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EXHIBIT 99-1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal
year ended December 31, 2009, including reconciliation to U.S. GAAP (Note 23)

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 59 to 100 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 59 to 63. 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., Sproule Associates Limited and RPS Energy Plc, 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 six 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	Bart Demosky
President and Chief Executive Officer	Chief Financial Officer

February 26, 2010

SUNCOR ENERGY INC. 2009ANNUAL REPORT 55

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.

On August 1, 2009, Suncor completed its merger with Petro-Canada. As permitted by the Securities and Exchange Commission, management has excluded Petro-Canada from its evaluation of the effectiveness of Suncor's internal control over financial reporting as of December 31, 2009. Assets attributable to Petro-Canada as of August 1, 2009 represented approximately 50% of Suncor's total assets as of August 1, 2009, and revenues attributable to Petro-Canada for the period August 1, 2009 to December 31, 2009 represented approximately 25% of Suncor's total revenues for the year ended December 31, 2009.

3.

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.

4.

Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2009, 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, 2009. 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.

5.

The effectiveness of the Company's internal control over financial reporting as of December 31, 2009 has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.

Richard L. George	Bart Demosky
President and Chief Executive Officer	Chief Financial Officer

February 26, 2010

56 SUNCOR ENERGY INC. 2009ANNUAL REPORT

INDEPENDENT AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have completed integrated audits of Suncor Energy Inc's 2009, 2008 and 2007 consolidated financial statements and of its internal control over financial reporting as at December 31, 2009. 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, 2009 and December 31, 2008, and the related consolidated statements of earnings, comprehensive income, changes in shareholders' equity and of cash flows for each of the years in the three year period ended December 31, 2009. 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, 2009 and 2008 and for each of the years in the three year period ended December 31, 2009 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, 2009 and December 31, 2008 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2009 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, 2009, 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. 2009ANNUAL REPORT 57

As described in Management's Report on Internal Control over Financial Reporting, management has excluded Petro-Canada from its assessment of internal control over financial reporting as at December 31, 2009 because it was acquired by the company in a purchase business combination during 2009. We have also excluded Petro-Canada from our audit of internal control over financial reporting. Assets attributable to Petro-Canada as of August 1, 2009 represented approximately 50% of the company's total assets as of August 1, 2009, and revenues attributable to Petro-Canada for the period August 1, 2009 to December 31, 2009 represented approximately 25% of the company's total revenues for the year ended December 31, 2009.

In our opinion, the company maintained, in all material respects, effective internal control over financial reporting as at December 31, 2009 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 26, 2010

58 SUNCOR ENERGY INC. 2009ANNUAL REPORT

SUNCOR ENERGY INC.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

(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 23.

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 (the "company"). 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. Significant estimates used in the preparation of the financial statements include, but are not limited to, asset retirement obligations, income taxes, employee future benefits, valuation of derivative instruments, the estimates of oil and natural gas reserves and related depreciation, depletion and amortization, and the valuation of goodwill.

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

(b) Revenues

Revenue from the sale of crude oil, natural gas, natural gas liquids, purchased products and refined petroleum products is recorded when title passes to the customer and collection is reasonably assured. Revenue from oil and natural gas production is recorded net of royalties payable to governments and other mineral interest owners and revenue from properties in which the company has an interest with other producers is recognized on the basis of the company's net working interest. Inter-segment sales of crude oil and natural gas are accounted for at market values and included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer. Inter-segment amounts are eliminated on consolidation.

International operations conducted pursuant to exploration and production-sharing agreements (EPSAs) are reflected in the Consolidated Financial Statements based on the company's working interest in such operations. Under the EPSAs, the company and other non-governmental partners, if any, pay all exploration costs and a pro-rata share of costs to develop and operate the concessions. Each EPSA establishes specific terms for the company to recover these costs (Cost Recovery Oil) and to share in the production profits (Profit Oil). Cost Recovery Oil is determined in accordance with a formula that is generally limited to a specified percentage of production during each fiscal year. Profit Oil is that portion of production remaining after deducting Cost Recovery Oil and is shared between the joint venture partners and the government of each country. Cost Recovery Oil, Profit Oil and amounts in respect of all income taxes payable by the company under the laws of the respective country are reported as sales revenue. All other government stakes, other than income taxes, are considered to be royalty interests.

(c) Transportation Costs

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

(d) Foreign Currency Translation

The International operating segment, the United States operations of our refining and marketing and natural gas businesses, 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 (loss) in the Consolidated Statements of Comprehensive Income.

Otherwise, 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. With the exception of balances pertaining to self-sustaining operations, 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.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 59

(e) 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.

(f) Earnings Per Share

Basic earnings per share are calculated by dividing the net earnings by the weighted-average number of common shares outstanding. Diluted earnings per share reflect the potential dilution that would occur if stock options, excluding stock options with a cash payment alternative were exercised. The treasury stock method is used in calculating diluted earnings per share, which assumes that any proceeds received from the exercise of in-the-money stock options would be used to purchase common shares at the average market price for the period. A liability and expense is recorded for stock options with a cash payment alternative. Accordingly, the potential issuance of common shares associated with these stock options is not included in the calculation of diluted earnings per share.

(g) Cash and Cash Equivalents

Cash and cash equivalents consist primarily of cash in banks, term deposits, certificates of deposit and all other highly liquid investments with a maturity at the time of purchase of three months or less.

(h) Inventories

Inventories of crude oil and refined products, other than inventories held for trading purposes are valued at the lower of cost (using the first-in, first-out (FIFO) method) and net realizable value. Costs include direct and indirect expenditures incurred in bringing an item or product to its existing condition and location. Materials and supplies are valued at the lower of average cost and net realizable value.

Inventories held for trading purposes in the company's energy supply and trading operations are carried at fair value less costs to sell and any changes in fair value are recognized as gains or losses within Energy Supply and Trading Activities revenue in the Consolidated Statements of Earnings.

(i) Investments

Investments in companies over which the company has significant influence are accounted for using the equity method.

(j) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

The company follows the successful efforts method of accounting for the exploration and development expenditures of oil and gas producing activities. 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.

Development costs, including the costs of developing production facilities, which include the costs of wellhead equipment, development drilling costs, applicable geological and geophysical costs, gas plants and handling facilities, offshore platforms and subsea structures, upgraders, extraction plants 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.

Development of oil sands mining activities are capitalized when costs are recoverable and directly result in an identifiable future benefit.

Costs incurred after the inception of operations are expensed. Planned major maintenance and expenditures that increase capacity or extend the useful lives of assets are capitalized.

Interest Capitalization

Interest costs relating to major capital projects in progress 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. Capitalization of

60 SUNCOR ENERGY INC. 2009ANNUAL REPORT

interest is suspended while an asset is in safe mode. Capitalized interest cannot exceed the actual interest incurred during the period.

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

Depreciation and depletion of property, plant and equipment for oil and gas producing properties follow successful efforts accounting. Acquisition costs of unproved properties for natural gas and conventional crude are amortized over the lease term until proved reserves are confirmed. Exploration drilling and development costs are depleted over the remaining proved developed reserves. Proved property acquisition costs are depleted over the remaining proved reserves.

Mine and mobile equipment costs are depleted on unit-of-production basis over proved developed reserves or depreciated on a straight-line basis over periods ranging from two to 20 years, while mining extraction and upgrading facilities and other property and equipment, including leases in service, are depreciated on a straight-line basis over periods ranging from four to 40 years. Gas plants, central processing facilities of in-situ oil sands activities, and support facilities and equipment are depreciated on a straight-line basis over their useful lives, which range from 3 years to 30 years.

Capital expenditures associated with significant development projects are not depleted until facilities are substantially complete and ready for their intended productive use.

Depreciation of property, plant and equipment in the refining and marketing operations are provided on a straight-line basis over the useful lives of assets. The refineries and lubricants plant and additions thereto are depreciated over an average of 30 years, service stations and related equipment over four to 20 years and pipeline facilities and other equipment over three to 40 years.

Depreciation, depletion and amortization rates for all capitalized costs associated with all of the company's activities are reviewed, at least annually, or when events or conditions occur that impact capitalized costs, reserves or estimated service lives.

The cost of major maintenance shutdowns is capitalized and amortized on a straight-line basis over the period to the next shutdown, which varies from three to nine years.

Impairment

Property, plant and equipment are reviewed for impairment whenever events or conditions indicate that their net carrying amount 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 and Abandonments

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 on significant disposals or disposal of an entire property are recognized in earnings. All other disposals and abandonments of oil and gas property, plant and equipment are charged to depreciation, depletion and amortization expense.

(k) Business Combinations and Goodwill

Acquisitions are accounted for using the purchase method in accordance with Canadian Institute of Chartered Accountants ("CICA") Handbook section 1581. Under this method, the purchase consideration of the combination is allocated to the identifiable assets, liabilities and contingent liabilities on the basis of fair value as of the date of acquisition.

Goodwill, which is not amortized, is the excess of the purchase price over such fair value and is assigned to the appropriate reporting units. The carrying value of goodwill is assessed for impairment annually or more frequently as economic events dictate, by comparing the fair value of the reporting unit to its carrying value, including goodwill. If the fair value of the reporting unit is less than its carrying value, goodwill impairment is recognized as the excess of the carrying value of the goodwill over the fair value of the goodwill.

(l) Intangible Assets

Intangible assets, other than goodwill, include acquired customers lists and brand value and are stated at the amount initially recognized, less accumulated amortization. Intangible assets with a finite life are amortized over their expected useful lives which range from five to 10 years, while intangible assets with an indefinite useful life are not subject to amortization. Expected useful

SUNCOR ENERGY INC. 2009ANNUAL REPORT 61

lives of intangible assets are reviewed on an annual basis and, if necessary, changes in useful lives are accounted for prospectively.

The carrying values of intangible assets with a finite life are reviewed for impairment whenever events or changes in circumstances indicate the carrying value may not be recoverable. Intangible assets with an indefinite useful life are assessed for impairment annually, or more frequently as economic events dictate that carrying value may be less than fair value. If it is determined that the estimated net recoverable amount or fair value is less than the net carrying amount, a write-down is recognized during the period, with a charge to earnings.

(m) 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. Changes in the estimated obligation resulting from revisions to the estimated timing or amount of undiscounted cash flows are recognized as a change in the asset retirement obligation and related asset. Actual expenditures incurred are charged against the accumulated obligation.

(n) Stock-Based Compensation Plans

Under the company's common stock-based compensation plans (see note 15), stock-based awards are granted to executives, employees and non-employee directors. Compensation expense is recorded in the Consolidated Statements of Earnings as operating, selling and general expense.

For common share options granted to employees and non-employee directors on or after January 1, 2003, 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 over the estimated vesting periods of the respective options. A corresponding increase is recorded as contributed surplus in the Consolidated Statements of Changes in Shareholders' Equity. Consideration paid to the company on exercise of options is credited to share capital.

Stock-based compensation awards that are to be settled in cash or have the option to settle in cash or shares are measured using the intrinsic value method at each period end. A liability and expense are recorded over the vesting period in the amount by which the then current market price exceeds the option exercise price. The expense is recognized in the Consolidated Statements of Earnings. When awards are surrendered for cash, the cash settlement paid reduces the outstanding liability. When awards are exercised for common shares, consideration paid by the holder and the previously recognized liability associated with the stock options are recorded as common shares.

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.

(o) 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 as described in note 14.

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 corporate 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.

(p) Financial Instruments

All financial instruments are initially recognized at fair value on the balance sheet. The company has classified each financial instrument into one of the following categories: held-for-trading financial assets and liabilities, loans and receivables, held-to-maturity financial assets, and other financial liabilities. Subsequent measurement of financial instruments is based on their classification.

Held-for-trading financial assets and liabilities are subsequently measured at fair value with changes in those fair values recognized in net earnings. Loans and receivables, held-to-maturity financial assets and other financial liabilities are subsequently measured at amortized cost using the effective interest method.

62 SUNCOR ENERGY INC. 2009ANNUAL REPORT

The company classifies cash and cash equivalents as held-for-trading financial assets, accounts receivable as loans and receivables, and accounts payable and accrued liabilities, short-term notes payable, long-term debt and other liabilities as other financial liabilities. The company combines transaction costs and premiums or discounts directly attributable to the issuance of long-term debt with the fair value of the debt and amortizes these amounts to earnings using the effective interest 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 below.

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.

Derivative Financial Instruments

The company may use derivative financial instruments to manage certain exposures to fluctuations in interest rates, commodity prices, foreign exchange rates, as well as for trading purposes. Derivative contracts for trading and non-trading activities are required to be recorded on the balance sheet at fair value. Derivative contracts that the company accounts for as designated hedges are assessed at each reporting date to determine if the relationship between the derivative and the underlying hedged exposure is still effective, and to quantify any ineffectiveness in the relationship.

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 realized. 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 that utilize observable market data. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

Derivative contracts not accounted for as designated hedges are recorded on the balance sheet at fair value, with any change in fair value immediately recorded as a net gain or loss in net earnings.

(q) Recent Accounting Pronouncements

Business Combinations

In January 2009, the CICA issued section 1582 "Business Combinations" to replace section 1581. The CICA concurrently issued section 1601 "Consolidated Financial Statements" and section 1602 "Non-Controlling Interests" which replace section 1600 "Consolidated Financial Statements". Prospective application of the standards is effective for fiscal years beginning on or after January 1, 2011, with early adoption permitted. The new standards revise guidance on the determination of the carrying amount of the assets acquired and liabilities assumed, goodwill and accounting for non-controlling interests at the time of a business combination. The company applied section 1581 to the Petro-Canada business combination; however the company will continue to consider the application of section 1582 to business combinations in 2010.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 63

CONSOLIDATED STATEMENTS OF EARNINGS

For the years ended December 31 ($ millions)		2009		2008 (restated)		2007 (restated)
Revenues
	Operating revenues (notes 4 and 22)	18 658		18 179		15 193
	Less: Royalties	(1 199	)	(890	)	(691	)
	Operating revenues (net of royalties)	17 459		17 289		14 502
	Energy supply and trading activities (notes 4 and 5)	7 577		11 320		2 782
	Interest and other income (note 2e)	444		28		30
		25 480		28 637		17 314
Expenses
	Purchases of crude oil and products	7 383		7 582		6 414
	Operating, selling and general (note 15)	6 641		4 186		3 450
	Energy supply and trading activities (notes 4 and 5)	7 381		11 323		2 870
	Transportation	427		246		160
	Depreciation, depletion and amortization	2 306		1 049		864
	Accretion of asset retirement obligations	155		64		48
	Exploration (note 21)	268		90		95
	Loss on disposal of assets	66		13		7
	Project start-up costs	51		35		68
	Financing expenses (income) (note 6)	(487	)	917		(211	)
		24 191		25 505		13 765
Earnings Before Income Taxes		1 289		3 132		3 549
Provisions for (Recovery of) Income Taxes (note 7)
	Current	868		514		382
	Future	(725	)	481		184
		143		995		566
Net Earnings		1 146		2 137		2 983
Net Earnings Per Common Share (dollars) (note 8)
	Basic	0.96		2.29		3.23
	Diluted	0.95		2.26		3.17
Cash dividends		0.30		0.20		0.19

CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

Years ended December 31 ($ millions)		2009		2008	2007
Net earnings		1 146		2 137	2 983
Other comprehensive income (loss), net of tax (notes 4 and 20)
	Change in foreign currency translation adjustment	(332	)	350	(195	)
	Gain on derivative contracts designated as cash flow hedges	2		—	5
Comprehensive Income		816		2 487	2 793

See accompanying Summary of Significant Accounting Policies and Notes.

