EX-99.1 2 a2183122zex-99_1.htm EXHIBIT 99.1
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EXHIBIT 99-1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal
year ended December 31, 2007, including reconciliation to U.S. GAAP (Note 20)

MANAGEMENT'S STATEMENT
OF RESPONSIBILITY FOR FINANCIAL REPORTING

The management of Suncor Energy Inc. is responsible for the presentation and preparation of the accompanying consolidated financial statements of Suncor Energy Inc. on pages 53 to 90 and all related financial information contained in this Annual Report, including Management's Discussion and Analysis.

We, as Suncor Energy Inc.'s Chief Executive Officer and Chief Financial Officer, have certified Suncor's annual disclosure document filed with the United States Securities and Exchange Commission (Form 40-F) as required by the United States Sarbanes-Oxley Act.

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 53 to 57. 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 all aspects of the company's operations.

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

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



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

February 27, 2008

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 49

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

MANAGEMENT'S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

1.: Management is responsible for establishing and maintaining adequate internal control over the Company's financial reporting.
2.: Management has used the Committee of Sponsoring Organizations of the Treadway Commission ("COSO") framework in "Internal Control – Integrated Framework" to evaluate the effectiveness of the Company's internal control over financial reporting.
3.: Management has assessed the effectiveness of the Company's internal control over financial reporting as of December 31, 2007, 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, 2007.
4.: The effectiveness of the Company's internal control over financial reporting as of December 31, 2007 has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report which appears herein.



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

February 27, 2008

50 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

INDEPENDENT AUDITORS' REPORT

TO THE SHAREHOLDERS OF SUNCOR ENERGY INC.

We have completed integrated audits of the consolidated financial statements and internal control over financial reporting of Suncor Energy Inc. (the "Company") as of December 31, 2007 and 2006 and an audit of its 2005 consolidated financial statements. Our opinions, based on our audits, are presented below.

Consolidated financial statements

We have audited the accompanying consolidated balance sheets of Suncor Energy Inc. as at December 31, 2007 and December 31, 2006, and the related consolidated statements of earnings and comprehensive income, cash flows and shareholders' equity for each of the years in the three year period ended December 31, 2007. 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, 2007 and December 31, 2006 and for each of the years then ended in accordance with Canadian generally accepted auditing standards and the standards of the Public Company Accounting Oversight Board (United States). We conducted our audit of the Company's financial statements for the year ended December 31, 2005 in accordance with Canadian generally accepted auditing standards. 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, 2007 and December 31, 2006 and the results of its operations and its cash flows for each of the years in the three year period ended December 31, 2007 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 of December 31, 2007, 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 effectiveness of 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.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 51

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.

In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2007 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta

February 27, 2008

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

In the United States, reporting standards for auditors require the addition of an explanatory paragraph (following the opinion paragraph) when there is a change in accounting principles that has a material effect on the comparability of the company's financial statements, such as the changes described in note 1 to the consolidated financial statements. Our report to the shareholders dated February 27, 2008 is expressed in accordance with Canadian reporting standards which do not require a reference to such a change in accounting principles in the Auditors' Report when the change is properly accounted for and adequately disclosed in the financial statements.

PricewaterhouseCoopers LLP
Chartered Accountants
Calgary, Alberta, Canada

February 27, 2008

52 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

SUNCOR ENERGY INC.
SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

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

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

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

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

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

The significant accounting policies of the company are summarized below:

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

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

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

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

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

(b) Cash Equivalents and Investments

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

(c) Revenues

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

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

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 53

(d) Property, Plant and Equipment

Cost

Property, plant and equipment are recorded at cost.

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

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

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

Costs incurred after the inception of operations are expensed.

Interest Capitalization

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

Leases

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

Depreciation, Depletion and Amortization

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

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

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

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

54 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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.

Impairment

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

Disposals

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

(e) Deferred Charges and Other

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

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

(f) Employee Future Benefits

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

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

(g) Inventories

Inventories of crude oil and refined products are valued at the lower of cost (using the LIFO method) and net realizable value.

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

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

See also Section (m) Recently Issued Canadian Accounting Standards.

(h) Financial Instruments

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

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

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 55

derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in net earnings. If the derivative is designated as a cash flow hedge each period, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in net earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in net earnings immediately for both fair value and cash flow hedges.

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

The company's fixed-term debt is accounted for under the amortized cost method with the exception of the portion of debt that has related financial hedges, which is accounted for under the fair value hedge methodology outlined 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.

See also Section (m) Recently Issued Canadian Accounting Standards.

(i) Foreign Currency Translation

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

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

(j) Stock-Based Compensation Plans

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

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

For common share options granted prior to January 1, 2003 ("pre-2003 options"), compensation expense is not recognized in the Consolidated Statements of Earnings and Comprehensive Income. The company continues to disclose the pro forma earnings impact of related stock-based compensation expense for pre-2003 options. 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 are measured using the fair value based method of accounting. The expense is based on the fair values of the award at the time of grant and the change in fair value from the time of grant. The expense is recognized in the Consolidated Statements of Earnings and Comprehensive Income over the estimated vesting periods of the respective award.

(k) Transportation Costs

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

(l) Income Taxes

Suncor follows the liability method of accounting for income taxes. Future income taxes are recorded for the effect of any difference between the accounting and income tax basis of an asset or liability, using the substantively enacted income tax rates. Accumulated future income tax balances are adjusted to reflect changes in income tax rates that are substantively enacted with

56 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

the adjustment being recognized in net earnings in the period that the change occurs. Investment tax credits are recorded as an offset to the related expenditures.

(m) Recently Issued Canadian Accounting Standards

Inventories

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

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

Inventory		$404 million
Future Income Tax Liability		$121 million
Retained Earnings		$283 million

Going Concern

In June 2007, the CICA approved amendments to Handbook section 1400 "General Standards of Financial Statement Presentation". The revisions, effective January 1, 2008, are to include specific requirements for assessing and disclosing an entity's ability to continue as a going concern. The revised standard will not impact net earnings or financial position.

Capital Disclosures

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

Financial Instruments

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 57

CONSOLIDATED STATEMENTS OF EARNINGS
AND COMPREHENSIVE INCOME

For the years ended December 31 ($ millions)		2007		2006 (restated) (note 1)		2005 (restated) (note 1)

Revenues
	Operating revenues (notes 7, 17 and 19)	15 020		13 798		9 728
	Energy marketing and trading activities (note 7c)	2 883		1 582		827
	Net insurance proceeds	—		436		572
	Interest	30		13		2

		17 933		15 829		11 129

Expenses
	Purchases of crude oil and products	5 935		4 678		4 164
	Operating, selling and general	3 375		3 043		2 437
	Energy marketing and trading activities (note 7c)	2 870		1 541		789
	Transportation and other costs	198		212		152
	Depreciation, depletion and amortization	864		695		568
	Accretion of asset retirement obligations	48		34		30
	Exploration (note 19)	95		104		56
	Royalties (note 5)	691		1 038		555
	Taxes other than income taxes (note 19)	648		595		529
	Loss (gain) on disposal of assets	7		(1	)	(13	)
	Project start-up costs	68		45		25
	Financing expenses (income) (note 15)	(211	)	39		(15	)

		14 588		12 023		9 277

Earnings Before Income Taxes		3 345		3 806		1 852

Provision for income taxes (note 10)
	Current	382		20		39
	Future	131		815		655

		513		835		694

Net Earnings		2 832		2 971		1 158

Other comprehensive income (loss) (notes 1, 7 and 18)		(190	)	10		(26	)

Comprehensive Income		2 642		2 981		1 132

Net Earnings Per Common Share (dollars) (note 13)
Net earnings attributable to common shareholders
	Basic	6.14		6.47		2.54
	Diluted	6.02		6.32		2.48

Cash dividends		0.38		0.30		0.24

See accompanying Summary of Significant Accounting Policies and Notes.

