.8	34.8	34.8	36.8
	Net (a)		28.0	27.9	25.8	25.3	27.1
Total (millions of cubic feet equivalent per day)
	Gross		220	215	209	209	221
	Net (a)		168	167	155	152	163
Average sales price
Natural gas (dollars per thousand cubic feet)			8.23	6.32	7.15	8.57	6.70
Natural gas (dollars per thousand cubic feet) (c)			8.25	6.27	6.95	8.59	6.73
Natural gas liquids and crude oil – conventional (dollars per barrel)			70.89	56.64	51.93	54.24	44.99
Ending capital employed			1 152	1 153	857	562	447
Return on capital employed (%) (g)			7.7	2.5	14.9	30.7	26.9
Undeveloped landholdings (d)
Oil and gas (millions of acres)
	Western Canada
		Gross	1.8	1.3	1.2	0.6	0.7
		Net (e)	0.9	0.7	0.7	0.4	0.5
	International
		Gross	0.1	0.1	0.1	0.4	0.7
		Net (e)	—	—	—	0.2	0.4
Net wells drilled (f)
	Exploratory
		Oil	—	—	—	—	—
		Gas	6	7	3	8	5
		Dry	4	6	5	4	5
	Development
		Oil	—	1	1	1	—
		Gas	18	14	13	18	16
		Dry	5	3	4	3	—
			33	31	26	34	26

(a)

Net of royalties

(b)

Barrel of oil equivalent – converts natural gas to oil on the approximate energy equivalent basis that 6,000 cubic feet equals one barrel of oil.

(c)

Excludes the impact of hedging activities.

(d)

Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres

(e)

Our interest in the undeveloped landholdings

(f)

Excludes interests in 4 net exploratory wells and 6 net development wells in progress at the end of 2008.

(g)

See definitions on page 91.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 93

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2008	2007	2006	2005	2004
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
	Retail (a)	4.6	5.2	5.3	5.2	5.3
	Other	11.3	11.6	10.6	10.1	7.9
Distillate		10.8	10.6	8.5	8.3	6.7
Total transportation fuel sales		26.7	27.4	24.4	23.6	19.9
Petrochemicals		0.8	0.9	0.9	0.7	0.8
Asphalt		1.8	1.7	1.2	1.6	1.5
Other		2.2	3.5	3.0	3.0	2.5
Total refined product sales		31.5	33.5	29.5	28.9	24.7
Crude oil supply and refining
	Processed at refineries (thousands of cubic metres per day)	24.7	25.1	21.7	22.7	19.9
Utilization of refining capacity (%)		97	98	85	97	96
Ending capital employed excluding major projects in progress		3 220	2 489	1 938	907	784
Return on capital employed (%) (b)		1.7	20.0	19.3	27.5	16.2
Return on capital employed (%) (b), (c)		1.7	17.4	12.2	17.6	14.9
Retail outlets (d) (number at year-end)		427	419	417	417	421

(a)

Excludes sales through joint venture interests.

(b)

See definitions on page 91.

(c)

If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.

(d)

Sunoco-branded and Phillips 66-branded service stations, other private brands managed by refining and marketing, and refining and marketing's interest in service stations managed through joint ventures.

94 SUNCOR ENERGY INC. 2008ANNUAL REPORT

SHARE TRADING INFORMATION (unaudited)

Common shares are listed on the Toronto Stock Exchange and New York Stock Exchange under the symbol SU.

		For the Quarter Ended					For the Quarter Ended
		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008		Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007
Share ownership
Average number outstanding, weighted monthly (thousands) (a)		926 216	928 572	930 393	931 524		920 148	920 844	921 578	922 374
Share price (dollars)
Toronto Stock Exchange
	High	56.14	73.10	62.37	43.78		46.43	49.85	50.78	54.74
	Low	40.92	47.78	39.61	18.80		39.83	43.79	44.36	45.63
	Close	49.61	59.20	44.00	23.72		43.93	47.98	47.23	53.96
New York Stock Exchange – US$
	High	56.73	74.28	61.99	41.12		38.90	46.76	50.06	58.99
	Low	39.67	46.31	38.00	14.52		33.89	37.86	41.19	45.70
	Close	52.61	68.56	51.64	19.50		38.18	44.96	47.41	54.37
Shares traded (thousands)
	Toronto Stock Exchange	219 093	226 392	266 381	396 680		218 970	175 568	199 402	200 466
	New York Stock Exchange	342 938	371 303	458 534	720 851		355 471	290 564	321 810	300 176
Per common share information (dollars)
Net earnings attributable to common shareholders		0.77	0.89	0.87	(0.24	)	0.63	0.80	0.68	1.12
Cash dividends		0.05	0.05	0.05	0.05		0.04	0.05	0.05	0.05

(a)

The company had approximately 2,971 holders of record of common shares as at January 31, 2008.

On May 14, 2008, the company implemented a two-for-one stock split of its issued and outstanding common shares.

Information for Security Holders Outside Canada

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to Canadian non-resident withholding tax of 15%. The withholding tax rate is reduced to 5% on dividends paid to a corporation if it is a resident of the United States that owns at least 10% of the voting shares of the company.

SUNCOR ENERGY INC. 2008ANNUAL REPORT 95

QuickLinks

EXHIBIT 99-1

AUDITED CONSOLIDATED FINANCIAL STATEMENTS OF SUNCOR ENERGY INC. FOR THE FISCAL YEAR ENDED DECEMBER 31, 2008, INCLUDING RECONCILIATION TO U.S. GAAP (NOTE 20)