64 SUNCOR ENERGY INC. 2009ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)			2009 (note 2)	2008 (restated) (note 1)
Assets
	Current assets
		Cash and cash equivalents	505	660
		Accounts receivable (note 4)	3 936	1 580
		Inventories (note 11)	2 971	909
		Income taxes receivable	587	67
		Future income taxes (note 7)	332	21
	Total current assets		8 331	3 237
	Property, plant and equipment, net (note 13)		57 485	28 882
	Other assets (note 12)		536	388
	Goodwill (note 2d)		3 201	21
	Future income taxes (note 7)		193	—
	Total assets		69 746	32 528
Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	2	2
		Current portion of long-term debt	25	18
		Accounts payable and accrued liabilities (notes 4, 14, 15 and 16)	6 529	3 326
		Income taxes payable	1 274	81
		Future income taxes (note 7)	18	111
	Total current liabilities		7 848	3 538
	Long-term debt (note 17)		13 855	7 866
	Accrued liabilities and other (notes 4, 14, 15 and 16)		5 062	1 986
	Future income taxes (note 7)		8 870	4 615
	Shareholders' equity (see below)		34 111	14 523
	Total liabilities and shareholders' equity		69 746	32 528
	Commitments and contingencies (note 19)

SHAREHOLDERS' EQUITY

As at December 31 ($ millions)	Number (thousands)	2009		Number (thousands)	2008
Share capital	1 559 778	20 053		935 524	1 113
Contributed surplus		526			288
Accumulated other comprehensive income (loss) (notes 4 and 20)		(233	)		97
Retained earnings		13 765			13 025
Total shareholders' equity		34 111			14 523

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 26, 2010

SUNCOR ENERGY INC. 2009ANNUAL REPORT 65

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the Years Ended December 31 ($ millions)		2009		2008 (restated)		2007 (restated)
Operating Activities
Net earnings		1 146		2 137		2 983
Adjustments for:
	Depreciation, depletion and amortization	2 306		1 049		864
	Future income taxes	(725	)	481		184
	Accretion of asset retirement obligations	155		64		48
	Unrealized foreign exchange (gain) loss on U.S. dollar denominated long-term debt	(858	)	919		(252	)
	Change in fair value of derivative contracts	980		(638	)	6
	Loss on disposal of assets	66		13		7
	Stock-based compensation	262		(22	)	148
	Gain on effective settlement of pre-existing contract with Petro-Canada (note 2e)	(438	)	—		—
	Other	(278	)	(7	)	(18	)
	Exploration expenses	183		61		67
Cash flow from operating activities before changes in non-cash working capital		2 799		4 057		4 037
Decrease (increase) in non-cash working capital related to operating activities (note 10)		(224	)	405		(144	)
Cash flow from operating activities		2 575		4 462		3 893
Investing Activities
Capital and exploration expenditures		(4 246	)	(7 987	)	(5 629	)
Deferred outlays and other investments		(30	)	(51	)	(32	)
Cash acquired through business combination (net) (note 2d)		248		—		—
Proceeds from disposals		148		33		9
Decrease (increase) in non-cash working capital related to investing activities		(791	)	415		290
Cash flow used in investing activities		(4 671	)	(7 590	)	(5 362	)
Net cash deficiency before financing activities		(2 096	)	(3 128	)	(1 469	)
Financing Activities
Decrease in short-term debt		—		(1	)	(4	)
Net proceeds from issuance of long-term debt		—		2 704		1 835
Net increase (decrease) in revolving-term debt		2 325		422		(171	)
Issuance of common shares under stock option plan		41		190		62
Dividends paid on common shares		(401	)	(180	)	(162	)
Deferred revenue		—		—		4
Cash flow provided by financing activities		1 965		3 135		1 564
Increase (Decrease) in Cash and Cash Equivalents		(131	)	7		95
Effect of Foreign Exchange on Cash and Cash Equivalents		(24	)	84		(47	)
Cash and Cash Equivalents at Beginning of Period		660		569		521
Cash and Cash Equivalents at End of Period		505		660		569

See accompanying Summary of Significant Accounting Policies and Notes.

66 SUNCOR ENERGY INC. 2009ANNUAL 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, 2006	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 accumulated other comprehensive income (loss)	—	—		(190	)	—
At December 31, 2007	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 accumulated other comprehensive income (loss)	—	—		350		—
At December 31, 2008	1 113	288		97		13 025
Net earnings	—	—		—		1 146
Dividends paid on common shares	—	—		—		(401	)
Issued for cash under stock option plans	57	(16	)	—		—
Issued under dividend reinvestment plan	5	—		—		(5	)
Stock-based compensation expense	—	103		—		—
Issued for Petro-Canada acquisition (note 2c)	18 878	—		—		—
Fair value of Petro-Canada stock options exchanged for Suncor stock options (note 2c)	—	147		—		—
Income tax benefit of stock option deduction in the U.S.	—	4		—		—
Change in accumulated other comprehensive income (loss)	—	—		(330	)	—
At December 31, 2009	20 053	526		(233	)	13 765

See accompanying Summary of Significant Accounting Policies and Notes.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 67

SCHEDULES OF SEGMENTED DATA ^(a)

	Oil Sands						Natural Gas						East Coast Canada				International
For the Years Ended December 31 ($ millions)	2009		2008		2007		2009		2008		2007		2009		2008	2007	2009		2008	2007
EARNINGS
Revenues (b)
Operating revenues	4 135		8 045		6 160		612		696		541		499		—	—	1 434		—	—
Less: Royalties	(645	)	(715	)	(565	)	(85	)	(175	)	(126	)	(217	)	—	—	(252	)	—	—
Operating revenues (net of royalties)	3 490		7 330		5 595		527		521		415		282		—	—	1 182		—	—
Energy supply and trading activities	—		—		—		—		—		—		—		—	—	—		—	—
Intersegment revenues (c)	2 609		1 309		580		154		58		12		159		—	—	—		—	—
Interest and other income	440		—		—		—		—		—		—		—	—	1		—	—
	6 539		8 639		6 175		681		579		427		441		—	—	1 183		—	—
Expenses
Purchases of crude oil and products	325		574		157		—		—		—		33		—	—	—		—	—
Operating, selling and general	4 277		3 203		2 439		322		160		155		72		—	—	242		—	—
Energy supply and trading activities	—		—		—		—		—		—		—		—	—	—		—	—
Transportation	248		229		138		58		17		15		19		—	—	33		—	—
Depreciation, depletion and amortization	922		580		462		448		225		189		184		—	—	400		—	—
Accretion of asset retirement obligations	111		55		40		22		8		7		4		—	—	17		—	—
Exploration	10		17		13		127		73		82		4		—	—	127		—	—
Loss (gain) on disposal of assets	70		36		1		(20	)	(22	)	(1	)	—		—	—	—		—	—
Project start-up costs	51		35		60		—		—		—		—		—	—	—		—	—
Financing expenses (income)	1		—		—		—		—		—		1		—	—	(1	)	—	—
	6 015		4 729		3 310		957		461		447		317		—	—	818		—	—
Earnings (loss) before income taxes	524		3 910		2 865		(276	)	118		(20	)	124		—	—	365		—	—
Income taxes	33		(1 035	)	(391	)	77		(29	)	45		(12	)	—	—	(200	)	—	—
Net earnings (loss)	557		2 875		2 474		(199	)	89		25		112		—	—	165		—	—
As at December 31
TOTAL ASSETS	37 553		25 795		18 172		5 003		1 862		1 811		4 771		—	—	9 913		—	—

(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 2009, 2008 or 2007 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.

68 SUNCOR ENERGY INC. 2009ANNUAL REPORT

	Refining and Marketing						Corporate, Energy Trading and Eliminations						Total
For the Years Ended December 31 ($ millions)	2009		2008		2007		2009		2008		2007		2009		2008		2007
EARNINGS
Revenues (b)
Operating revenues	11 962		9 418		8 486		16		20		6		18 658		18 179		15 193
Less: Royalties	—		—		—		—		—		—		(1 199	)	(890	)	(691	)
Operating revenues (net of royalties)	11 962		9 418		8 486		16		20		6		17 459		17 289		14 502
Energy supply and trading activities	—		—		—		7 577		11 320		2 782		7 577		11 320		2 782
Intersegment revenues (c)	51		—		(100	)	(2 973	)	(1 367	)	(492	)	—		—		—
Interest and other income	—		1		5		3		27		25		444		28		30
	12 013		9 419		8 391		4 623		10 000		2 321		25 480		28 637		17 314
Expenses
Purchases of crude oil and products	9 731		8 472		6 847		(2 706	)	(1 464	)	(590	)	7 383		7 582		6 414
Operating, selling and general	1 279		746		720		449		77		136		6 641		4 186		3 450
Energy supply and trading activities	—		—		—		7 381		11 323		2 870		7 381		11 323		2 870
Transportation	87		16		20		(18	)	(16	)	(13	)	427		246		160
Depreciation, depletion and amortization	323		202		171		29		42		42		2 306		1 049		864
Accretion of asset retirement obligations	1		1		1		—		—		—		155		64		48
Exploration	—		—		—		—		—		—		268		90		95
Loss (gain) on disposal of assets	16		6		7		—		(7	)	—		66		13		7
Project start-up costs	—		—		8		—		—		—		51		35		68
Financing expenses (income)	4		—		—		(492	)	917		(211	)	(487	)	917		(211	)
	11 441		9 443		7 774		4 643		10 872		2 234		24 191		25 505		13 765
Earnings (loss) before income taxes	572		(24	)	617		(20	)	(872	)	87		1 289		3 132		3 549
Income taxes	(139	)	19		(175	)	98		50		(45	)	(143	)	(995	)	(566	)
Net earnings (loss)	433		(5	)	442		78		(822	)	42		1 146		2 137		2 983
As at December 31
TOTAL ASSETS	10 568		3 795		4 065		1 938		1 076		461		69 746		32 528		24 509

SUNCOR ENERGY INC. 2009ANNUAL REPORT 69

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Oil Sands						Natural Gas						East Coast Canada				International
For the Years Ended December 31 ($ millions)			2009		2008		2007		2009		2008		2007		2009		2008	2007	2009		2008	2007
CASH FLOW BEFORE
	FINANCING ACTIVITIES
Operating activities
	Net earnings (loss)		557		2 875		2 474		(199	)	89		25		112		—	—	165		—	—
	Adjustments for:
		Depreciation, depletion and amortization	922		580		462		448		225		189		184		—	—	400		—	—
		Future income taxes	(643	)	535		108		(52	)	15		(43	)	12		—	—	(56	)	—	—
		Accretion of asset retirement obligations	111		55		40		22		8		7		4		—	—	17		—	—
		Unrealized (gain) loss on translation of U.S. dollar denominated long-term debt	—		—		—		—		—		—		—		—	—	—		—	—
		Change in fair value of derivative contracts	960		(590	)	10		—		—		2		—		—	—	—		—	—
		Loss (gain) on disposal of assets	70		36		1		(20	)	(22	)	(1	)	—		—	—	—		—	—
		Stock-based compensation	90		54		86		19		4		7		2		—	—	10		—	—
		Gain on effective settlement of pre-existing contract with Petro-Canada	(438	)	—		—		—		—		—		—		—	—	—		—	—
		Other	(378	)	(38	)	(16	)	(11	)	(13	)	(2	)	21		—	—	19		—	—
		Exploration expenses	—		—		—		122		61		67		—		—	—	61		—	—
Cash flow from (used in) operating activities before changes in non-cash working capital			1 251		3 507		3 165		329		367		251		335		—	—	616		—	—
Decrease (increase) in operating working capital			(202	)	934		564		(9	)	43		19		(34	)	—	—	(35	)	—	—
Total cash from (used in)
	operating activities		1 049		4 441		3 729		320		410		270		301		—	—	581		—	—
Investing activities:
	Capital and exploration expenditures		(2 807	)	(7 391	)	(4 566	)	(320	)	(342	)	(537	)	(123	)	—	—	(543	)	—	—
	Deferred outlays and other investments		(36	)	(39	)	(18	)	—		—		—		—		—	—	—		—	—
	Cash acquired through business
		combination (net)	—		—		—		—		—		—		—		—	—	—		—	—
	Proceeds from disposals		96		—		3		27		26		5		—		—	—	—		—	—
	Decrease (increase) in investing
		working capital	(799	)	434		333		(19	)	—		—		(29	)	—	—	60		—	—
Total cash from (used in) investing activities			(3 546	)	(6 996	)	(4 248	)	(312	)	(316	)	(532	)	(152	)	—	—	(483	)	—	—
Net cash surplus (deficiency)
	before financing activities		(2 497	)	(2 555	)	(519	)	8		94		(262	)	149		—	—	98		—	—

(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.

70 SUNCOR ENERGY INC. 2009ANNUAL REPORT

			Refining and Marketing						Corporate, Energy Trading and Eliminations						Total
For the Years Ended December 31 ($ millions)			2009		2008		2007		2009		2008		2007		2009		2008		2007
CASH FLOW BEFORE
	FINANCING ACTIVITIES
Operating activities
	Net earnings (loss)		433		(5	)	442		78		(822	)	42		1 146		2 137		2 983
	Adjustments for:
		Depreciation, depletion and amortization	323		202		171		29		42		42		2 306		1 049		864
		Future income taxes	109		(7	)	77		(95	)	(62	)	42		(725	)	481		184
		Accretion of asset retirement obligations	1		1		1		—		—		—		155		64		48
		Unrealized (gain) loss on translation of U.S. dollar denominated long-term debt	—		—		—		(858	)	919		(252	)	(858	)	919		(252	)
		Change in fair value of derivative contracts	(14	)	27		(6	)	34		(75	)	—		980		(638	)	6
		Loss (gain) on disposal of assets	16		6		7		—		(7	)	—		66		13		7
		Stock-based compensation	35		16		35		106		(96	)	20		262		(22	)	148
		Gain on effective settlement of pre-existing contract with Petro-Canada	—		—		—		—		—		—		(438	)	—		—
		Other	60		8		(16	)	11		36		16		(278	)	(7	)	(18	)
		Exploration expenses	—		—		—		—		—		—		183		61		67
Cash flow from (used in) operating activities before changes in non-cash working capital			963		248		711		(695	)	(65	)	(90	)	2 799		4 057		4 037
Decrease (increase) in operating working capital			(270	)	292		(247	)	326		(864	)	(480	)	(224	)	405		(144	)
Total cash from (used in)
	operating activities		693		540		464		(369	)	(929	)	(570	)	2 575		4 462		3 893
Investing activities:
	Capital and exploration expenditures		(409	)	(226	)	(449	)	(44	)	(28	)	(77	)	(4 246	)	(7 987	)	(5 629	)
	Deferred outlays and other investments		(3	)	(11	)	—		9		(1	)	(14	)	(30	)	(51	)	(32	)
	Cash acquired through business combination (net)		—		—		—		248		—		—		248		—		—
	Proceeds from disposals		25		—		1		—		7		—		148		33		9
	Decrease (increase) in investing working capital		(4	)	(19	)	(43	)	—		—		—		(791	)	415		290
Total cash from (used in) investing activities			(391	)	(256	)	(491	)	213		(22	)	(91	)	(4 671	)	(7 590	)	(5 362	)
Net cash surplus (deficiency) before financing activities			302		284		(27	)	(156	)	(951	)	(661	)	(2 096	)	(3 128	)	(1 469	)

SUNCOR ENERGY INC. 2009ANNUAL REPORT 71

SUNCOR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGES IN ACCOUNTING POLICIES AND DISCLOSURES

(a)   Goodwill and Intangible Assets

On January 1, 2009, the company retroactively adopted Canadian Institute of Chartered Accountants (CICA) Handbook section 3064 "Goodwill and Intangible Assets." This new standard replaces section 3062 "Goodwill and Other Intangible Assets" and section 3450 "Research and Development Costs," and focuses on the criteria for asset recognition in the financial statements, including those internally developed. The impact of adopting this standard resulted in a change in the classification of our deferred maintenance shutdown costs that had previously been classified within other assets and amortized over the period to the next shutdown. At December 31, 2008, property, plant and equipment was increased by $566 million, with an equal and offsetting reduction to other assets.