58 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

CONSOLIDATED BALANCE SHEETS

As at December 31 ($ millions)			2007		2006 (restated) (note 1)

Assets
	Current assets
		Cash and cash equivalents	569		521
		Accounts receivable (notes 1, 7, 11 and 19)	1 416		1 050
		Inventories (note 16)	608		589
		Income taxes receivable	95		33
		Future income taxes (note 10)	130		109

	Total current assets		2 818		2 302
	Property, plant and equipment, net (note 3)		20 945		16 160
	Deferred charges and other (note 4)		404		297

	Total assets		24 167		18 759

Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	6		7
		Accounts payable and accrued liabilities (notes 1, 7, 8 and 9)	2 775		2 111
		Taxes other than income taxes	72		40
		Income taxes payable	244		—

	Total current liabilities		3 097		2 158
	Long-term debt (note 6)		3 811		2 363
	Accrued liabilities and other (notes 8 and 9)		1 434		1 214
	Future income taxes (note 10)		4 212		4 072

	Total liabilities		12 554		9 807

	Commitments and contingencies (note 11)
	Shareholders' equity
		Share capital (note 12)	881		794
		Contributed surplus (note 12)	194		100
		Accumulated other comprehensive income (loss) (notes 1, 7 and 18)	(253	)	(71	)
		Retained earnings (note 1)	10 791		8 129

	Total shareholders' equity		11 613		8 952

	Total liabilities and shareholders' equity		24 167		18 759

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 27, 2008

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 59

CONSOLIDATED STATEMENTS OF CASH FLOWS

For the years ended December 31 ($ millions)		2007		2006		2005

Operating Activities
Cash flow from operations ^(a)		3 805		4 533		2 476
Decrease (increase) in operating working capital
	Accounts receivable	(365	)	53		(477	)
	Inventories	(19	)	(66	)	(63	)
	Accounts payable and accrued liabilities	226		87		435
	Taxes payable/receivable	246		(43	)	(23	)

Cash flow from operating activities		3 893		4 564		2 348

Cash Used in Investing Activities ^(a)		(5 362	)	(3 489	)	(3 113	)

Net Cash Surplus (Deficiency) Before Financing Activities		(1 469	)	1 075		(765	)

Financing Activities
Increase (decrease) in short-term debt		(4	)	(42	)	19
Net proceeds from issuance of long-term debt		1 835		—		—
Net increase (decrease) in long-term debt		(171	)	(622	)	808
Issuance of common shares under stock option plans		62		45		69
Dividends paid on common shares		(162	)	(127	)	(102	)
Deferred revenue		4		27		50

Cash flow provided by (used in) financing activities		1 564		(719	)	844

Increase in Cash and Cash Equivalents		95		356		79
Effect of Foreign Exchange on Cash and Cash Equivalents		(47	)	—		(2	)
Cash and Cash Equivalents at Beginning of Year		521		165		88

Cash and Cash Equivalents at End of Year		569		521		165

(a): See Schedules of Segmented Data on pages 63 and 64.

See accompanying Summary of Significant Accounting Policies and Notes.

60 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

CONSOLIDATED STATEMENTS OF CHANGES
IN SHAREHOLDERS' EQUITY

For the years ended December 31 ($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings		Accumulated Other Comprehensive Income (AOCI)

At December 31, 2004, as previously reported	651	32		(55	)	4 246		—
Retroactive adjustment for change in accounting policy, net of tax (note 1)	—	—		55		—		(55	)

At December 31, 2004, as restated	651	32		—		4 246		(55	)
Net earnings	—	—		—		1 158		—
Dividends paid on common shares	—	—		—		(102	)	—
Issued for cash under stock option plans	74	(5	)	—		—		—
Issued under dividend reinvestment plan	7	—		—		(7	)	—
Stock-based compensation expense	—	23		—		—		—
Change in AOCI related to foreign currency translation	—	—		—		—		(26	)

At December 31, 2005, as restated	732	50		—		5 295		(81	)
Net earnings	—	—		—		2 971		—
Dividends paid on common shares	—	—		—		(127	)	—
Issued for cash under stock option plans	52	(7	)	—		—		—
Issued under dividend reinvestment plan	10	—		—		(10	)	—
Stock-based compensation expense	—	53		—		—		—
Income tax benefit of stock option deductions in the U.S.	—	4		—		—		—
Change in AOCI related to foreign currency translation	—	—		—		—		10

At December 31, 2006, as restated	794	100		—		8 129		(71	)
Net earnings	—	—		—		2 832		—
Dividends paid on common shares	—	—		—		(162	)	—
Issued for cash under stock option plans	74	(12	)	—		—		—
Issued under dividend reinvestment plan	13	—		—		(13	)	—
Stock-based compensation expense	—	103		—		—		—
Income tax benefit of stock option deductions in the U.S.	—	3		—		—		—
Adjustment to opening retained earnings arising from ineffective portion of cash flow hedges at January 1, 2007	—	—		—		5		—
Adjustment to opening AOCI arising from effective portion of cash flow hedges at January 1, 2007	—	—		—		—		8
Change in AOCI related to foreign currency translation	—	—		—		—		(195	)
Change in AOCI related to derivative hedging activities	—	—		—		—		5

At December 31, 2007	881	194		—		10 791		(253	)

See accompanying Summary of Significant Accounting Policies and Notes.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 61

SCHEDULES OF SEGMENTED DATA ^(a)

	Oil Sands						Natural Gas						Refining and Marketing (note 2)
For the years ended December 31 ($ millions)	2007		2006		2005		2007		2006		2005		2007		2006		2005

EARNINGS
Revenues ^(b)
Operating revenues	6 195		6 259		2 938		541		554		632		8 278		6 981		6 155
Energy marketing and trading activities	—		—		—		—		—		—		2 890		1 607		827
Net insurance proceeds	—		436		572		—		—		—		—		—		—
Intersegment revenues ^(c)	580		712		455		12		23		47		—		—		—
Interest	—		—		—		—		1		—		5		5		2