(b)   Credit Risk and the Fair Value of Financial Assets and Financial Liabilities

On January 1, 2009, the company adopted the recommendations of CICA Emerging Issues Committee Abstract 173 relating to the fair value of financial assets and liabilities. The Abstract requires that an entity's own credit risk and the credit risk of the counterparty are taken into account in determining the fair value of financial assets and liabilities, including derivative instruments. The Abstract is to be applied retroactively without restatement of prior periods. The company has evaluated the new abstract and concluded that the adoption of the new requirements did not have a material impact on Suncor's financial statements.

(c)    Financial Instruments Disclosures

On December 31, 2009, the company prospectively adopted amendments to CICA Handbook section 3862 "Financial Instruments: Disclosures," requiring adoption for annual periods ending on or after September 30, 2009. The amendments require additional disclosures on fair value measurements of financial instruments and enhanced liquidity risk disclosure. These additional disclosures are provided in note 4.

2. BUSINESS COMBINATION WITH PETRO-CANADA

(a)   Overview

In the first quarter of 2009, Suncor announced that it had agreed to merge with Petro-Canada. The transaction was accomplished through a plan of arrangement, which included a share exchange, pursuant to which holders of common shares of Petro-Canada received 1.28 common shares of Suncor for each common share of Petro-Canada held.

In the second and third quarters of 2009, the arrangement received approval from Suncor and Petro-Canada shareholders, the Alberta Court of Queen's Bench, and the Competition Bureau of Canada. The transaction closed August 1, 2009 and the merged company continues to operate as Suncor Energy Inc.

(b)   Accounting for Business Combinations

The company has accounted for this business combination as prescribed by CICA Handbook section 1581 "Business Combinations." As the acquirer, the company is required to recognize Petro-Canada assets and liabilities as at August 1, 2009. The results of Petro-Canada operations are included in the consolidated financial statements of the company from August 1, 2009.

(c)    Consideration and Purchase Price

Consideration offered to complete the merger included 621.1 million shares of Suncor with a value of $18,878 million, or $30.39 per share, that were issued to Petro-Canada shareholders and 7.1 million Suncor share options with a fair value of $147 million, that were exchanged for existing Petro-Canada share options. The replacement of stock options and other stock-based compensation plans that are accounted for as liabilities are not included in consideration (see note 15).

72 SUNCOR ENERGY INC. 2009ANNUAL REPORT

The total purchase price for the acquisition was $19,630 million, consisting of the following amounts:

($ millions)
621.1 million common shares issued to Petro-Canada shareholders	18 878
7.1 million Petro-Canada share options exchanged for share options of Suncor	147
Transaction costs	167
Effective settlement of pre-existing contract with Petro-Canada (note e)	438
Total purchase price	19 630

(d)   Preliminary Allocation of Purchase Price

The following estimated fair values were assigned to the net assets of Petro-Canada as at August 1, 2009:

($ millions)
Current assets		4 645
Property, plant and equipment		27 407
Other assets		537
	Total assets	32 589
Current liabilities		3 741
Long-term debt		4 410
Accrued liabilities and other		3 416
Future income taxes		4 570
	Total liabilities	16 137
Net assets purchased		16 452
Goodwill		3 178
	Total purchase price	19 630

The preliminary purchase price allocation is based on current best estimates by Suncor's management and is based principally on valuations prepared by independent valuation specialists.

Cash acquired was $248 million, net of transaction costs of $167 million.

Other assets includes $236 million for intangible assets, relating to the Petro-Canada brand, with an indefinite life, and customer lists, which will be amortized over their estimated useful lives.

The fair value for current liabilities includes $216 million for provisions for costs related to exiting certain activities of Petro-Canada and involuntary termination benefits. As at December 31, 2009, $118 million of actual expenses had been charged against these provisions.

$3,019 million of the goodwill has been allocated to the Oil Sands segment and the remaining $159 million has been allocated to the Refining and Marketing segment. No amount that is part of goodwill is expected to be deductible for tax purposes.

(e)   Pre-Existing Contract with Petro-Canada

CICA Emerging Issues Committee Abstract 154 (EIC 154) Accounting for Pre-existing Relationships between the Parties of a Business Combination states that the consummation of a business combination between parties with a pre-existing relationship requires an evaluation to determine if a settlement of the related contract exists, and where the relationship is favourable to the acquirer, that the purchase cost of the acquisition be the sum of the consideration paid and the benefit from the settlement of the relationship. The benefit is measured as the lesser of the amount of any stated settlement provisions in the contract and the amount by which the contract is favourable, from the perspective of the acquirer, when compared to pricing for current market transactions for the same or similar items.

In 2003, Suncor entered into a fee-for-service contract where it agreed to upgrade bitumen supplied by Petro-Canada. The contract came into effect January 1, 2009. The contract processing fee included an escalation factor tied to the price of West Texas Intermediate (WTI) crude, which was intended to approximate changes in Canadian light/heavy differentials for crude oil. The contract terms included a take-or-pay volume commitment and no early settlement provisions.

Since 2003, crude prices have increased significantly and industry conditions for the supply and demand of upgraded bitumen have changed dramatically resulting in the contract being favourable to Suncor at the transaction closing date. A value of $438 million was assigned to the effective settlement of the contract, by comparing estimated future processing fees on the take-or-pay volume commitment to estimated Canadian light/heavy differentials using future pricing assumptions for WTI, synthetic crude and bitumen.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 73

The deemed settlement amount of $438 million (net of income taxes of $nil) is included in the total purchase price of the acquisition and included in interest and other income in the Consolidated Statement of Earnings.

3. CHANGE IN SEGMENTED DISCLOSURES

As a result of the business combination described in note 2, the company has reclassified its operations into the following segments.

Oil Sands includes the company's operations in northeast Alberta to produce synthetic crude through the recovery and upgrading of bitumen from mining and in-situ development.

Natural Gas includes exploration and production of natural gas, crude oil and natural gas liquids, primarily in Western Canada.

The East Coast Canada segment comprises activity offshore Newfoundland and Labrador, and includes interests in the Hibernia, Terra Nova, White Rose and Hebron oilfields.

The International segment includes the exploration for, and production of, crude oil and natural gas in the United Kingdom, the Netherlands, Norway, Trinidad and Tobago, Libya and Syria.

Refining and Marketing includes the purchase and sale of crude oil, the refining of crude oil products, and the distribution and marketing of these and other purchased products through refineries located in Eastern and Western Canada and the U.S., as well as a lubricants plant located in Eastern Canada. Energy supply and trading activities that were previously included in the Refining and Marketing segment are now included within Corporate, Energy Trading and Eliminations.

The Corporate, Energy Trading and Eliminations includes third-party energy supply and trading activities, and activities not directly attributable to an operating segment.

All prior periods have been restated to conform to these segment definitions.

4. 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.

The recent merger has provided Suncor with the ability to capitalize on future trading opportunities due to increased transactional and trading capacity. The company determined that new transaction levels for certain physical trading commodity contracts exceeded the company's expected purchase, sale or usage requirements. Effective October 1, 2009, these contracts are now considered derivative financial instruments whereby realized and unrealized gains and losses, and the underlying settlement of these contracts is recognized and reported on a net basis in Energy Supply and Trading Activities revenue. The related inventory is carried at fair value less costs to sell, with changes in fair value recognized as gains or losses within Energy Supply and Trading Activities revenue.

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).

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.

74 SUNCOR ENERGY INC. 2009ANNUAL REPORT

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 income taxes), long-term debt, and a portion of non-current accrued liabilities and other. 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, with the exception of the portion of debt that has related financial hedges which is accounted for under the fair value methodology discussed below. 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, 2009, the carrying value of our fixed-term debt accounted for under the amortized cost method was $10.1 billion (December 31, 2008 – $6.7 billion) and the fair value at December 31, 2009 was $10.7 billion (December 31, 2008 – $5.4 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, 2009, the company had interest rate swaps classified as fair value hedges outstanding for up to two years relating to $200 million of its fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the year ended December 31, 2009 (no ineffectiveness during the year ended December 31, 2008). The fair value of interest rate swap contracts outstanding at December 31, 2009 is detailed in note 17.

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. There was no earnings impact associated with hedge ineffectiveness on derivative contracts to hedge risks specific to individual transactions during the year ended December 31, 2009 (2008 – loss 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.

There was no earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the years ended December 31, 2009 and December 31, 2008.

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.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 75

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 2009	December 31 2008
Revenue hedge swaps and collars (b)	—	(2	)
Fixed to floating interest rate swaps (a)	18	25
Specific hedges of individual transactions (b)	—	(11	)
Fair value of outstanding hedging derivative financial instruments	18	12

(a)

As at December 31, 2009, $10 million is recorded in accounts receivable (2008 – $9 million) and $8 million is recorded in other assets (2008 – $16 million) in the Consolidated Balance Sheets.

(b)

As at December 31, 2009, $nil is recorded in accounts payable and accrued liabilities (2008 – $13 million) in the Consolidated Balance Sheets.

Accumulated Other Comprehensive Income (AOCI)

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

($ millions)	2009	2008
AOCI attributable to derivative hedging activities, beginning of the period, net of income taxes of $5 (2008 – $4)	13	13
Current year net changes arising from cash flow hedges, net of income taxes of $nil (2008 – $2)	—	(7	)
Net unrealized hedging losses (gains) at the beginning of the year reclassified to earnings during the period, net of income taxes of $nil (2008 – $3)	2	7
AOCI attributable to derivative hedging activities, at December 31, net of income taxes of $5 (2008 – $5)	15	13

(c)    Derivatives

Commodity Price Risk Derivatives

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. Changes in fair value of these derivative financial instruments are immediately recorded as a gain or loss in the same revenue or expense account where the hedged transaction is recorded. The earnings impact associated with these contracts for the year ended December 31, 2009, was a loss of $763 million, net of income taxes of $261 million (2008 – a gain of $348 million, net of income taxes of $142 million).

Significant contracts outstanding at December 31, 2009 were as follows:

Crude oil	Quantity (bpd)	Average Price (1) (US$/bbl)	Hedge Period
Purchased puts (2)	55 000	60.00	2010
Sold puts (3)	54 753	60.00	2010
Collars – floor	50 041	50.00	2010
Collars – cap	49 986	68.06	2010

(1)

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

(2)

Premium paid was US$29.5 million.

(3)

Premium received was US$213 million.

Energy Trading Derivatives

The company's Energy Trading group also 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 and physical energy trading activities are accounted for using the mark-to-market method, with the associated gains and losses and the underlying settlement of these contracts recognized and reported on a net basis in Energy Supply and Trading Activities Revenue in the Consolidated Statements of Earnings.

The earnings impact associated with these contracts for the year ended December 31, 2009, was a loss of $52 million, net of income taxes of $18 million (2008 – a gain of $90 million, net of income taxes of $37 million).

76 SUNCOR ENERGY INC. 2009ANNUAL REPORT

Fair Value of Non-Designated Derivative Financial Instruments

The fair values of the derivative assets and liabilities above are as follows:

($ millions)	December 31 2009		December 31 2008
Derivative assets (a)	213		635
Derivative liabilities (b)	(572	)	(14	)
Net derivative assets (liabilities)	(359	)	621

(a)

As at December 31, 2009, $213 million is recorded in accounts receivable (2008 – $376 million recorded in accounts receivable and $259 million recorded in other assets) in the Consolidated Balance Sheets.

(b)

As at December 31, 2009, $572 million is recorded in accounts payable and accrued liabilities (2008 – $14 million) in the Consolidated Balance Sheets.

Change in fair value of net assets

($ millions)	2009
Fair value of contracts at December 31, 2008	621
Fair value of contracts realized during the period	448
Fair value of contracts entered into during the period	(983	)
Changes in fair value during the period	(445	)
Fair value of contracts outstanding at December 31, 2009	(359	)

(d)   Fair Value of Financial Instruments

To estimate fair value of financial instruments, the company uses quoted market prices when available, or industry accepted third-party models and valuation methodologies that utilize observable market data. In addition to market information, the company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. The company characterizes inputs used in determining fair value using a hierarchy that prioritizes inputs depending on the degree to which they are observable. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction. The three levels of the fair value hierarchy are as follows:

•

Level 1 – inputs represent quoted prices in active markets for identical assets or liabilities (for example, exchange-traded commodity derivatives). Active markets are those in which transactions occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

•

Level 2 – inputs other than quoted prices included within Level 1 that are observable, either directly or indirectly, as of the reporting date. Level 2 valuations are based on inputs, including quoted forward prices for commodities, market interest rates, and volatility factors, which can be observed or corroborated in the marketplace. The company obtains information from sources such as the New York Mercantile Exchange and independent price publications.

•

Level 3 – inputs that are less observable, unavailable or where the observable data does not support the majority of the instrument's fair value.

In forming estimates, the company utilizes the most observable inputs available for valuation purposes. If a fair value measurement reflects inputs of different levels within the hierarchy, the measurement is categorized based upon the lowest level of input that is significant to the fair value measurement. The valuation of over-the-counter financial swaps and collars is based on similar transactions observable in active markets or industry standard models that primarily rely on market observable inputs. Substantially all of the assumptions for industry standard models are observable in active markets throughout the full term of the instrument. These are categorized as Level 2.

The following table presents the company's material assets and liabilities measured at fair value for each hierarchy level as of December 31, 2009:

($ millions)	Level 1		Level 2		Level 3	Total Fair Value
Designated hedge financial instruments	—		18		—	18
Other derivative financial instruments	(13	)	(348	)	2	(359	)
Total	(13	)	(330	)	2	(341	)

SUNCOR ENERGY INC. 2009ANNUAL REPORT 77

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 prices for portions of the total crude oil planned production for specified periods of time.

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 at our North American operations, 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 year ended December 31, 2009:

Sensitivity Analysis

($ millions)		December 31, 2009 (1)	Change	Net Earnings		Other Comprehensive Income
Crude Oil		US$85.55/barrel
	Price increase		US$1.00/barrel	(18	)	—
	Price decrease		US$1.00/barrel	18		—
Natural Gas		US$5.81/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, 2009.

(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 17) 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 $0.01 change in the December 31, 2009 US$/Cdn$ exchange rate would change after-tax earnings by approximately $75 million and after-tax other comprehensive income by approximately $40 million for the year ended December 31, 2009.

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.

78 SUNCOR ENERGY INC. 2009ANNUAL REPORT

(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 our revolving-term debt (commercial paper, bankers' acceptances and London Interbank Offered Rate (LIBOR) loans). 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 on page 75) 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, 2009 was 25% of total debt outstanding (December 31, 2008 – 15%). The weighted-average interest rate on total debt for the year ending December 31, 2009 was 5.6% (December 31, 2008 – 5.9%).

The company's cash flows are sensitive to changes in interest rates on the floating rate portion of the company's debt. 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 year ended December 31, 2009 would decrease by approximately $34 million and earnings would decrease by approximately $27 million. This assumes that the amount and mix of fixed and floating rate debt remains unchanged from December 31, 2009, and that the change in interest rates is effective from the beginning of the year.

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, 2009		December 31, 2008
($ millions)	Trade and other payables (1)	Finance debt (2)	Trade and other payables (1)	Finance debt (2)
Within one year	6 529	3 796	3 181	1 378
1 to 3 years	653	1 811	335	1 377
3 to 5 years	—	1 591	—	822
Over 5 years	—	18 900	16	13 387
Total	7 182	26 098	3 532	16 964

(1)

Includes the Fort Hills purchase obligation and the Libya EPSAs signature bonus.

(2)

Finance debt includes principal and interest payments on long-term debt and capital lease payments.

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, 2009, 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, 2009, the company's exposure was $231 million (December 31, 2008 – $659 million).