	6 775		7 407		3 965		553		578		679		11 173		8 593		6 984

Expenses
Purchases of crude oil and products	157		89		32		—		—		—		6 351		5 308		4 613
Operating, selling and general (note 2)	2 435		2 198		1 455		135		110		93		693		669		682
Energy marketing and trading activities	—		—		—		—		—		—		2 876		1 572		810
Transportation and other costs	138		162		104		31		25		22		29		25		26
Depreciation, depletion and amortization	462		385		330		189		152		130		171		132		96
Accretion of asset retirement obligations	40		28		24		7		5		5		1		1		1
Exploration	13		22		10		82		82		46		—		—		—
Royalties (note 5)	565		911		406		126		127		149		—		—		—
Taxes other than income taxes	90		75		51		4		3		3		553		516		475
Loss (gain) on disposal of assets	1		—		—		(1	)	(4	)	(12	)	7		3		(1	)
Project start-up costs	60		38		25		—		—		—		8		7		—
Financing expenses (income)	—		—		—		—		—		—		—		—		—

	3 961		3 908		2 437		573		500		436		10 689		8 233		6 702

Earnings (loss) before income taxes	2 814		3 499		1 528		(20	)	78		243		484		360		282
Income taxes	(380	)	(716	)	(571	)	45		28		(88	)	(139	)	(125	)	(108	)

Net earnings (loss)	2 434		2 783		957		25		106		155		345		235		174

As at December 31
TOTAL ASSETS	18 108		13 692		11 648		1 811		1 503		1 307		4 519		4 037		3 172

(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 2007, 2006 or 2005 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.

62 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

	Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2007		2006		2005		2007		2006		2005

EARNINGS
Revenues ^(b)
Operating revenues	6		4		3		15 020		13 798		9 728
Energy marketing and trading activities	(7	)	(25	)	—		2 883		1 582		827
Net insurance proceeds	—		—		—		—		436		572
Intersegment revenues ^(c)	(592	)	(735	)	(502	)	—		—		—
Interest	25		7		—		30		13		2

	(568	)	(749	)	(499	)	17 933		15 829		11 129

Expenses
Purchases of crude oil and products	(573	)	(719	)	(481	)	5 935		4 678		4 164
Operating, selling and general (note 2)	112		66		207		3 375		3 043		2 437
Energy marketing and trading activities	(6	)	(31	)	(21	)	2 870		1 541		789
Transportation and other costs	—		—		—		198		212		152
Depreciation, depletion and amortization	42		26		12		864		695		568
Accretion of asset retirement obligations	—		—		—		48		34		30
Exploration	—		—		—		95		104		56
Royalties (note 5)	—		—		—		691		1 038		555
Taxes other than income taxes	1		1		—		648		595		529
Loss (gain) on disposal of assets	—		—		—		7		(1	)	(13	)
Project start-up costs	—		—		—		68		45		25
Financing expenses (income)	(211	)	39		(15	)	(211	)	39		(15	)

	(635	)	(618	)	(298	)	14 588		12 023		9 277

Earnings (loss) before income taxes	67		(131	)	(201	)	3 345		3 806		1 852
Income taxes	(39	)	(22	)	73		(513	)	(835	)	(694	)

Net earnings (loss)	28		(153	)	(128	)	2 832		2 971		1 158

As at December 31
TOTAL ASSETS	(271	)	(473	)	(1 001	)	24 167		18 759		15 126

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 63

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Oil Sands						Natural Gas						Refining and Marketing (note 2)
For the years ended December 31 ($ millions)			2007		2006		2005		2007		2006		2005		2007		2006		2005

CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		2 434		2 783		957		25		106		155		345		235		174
	Exploration expenses		—		—		—		67		52		46		—		—		—
	Non-cash items included in earnings
		Depreciation, depletion and amortization	462		385		330		189		152		130		171		132		96
		Future income taxes	97		731		609		(43	)	(28	)	88		40		70		72
		Loss (gain) on disposal of assets	1		—		—		(1	)	(4	)	(12	)	7		3		(1	)
		Stock-based compensation expense	49		25		11		5		2		—		25		13		6
		Other	1		14		23		7		1		5		(5	)	(7	)	16
	Increase (decrease) in deferred credits and other		48		(21	)	(14	)	(1	)	—		—		(3	)	(3	)	—

Total cash flow from (used in) operations			3 092		3 917		1 916		248		281		412		580		443		363
Decrease (increase) in operating working capital			637		426		(270	)	22		(27	)	(5	)	(118	)	(102	)	(30	)

Total cash from (used in) operating activities			3 729		4 343		1 646		270		254		407		462		341		333

Cash from (used in) investing activities:
Capital and exploration expenditures			(4 431	)	(2 463	)	(1 948	)	(531	)	(458	)	(363	)	(376	)	(665	)	(779	)
Acquisition of Denver refineries and related assets			—		—		—		—		—		—		—		—		(62	)
Deferred maintenance shutdown expenditures			(135	)	—		(65	)	(6	)	—		(2	)	(73	)	(80	)	(10	)
Deferred outlays and other investments			(18	)	(2	)	(1	)	—		—		—		—		7		4
Proceeds from disposals			3		2		41		5		15		21		1		4		3
Proceeds from property loss			—		36		44		—		—		—		—		—		—
Decrease (increase) in investing working capital			333		197		47		—		—		—		(43	)	(53	)	26

Total cash (used in) investing activities			(4 248	)	(2 230	)	(1 882	)	(532	)	(443	)	(344	)	(491	)	(787	)	(818	)

Net cash surplus (deficiency) before financing activities			(519	)	2 113		(236	)	(262	)	(189	)	63		(29	)	(446	)	(485	)

(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.

64 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

SCHEDULES OF SEGMENTED DATA ^(a) (continued)

			Corporate and Eliminations						Total
For the years ended December 31 ($ millions)			2007		2006		2005		2007		2006		2005

CASH FLOW BEFORE FINANCING ACTIVITIES
Cash from (used in) operating activities:
Cash flow from (used in) operations
	Net earnings (loss)		28		(153	)	(128	)	2 832		2 971		1 158
	Exploration expenses		—		—		—		67		52		46
	Non-cash items included in earnings
		Depreciation, depletion and amortization	42		26		12		864		695		568
		Future income taxes	37		42		(114	)	131		815		655
		Loss (gain) on disposal of assets	—		—		—		7		(1	)	(13	)
		Stock-based compensation expense	24		13		6		103		53		23
		Other	(236	)	(22	)	(77	)	(233	)	(14	)	(33	)
	Increase (decrease) in deferred credits and other		(10	)	(14	)	86		34		(38	)	72

Total cash flow from (used in) operations			(115	)	(108	)	(215	)	3 805		4 533		2 476
Decrease (increase) in operating working capital			(453	)	(266	)	177		88		31		(128	)

Total cash from (used in) operating activities			(568	)	(374	)	(38	)	3 893		4 564		2 348

Cash from (used in) investing activities:
Capital and exploration expenditures			(77	)	(27	)	(63	)	(5 415	)	(3 613	)	(3 153	)
Acquisition of Denver refineries and related assets			—		—		—		—		—		(62	)
Deferred maintenance shutdown expenditures			—		—		—		(214	)	(80	)	(77	)
Deferred outlays and other investments			(14	)	(2	)	(6	)	(32	)	3		(3	)
Proceeds from disposals			—		—		—		9		21		65
Proceeds from property loss			—		—		—		—		36		44
Decrease (increase) in investing working capital			—		—		—		290		144		73

Total cash (used in) investing activities			(91	)	(29	)	(69	)	(5 362	)	(3 489	)	(3 113	)

Net cash surplus (deficiency) before financing activities			(659	)	(403	)	(107	)	(1 469	)	1 075		(765	)

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 65

SUNCOR ENERGY INC.
NOTES TO THE CONSOLIDATED FINANCIAL STATEMENTS

1. CHANGES IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007 the company adopted CICA Handbook Section 3855 "Financial Instruments, Recognition and Measurement", Section 3865 "Hedging", Section 1530 "Comprehensive Income" and Section 3251 "Equity".

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

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

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

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

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

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

($ millions)

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

(1): Recognition of fair value of derivative financial instruments designated as cash flow hedges and fair value hedges, and the related income tax impacts
(2): Impact on adoption of the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges
(3): Restatement of foreign currency translation adjustment to accumulated other comprehensive loss
(4): Recognition of accumulated other comprehensive loss arising from the restatement of foreign currency translation adjustment, offset by accumulated other comprehensive income arising from the effective component on derivative financial instruments designated as cash flow hedges

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

See Note 7 for a summary of financial instrument disclosures at December 31, 2007.

66 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

2. CHANGE IN SEGMENTED DISCLOSURES

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

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

3. PROPERTY, PLANT AND EQUIPMENT

		2007		2006
($ millions)		Cost	Accumulated Provision	Cost	Accumulated Provision

Oil sands
	Plant	11 049	1 962	8 160	1 706
	Mine and mobile equipment	1 423	388	1 191	320
	In-situ properties	2 566	222	1 963	148
	Pipeline	149	35	149	29
	Capital leases	102	6	38	4
	Major projects in progress	3 830	—	2 887	—

		19 119	2 613	14 388	2 207

Natural gas
	Proved properties	2 405	1 042	1 975	874
	Unproved properties	238	32	186	21
	Other support facilities and equipment	92	30	90	23

		2 735	1 104	2 251	918

Refining and marketing
	Refinery	2 699	628	2 179	555
	Marketing	783	304	741	291
	Pipeline	53	4	35	3
	Major projects in progress	—	—	386	—

		3 535	936	3 341	849

Corporate		305	96	208	54

		25 694	4 749	20 188	4 028

Net property, plant and equipment			20 945		16 160

4. DEFERRED CHARGES AND OTHER

($ millions)	2007	2006

Deferred maintenance shutdown costs	296	172
Deferred government tax credits	36	74
Other	72	51

Total deferred charges and other	404	297

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 67

5. ROYALTIES

Our current estimation of Alberta Crown royalties is based on regulations currently in effect. Alberta Crown royalties currently in effect for each oil sands project require payments to the Government of Alberta based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. Royalty expense for the company's oil sands operations for the year ended December 31, 2007, was $565 million (2006 – $911 million, 2005 – $406 million). The balance of the consolidated royalty expense is in respect of natural gas royalties of $126 million (2006 – $127 million, 2005 – $149 million).

The regime changes proposed by the Government of Alberta will increase royalty rates, effective January 1, 2009 to a sliding scale of 25% – 40% of R-C, subject to a minimum royalty of 1% – 9% depending on oil price. In both cases, the sliding scale royalty would move with increases in WTI prices from Cdn$55 to the maximum rates at a WTI price of Cdn$120.

In January 2008, Suncor entered into a Royalty Amending Agreement with the government of Alberta to transition to the new royalty framework rates in the Generic Regime commencing January 1, 2010 to January 1, 2016. The new royalty framework rates will apply to the bitumen royalty for current production levels of our base oil sands mining operations, subject to a cap of 30% of R-C, and a minimum royalty of 1.2% of R (assuming the government enacts their proposed framework). In addition, the Suncor Royalty Amending agreement provides Suncor with certainty for various matters, including the bitumen valuation methodology, allowed costs, royalty in-kind and certain taxes.

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

6. LONG-TERM DEBT

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

($ millions)	2007		2006

6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150) ⁽ⁱ⁾	1 137		—
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	494		583
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	494		583
5.39% Series 4 Medium Term Notes, due in 2037 ⁽ⁱⁱ⁾	600		—
6.70% Series 2 Medium Term Notes, due in 2011 ⁽ⁱⁱⁱ⁾	500		500
6.80% Medium Term Notes, repaid in 2007 ⁽ⁱⁱⁱ⁾ ^(iv)	—		250
6.10% Medium Term Notes, repaid in 2007 ⁽ⁱⁱⁱ⁾ ^(iv)	—		150

	3 225		2 066
Revolving-term debt, with interest at variable rates (see B. Credit Facilities)
Commercial Paper (interest at December 31, 2007 – 4.8%, 2006 – 4.3%) ^(v)	522		280

Total unsecured long-term debt	3 747		2 346
Secured long-term debt	1		1
Capital leases ^{(vi), (vii)}	102		38
Fair values of interest swaps	6		—
Deferred financing costs	(45	)	(22	)

Total long-term debt	3 811		2 363

(i): During the third quarter of 2007, the company issued additional 6.50% Notes with a principal amount of US$400 million under an outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.

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

(ii): During the first quarter of 2007, the company issued 5.39% Medium Term Notes with a principal amount of $600 million under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on March 26, 2037. The net proceeds were used for general corporate purposes, including reducing short-term borrowings, supporting our ongoing capital spending program and for working capital requirements.
(iii): The company has entered into various 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	2007	2006

Swap of 6.70% Medium Term Notes to floating rates	200	2011	5.7%	5.2%
Swap of 6.80% Medium Term Notes to floating rates ^(iv)	250	2007	6.0%	6.0%
Swap of 6.10% Medium Term Notes to floating rates ^(iv)	150	2007	4.7%	5.3%

68 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

(iv): During the third quarter of 2007, the company repaid maturing 6.10% $150 million Medium Term Notes using commercial paper, and the associated swap transaction expired.

During the first quarter of 2007, the company repaid maturing 6.80% $250 million Medium Term Notes using commercial paper, and the associated swap transaction expired.