SUNCOR ENERGY INC. 2009ANNUAL REPORT 79

5. ENERGY SUPPLY AND TRADING ACTIVITIES

($ millions)	December 31 2009		December 31 2008		December 31 2007
Settlement of non-trading physical contracts (1)	8 008		11 295		2 931
Settlement of trading physical contracts (1)	20		—		—
Gains (losses) on trading derivatives (1)	(70	)	127		(39	)
Gains on inventory valuation (1)	47		—		—
Less: Intercompany eliminations	(428	)	(102	)	(110	)
Energy Supply and Trading Activities Revenue	7 577		11 320		2 782
Settlement of non-trading physical contracts (1)	7 929		11 331		2 871
Less: Intercompany eliminations	(548	)	(8	)	(1	)
Energy Supply and Trading Activities Expense	7 381		11 323		2 870

(1)

As described in Note 4, certain physical trading strategies are no longer being used for the company's expected purchase, sale or usage requirements. Effective October 1, 2009, contracts within these strategies are now considered derivative financial instruments whereby realized and unrealized gains and losses, and the underlying settlement of these contracts, is recognized and reported on a net basis in Energy Supply and Trading Activities Revenue. Prior to October 1, 2009, the settlement of these contracts was recorded on a gross basis within Energy Supply and Trading Activity Revenue and Energy Supply and Trading Activity Expense.

6. FINANCING EXPENSES (INCOME)

($ millions)		2009		2008		2007
Interest on debt		573		352		189
Capitalized interest		(136	)	(352	)	(189	)
	Interest expense	437		—		—
	Foreign exchange loss (gain) on long-term debt	(858	)	919		(252	)
	Other foreign exchange (gain) loss	(66	)	(2	)	41
Total financing expenses (income)		(487	)	917		(211	)

Cash interest payments in 2009 totalled $581 million (2008 – $328 million; 2007 – $183 million).

7. 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.

80 SUNCOR ENERGY INC. 2009ANNUAL REPORT

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:

($ millions)		2009		2008		2007
Earnings before income tax		1 289		3 132		3 549
Canadian statutory tax rate		30.95	%	29.52	%	32.14	%
Statutory tax		399		925		1 141
Add (deduct) the tax effect of:
	Non-taxable component of capital gains and losses	(133	)	136		(40	)
	Stock-based compensation and other permanent items	42		36		33
	Assessments and adjustments	(42	)	(48	)	(1	)
	Effect of changes to statutory enacted rates	(148	)	—		(427	)
	Impact of income tax rate adjustments on future income tax liabilities	152		—		—
	Change in valuation allowance	(59	)	—		—
	Canadian tax rate differential	(27	)	(113	)	(145	)
	Foreign tax rate differential	84		12		23
	Non-taxable gain on effective settlement of pre-existing contract with Petro-Canada (note 2(e))	(105	)	—		—
	Other	(20	)	47		(18	)
Provision for income taxes		143		995		566

At December 31, geographic distribution of current income tax provisions were as follows:

($ millions)			2009		2008		2007
Provision for (recovery of) Income Taxes:
	Current:
		Canada	599		493		271
		Foreign	269		21		111
	Future:
		Canada	(702	)	515		142
		Foreign	(23	)	(34	)	42
Total provision for income taxes			143		995		566

The provisions for current and future income taxes include tax recoveries (expenses), which are largely due to changes to income tax rates. These amounts have been allocated to the business segments as follows:

($ millions)	2009		2008	2007
Oil Sands	103		—	413
Natural Gas	8		—	39
East Coast Canada	20		—	—
Refining and Marketing	19		—	17
Corporate, Energy Trading and Eliminations	(2	)	—	(42	)
	148		—	427

In 2009, net income tax payments totalled $872 million (2008 – $638 million; 2007 – $152 million).

SUNCOR ENERGY INC. 2009ANNUAL REPORT 81

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

($ millions)		2009		2008		2007
Future income tax liabilities:
	Property, plant and equipment	9 670		4 987		4 467
	Risk management and energy trading	—		149		—
	Other	177		48		86
Future income tax assets:
	Asset retirement obligations	(813	)	(400	)	(269	)
	Employee future benefits	(352	)	(72	)	(118	)
	Risk management and energy trading	(113	)	—		—
	Other Assets	(206	)	(7	)	37
Net Future income tax liabilities		8 363		4 705		4 203
Less: Current portion of future income tax (assets)/liabilities		(314	)	90		(9	)
Future income tax liabilities		8 677		4 615		4 212

Deferred distribution taxes associated with International business operations have not been recorded. Based on current plans, repatriation of funds in excess of foreign reinvestment will not result in material additional income tax expense.

Complex income tax issues, which involve interpretation of continually changing regulations, are encountered in computing the provision for income taxes. Management believes that adequate provisions have been made for all such outstanding issues and the resolution of these issues would not materially affect the financial position or results of operation of the company,

8. EARNINGS PER COMMON SHARE

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

($ millions)		2009	2008	2007
Net earnings		1 146	2 137	2 983
(millions of common shares)
Weighted-average number of common shares		1 198	932	922
Dilutive securities:
	Shares issued under stock-based compensation plans	13	13	20
Weighted-average number of diluted common shares		1 211	945	942
(dollars per common share)
Basic earnings per share (a)		0.96	2.29	3.23
Diluted earnings per share (b)		0.95	2.26	3.17

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.

9. CASH AND CASH EQUIVALENTS

($ millions)	2009	2008
Cash	205	30
Short-term investments	300	630
	505	660

82 SUNCOR ENERGY INC. 2009ANNUAL REPORT

10. CHANGES IN NON-CASH WORKING CAPITAL RELATING TO OPERATING ACTIVITIES

Non-cash working capital is comprised of current assets and current liabilities, other than cash and cash equivalents, future income taxes and the current portion of long-term debt.

The (increase) decrease in non-cash working capital is comprised of:

($ millions)	2009 (1)		2008		2007
Operating activities
Accounts receivable	123		226		(374	)
Inventories	(585	)	103		(223	)
Accounts payable and accrued liabilities	282		186		207
Income taxes payable/receivable	(44	)	(110	)	246
	(224	)	405		(144	)

(1)

Balances do not include amounts acquired from Petro-Canada as a result of the merger, but do reflect the changes in these working capital accounts subsequent to August 1, 2009.

11. INVENTORIES

($ millions)	2009	2008
Crude oil	781	459
Refined products	1 303	247
Materials, supplies and merchandise	532	203
Energy trading commodity inventories (1)	355	—
Total	2 971	909

(1)

As described in note 4, certain physical trading commodity contracts are no longer being used for the company's expected purchase, sale or usage requirements. Inventories related to these derivative contracts are now recorded at fair value less costs to sell with the associated gains and losses and the underlying settlement of the inventory recorded on a net basis in Energy Supply and Trading Activities revenue.

During 2009, inventories of $14.9 billion (2008 – $15.7 billion) were expensed. There were no write-downs of inventories in 2009 (2008 – $40 million) and no reversals of write-downs were recorded in 2009 and 2008.

12. OTHER ASSETS

($ millions)	2009	2008
Unrealized mark-to-market gains on commodity derivatives	6	273
Intangible assets (1)	233	—
Investments	148	23
Other	149	92
Total	536	388

(1)

In 2009, $236 million of intangible assets were acquired through the business combination with Petro-Canada. $166 million of these assets relate to the Petro-Canada brand and have an indefinite life, and $70 million relate to customer lists which will be amortized over their estimated useful lives which range from five to ten years. Amortization expense recognized for the year ended December 31, 2009 related to intangible assets was $4 million (2008 – nil).

SUNCOR ENERGY INC. 2009ANNUAL REPORT 83

13. PROPERTY, PLANT AND EQUIPMENT

		2009		2008
($ millions)		Cost	Accumulated Provision	Cost	Accumulated Provision
Oil Sands
	Oil and gas properties	5 224	448	2 021	285
	Plant and equipment	19 012	3 677	14 184	2 988
	Assets not subject to depreciation or depletion(1)	12 551	—	11 107	—
		36 787	4 125	27 312	3 273
Natural Gas
	Oil and gas properties	5 925	1 613	2 584	1 213
	Plant and equipment	351	118	219	100
	Assets not subject to depreciation or depletion(1)	24	—	211	—
		6 300	1 731	3 014	1 313
East Coast Canada				—	—
	Oil and gas properties	3 463	207	—	—
	Plant and equipment	49	1	—	—
	Assets not subject to depreciation or depletion(1)	1 360	—	—	—
		4 872	208	—	—
International
	Oil and gas properties	4 130	271	—	—
	Plant and equipment	53	31	—	—
	Assets not subject to depreciation or depletion(1)	4 294	—	—	—
		8 477	302	—	—
Refining and Marketing
	Plant and equipment	8 312	1 654	4 049	1 313
	Assets not subject to depreciation or depletion(1)	503	—	215	—
		8 815	1 654	4 264	1 313
Corporate		419	165	329	138
		65 670	8 185	34 919	6 037
Net property, plant and equipment			57 485		28 882

(1)

Consists of work in progress, development assets, and assets under construction which are not currently being depreciated or depleted.

At December 31, 2009, capital leases at a net cost of $225 million (December 31, 2008 – $91 million) and $48 million are included in the assets of Oil Sands and East Coast Canada, respectively.

14. EMPLOYEE FUTURE BENEFITS LIABILITY

Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire under the terms of the company's defined benefit and defined contribution plans. The related Benefit Obligation or commitment that Suncor has to employees and retirees at December 31, 2009, was $3 279 million (2008 – $955 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of the defined benefit 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 2009, Plan Assets to meet the Benefit Obligation were $2 072 million (2008 – $613 million).

The excess of the Benefit Obligation over Plan Assets of $1 207 million (2008 – $342 million) represents the Net Unfunded Obligation.

The company also provides a number of defined contribution plans, including a U.S. 401(k) savings plan, that provide for an annual contribution of 5% to 8% of each participating employee's pensionable earnings.

84 SUNCOR ENERGY INC. 2009ANNUAL REPORT

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 plans was performed as at December 31, 2009 and the next required valuation will be as of December 31, 2012.

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.

Defined Benefit 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)		2009		2008		2009		2008
Change in benefit obligation
	Benefit obligation at beginning of year	806		901		149		162
	Plan acquisition upon merger (a)	1 912		—		265		—
	Service costs	64		56		6		4
	Interest costs	96		49		15		9
	Plan participants' contributions	17		9		—		—
	Foreign exchange	(13	)	8		(4	)	4
	Actuarial (gain) loss	59		(168	)	1		(27	)
	Benefits paid	(86	)	(49	)	(8	)	(3	)
Benefit obligation at end of year (b)(e)		2 855		806		424		149
Change in plan assets (c)
	Fair value of plan assets at beginning of year	613		684		—		—
	Plan acquisition upon merger	1 255		—				—
	Actual return (loss) on plan assets	175		(107	)	—		—
	Employer contributions	105		72		—		—
	Foreign exchange	(7	)	4		—		—
	Plan participants' contributions	17		9		—		—
	Benefits paid	(86	)	(49	)	—		—
Fair value of plan assets at end of year (e)		2 072		613		—		—
Net unfunded obligation		(783	)	(193	)	(424	)	(149	)
Items not yet recognized in earnings:
	Unamortized net actuarial loss (d)	50		123		8		12
	Unamortized past service costs	9		—		(14	)	(17	)
Accrued benefit liability		(724	)	(70	)	(430	)	(154	)
	Current liability	(30	)	(37	)	(3	)	(3	)
	Long-term liability	(701	)	(40	)	(427	)	(151	)
	Long-term asset	7		7		—		—
Total accrued benefit liability		(724	)	(70	)	(430	)	(154	)

(a)

The valuation of accrued benefit obligations for plans acquired through the business combination with Petro-Canada assumed a discount rate of 5.25%, a rate of compensation increase of 3.00% and an expected return on plan assets rate of 6.75%.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 85

(b)

Obligations are based on the following assumptions:

	Pension Benefit               Obligations		Other Post-Retirement               Benefits Obligations
(percent)	2009	2008	2009	2008
Discount rate	5.85	6.50	6.00	6.50
Rate of compensation increase	3.90	5.00	4.00	4.75

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	2	(2	)
Increase (decrease) to the health care component of the accumulated post-retirement benefit obligation	34	(28	)

(c)

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

(d)

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 7 years for pension benefits (2008 – 11 years; 2007 – 11 years), and over the expected average future service life to full eligibility age of 11 years for other post-retirement benefits (2008 – 11 years; 2007 – 12 years).

(e)

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)	2009	2008	2009	2008
Partially funded plans	2 855	806	—	—
Unfunded plans	—	—	424	149
Benefit obligation at end of year	2 855	806	424	149

Benefit Plans Expense

		Pension Benefits						Other                      Post-Retirement Benefits
($ millions)		2009		2008		2007		2009		2008		2007
	Current service costs	64		56		51		6		4		4
	Interest costs	96		49		45		15		9		8
	Actual (return) loss on plan assets (i)	(175	)	107		(7	)	—		—		—
	Actuarial (gain) loss	59		(168	)	(28	)	1		(27	)	(4	)
Pension expense before adjustments for the long-term nature of employee future benefit costs		44		44		61		22		(14	)	8
	Difference between actual and expected return on plan assets (i)	98		(152	)	(35	)	—		—		—
	Difference between actual and recognized actuarial losses	(36	)	188		51		3		33		10
	Difference between actual and recognized past service costs	2		2		2		(3	)	(3	)	(3	)
Defined benefit plans expense (ii)		108		82		79		22		16		15
Defined contribution plans expense		28		15		13		—		—		—
Total benefit plans expense		136		97		92		22		16		15

(i)

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 7 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.

86 SUNCOR ENERGY INC. 2009ANNUAL REPORT

(ii)

Defined benefit plans pension expense is based on the following assumptions:

	Pension               Benefit Expense			Other Post-Retirement               Benefits Expense
(percent)	2009	2008	2007	2009	2008	2007
Discount rate	6.50	5.25	5.00	6.00	5.25	5.00
Expected return on plan assets	6.70	6.50	6.50	N/A	N/A	N/A
Rate of compensation increase	3.90	5.00	5.00	4.00	4.75	4.75

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, 2009 and 2008, and the target allocation for 2010, are as follows:

	Target Allocation %	Plan Assets %
Asset Category	2010	2009	2008
Equities	57	59	57
Fixed income	43	41	43
Total	100	100	100

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

Cash Flows

The company expects that cash contributions to its defined benefit pension plans in 2010 will be $133 million. Expected benefit payments from all of the plans are as follows:

	Pension Benefits	Other Post-Retirement Benefits
2010	136	18
2011	145	19
2012	153	21
2013	163	23
2014	170	24
2015 – 2019	963	141
Total	1 730	246

15. SHARE CAPITAL

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. 2009ANNUAL REPORT 87

Issued

	Common Shares
	Number (thousands)	Amount ($ millions)
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
Shares issued to Petro-Canada shareholders (note 2)	621 142	18 878
Issued for cash under stock options plan	2 968	57
Issued under dividend reinvestment plan	144	5
Balance as at December 31, 2009	1 559 778	20 053

Stock-Based Compensation

A stock 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. The holder must fulfill a time requirement for service to the company, at which time the option is considered vested. Certain options are subject to accelerated vesting should the company meet predetermined performance criteria.

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 option is granted.

Certain stock options with a cash payment alternative (CPA) entitle the holder to surrender vested options for cancellation in return for a direct cash payment based on the excess of the then current market price of the underlying common share over the option exercise price or for a common share in the company at the option exercise price.

A stock appreciation right unit (SAR) entitles the holder to receive a cash payment equal to the difference between the stated exercise price and the market price of the company's common shares on the date the vested option is surrendered.

A performance share unit (PSU) is a time-vested award entitling employees to receive cash to varying degrees contingent upon the company's shareholder return relative to a peer group of companies.

A restricted share unit (RSU) is a time-vested award entitling employees to receive cash based on the company's share price at time of vesting.