(v): The company is authorized to issue commercial paper to a maximum of $1,500 million having a term not to exceed 365 days. Commercial paper is supported by unutilized credit facilities (see B. Credit Facilities).
(vi): Equipment leases with interest rates between 6.5% and 15.7% and maturity dates ranging from 2008 to 2037.
(vii): Future minimum amounts payable under capital leases and other long-term debt are as follows:

($ millions)	Capital Leases	Other Long-term Debt

2008	9	529 ^(a)
2009	9	—
2010	9	—
2011	10	500
2012	10	—
Later years	277	2 680

Total minimum payments	324	3 709

Less amount representing imputed interest	222

Present value of obligation under capital leases	102

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

Long-term Debt (per cent)

	2007	2006

Variable rate	19	37
Fixed rate	81	63

B. Credit facilities

During 2007, our $300 million bilateral credit facility was amended and extended by one year to 2008 and the credit limit was increased by $30 million to $330 million total funds available. Our $2 billion syndicated credit facility was renegotiated and extended by one year to have a five year term expiring in June 2012 and the company's commercial paper program limit was increased by $300 million from $1.2 billion to $1.5 billion. Additionally, a $15 million revolving demand credit facility was renegotiated and increased by $15 million to $30 million. At December 31, 2007, the company had available credit facilities of $2,375 million, of which $1,579 was undrawn as follows:

($ millions)		2007

Facility that is fully revolving for 364 days, has a term period of one year and expires in 2008		330
Facility that is fully revolving for a period of five years and expires in 2012		2 000
Facilities that can be terminated at any time at the option of the lenders		45

Total available credit facilities		2 375

Credit facilities supporting outstanding commercial paper		522
Credit facilities supporting standby letters of credit		274

Total undrawn credit facilities		1 579

7. FINANCIAL INSTRUMENTS

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 or currency-sensitive assets and liabilities. Suncor also uses derivatives for trading purposes. When used in a trading activity, the company is attempting to realize a gain on the fluctuations in the market value of the derivative.

Forwards and futures are contracts to purchase or sell a specific item at a specified date and price. When used as hedges, forwards and futures manage the exposure to losses that could result if commodity prices or foreign currency exchange 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 can 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, or vice versa; a domestic currency debt may be converted to a foreign currency debt.

See below for more technical details and amounts.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 69

(a) Balance Sheet Financial Instruments

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

The company's fixed-term debt is accounted for under the amortized cost method with the exception of the portion of debt that has related financial hedges which is accounted for under the fair value hedge methodology outlined 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, other than the foreign exchange effect, of this debt until the gains or losses are realized.

The following table summarizes estimated fair value information about the company's financial instruments recognized in the Consolidated Balance Sheets at December 31:

	2007		2006
($ millions)	Carrying Amount	Fair Value	Carrying Amount	Fair Value

Cash and cash equivalents	569	569	521	521
Accounts receivable	1 416	1 416	1 050	1 050
Current liabilities	2 507	2 507	1 947	1 947
Long-term debt	3 811	3 926	2 363	2 505

(b) Hedges

Fair Value Hedges

Suncor 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 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, 2007, the company had interest rate derivatives classified as fair value hedges outstanding for up to four years relating to fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the twelve-month period ended December 31, 2007. The notional amounts of interest rate swap contracts outstanding at December 31, 2007 are detailed in note 6, Long-Term Debt.

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

Cash Flow Hedges

Suncor 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 oil 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 swap transactions and foreign exchange forward contracts.

At December 31, 2007, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity risk for 2008.

The earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the twelve-month period ended December 31, 2007 was a loss of $5 million, net of income taxes of $2 million.

Certain derivative contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding

70 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.

As at December 31, 2007, assets increased by $27 million and liabilities increased by $31 million as a result of recording derivative instruments at fair value in accordance with the new standards.

Contracts outstanding at December 31 were as follows:

Revenue Hedges

Strategic Crude Oil	Quantity (bpd)	Average Price (US$/bbl) ^(a)	Revenue Hedged (Cdn$ millions) ^(b)	Hedge Period ^(c)

As at December 31, 2007
Costless collars	10 000	59.85 – 101.06	216 – 365	2008

As at December 31, 2006
Costless collars	60 000	51.64 – 93.26	1 318 – 2 380	2007
Costless collars	10 000	59.85 – 101.06	255 – 431	2008

As at December 31, 2005
Costless collars	7 000	50.00 – 92.57	149 – 276	2006
Costless collars	7 000	50.00 – 92.57	149 – 276	2007

Natural Gas	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period ^(c)

As at December 31, 2007
Swaps	–	–	–	–

As at December 31, 2006
Swaps	4 000	6.11	9	2007

As at December 31, 2005
Swaps	4 000	6.58	10	2006
Costless collars	25 000	10.76 – 16.13	24 – 36	2006	^(d)
Costless collars	10 000	8.75 – 13.38	19 – 29	2006	^(e)
Swaps	4 000	6.11	9	2007

Margin Hedges	Quantity (bpd)	Average Margin (US$/bbl)	Margin Hedged (Cdn$ millions) ^(b)	Hedge Period ^(c)

Refined product sale and crude purchase swaps
As at December 31, 2007	–	–	–	–
As at December 31, 2006	–	–	–	–
As at December 31, 2005	5 100	11.69	10	2006	^(f)

Foreign Currency Hedges	Notional (Euro Millions)	Average Forward Rate	Dollars Hedged (Cdn$ millions)	Hedge Period ^(c)

As at December 31, 2007
Euro/Cdn forward	–	–	–	–

As at December 31, 2006
Euro/Cdn forward	20.6	1.41	29.0	2007	^(g)

As at December 31, 2005
Euro/Cdn forward	9.9	1.39	13.8	2006	^(h)
Euro/Cdn forward	20.6	1.41	29.0	2007	^(g)

(a): Average price for crude costless collars is US$ WTI per barrel at Cushing, Oklahoma.
(b): The revenue and margin hedged is translated to Cdn$ at the respective year-end exchange rate and is subject to change as the US$/Cdn$ exchange rate fluctuates during the hedge period.
(c): Original hedge term is for the full year unless otherwise noted.
(d): For the period January to March 2006, inclusive.
(e): For the period April to October 2006, inclusive.
(f): For the period January to May 2006, inclusive.
(g): Settlement for applicable forwards occurring within the period April to September 2007.
(h): Settlement for applicable forward was March 2006.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 71

Fair Value of Hedging Derivative Financial Instruments

The fair value of hedging derivative financial instruments as recorded, is the estimated amount, based on broker quotes and/or internal valuation models 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 at December 31:

($ millions)	2007		2006

Revenue hedge swaps and collars	(11	)	22
Fixed to floating interest rate swaps	8		16
Specific hedges of individual transactions	12		(4	)

Fair value of outstanding hedging derivative financial instruments	9		34

Accumulated Other Comprehensive Income (AOCI)

A reconciliation of changes in AOCI attributable to derivative hedging activities for the twelve-month period ending December 31, 2007, is as follows:

($ millions)	2007

AOCI attributable to derivatives and hedging activities, recorded upon initial adoption on January 1, 2007, net of income taxes of $5	8
Current year net changes arising from cash flow hedges, net of income taxes of $1	8
Net unrealized hedging gains at the beginning of the year reclassified to earnings during the period, net of income taxes of $2	(3	)

AOCI attributable to derivatives and hedging activities, at December 31, 2007, net of income taxes of $4	13

(c) Energy Marketing and Trading Activities

In addition to the financial derivatives used for hedging activities, the company uses physical and financial energy contracts, including swaps, forwards and options to earn trading and marketing revenues. The financial energy trading activities are accounted for using the mark-to-market method and, as such, these derivative instruments are recorded at fair value at each balance sheet date. Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. The results of these activities are reported as revenue and as energy trading and marketing expenses in the Consolidated Statements of Earnings and Comprehensive Income. The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss)

($ millions)	2007		2006		2005

Physical energy contracts trading activity	21		41		15
Financial energy contracts trading activity	(3	)	(3	)	5
General and administrative costs	(4	)	(3	)	(3	)