A deferred share unit (DSU) is a notional share unit, redeemable for cash or a common share for a period of time after a unitholder ceases employment or Board membership. The DSU plan is only for executives and members of the company's Board of Directors.

(a)   Stock Option Plans:

(i)    SunShare 2012 Performance Stock Option Plan

Granting of options under this plan ended on July 31, 2009. The company granted 1,204,000 options in 2009 (2008 – 2,637,000, 2007 – 15,686,000) to all eligible permanent full-time and part-time employees, both executive and non-executive, under its SunShare 2012 performance stock option plan. On January 1, 2010, 25% of the outstanding options vested and the remaining 75% of outstanding options may vest on January 1, 2013 if certain specified performance targets are met. All unvested options at January 1, 2013, which have not previously expired or been cancelled will automatically expire.

(ii)   Executive Stock Plan

Granting of options under this plan ended on July 31, 2009. Under this plan, the company granted 711,000 common share options in 2009 (2008 – 895,000; 2007 – 958,000) 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.

88 SUNCOR ENERGY INC. 2009ANNUAL REPORT

(iii)  Key Contributor Stock Option Plan

Granting of options under this plan ended on July 31, 2009. Under this plan, the company granted 571,000 common share options in 2009 (2008 – 2,375,000; 2007 – 2,370,000) to non-insider senior managers and key employees. Options granted have a 10-year life and vest annually over a three-year period.

(iv)  Petro-Canada Stock Options ("Adjusted Options")

Granting of options under this plan ended on July 31, 2009. In conjunction with the business combination transaction described in note 2, each outstanding option issued under this plan to purchase Petro-Canada common shares was exchanged on August 1, 2009 for 1.28 options to purchase Suncor common shares, for a total of 29.9 million options outstanding at August 1, 2009. The same exchange ratio was applied to the exercise price of these options.

The Adjusted Options, issued to officers and certain employees, have a term of ten years if granted prior to 2004 and seven years if granted subsequent to 2003. Holders of options granted after 2003 are entitled to exercise the options in exchange for a cash payment alternative (CPA). A total of 22.8 million of the Adjusted Options outstanding on August 1, 2009 had a CPA and are recorded in accrued liabilities and other on the Consolidated Balance Sheets, based on their intrinsic value at each period end. All Adjusted Options vest over periods of up to four years.

(v)   Suncor Energy Inc. Stock Options

This plan replaces the pre-merger stock option plans of legacy Petro-Canada and Suncor. The company granted 4,000 options under this plan, which came into effect on August 1, 2009. Outstanding options that are cancelled, expire or are terminated or otherwise result in no underlying common share being issued will be available for issuance as options under this plan. Options granted have a seven-year life and vest annually over a three-year period.

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, 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
	Forfeited/expired	(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
	Forfeited/expired	(3 682	)	12.31 – 67.58	41.72
Outstanding, December 31, 2008		46 402		5.06 – 69.97	34.55
	Granted	2 490		20.99 – 49.67	35.78
	Adjusted options issued to Petro-Canada stock option holders	29 900		8.22 – 44.27	28.05
	Exercised	(2 870	)	5.06 – 36.68	13.69
	Forfeited/expired	(3 898	)	13.31 – 71.12	40.48
Outstanding, December 31, 2009		72 024		7.84 – 72.68	32.52
Exercisable, December 31, 2009		42 755		7.84 – 72.68	26.16

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)	2009	2008	2007
	15 942	12 345	14 570

SUNCOR ENERGY INC. 2009ANNUAL REPORT 89

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2009:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life (years)	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)
7.84 – 12.99	2 476	1	10.03	2 476	10.03
13.00 – 17.99	13 984	2	14.18	13 984	14.18
18.00 – 29.99	15 157	4	22.31	10 788	22.93
30.00 – 44.99	17 736	4	38.91	10 863	39.72
45.00 – 49.99	21 216	5	47.45	4 557	46.51
50.00 – 72.68	1 455	5	57.62	87	52.75
Total	72 024	4	32.52	42 755	26.16

Fair Value of Options Granted

The fair values of all legacy Suncor common share options granted during the period and Adjusted Options granted in 2003 are estimated as at the grant date using the Monte Carlo simulation approach for the SunShare 2012 option plan and the Black-Scholes option-pricing model for all other option plans. Adjusted Options which have a CPA granted subsequent to 2003 are accounted for based on the intrinsic value at each period end. 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:

	2009	2008	2007
Annual dividend per share	$0.30	$0.20	$0.19
Risk-free interest rate	2.31%	3.35%	4.22%
Expected life	5 years	6 years	6 years
Expected volatility	47%	30%	30%
Weighted-average fair value per option	$10.28	$13.86	$14.89

(b)   Petro-Canada Stock Appreciation Rights ("Adjusted SARs")

Grants under this plan ended on July 31, 2009. In conjunction with the business combination described in note 2, each outstanding SAR issued under this plan was exchanged with 1.28 SARs resulting in the addition of 15,353,000 SARs at August 1, 2009. SARS have a seven-year life and vest annually over a four-year period.

Changes in the number of Adjusted SARs outstanding were as follows:

		Number (thousands)		Range of Exercise Prices Per Share ($)	Weighted-Average Exercise Price Per Share ($)
	Shares issued to Petro-Canada shareholders (note 2)	15 353		19.13 – 46.13	28.74
	Exercised	(306	)	19.13 – 39.41	35.01
	Forfeited/expired	(982	)	19.13 – 46.13	28.28
Outstanding, December 31, 2009		14 065		19.13 – 46.13	28.63
Exercisable, December 31, 2009		2 740		19.13 – 46.13	35.45

90 SUNCOR ENERGY INC. 2009ANNUAL REPORT

The following table summarizes outstanding and exercisable Adjusted SARs as at December 31, 2009:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life (years)	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)
19.13 – 25.00	6 177	6	19.45	7	20.81
25.01 – 35.00	3 538	4	34.31	1 637	34.33
35.01 – 40.00	4 212	5	36.84	1 040	36.87
40.01 – 46.13	138	5	43.83	56	43.65
Total	14 065	5	28.63	2 740	35.45

(c)    Deferred Share Units (DSUs)

The company had 2,616,000 DSUs outstanding at December 31, 2009 (1,903,000 at December 31, 2008). In conjunction with the business combination described in note 2, each outstanding Petro-Canada DSU was adjusted by 1.28, resulting in the addition of 1,008,000 DSUs at August 1, 2009. 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 2009, 443,000 DSUs were redeemed for cash consideration of $16 million (2008 – 473,000 redeemed for cash consideration of $30 million; 2007 – 40,000 redeemed for cash consideration of $2 million). Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments.

(d)   Performance Share Units (PSUs)

During 2009, the company issued 1,149,000 PSUs (2008 – 795,000; 2007 – 830,000) under its Performance Share Unit Compensation Plan. In conjunction with the business combination described in note 2, each outstanding Petro-Canada PSU was adjusted by 1.28, resulting in the addition of 945,000 PSUs at August 1, 2009. 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.

(e)   Restricted Share Units (RSUs)

In 2009, the company issued 2,715,000 RSUs (2008 – 1,078,000) under the share unit portion of its new employee stock-based compensation plan ("SunShare 2012"). In conjunction with the business combination described in note 2, each outstanding Petro-Canada RSU was adjusted by 1.28, resulting in the addition of 1,018,000 RSUs at August 1, 2009.

Stock-Based Compensation Expense (Recovery)

The following table summarizes the stock based compensation expense (recovery) recorded for all plans within operating, selling and general expense on the Consolidated Statements of Earnings:

($ millions)	2009	2008		2007
Stock option plans	148	120		103
Adjusted SARs	35	—		—
Performance share units (PSUs)	30	(30	)	60
Restricted share units (RSUs)	50	8		—
Deferred share units (DSUs)	30	(51	)	21
Total stock based compensation expense	293	47		184

SUNCOR ENERGY INC. 2009ANNUAL REPORT 91

16.  ACCRUED LIABILITIES AND OTHER

($ millions)	2009	2008
Asset retirement obligations (a)	2 888	1 444
Employee future benefits liability (note 14)	1 128	191
Stock-based compensation plans (b)	219	67
Deferred revenue	94	161
Other long-term financial liabilities (c)	602	—
Other	131	123
Total	5 062	1 986

(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)	2009		2008
Asset retirement obligations, beginning of year	1 600		1 072
Liabilities incurred	253		38
Petro-Canada liabilities acquired during the year (note 2) (1)	1 605		—
Changes in estimates	(145	)	560
Liabilities settled	(248	)	(134	)
Accretion of asset retirement obligations	155		64
Foreign exchange	(20	)	—
Asset retirement obligations, end of year	3 200		1 600
Less: Current portion	(312	)	(156	)
	2 888		1 444

(1)

The majority of the asset retirement obligation liability acquired as a result of the merger with Petro-Canada was discounted at August 1, 2009 using the company's long-term credit-adjusted risk-free rate at that time of 6.5%.

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2009, was approximately $8.3 billion (2008 – $3.5 billion). Substantially all of the liability recognized in 2009 was discounted using the company's long-term credit-adjusted risk-free rate of 6.2% (2008 – 9.0%). The credit-adjusted risk-free rate used reflects the expected timeframe of the related liability. Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed fifty years. The current portion of asset retirement obligations is included in accounts payable and accrued liabilities.

A significant portion of the company's assets, including the upgrading facilities at the oil sands operation and the downstream refineries, 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)   Stock Based Compensation Plans

The portion of the stock based compensation plans expected to be paid within one year is shown within current liabilities and amounts to an additional $10 million (2008 – $8 million). See note 15 for further information on our liability-based stock-based compensation awards.

(c)    Other Long-Term Financial Liabilities

As part of the business combination described in Note 2, the company assumed an obligation relating to Petro-Canada's acquisition of an additional 5% interest in the Fort Hills project in 2007 from another partner in the project. To pay for this investment the company will fund $375 million of expenditures in excess of its working interest. Upon the acquisition of Petro-Canada, this obligation was revalued using an estimated payout pattern for the funding, discounted using the company's estimated cost of debt. At December 31, 2009, the carrying amount of the Fort Hills obligation was $322 million.

The company also assumed the remaining US$500 million obligation for a signature bonus relating to Petro-Canada's ratification of six Exploration and Production Sharing Agreements in Libya in 2008, payable in several instalments to be paid through 2013. Upon the acquisition of Petro-Canada, this obligation was revalued using the company's estimated cost of debt.

92 SUNCOR ENERGY INC. 2009ANNUAL REPORT

At December 31, 2009, the carrying amount of the Libya obligation was $511 million, of which the current portion is $231 million and is recorded in accounts payable and accrued liabilities.

17.  LONG-TERM DEBT AND CREDIT FACILITIES

($ millions)		2009		2008
Fixed-term debt, redeemable at the option of the company
6.85% Notes, denominated in U.S. dollars, due in 2039 (US$750) (i)		785		918
6.80% Notes, denominated in U.S. dollars, due in 2038 (US$900)		972		—
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150)		1 204		1 408
5.95% Notes, denominated in U.S. dollars, due in 2035 (US$600)		578		—
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)		523		612
5.35% Notes, denominated in U.S. dollars, due in 2033 (US$300)		266		—
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)		523		612
6.10% Notes, denominated in U.S. dollars, due in 2018 (US$1250) (i)		1 308		1 531
6.05% Notes, denominated in U.S. dollars, due in 2018 (US$600)		643		—
5.00% Notes, denominated in U.S. dollars, due in 2014 (US$400) (ii)		429		—
4.00% Notes, denominated in U.S. dollars, due in 2013 (US$300)		313		—
7.00% Debentures, denominated in U.S. dollars, due in 2028 (US$250)		271		—
7.875% Debentures, denominated in U.S. dollars, due in 2026 (US$275)		325		—
9.25% Debentures, denominated in U.S. dollars, due in 2021 (US$300)		402		—
5.39% Series 4 Medium Term Notes, due in 2037		600		600
5.80% Series 4 Medium Term Notes, due in 2018 (iii)		700		700
6.70% Series 2 Medium Term Notes, due in 2011 (iv)		500		500
		10 342		6 881
Revolving-term debt, with interest at variable rates
Commercial paper (v), bankers' acceptances and LIBOR loans (interest rate at December 31, 2009 – 0.7%, 2008 – 2.2%)		3 244		934
Total unsecured long-term debt		13 586		7 815
Secured long-term debt		13		13
Capital leases (vi)		326		103
Fair value of interest swaps		18		25
Deferred financing costs		(63	)	(72	)
		13 880		7 884
Current portion of long-term debt
	Capital leases (vii)	(14	)	(9	)
	Fair value of interest swaps	(11	)	(9	)
Total current portion of long-term debt		(25	)	(18	)
Total long-term debt		13 855		7 866

(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)

These notes, acquired on August 1, 2009 under the merger with Petro-Canada, were originally issued by PC Financial Partnership, a wholly-owned finance subsidiary of Petro-Canada. Suncor has fully and unconditionally guaranteed the notes.

(iii)

In May 2008, the company issued 5.80% Medium Term Notes with a principal amount of $700 million under an outstanding $2,000 million 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.

(iv)

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	2009	2008
Swap of 6.70% Medium Term Notes to floating rates	200	2011	2.0%	4.8%

(v)

The company is authorized to issue commercial paper to a maximum of $2.5 billion having a term not to exceed 365 days. Commercial paper is supported by available committed credit facilities, (see Credit facilities below).

(vi)

Interest rates on capital leases range from 4.7% to 13.4%, and maturity dates range from 2012 to 2037.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 93

Credit facilities

During 2009, the company acquired $4,524 million of available credit facilities in the merger with Petro-Canada. At December 31, 2009, the company had available credit facilities of $8,188 million, of which $4,208 million was unutilized, as follows:

($ millions)	2009
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2010	61
Facility that is fully revolving for a period of four years and expires in 2013	209
Facilities that are fully revolving for a period of five years and expire in 2013	7 320
Facilities that can be terminated at any time at the option of the lenders	598
Total available credit facilities	8 188
Credit facilities supporting outstanding revolving-term debt	(3 244	)
Credit facilities supporting standby letters of credit	(736	)
Total unutilized credit facilities	4 208

Certain of the notes and debentures of the company were acquired in the merger described in note 2 and were accounted for at their fair value at the date of acquisition, which was higher than the principal amount. The difference between the fair value and the principal amount of these debts of $121 million is being amortized over the remaining life of the debt acquired.

18.  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 ⁽¹⁾ and total debt to total debt plus shareholders' equity.

Net debt to cash flow from operations is calculated as short-term debt plus total 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 total long-term debt divided by short-term debt plus total long-term debt plus shareholders' equity.

Financial covenants associated with the company's various banking and debt arrangements are reviewed regularly and controls are in place to maintain compliance with these covenants. The company complied with all financial covenants for the years ended December 31, 2009 and 2008.

The company's strategy during 2009, which was unchanged from 2008, was to maintain the measure set out in the following schedule. The company believes that achieving our capital target helps to provide the company access to capital at a reasonable cost by maintaining solid investment-grade credit ratings. The company operates in a cyclical business environment and ratios may periodically fall outside of management targets.

At December 31, ($ millions)			Capital Measure Target	2009		2008
Components of ratios
	Short-term debt			2		2
	Current portion of long-term debt			25		18
	Long-term debt			13 855		7 866
		Total debt		13 882		7 886
	Cash and equivalents			505		660
		Net debt		13 377		7 226
	Shareholders' equity			34 111		14 523
	Total capitalization (total debt + shareholders' equity)			47 993		22 409
	Cash flow from operations (1)			2 799		4 057
Net debt/cash flow from operations			<2.0 times	4.8		1.8
Total debt/total debt plus shareholders' equity				29	%	35 %

94 SUNCOR ENERGY INC. 2009ANNUAL REPORT

The increase in debt levels as a result of the merger with Petro-Canada on August 1, 2009 has caused our net debt/cash flow from operations measure for the year ended December 31, 2009 to increase significantly, as the calculation only includes five months of cash flow from operations relating to legacy Petro-Canada operations.