Total	14		35		17

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

($ millions)	2007		2006

Energy trading assets	18		16
Energy trading liabilities	21		13

Net energy trading assets (liabilities)	(3	)	3

72 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

Change in fair value of net assets

($ millions)	2007

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

Fair Value of Contracts outstanding at December 31, 2007	(3	)

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

(d) Counterparty Credit Risk

The company may be exposed to certain losses in the event that counterparties to the 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. The company minimizes this risk by ensuring that substantially all agreements are with counterparties of investment grade. Risk is also minimized through regular management review of credit ratings and potential exposure to such counterparties. At December 31, the company had exposure to credit risk with counterparties as follows:

($ millions)	2007	2006

Derivative contracts not accounted for as hedges	18	16
Derivative contracts accounted for as hedges	20	35

Total	38	51

8. ACCRUED LIABILITIES AND OTHER

($ millions)	2007	2006

Asset retirement obligations ^(a)	882	704
Employee future benefits liability (see note 9)	175	170
Employee and director incentive plans ^(b)	173	143
Deferred revenue	164	143
Environmental remediation costs ^(c)	11	26
Other	29	28

Total	1 434	1 214

(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)	2007		2006

Asset retirement obligations, beginning of year	808		543
Liabilities incurred	275		286
Liabilities settled	(59	)	(54	)
Accretion of asset retirement obligations	48		33

Asset retirement obligations, end of year	1 072		808

The portion of the ARO expected to be paid within one year is shown within current liabilities and amounts to an additional $190 million (2006 – $104 million).

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2007, was approximately $2.2 billion (2006 – $1.7 billion). The liability recognized in 2007 was discounted using the company's credit-adjusted risk-free rate of 6.0% (2006 – 5.5%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 30 years.

A significant portion of the company's assets, including the upgrading facilities at the oil sands operation and the two downstream refineries located in Sarnia and Commerce City, have retirement obligations for which the fair value cannot be

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 73

reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets will be recorded in the first period in which the lives of the assets are determinable.

(b) Employee and Director Incentive Plans

The portion of the employee and director incentive plans expected to be paid within one year is shown within current liabilities and amounts to an additional $50 million (2006 – $32 million).

(c) Environmental Remediation Costs

The portion of the environmental remediation costs expected to be paid within one year is shown within current liabilities and amounts to an additional $19 million (2006 – $17 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

9. EMPLOYEE FUTURE BENEFITS LIABILITY

Suncor employees are eligible to receive certain pension, health care and insurance benefits when they retire. The related Benefit Obligation or commitment that Suncor has to employees and retirees at December 31, 2007, was $1,063 million (2006 – $1,024 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of the pension obligations. The company funds its unregistered supplementary pension plan and supplementary senior executive retirement plan on a voluntary basis. The amount and timing of future funding for these supplementary plans is subject to capital availability and is at the company's discretion. At the end of December 2007, Plan Assets to meet the Benefit Obligation were $684 million (2006 – $616 million).

The excess of the Benefit Obligation over Plan Assets of $379 million (2006 – $408 million) represents the Net Unfunded Obligation.

See below for more technical details and amounts.

Defined Benefit Pension Plans and Other Post-Retirement Benefits

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

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

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

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

74 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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)		2007		2006		2007		2006

Change in benefit obligation
	Benefit obligation at beginning of year	866		745		158		144
	Service costs	51		44		4		5
	Interest costs	45		40		8		8
	Plan participants' contributions	5		4		—		—
	Foreign exchange	(5	)	(2	)	(2	)	—
	Actuarial (gain) loss	(28	)	67		(3	)	5
	Benefits paid	(33	)	(32	)	(3	)	(4	)

Benefit obligation at end of year ^(a) ^(d)		901		866		162		158

Change in plan assets ^(b)
	Fair value of plan assets at beginning of year	616		479		—		—
	Actual return on plan assets	7		60		—		—
	Employer contributions	88		103		—		—
	Foreign exchange	(2	)	—		—		—
	Plan participants' contributions	5		4		—		—
	Benefits paid	(30	)	(30	)	—		—

Fair value of plan assets at end of year ^(d)		684		616		—		—

Net unfunded obligation		(217	)	(250	)	(162	)	(158	)
Items not yet recognized in earnings:
	Unamortized net actuarial loss ^(c)	158		177		43		52
	Unamortized past service costs	—		—		(20	)	(23	)

Accrued benefit liability		(59	)	(73	)	(139	)	(129	)

	Current liability	(41	)	(46	)	(3	)	(3	)
	Long-term liability	(40	)	(44	)	(136	)	(126	)
	Long-term asset	22		17		—		—

Total accrued benefit liability		(59	)	(73	)	(139	)	(129	)

(a): Obligations are based on the following assumptions:

	Pension Benefit Obligations		Other Post-Retirement Benefits Obligations
(percent)	2007	2006	2007	2006

Discount rate	5.25	5.00	5.25	5.00
Rate of compensation increase	5.00	5.00	4.75	4.75

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

	Rate of Return on Plan Assets			Discount Rate			Rate of Compensation Increase
($ millions)	1% increase		1% decrease	1% increase		1% decrease	1% increase	1% decrease

Increase (decrease) to net periodic benefit cost	(6	)	6	(21	)	25	10	(9	)
Increase (decrease) to benefit obligation	—		—	(140	)	165	35	(32	)

In order to measure the expected cost of other post-retirement benefits, a 9% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2007 (2006 – 9.5%; 2005 – 10%). It is assumed that this rate will remain constant in 2008 and 2009 and will decrease by 0.5% annually, to 5% by 2017, and remain at that level thereafter.

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 75

(b): Pension plan assets are not the company's assets and therefore are not included in the Consolidated Balance Sheets.
(c): The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 11 years for pension benefits (2006 – 11 years; 2005 – 11 years), and over the expected average future service life to full eligibility age of 12 years for other post-retirement benefits (2006 – 10 years; 2005 – 9 years).
(d): The company uses a measurement date of December 31 to value the plan assets and accrued benefit obligation.

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

	Pension Benefits		Other Post-Retirement Benefits
($ millions)	2007	2006	2007	2006

Partially funded plans	901	866	—	—
Unfunded plans	—	—	162	158

Benefit obligation at end of year	901	866	162	158

Components of Net Periodic Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other Post-Retirement Benefits
($ millions)	2007		2006		2005		2007	2006	2005

Current service costs	51		44		32		4	5	5
Interest costs	45		40		38		8	8	6
Expected return on plan assets ⁽ⁱⁱ⁾	(42	)	(32	)	(28	)	—	—	—
Amortization of net actuarial loss	25		28		21		3	1	1

Net periodic benefit cost recognized ⁽ⁱⁱⁱ⁾	79		80		63		15	14	12

Components of Net Incurred Benefit Cost ⁽ⁱ⁾

	Pension Benefits						Other Post-Retirement Benefits
($ millions)	2007		2006		2005		2007		2006	2005

Current service costs	51		44		32		4		5	5
Interest costs	45		40		38		8		8	6
Actual return on plan assets ⁽ⁱⁱ⁾	(7	)	(60	)	(41	)	—		—	—
Actuarial (gain) loss	(28	)	67		75		(4	)	5	8

Net incurred benefit cost	61		91		104		8		18	19

(i): The net periodic benefit cost includes certain accounting adjustments made to allocate costs to the periods in which employee services are rendered, consistent with the long-term nature of the benefits. Costs actually incurred in the period (arising from actual returns on plan assets and actuarial gains and losses in the period) differ from allocated costs recognized.
(ii): The expected return on plan assets is the expected long-term rate of return on plan assets for the year. It is based on plan assets at the beginning of the year that have been adjusted on a weighted-average basis for contributions and benefit payments expected for the year. The expected return on plan assets is included in the net periodic benefit cost for the year to which it relates, while the difference between it and the actual return realized on plan assets in the same year is amortized over the expected average remaining service life of employees of 11 years for pension benefits.

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

(iii): Pension expense is based on the following assumptions:

	Pension Benefit Expense			Other Post-Retirement Benefits Expense
(percent)	2007	2006	2005	2007	2006	2005

Discount rate	5.00	5.00	5.75	5.00	5.00	5.75
Expected return on plan assets	6.50	6.50	6.75	N/A	N/A	N/A
Rate of compensation increase	5.00	4.50	4.50	4.75	4.25	4.25

76 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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, 2007 and 2006, and the target allocation for 2008, are as follows:

	Target Allocation %	Plan Assets %
Asset Category	2008	2007	2006

Equities	60	58	61
Fixed income	40	42	39

Total	100	100	100

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

Cash Flows

The company expects that contributions to its pension plans in 2008 will be $72 million, including approximately $10 million for the company's supplemental executive and supplemental retirement plans. Expected benefit payments from all of the plans are as follows:

	Pension Benefits	Other Post-Retirement Benefits

2008	38	5
2009	42	6
2010	45	6
2011	47	7
2012	51	8
2013 - 2017	310	47

Total	533	79

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and a U.S. 401(k) savings plan, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $13 million in 2007 (2006 – $11 million; 2005 – $10 million).

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 77

10. INCOME TAXES

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

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

See below for more technical details and amounts.

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

		2007				2006				2005
($ millions)		Amount		%		Amount		%		Amount		%

Federal tax rate		1 053		32		1 256		33		648		35
Provincial abatement		(294	)	(9	)	(381	)	(10	)	(186	)	(10	)
Federal surtax		33		1		43		1		21		1
Provincial tax rates		307		9		395		10		213		12

Statutory tax and rate		1 099		33		1 313		34		696		38
Adjustment of statutory rate for future rate reductions		(133	)	(4	)	(146	)	(4	)	(84	)	(5	)

		966		29		1 167		30		612		33
Add (deduct) the tax effect of:
	Crown royalties	—		—		125		3		119		6
	Resource allowance ^(a)	—		—		(42	)	(1	)	(48	)	(2	)
	Large corporations tax	—		—		2		—		23		1
	Tax rate changes on opening future income taxes ^(b)	(427	)	(13	)	(419	)	(11	)	—		—
	Attributed Canadian royalty income	—		—		(23	)	(1	)	(24	)	(1	)
	Stock-based compensation	33		1		18		1		8		—
	Assessments and adjustments	(1	)	—		(9	)	—		7		—
	Capital gains	(40	)	(1	)	—		—		(6	)	—
	Other	(18	)	(1	)	16		—		3		—

Income taxes and effective rate		513		15		835		21		694		37

(a): The resource allowance was a federal tax deduction allowed as a proxy for non-deductible provincial Crown royalties. As required by GAAP in Canada, resource allowance is accounted for by adjusting the statutory tax rate by the resource allowance rate. Resource allowance has been phased out effective January 1, 2007.
(b): During 2007, the federal government enacted tax rate reductions totalling $427 million. During the fourth quarter of 2007 the federal government substantively enacted a 3.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $360 million related to the revaluation of its opening future income tax balances. During the second quarter of 2007 the federal government substantively enacted a 0.5% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $67 million related to the revaluation of its opening future income tax balances.

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

In 2007 net income tax payments totalled $152 million (2006 – $36 million; 2005 – $77 million).

78 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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

		2007				2006
($ millions)		Current		Non-Current		Current	Non-Current

Future income tax assets:
	Employee future benefits	16		—		12	—
	Asset retirement obligations	49		—		32	—
	Inventories	84		—		59	—
	Other	(19	)	—		6	—

		130		—		109	—

Future income tax liabilities:
	Excess of book values of assets over tax values	—		4 378		—	4 413
	Deferred maintenance shutdown costs	—		89		—	43
	Employee future benefits	—		(102	)	—	(88	)
	Asset retirement obligations	—		(220	)	—	(203	)
	Attributed Canadian royalty income	—		—		—	(93	)
	Other	—		67		—	—

		—		4 212		—	4 072

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

(a) Operating Commitments

In order to ensure continued availability of, and access to, facilities and services to meet its operational requirements, the company periodically enters into transportation service agreements for pipeline capacity and energy services agreements as well as non-cancellable operating leases for service stations, office space and other property and equipment. Under contracts existing at December 31, 2007, future minimum amounts payable under these leases and agreements are as follows:

($ millions)	Pipeline Capacity and Energy Services ⁽¹⁾	Operating Leases

2008	284	46
2009	313	38
2010	388	31
2011	379	26
2012	364	23
Later years	5 284	134

	7 012	298

(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, including the shipment of crude oil from Fort McMurray to Hardisty, Alberta. The agreements commenced in 1999 and extend up to 2033. As the initial shipper on one of the pipelines, Suncor's tolls payable are subject to annual adjustments.

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

(b) Contingencies

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

The company carries both property damage and business interruption insurance policies with a combined coverage limit of up to US$1.7 billion, net of deductible amounts or waiting periods. The primary property loss policy of US$250 million has a deductible of US$10 million per incident. Suncor has 100% ownership interest in Fort Insurance Limited, an insurance company which provides coverage to Suncor including business interruption coverage for oil sands with a limit of US$150 million and a deductible of the greater of 30 days or US$50 million. The excess coverage of US$1.3 billion can be used for either property damage or business interruption coverage for oil sands operations. Excess business interruption coverage begins the greater of 90 days from the date of the incident or US$250 million in gross earnings lost. For the purposes of determining loss for business interruption claims, the excess coverage has a ceiling of US$50 WTI and a lost production maximum of 150,000 barrels per day.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 79

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

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

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

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

The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, up to $170 million of accounts receivable (2006 – $170 million) having a maturity of 45 days or less, to a third party. The third party is a multiple party securitization vehicle that provides funding for numerous asset pools. As at December 31, 2007, no outstanding accounts receivable had been sold under the program (2006 – $170 million). Although the company does not believe it has any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $42 million in 2007 and no contingent liability or earnings impact have been recorded for this indemnification as the company believes it has no significant exposure to credit losses. Proceeds received from new securitizations and proceeds from collections reinvested in securitizations on a revolving basis for the year ended December 31, 2007, were $170 million and approximately $1,530 million, respectively. The company recorded an after-tax loss of approximately $4 million on the securitization program in 2007 (2006 – $2 million; 2005 – $4 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE's sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term covers a period of seven years and is accounted for as an operating lease. The company repurchased the equipment in 2006 for $21 million. As at December 31, 2007, the VIE did not have any assets or liabilities.