(1)

Cash flow from operations is expressed before changes in non-cash working capital. Cash flow from operations is the same measure as the cash flow from operating activities before changes in working capital measure that is included in the Consolidated Statements of Cash Flows.

19.  COMMITMENTS, CONTINGENCIES, VARIABLE INTEREST ENTITIES, AND GUARANTEES

(a)   Operating Commitments

($ millions)	Pipeline Capacity, Energy Services and Delivery Obligations(1)	Operating Leases
2010	714	376
2011	708	212
2012	707	160
2013	688	114
2014	647	101
Later years	7 538	759
Total	11 002	1 722

(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 United States.

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 and obligations associated with reimbursing BG Gas Marketing for gas quantities as outlined in the Trinidad LNG Sales Contract.

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

Crude Oil

At December 31, 2009, Suncor had purchase commitments relating to crude oil predominately for refinery supply. Crude oil commitments consisted of market price evergreen contracts for a total volume of 245,000 barrels per day of crude oil (2008 – 182,000 bbls/day), of which most have industry standard thirty-day cancellation clauses.

Natural Gas

At December 31, 2009, Suncor had purchase commitments relating to natural gas for physical trading. Natural gas commitments consist of fixed price contracts with a total volume of 7 million GJ (2008 – 8 million GJ) within a price range of Cdn $4.51 – $7.05 per GJ (2008 – $5.80-$9.47 per GJ) and having terms extending to October 2010 (2008 – December 2009), as well as market price contracts for a total volume of 60 million GJ (2008 – 17 million GJ) with terms extending to October 2015
(2008 – October 2009).

Refined Products

At December 31, 2009, Suncor's significant purchase commitments relating to finished products at its refineries consisted of market price contracts for a total volume of 5,429 millions of litres and having terms extending to 2012.

(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 reduces exposure to some operational risks by maintaining a comprehensive insurance program at limits and deductible amounts that management believes to be acceptable.

The company carries property damage and business interruption insurance with varying coverage limits and deductible amounts based on the asset. As of December 31, 2009, Suncor's insurance program includes a coverage limit of up to US$1.35 billion for

SUNCOR ENERGY INC. 2009ANNUAL REPORT 95

oil sands risks, up to US$1.25 billion for offshore risks and up to US$420 million for refining risks. These limits are all net of deductible amounts or waiting periods and subject to certain price and volume caps. The company also has primary property insurance for US$250 million that covers all of Suncor's assets.

Suncor believes its liability, property and business interruption insurance is appropriate to its business, although such insurance will not provide coverage in all circumstances or fully protect against prolonged outages. In the future, the insurance program may change due to market conditions or other business considerations.

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)    Variable Interest Entities

CICA Accounting Guideline 15, Consolidation of Variable Interest Entities (VIEs), provides criteria for the identification of VIEs and further criteria for determining what entity, if any, should consolidate them. Entities in which equity investors do not have the characteristic of a controlling financial interest or do not have sufficient equity at risk for the entity to finance its activities without additional subordinate financial support are subject to consolidation by a company if that company is deemed the primary beneficiary. The primary beneficiary is the party that is subject to a majority of the risk of loss from the VIEs activities, or is entitled to receive a majority of the VIE's residual returns, or both. The company has determined that certain retail licensee and wholesale marketer agreements would constitute VIEs, even though the company has no ownership in these entities. The company, however, is not the primary beneficiary and, therefore, consolidation is not required. In certain of the retail licensee arrangements, the company has provided loan guarantees. Management is of the opinion that the company's maximum exposure to loss from these arrangements would not be significant.

(d)   Guarantees and Off-Balance Sheet Arrangements

At December 31, 2009, the company had various indemnification agreements with third parties as described below.

The company has agreed to indemnify holders of all notes and debentures and the company's credit facility lenders (see note 17) 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, the company has the option to redeem or terminate these contracts if additional costs are incurred.

20.  ACCUMULATED OTHER COMPREHENSIVE INCOME

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

As at December 31 ($ millions)	2009		2008
Unrealized foreign currency translation adjustment	(248	)	84
Unrealized gains on derivative hedging activities	15		13
Total	(233	)	97

96 SUNCOR ENERGY INC. 2009ANNUAL REPORT

21.  SUPPLEMENTAL INFORMATION

($ millions)			2009	2008	2007
Geographic areas
	Revenues
		Canada	20 184	23 742	13 262
		U.S.	4 010	4 794	3 943
		Other	1 286	101	109
			25 480	28 637	17 314
	Total assets
		Canada	54 259	29 178	21 615
		U.S.	5 239	2 840	2 556
		Other	10 248	510	338
			69 746	32 528	24 509
Exploration expenses
	Geological and geophysical		85	29	28
	Dry hole costs		173	61	67
	Other		10	—	—
	Total		268	90	95
Allowance for doubtful accounts			16	4	3

22.  SUBSEQUENT EVENTS

A fire on February 9, 2010 damaged portions of one of the company's oil sands upgraders. An assessment of the damage and expected schedule for repairs has been completed, and repairs are currently underway. The company expects the damaged upgrader to return to production in early April 2010. Based on the damage assessment and repair schedule, and applicable waiting periods and deductibles, the company does not expect insurance to play a significant role in mitigating losses from this incident.

On February 9, 2010, Suncor entered into an agreement to sell certain natural gas properties located in northeast British Columbia for proceeds of $390 million. The sale is expected to close in March 2010.

On February 25, 2010, Suncor entered into an agreement to sell its assets in Trinidad and Tobago for proceeds of $396 million (US$380 million). The sale is expected to close in March 2010.

23.  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 net earnings and comprehensive income as reported:

($ millions)		Notes	2009		2008		2007
Net earnings as reported, Canadian GAAP			1 146		2 137		2 983
Adjustments
	Transaction costs and provisions	(a)	(302	)	—		—
	Stock-based compensation expense	(b)	41		(7	)	15
	Energy supply and trading activities (inventory valuation)	(e)	(47	)	—		—
	Income tax expense	(a,b,e)	80		1		(6	)
Net earnings, U.S. GAAP			918		2 131		2 992
Pension and post-retirement obligation, net of income taxes of $22 (2008 – $20; 2007 – $8)		(c)	43		43		17
Other comprehensive income (loss) items			(330	)	350		(190	)
Comprehensive income, U.S. GAAP			631		2 524		2 819

SUNCOR ENERGY INC. 2009ANNUAL REPORT 97

Per common share (dollars)		2009	2008	2007
Net earnings per share, U.S. GAAP
	Basic	0.77	2.29	3.24
	Diluted	0.76	2.26	3.18

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

				December 31, 2009				December 31, 2008
		Notes		As Reported		U.S. GAAP		As Reported	U.S. GAAP
Current assets		(a,e	)	8 331		8 318		3 237	3 237
Property, plant and equipment, net				57 485		57 485		28 882	28 882
Other assets		(d	)	536		599		388	460
Goodwill		(a	)	3 201		5 762		21	21
Future income taxes				193		210		—	—
	Total assets			69 746		72 374		32 528	32 600
Current liabilities		(a,b	)	7 848		7 881		3 538	3 538
Long-term borrowings		(d	)	13 855		13 918		7 866	7 938
Accrued liabilities and other		(b,c	)	5 062		5 119		1 986	2 094
Future income taxes		(a,b,c	)	8 870		8 840		4 615	4 579
Share capital		(b	)	20 053		22 908		1 113	1 201
Contributed surplus		(b	)	526		546		288	313
Retained earnings		(a,b,e	)	13 765		13 431		13 025	12 919
Accumulated other comprehensive income (loss)		(c	)	(233	)	(269	)	97	18
	Total liabilities and shareholders' equity			69 746		72 374		32 528	32 600

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

(a)   Business Combination with Petro-Canada

Under U.S. GAAP, the total purchase price for the acquisition was $22,225 million. U.S. GAAP requires the 621.1 million Suncor shares offered as consideration to complete the merger to be valued at $34.84 per share, which was the Suncor Share price as at the transaction close date of August 1, 2009. Under Canadian GAAP the share price is that value as at the merger announcement date. In addition, transaction costs of $124 million (net of income taxes of $43 million) are not permitted to be included in consideration under U.S. GAAP, and are expensed instead.

Under Canadian GAAP, the transaction costs were netted against cash acquired in the business combination and presented as part of cash flow from investing activities in the Consolidated Statements of Cash Flows. Under U.S. GAAP the $124 million of transaction costs would be included in net earnings and thus be presented as a reduction in cash flow from operating activities.

The fair value of current liabilities assumed by Suncor in the business combination under Canadian GAAP includes $160 million (net of income taxes of $56 million) for provisions for severance and other costs associated with exiting certain activities of Petro-Canada that cannot be recognized at the time of the merger under U.S. GAAP and instead must be expensed as incurred. As at December 31, 2009, $99 million (net of income taxes of $36 million) of amounts related to these provisions had been incurred, for which $12 million (net of income taxes of $4 million) remains in current liabilities under U.S. GAAP.

As per note (b), under U.S. GAAP stock-based compensation awards recognized as liabilities are measured using different methods than Canadian GAAP. At August 1, 2009, the value of CPAs, SARs, RSUs and PSUs calculated using methods prescribed by U.S. GAAP was $126 million (net of income taxes of $43 million) greater than the value calculated using methods prescribed under Canadian GAAP.

As a result of these differences in accounting for this business combination, the resulting value for goodwill under U.S. GAAP is $5,762 million, of which $5,474 million would be allocated to the Oil Sands segment and the remaining $288 million would be allocated to the Refining and Marketing segment.

(b)   Stock-Based Compensation

Under Canadian GAAP, the company's stock options with a cash payment alternatives (CPAs), stock appreciation rights (SARs), performance share units (PSUs) and restricted share units (RSUs) are measured using an intrinsic approach, which is a fair-value technique not permitted under U.S. GAAP. For U.S. GAAP, our CPAs and SARs have been measured at fair value using the Black-Scholes option-pricing model, while our PSUs and RSUs have been measured using a Monte Carlo Simulation approach to

98 SUNCOR ENERGY INC. 2009ANNUAL REPORT

determine fair value. The impact on net earnings for the year ended December 31, 2009 is a recovery of previously recognized stock-based compensation expense of $31 million, net of income taxes of $10 million (2008 — expense of $2 million, net of income taxes $1 million; 2007 — recovery of $17 million, net of income taxes of $6 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. U.S. GAAP requires the recognition of expense related to the company's pre-2003 options. There was no additional compensation expense to recognize in 2009, as the remaining expense for pre-2003 options was recognized in 2008 (2008 — $4 million, 2007 — $8 million). There was no impact on income taxes.

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

U.S. GAAP requires the company recognize 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. Canadian GAAP currently does not require the company to recognize the funded status of these plans in the Consolidated Balance Sheet. In 2009, other comprehensive income under U.S. GAAP would increase by $43 million, net of income taxes of $22 million (2008 – $43 million, net of income taxes of $20 million).

(d)   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, $63 million would have been reclassified from long-term debt to deferred charges and other at December 31, 2009 (December 31, 2008 – $72 million).

(e)   Inventory

U.S. GAAP requires inventory to be measured at the lower of cost or net realizable value and does not permit the measurement of held for trading inventories at fair value less costs to sell. As a result, the value of energy trading inventories at December 31, 2009 is lower by $47 million, with the difference in valuation charged to energy supply and trading activities revenue ($32 million, net of income taxes of $15 million).

(f)    Cash Flow Information

Other than described in note (a), the application of U.S. GAAP would not have a material effect on cash flow from total operating, investing, or financing activities on the Consolidated Statement of Cash Flows.

Recently Adopted Accounting Standards

Codification

Effective September 15, 2009 the U.S. Financial Accounting Standards Board (FASB) introduced the FASB Accounting Standards Codification (Codification) as the source of authoritative U.S. GAAP for financial statements issued for annual periods ending after the effective date. The Codification did not affect the application of U.S. GAAP to the company's U.S. GAAP financial statements.

Business Combinations

In December 2007, the FASB amended Topic 805 "Business Combinations" and Topic 810 "Consolidations" which are effective for all business combinations occurring on or after January 1, 2009. These standards require the identifiable assets acquired and liabilities assumed in a business combination to be recorded at fair value and most of the related acquisition and restructuring costs to be expensed. The impact to Suncor has been quantified in section (a) above.

Oil and Gas Reporting Requirements

In January 2010, the FASB amended Topic 932 "Extractive Industries Oil and Gas" to align the oil and gas reserve estimation and disclosure requirements of Topic 932 with the changes implemented by the Securities and Exchange Commission Final Rule, Modernization of Oil and Gas Reporting Requirements.

The amendments expand the definition of an oil and gas producing activity to include resources extracted through mining activities, coal beds and shale. The new rules also permit the use of new technologies to determine proved reserves, if those technologies have been demonstrated empirically to lead to reliable conclusions about reserves volumes. The new rules will also require companies to report their oil and gas reserves based on annual average prices determined by the prices in effect on the first day of each month, rather than year-end prices. The amendments are effective for December 31, 2009.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 99

Recently Issued Accounting Standards

Consolidations

In June 2009, the FASB issued amendments to Topic 810 "Consolidations" to improve financial reporting for enterprises involved with variable interest entities (VIEs). The amendments change how a company determines when these entities should be consolidated, replacing the quantitative-based risks and rewards calculation with an approach that is primarily qualitative. The amendments are effective for January 1, 2010. The company does not anticipate changes to its reporting for VIEs as a result of these amendments.

100 SUNCOR ENERGY INC. 2009ANNUAL REPORT

QUARTERLY SUMMARY (unaudited)

FINANCIAL DATA ⁽¹⁾

		For the Quarter Ended								Total Year		For the Quarter Ended								Total Year
($ millions, except per share amounts)		Mar 31 2009		June 30 2009		Sept 30 2009		Dec 31 2009		2009		Mar 31 2008		June 30 2008		Sept 30 2008		Dec 31 2008		2008
Revenues (net of royalties)		4 633		4 768		8 443		7 636		25 480		5 538		7 640		8 507		6 952		28 637
Net earnings (loss)
Oil Sands		(110	)	(307	)	738		236		557		695		751		854		575		2 875
Natural Gas		(10	)	(28	)	(111	)	(50	)	(199	)	19		52		18		—		89
East Coast Canada		—		—		39		73		112		—		—		—		—		—
International		—		—		32		133		165		—		—		—		—		—
Refining and Marketing		118		106		51		158		433		78		102		(11	)	(174	)	(5	)
Corporate, Energy Trading and Eliminations		(187	)	178		180		(93	)	78		(84	)	(76	)	(46	)	(616	)	(822	)
		(189	)	(51	)	929		457		1 146		708		829		815		(215	)	2 137
Per common share
Net earnings (loss) attributable to common shareholders
	– basic	(0.20	)	(0.06	)	0.69		0.29		0.96		0.77		0.89		0.87		(0.24	)	2.29
	– diluted	(0.20	)	(0.06	)	0.68		0.29		0.95		0.75		0.87		0.86		(0.24	)	2.26
Cash dividends		0.05		0.05		0.10		0.10		0.30		0.05		0.05		0.05		0.05		0.20
Cash flow from (used in) operations
Oil Sands		480		174		242		355		1 251		924		1 232		1 030		321		3 507
Natural Gas		53		42		74		160		329		84		122		98		63		367
East Coast Canada		—		—		130		205		335		—		—		—		—		—
International		—		—		163		453		616		—		—		—		—		—
Refining and Marketing		222		198		275		268		963		173		237		19		(181	)	248
Corporate, Energy Trading and Eliminations		46		(119	)	(310	)	(312	)	(695	)	(31	)	(61	)	(1	)	28		(65	)
		801		295		574		1 129		2 799		1 150		1 530		1 146		231		4 057

(1)

The financial data includes the results of post-merger Suncor from August 1, 2009. As such, the amounts reflect results of the post-merger Suncor from August 1, 2009 together with results of legacy Suncor only from January 1, 2009 through July 31, 2009. The comparative figures reflect solely the 2008 results of legacy Suncor.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 101

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA

		For the Quarter Ended					Total Year		For the Quarter Ended				Total Year
		Mar 31 2009	June 30 2009	Sept 30 2009		Dec 31 2009	2009		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008
OIL SANDS
Production (a)
	Total production (excluding Syncrude)	278.0	301.0	305.3		278.9	290.6		248.0	174.6	245.6	243.8	228.0
	Firebag (b)	42.4	48.3	54.3		51.1	49.1		34.6	34.7	40.4	39.7	37.4
	Mackay River (b)	—	—	26.5	***	31.7	29.7	***	—	—	—	—	—
Syncrude		—	—	37.4	***	39.3	38.5	***	—	—	—	—	—
Sales (a)
	Light sweet crude oil	108.8	99.4	89.6		100.8	99.6		96.2	68.2	48.1	95.7	77.0
	Diesel	22.8	25.3	36.9		31.4	29.1		28.0	21.2	10.9	19.1	19.8
	Light sour crude oil	102.7	150.5	146.8		142.4	135.7		120.8	91.8	157.4	144.2	128.7
	Bitumen	9.1	10.5	14.3		13.0	11.8		0.1	0.3	2.6	3.1	1.5
Total sales		243.4	285.7	287.6		287.6	276.2		245.1	181.5	219.0	262.1	227.0
Average sales price (1), (c)
	Light sweet crude oil*	54.64	65.83	71.99		77.71	67.26		100.93	122.12	125.70	63.69	98.66
	Other (diesel, light sour crude oil and bitumen)*	48.80	62.71	67.51		72.93	64.18		93.09	120.52	114.74	59.77	95.14
	Total*	52.78	63.79	68.91		74.61	65.29		96.22	122.39	117.14	61.20	96.33
	Total	59.14	59.00	61.70		64.81	61.26		96.16	121.12	116.32	61.53	95.96
Syncrude average sales price (1), (c)		—	—	75.17		78.81	77.36		—	—	—	—	—
Cash operating costs and Total operating costs – Total Operations (excluding Syncrude) (d)
Cash costs		30.65	29.65	30.65		35.10	31.50		25.10	40.10	27.80	35.35	31.45
Natural gas		3.00	1.65	1.55		3.40	2.40		5.00	8.75	4.30	4.05	5.25
Imported bitumen		0.05	—	0.05		0.20	0.05		1.45	2.00	1.90	1.90	1.80
Cash operating costs (2)		33.70	31.30	32.25		38.70	33.95		31.55	50.85	34.00	41.30	38.50
Project start-up costs		0.65	0.35	0.45		0.50	0.45		0.30	0.90	0.35	0.30	0.40
Total cash operating costs (3)		34.35	31.65	32.70		39.20	34.40		31.85	51.75	34.35	41.60	38.90
Depreciation, depletion and amortization		7.30	7.20	7.60		10.00	8.00		5.75	8.30	6.70	7.50	6.95
Total operating costs (4)		41.65	38.85	40.30		49.20	42.40		37.60	60.05	41.05	49.10	45.85
Cash operating costs and Total operating costs – Syncrude (d)****
Cash costs		—	—	29.50		29.65	29.60		—	—	—	—	—
Natural gas		—	—	2.10		3.45	2.90		—	—	—	—	—
Cash operating costs (5)		—	—	31.60		33.10	32.50		—	—	—	—	—
Project start-up costs		—	—	—		—	—		—	—	—	—	—
Total cash operating costs (6)		—	—	31.60		33.10	32.50		—	—	—	—	—
Depreciation, depletion and amortization		—	—	12.70		11.80	12.15		—	—	—	—	—
Total operating costs (7)		—	—	44.30		44.90	44.65		—	—	—	—	—
Cash operating costs and Total operating costs – In-situ Bitumen Production Only (c)
Cash costs		10.50	11.15	10.25		11.35	10.90		14.60	10.10	10.75	16.55	13.00
Natural gas		7.90	5.25	4.30		6.05	5.70		14.10	14.55	11.30	9.65	12.30
Cash operating costs (5)		18.40	16.40	14.55		17.40	16.60		28.70	24.65	22.05	26.20	25.30
In-situ start-up costs		3.35	1.50	0.65		1.25	1.30		0.35	1.65	0.80	—	0.65
Total cash operating costs (6)		21.75	17.90	15.20		18.65	17.90		29.05	26.30	22.85	26.20	25.95
Depreciation, depletion and amortization		7.10	6.00	5.95		6.65	6.35		6.75	6.70	5.40	6.55	6.35
Total operating costs (7)		28.85	23.90	21.15		25.30	24.25		35.80	33.00	28.25	32.75	32.30

Footnotes and definitions, see page 113.

102 SUNCOR ENERGY INC. 2009ANNUAL REPORT

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

		For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
		Mar 31 2009	June 30 2009	Sept 30 2009	Dec 31 2009	2009	Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008
NATURAL GAS
Gross production
Natural gas (e)
	Western Canada	200	192	477	620	374	209	205	197	195	202
	U.S. Rockies	—	—	40	54	24	—	—	—	—	—
Natural gas liquids and crude oil (a)
	Western Canada	3.1	3.2	8.3	10.8	6.4	3.3	3.4	2.6	3.1	3.1
	U.S. Rockies	—	—	2.4	4.2	1.7	—	—	—	—	—
Total gross production (f)
	Western Canada	219	211	527	685	412	229	226	213	213	220
	U.S. Rockies	—	—	54	79	34	—	—	—	—	—
Average sales price (1)
Natural gas (g)
	Western Canada	5.63	3.56	2.79	3.99	3.70	7.30	9.62	9.10	6.90	8.23
	U.S. Rockies	—	—	3.01	4.62	3.93	—	—	—	—	—
Natural gas (g)*
	Western Canada	5.61	3.52	2.77	3.99	3.68	7.31	9.68	9.14	6.84	8.25
	U.S. Rockies	—	—	3.01	4.62	3.93	—	—	—	—	—
Natural gas liquids and crude oil (c)
	Western Canada	39.03	41.39	53.28	60.06	52.97	64.14	86.14	96.88	39.31	70.89
	U.S. Rockies	—	—	67.08	74.19	71.62	—	—	—	—	—
EAST COAST CANADA ***
Production (a)
Terra Nova		—	—	16.0	24.0	20.8	—	—	—	—	—
Hibernia		—	—	28.5	26.3	27.2	—	—	—	—	—
White Rose		—	—	5.1	13.3	10.0	—	—	—	—	—
Total production		—	—	49.6	63.6	58.0	—	—	—	—	—
Average sales price (1)		—	—	75.22	77.71	76.86	—	—	—	—	—
INTERNATIONAL ***
Production (h)
North Sea
	Buzzard	—	—	29.4	59.9	47.8	—	—	—	—	—
	Other U.K.	—	—	11.4	18.2	15.5	—	—	—	—	—
	The Netherlands sector of the         North Sea	—	—	13.8	12.9	13.2	—	—	—	—	—
Total North Sea		—	—	54.6	91.0	76.5	—	—	—	—	—
Other International
	Libya	—	—	42.7	26.0	32.6	—	—	—	—	—
	Trinidad & Tobago	—	—	11.3	12.0	11.7	—	—	—	—	—
Total Other International		—	—	54.0	38.0	44.3	—	—	—	—	—
Total production		—	—	108.6	129.0	120.8	—	—	—	—	—
Average sales price (1) – North Sea (i)		—	—	68.67	71.46	71.63	—	—	—	—	—
Average sales price (1) – Other International (i)		—	—	62.40	59.04	61.25	—	—	—	—	—

Footnotes and definitions, see page 113.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 103

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

					For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
					Mar 31 2009	June 30 2009	Sept 30 2009	Dec 31 2009	2009	Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008
REFINING AND MARKETING
	Eastern North America
		Refined product sales (j)
			Transportation fuels
			Gasoline
				– retail	3.8	4.0	12.5	16.5	9.3	3.9	3.9	3.8	3.9	3.9
				– other	4.4	4.7	5.8	6.5	5.3	3.8	4.0	4.3	5.0	4.0
			Distillate		5.1	5.4	10.3	13.9	8.8	4.8	5.6	5.2	5.4	5.2
			Total transportation fuel sales		13.3	14.1	28.6	36.9	23.4	12.5	13.5	13.3	14.3	13.1
			Petrochemicals		1.0	1.0	1.7	1.2	0.8	0.6	0.9	1.0	1.0	0.8
			Asphalt		0.8	0.7	2.4	2.0	1.5	0.6	0.7	0.6	0.5	0.6
			Other		0.5	1.0	3.0	1.9	2.0	0.8	1.1	1.2	0.5	1.0
		Total refined product sales			15.6	16.8	35.7	42.0	27.7	14.5	16.2	16.1	16.3	15.5
		Crude oil supply and refining
			Processed at refineries (j)		11.3	11.8	25.5	28.3	29.6	9.9	11.5	11.6	11.2	11.0
			Utilization of refining capacity (%)		84	87	94	83	87	89	103	104	101	99
	Western North America
		Refined product sales (j)
			Transportation fuels
			Gasoline
				– retail	0.7	0.6	3.8	5.0	2.6	0.7	0.6	0.7	0.7	0.7
				– other	7.5	8.3	12.3	13.4	10.4	7.0	7.8	7.2	7.1	7.3
			Distillate		5.4	5.0	11.8	15.6	9.5	5.6	5.9	5.4	5.5	5.6
			Total transportation fuel sales		13.6	13.9	27.9	34.0	22.5	13.3	14.3	13.3	13.3	13.6
			Asphalt		1.2	1.4	1.7	0.9	1.3	1.6	1.0	1.3	1.0	1.2
			Other		1.0	1.8	4.6	6.0	3.4	1.1	1.6	1.3	0.9	1.2
		Total refined product sales			15.8	17.1	34.2	40.9	27.2	16.0	16.9	15.9	15.2	16.0
		Crude oil supply and refining
			Processed at refineries (j)		14.2	15.6	27.8	33.4	33.6	13.1	14.5	13.5	13.6	13.7
			Utilization of refining capacity (%)		96	106	100	96	97	92	102	95	95	96

Footnotes and definitions, see page 113.

104 SUNCOR ENERGY INC. 2009ANNUAL REPORT

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

			For the Quarter Ended								Total Year		For the Quarter Ended								Total Year
			Mar 31 2009		June 30 2009		Sept 30 2009		Dec 31 2009		2009		Mar 31 2008		June 30 2008		Sept 30 2008		Dec 31 2008		2008
NETBACKS
Natural Gas(g)
	Western Canada
		Average price realized (8)	5.77		3.88		3.76		5.05		4.58		8.23		11.20		10.98		6.99		9.35
		Royalties	(1.14	)	0.33		(0.24	)	(0.72	)	(0.49	)	(1.84	)	(2.52	)	(2.70	)	(1.60	)	(2.17	)
		Operating costs	(1.65	)	(1.71	)	(1.90	)	(1.77	)	(1.79	)	(1.41	)	(1.66	)	(1.87	)	(1.46	)	(1.60	)
		Operating netback	2.98		2.50		1.62		2.56		2.30		4.98		7.02		6.41		3.93		5.58
		Depreciation, depletion and amortization	(2.97	)	(2.92	)	(2.73	)	(2.62	)	(2.74	)	(2.85	)	(2.68	)	(3.08	)	(2.98	)	(2.89	)
		Administrative expenses and other	(0.78	)	(1.63	)	(1.60	)	(1.09	)	(1.29	)	(0.88	)	(0.92	)	(1.95	)	(1.23	)	(1.23	)
		Earnings before income taxes	(0.77	)	(2.05	)	(2.71	)	(1.15	)	(1.73	)	1.25		3.42		1.38		(0.28	)	1.46
	U.S. Rockies
		Average price realized (8)	—		—		5.20		7.15		6.35		—		—		—		—		—
		Royalties	—		—		(0.82	)	(1.13	)	(1.01	)	—		—		—		—		—
		Operating costs	—		—		(1.79	)	(1.83	)	(1.82	)	—		—		—		—		—
		Operating netback	—		—		2.59		4.19		3.52		—		—		—		—		—
		Depreciation, depletion and amortization	—		—		(3.20	)	(3.44	)	(3.35	)	—		—		—		—		—
		Administrative expenses and other	—		—		(0.47	)	(0.66	)	(0.58	)	—		—		—		—		—
		Earnings before income taxes	—		—		(1.08	)	0.09		(0.41	)	—		—		—		—		—
Total Natural Gas
		Average price realized (8)	5.77		3.88		3.89		5.26		4.71		8.23		11.20		10.98		6.99		9.35
		Royalties	(1.14	)	0.33		(0.29	)	(0.76	)	(0.53	)	(1.84	)	(2.52	)	(2.70	)	(1.60	)	(2.17	)
		Operating costs	(1.65	)	(1.71	)	(1.89	)	(1.78	)	(1.79	)	(1.41	)	(1.66	)	(1.87	)	(1.46	)	(1.60	)
		Operating netback	2.98		2.50		1.71		2.72		2.39		4.98		7.02		6.41		3.93		5.58
		Depreciation, depletion and amortization	(2.97	)	(2.92	)	(2.78	)	(2.70	)	(2.79	)	(2.85	)	(2.68	)	(3.08	)	(2.98	)	(2.89	)
		Administrative expenses and other	(0.78	)	(1.63	)	(1.49	)	(1.05	)	(1.23	)	(0.88	)	(0.92	)	(1.95	)	(1.23	)	(1.23	)
		Earnings before income taxes	(0.77	)	(2.05	)	(2.56	)	(1.03	)	(1.63	)	1.25		3.42		1.38		(0.28	)	1.46

Footnotes and definitions, see page 113.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 105

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

			For the Quarter Ended						Total Year		For the Quarter Ended				Total Year
			Mar 31 2009	June 30 2009	Sept 30 2009		Dec 31 2009		2009		Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008	2008
NETBACKS (continued)
	East Coast Canada(c)
		Average price realized (8)	—	—	77.85		79.69		79.07		—	—	—	—	—
		Royalties	—	—	(21.02	)	(25.26	)	(23.82	)	—	—	—	—	—
		Operating costs	—	—	(13.36	)	(7.89	)	(9.76	)	—	—	—	—	—
		Operating netback	—	—	43.47		46.54		45.49		—	—	—	—	—
		Depreciation, depletion and amortization	—	—	(17.48	)	(26.56	)	(23.47	)	—	—	—	—	—
		Administrative expenses and other	—	—	(0.52	)	(1.33	)	(1.05	)	—	—	—	—	—
		Earnings before income taxes	—	—	25.47		18.65		20.97		—	—	—	—	—
International
	North Sea(c)
		Average price realized (8)	—	—	72.06		71.46		71.63		—	—	—	—	—
		Operating costs	—	—	(14.04	)	(8.08	)	(9.78	)	—	—	—	—	—
		Operating netback	—	—	58.02		63.38		61.85		—	—	—	—	—
		Depreciation, depletion and amortization	—	—	(24.54	)	(34.63	)	(31.76	)	—	—	—	—	—
		Administrative expenses and other	—	—	(7.61	)	(4.62	)	(5.48	)	—	—	—	—	—
		Earnings before income taxes	—	—	25.87		24.13		24.61		—	—	—	—	—
Other International
	North Africa/Near East(c)
		Average price realized (8)	—	—	76.02		79.97		78.19		—	—	—	—	—
		Royalties	—	—	(46.46	)	(32.12	)	(39.88	)	—	—	—	—	—
		Operating costs	—	—	(2.21	)	(6.03	)	(4.05	)	—	—	—	—	—
		Operating netback	—	—	27.35		41.82		34.26		—	—	—	—	—
		Depreciation, depletion and amortization	—	—	(2.31	)	(7.70	)	(4.89	)	—	—	—	—	—
		Administrative expenses and other	—	—	(5.21	)	(10.15	)	(7.57	)	—	—	—	—	—
		Earnings before income taxes	—	—	19.83		23.97		21.80		—	—	—	—	—
Other International
	Northern Latin America(g)
		Average price realized (8)	—	—	2.09		2.58		2.42		—	—	—	—	—
		Royalties	—	—	(1.58	)	(0.10	)	(0.69	)	—	—	—	—	—
		Operating costs	—	—	(0.46	)	(0.13	)	(0.26	)	—	—	—	—	—
		Operating netback	—	—	0.05		2.35		1.47		—	—	—	—	—
		Depreciation, depletion and amortization	—	—	(0.79	)	(1.84	)	(1.44	)	—	—	—	—	—
		Administrative expenses and other	—	—	0.12		0.04		0.08		—	—	—	—	—
		Earnings before income taxes	—	—	(0.62	)	0.55		0.11		—	—	—	—	—
Total International(i)
		Average price realized (8)	—	—	67.42		67.96		67.86		—	—	—	—	—
		Royalties	—	—	(19.25	)	(6.52	)	(11.17	)	—	—	—	—	—
		Operating costs	—	—	(8.22	)	(6.99	)	(7.44	)	—	—	—	—	—
		Operating netback	—	—	39.95		54.45		49.25		—	—	—	—	—
		Depreciation, depletion and amortization	—	—	(13.74	)	(27.02	)	(22.27	)	—	—	—	—	—
		Administrative expenses and other	—	—	(5.79	)	(5.29	)	(5.46	)	—	—	—	—	—
		Earnings before income taxes	—	—	20.42		22.14		21.52		—	—	—	—	—

Footnotes and definitions, see page 113.

106 SUNCOR ENERGY INC. 2009ANNUAL REPORT

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions)	2009		2008		2007		2006		2005
Revenues (net of royalties)
Oil Sands	6 539		8 639		6 175		6 457		3 559
Natural Gas	681		579		427		451		530
East Coast Canada	441		—		—		—		—
International	1 183		—		—		—		—
Refining and Marketing	12 013		9 419		8 391		7 209		6 351
Corporate, Energy Trading and Eliminations	4 623		10 000		2 321		859		328
	25 480		28 637		17 314		14 976		10 768
Net earnings (loss)
Oil Sands	557		2 875		2 474		2 775		986
Natural Gas	(199	)	89		25		106		155
East Coast Canada	112		—		—		—		—
International	165		—		—		—		—
Refining and Marketing	433		(5	)	442		224		228
Corporate, Energy Trading and Eliminations	78		(822	)	42		(136	)	(115	)
	1 146		2 137		2 983		2 969		1 254
Cash flow from (used in) operations
Oil Sands	1 251		3 507		3 165		3 902		1 961
Natural Gas	329		367		251		279		412
East Coast Canada	335		—		—		—		—
International	616		—		—		—		—
Refining and Marketing	963		248		711		423		449
Corporate, Energy Trading and Eliminations	(695	)	(65	)	(90	)	(58	)	(193	)
	2 799		4 057		4 037		4 546		2 629
Capital and exploration expenditures
Oil Sands	2 807		7 391		4 566		2 463		2 013
Natural Gas	320		342		537		458		365
East Coast Canada	123		—		—		—		—
International	543		—		—		—		—
Refining and Marketing	409		226		449		745		789
Corporate, Energy Trading and Eliminations	44		28		77		27		63
	4 246		7 987		5 629		3 693		3 230
Total assets	69 476		32 528		24 509		18 959		15 335
Ending capital employed(A)
Short-term and long-term debt, less cash and cash equivalents	13 377		7 226		3 248		1 849		2 868
Shareholders' equity	34 111		14 523		11 896		9 084		6 130
	47 488		21 749		15 144		10 933		8 998
Less capitalized costs related to major projects in progress	(13 365	)	(6 583	)	(4 148	)	(2 649	)	(2 938	)
	34 123		15 166		10 996		8 284		6 060
Total Suncor employees (number at year-end)	12 978		6 798		6 465		5 766		5 152

Footnotes and definitions, see page 108.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 107

FIVE-YEAR FINANCIAL SUMMARY (unaudited) (continued)

		2009	2008	2007	2006	2005
Dollars per common share
	Net earnings attributable to common shareholders	0.96	2.29	3.23	3.23	1.37
	Cash dividends	0.30	0.20	0.19	0.15	0.12
	Cash flow from operations	2.34	4.36	4.38	4.95	2.88
Ratios
Return on capital employed (%) (B), (C)		2.6	22.5	29.3	40.0	21.2
Return on capital employed (%) (C), (D)		1.8	16.3	21.5	30.1	15.4
Return on shareholders' equity (%) (E)		5.1	16.2	28.4	39.0	22.7
Debt to debt plus shareholders' equity (%) (F)		28.9	35.2	24.3	20.7	33.1
Net debt to cash flow from operations (times) (G)		4.8	1.8	0.8	0.4	1.1
Interest coverage – cash flow basis (times) (H)		7.2	13.0	23.4	30.6	17.9
Interest coverage – net earnings basis (times) (I)		3.0	8.9	18.8	25.5	13.5

(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 less capitalized costs related to major projects in progress (as applicable), on a weighted-average basis. Return on capital employed (ROCE) for Suncor operating segments is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non-GAAP financial measure see page 53 of MD&A.

(C)

The increase in capital employed as a result of the merger with Petro-Canada has caused our return on capital employed measure to decrease significantly, as the calculation only includes five months of results relating to legacy Petro-Canada operations.

(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)

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.

(F)

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

(G)

Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended. The increase in debt levels as a result of the merger with Petro-Canada has caused our net debt/cash flow from operations measure to increase significantly, as the calculation only includes five months of cash flow from operations relating to legacy Petro-Canada operations.

(H)

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

(I)

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

108 SUNCOR ENERGY INC. 2009ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2009	2008	2007	2006	2005
OIL SANDS
Production (a)	290.6	228.0	235.6	260.0	171.3
Sales (a)
Light sweet crude oil	99.6	77.0	101.7	110.5	73.3
Diesel	29.1	19.8	25.0	28.2	15.6
Light sour crude oil	135.7	128.7	102.3	118.2	59.8
Bitumen	11.8	1.5	5.7	6.2	16.6
	276.2	227.0	234.7	263.1	165.3
Average sales price (c)
Light sweet crude oil*	67.26	98.66	78.03	71.98	49.93
Other (diesel, light sour crude oil and bitumen)*	64.18	95.14	70.86	65.17	56.90
Total*	65.29	96.33	74.07	68.03	62.68
Total	61.26	95.96	74.01	68.03	53.81
Cash operating costs – total operations (excluding Syncrude) (2),(d)	33.95	38.50	27.80	21.70	24.55
Total cash operating costs – total operations (excluding Syncrude) (3),(d)	34.40	38.90	28.75	22.10	24.65
Total operating costs – total operations (excluding Syncrude) (4),(d)	42.40	45.85	34.15	26.15	29.95
Cash operating costs – Syncrude (5),(d)****	32.50	—	—	—	—
Total cash operating costs – Syncrude (6),(d)****	32.50	—	—	—	—
Total operating costs – Syncrude (7),(d)****	44.65	—	—	—	—
Cash operating costs – In-situ bitumen production (5),(d)	16.60	25.30	20.75	17.30	22.20
Total cash operating costs – In-situ bitumen production (6),(d)	17.90	25.95	20.75	19.00	23.20
Total operating costs – In-situ bitumen production (7),(d)	24.25	32.30	26.95	24.55	28.10
Ending capital employed excluding major projects in progress (k)	16 141	9 352	6 605	5 039	4 468
Return on capital employed (%)	4.2	35.5	43.0	53.1	23.0
Return on capital employed (%) **	2.5	21.8	27.9	39.8	16.5

Footnotes and definitions, see page 113.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 109

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2009		2008	2007	2006	2005
NATURAL GAS
Gross production
Natural gas (e)
	Western Canada	374		202	196	191	190
	U.S. Rockies	24		—	—	—	—
Natural gas liquids and crude oil (a)
	Western Canada	6.4		3.1	3.1	3.0	3.2
	U.S. Rockies	1.7		—	—	—	—
Total (g)
	Western Canada	412		220	215	209	209
	U.S. Rockies	34		—	—	—	—
Average sales price
Natural gas (g)
	Western Canada	3.70		8.23	6.32	7.15	8.57
	U.S. Rockies	3.93		—	—	—	—
Natural gas (g)*
	Western Canada	3.68		8.25	6.27	6.95	8.59
	U.S. Rockies	3.93		—	—	—	—
Natural gas liquids and crude oil – conventional (c)
	Western Canada	52.97		70.89	56.64	51.93	54.24
	U.S. Rockies	71.62		—	—	—	—
Ending capital employed (k)		3 349		1 152	1 153	857	562
Return on capital employed (%)		(8.4	)	7.7	2.5	14.9	30.7

Footnotes and definitions, see page 113.

110 SUNCOR ENERGY INC. 2009ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2009	2008	2007	2006	2005
EAST COAST CANADA***
Production (a)
Terra Nova		20.8	—	—	—	—
Hibernia		27.2	—	—	—	—
White Rose		10.0	—	—	—	—
Total production		58.0	—	—	—	—
Average sales price		76.86	—	—	—	—
Ending capital employed excluding major projects in progress (k)		2 142	—	—	—	—
Return on capital employed (%)		10.7	—	—	—	—
Return on capital employed (%)*		6.5	—	—	—	—
INTERNATIONAL***
Production (h)
North Sea
	Buzzard	47.8	—	—	—	—
	Other U.K.	15.5	—	—	—	—
	The Netherlands sector of the North Sea	13.2	—	—	—	—
Total North Sea		76.5
Other International
	Libya	32.6	—	—	—	—
	Trinidad & Tobago	11.7	—	—	—	—
Total Other International		44.3	—	—	—	—
Total production		120.8	—	—	—	—
Average sales price – North Sea (c)		71.63	—	—	—	—
Average sales price – Other
	International (i)	61.25	—	—	—	—
Ending capital employed excluding major projects in progress (k)		2 828	—	—	—	—
Return on capital employed (%)		11.5	—	—	—	—
Return on capital employed (%)*		7.5	—	—	—	—

Footnotes and definitions, see page 113.

SUNCOR ENERGY INC. 2009ANNUAL REPORT 111

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2009	2008	2007	2006	2005
REFINING AND MARKETING
Eastern North America
Refined product sales (j)
Transportation fuels
Gasoline
	Retail	9.3	3.9	4.5	4.6	4.5
	Other	5.3	4.0	4.3	3.8	3.9
Distillate		8.8	5.2	5.4	3.9	4.2
Total transportation fuel sales		23.4	13.1	14.2	12.3	12.6
Petrochemicals		0.8	0.8	0.9	0.9	0.7
Asphalt		1.5	0.6	0.3	—	—
Other		2.0	1.0	2.2	1.9	1.9
Total refined product sales		27.7	15.5	17.6	15.1	15.2
Crude oil supply and refining
	Processed at refineries (j)	29.6	11.0	10.9	8.6	10.6
	Utilization of refining capacity (%)	87	99	98	78	95
Western North America
Refined product sales (j)
Transportation fuels
Gasoline
	Retail	2.6	0.7	0.7	0.7	0.7
	Other	10.4	7.3	7.3	6.8	6.2
Distillate		9.5	5.6	5.2	4.6	4.1
Total transportation fuel sales		22.5	13.6	13.2	12.1	11.0
Asphalt		1.3	1.2	1.4	1.2	1.6
Other		3.4	1.2	1.3	1.1	1.1
Total refined product sales		27.2	16.0	15.9	14.4	13.7
Crude oil supply and refining
Processed at refineries (j)		33.6	13.7	14.2	13.1	12.1
Utilization of refining capacity (%)		97	96	99	92	98
Ending capital employed excluding major projects in progress (k)		8 304	2 974	2 489	1 938	907
Return on capital employed (%)		7.5	1.8	20.0	19.3	27.5
Return on capital employed (%)**		7.5	1.8	17.4	12.2	17.6
Retail outlets(number at year-end)		1 813	427	419	417	417

Prior year capital employed measures have not been restated for the movement of energy trading activities to Corporate, Energy Trading and Eliminations.

Footnotes and definitions, see page 113.

112 SUNCOR ENERGY INC. 2009ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

Definitions

(1)

Average sales price – This operating statistic is calculated before royalties (where applicable) and net of related transportation costs and excludes the realized impact of hedging activities unless stated.

(2)

Cash operating costs – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense 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.

(3)

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

(4)

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

(5)

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

(6)

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

(7)

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.

(8)

Average price realized – This operating statistic is calculated before transportation costs and royalties and excludes the impact of hedging activities.

Explanatory Notes

*

Excludes the impact of realized hedging activities.

**

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.

***

For the three months ended September 30, 2009, and the twelve months ended December 31, 2009, operating summary information reflects results of operations since the merger with Petro-Canada on August 1, 2009.

****

Users are cautioned that the Syncrude costs per barrel measure may not be fully comparable to similar information calculated by other entities (including Suncor's own cash costs per barrel excluding Syncrude) due to differing treatments for operations and capital costs among producers.

(a) thousands of barrels per day
(b) thousands of barrels of bitumen per day
(c) dollars per barrel
(d) dollars per barrel rounded to the nearest $0.05 (e) millions of cubic feet per day
(f) millions of cubic feet equivalent per day
(g) dollars per thousand cubic feet equivalent
(h) thousands of barrels of oil equivalent per day (i) dollars per barrel of oil equivalent
(j) thousands of cubic metres per day
(k) $ millions

Metric conversion

Crude oil, refined products, etc. – 1m³ (cubic metre) = approx. 6.29 barrels

SUNCOR ENERGY INC. 2009ANNUAL REPORT 113

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 2009		June 30 2009		Sept 30 2009	Dec 31 2009	Mar 31 2008	June 30 2008	Sept 30 2008	Dec 31 2008
Share ownership
Average number outstanding,     weighted monthly (thousands) (a)		936 550		937 005		1 349 263	1 559 512	926 216	928 572	930 393	931 524
Share price (dollars)
Toronto Stock Exchange
	High	34.22		40.13		39.84	40.79	56.14	73.10	62.37	43.78
	Low	21.15		27.44		29.90	34.66	40.92	47.78	39.61	18.80
	Close	28.14		35.37		37.40	37.21	49.61	59.20	44.00	23.72
New York Stock Exchange – US$
	High	27.92		36.93		37.31	39.62	56.73	74.28	61.99	41.12
	Low	16.95		21.61		25.51	31.84	39.67	46.31	38.00	14.52
	Close	22.21		30.34		34.56	35.31	52.61	68.56	51.64	19.02
Shares traded (thousands)
	Toronto Stock Exchange	408 851		361 886		339 790	277 779	219 094	226 392	266 381	396 680
	New York Stock Exchange	778 887		697 065		541 485	436 930	342 938	371 303	458 534	720 851
Per common share information  (dollars)
Net earnings attributable to     common shareholders		(0.20	)	(0.06	)	0.69	0.29	0.77	0.89	0.87	(0.24	)
Cash dividends		0.05		0.05		0.10	0.10	0.05	0.05	0.05	0.05

(a)

The company had approximately 3,028 holders of record of common shares as at January 31, 2010.

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.

114 SUNCOR ENERGY INC. 2009ANNUAL REPORT

QuickLinks

EXHIBIT 99-1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2009, including reconciliation to U.S. GAAP (Note 23)