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

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

12. SHARE CAPITAL

(a) 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.

80 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

(b) Issued

	Common Shares
	Number (thousands)	Amount ($ millions)

Balance as at December 31, 2004	454 241	651
Issued for cash under stock option plans	3 302	74
Issued under dividend reinvestment plan	122	7

Balance as at December 31, 2005	457 665	732
Issued for cash under stock option plans	2 147	52
Issued under dividend reinvestment plan	132	10

Balance as at December 31, 2006	459 944	794
Issued for cash under stock options plan	2 694	74
Issued under dividend reinvestment plan	145	13

Balance as at December 31, 2007	462 783	881

Common Share Options

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

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

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

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

(a) Stock Option Plans

(i) Executive Stock Plan

Under this plan, the company granted 479,000 common share options in 2007 (2006 – 538,000; 2005 – 518,000) 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.

(ii) SunShare 2012 Performance Stock Option Plan

During 2007, the company granted 7,843,000 options to all eligible permanent full-time and part-time employees, both executive and non-executive, under its new employee stock option incentive plan ("SunShare 2012") which was approved at the Annual and Special Meeting of shareholders on April 26, 2007. Under this plan, meeting specified performance targets may accelerate the vesting of some options, such that 25% of outstanding options may vest on January 1, 2010, and the remaining 75% of outstanding options may vest on January 1, 2013. All unvested options at January 1, 2013, which have not previously been cancelled, will automatically expire.

(iii) SunShare Performance Stock Option Plan

During 2007, the company granted 1,045,000 options (2006 – 1,637,000; 2005 – 1,253,000) to eligible permanent full-time and part-time employees, both executive and non-executive, under its employee stock option incentive plan ("SunShare"). Under SunShare, meeting specified performance targets accelerates the vesting of some or all options.

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, approximately 25% of the then outstanding options vested under the SunShare plan. On June 30, 2005, an additional predetermined performance criterion under the SunShare plan was met, resulting in the vesting of 50% of the outstanding, unvested SunShare options on April 30, 2008. During 2007, the final predetermined performance criterion was met, and as a result, the remaining 50% of the outstanding, unvested SunShare options will vest on April 30, 2008.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 81

(iv) Key Contributor Stock Option Plan

Under this plan, the company granted 1,185,000 common share options in 2007 (2006 – 1,050,000; 2005 – 901,000) to non-insider senior managers and key employees. Options granted have a 10-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, 2004		20 687		5.22 – 42.02	24.49
	Granted	2 672		36.93 – 71.13	48.27
	Exercised	(3 302	)	5.22 – 41.38	20.71
	Cancelled	(854	)	26.14 – 70.53	30.82

Outstanding, December 31, 2005		19 203		5.22 – 71.13	28.12
	Granted	3 224		73.36 – 101.79	89.95
	Exercised	(2 147	)	5.22 – 61.92	20.99
	Cancelled	(471	)	25.00 – 96.10	46.66

Outstanding, December 31, 2006		19 809		7.77 – 101.79	38.48
	Granted	10 552		70.56 – 107.02	93.36
	Exercised	(2 694	)	7.77 – 92.11	22.75
	Cancelled	(667	)	25.31 – 101.73	65.68

Outstanding, December 31, 2007		27 000		10.13 – 107.02	60.61

Exercisable, December 31, 2007		7 276		10.13 – 100.04	30.87

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)	2007	2006	2005

	7 285	7 970	10 724

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2007:

	Outstanding			Exercisable
Exercise Prices ($)	Number (thousands)	Weighted-Average Remaining Contractual Life	Weighted-Average Exercise Price Per Share ($)	Number (thousands)	Weighted-Average Exercise Price Per Share ($)

10.13 – 17.45	1 598	2	15.40	1 598	15.40
21.35 – 28.93	8 538	4	27.00	3 588	26.26
31.59 – 42.65	2 656	6	37.83	1 527	37.32
45.51 – 72.42	965	5	56.81	71	52.83
73.36 – 92.68	4 993	7	88.29	475	91.32
93.36 – 107.02	8 250	7	95.16	17	98.07

Total	27 000	6	60.61	7 276	30.87

Fair Value of Options Granted

The fair values of all common share options granted during the period are estimated as at the grant date using a Monte Carlo simulation approach for the SunShare 2012 option plan and the Black-Scholes option-pricing model for all other option plans.

82 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

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:

	2007	2006	2005

Annual dividend per share	$0.38	$0.30	$0.24
Risk-free interest rate	4.22%	4.08%	3.69%
Expected life	6 years	5 years	6 years
Expected volatility	30%	29%	28%
Weighted-average fair value per option	$29.77	$29.17	$15.42

Stock-based compensation expense recognized for the year ended December 31, 2007 related to stock option plans was $103 million (2006 – $53 million; 2005 – $23 million).

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

($ millions, except per share amounts)		2007	2006	2005

Net earnings attributable to common shareholders – as reported		2 832	2 971	1 158
Less: compensation cost under the fair value method for pre-2003 options		8	15	13

Pro forma net earnings attributable to common shareholders for pre-2003 options		2 824	2 956	1 145

Basic earnings per share
	As reported	6.14	6.47	2.54
	Pro forma	6.12	6.44	2.51

Diluted earnings per share
	As reported	6.02	6.32	2.48
	Pro forma	6.00	6.29	2.46

(b) Deferred Share Units (DSUs)

The company had 1,168,000 DSUs outstanding at December 31, 2007 (1,170,000 at December 31, 2006). 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 2007, 20,000 DSUs were redeemed for cash consideration of $2 million (2006 – 59,000 redeemed for cash consideration of $5 million; 2005 – 81,000 redeemed for cash consideration of $5 million). Over time, DSU unitholders are entitled to receive additional DSUs equivalent in value to future notional dividend reinvestments. Final DSU redemption amounts are subject to change depending on the company's share price at the time of exercise. Accordingly, the company revalues the DSUs on each reporting date, with any changes in value recorded as an adjustment to compensation expense in the period. As at December 31, 2007, the total liability related to the DSUs was $126 million (2006 – $107 million), of which $5 million (2006 – $2 million) was classified as current.

During 2007, total pretax compensation expense related to DSUs was $21 million (2006 – $25 million; 2005 – $39 million).

(c) Performance Share Units (PSUs)

During 2007, the company issued 415,000 PSUs (2006 – 397,000; 2005 – 453,000) under its Performance Share Unit Compensation Plan. PSUs granted replace the remuneration value of reduced grants under the company's stock option plans. PSUs vest and are settled in cash approximately three years after the grant date to varying degrees (0%, 50%, 100% and 150%) contingent upon Suncor's performance (performance factor). Performance is measured by reference to the company's total shareholder return (stock price appreciation and dividend income) relative to a peer group of companies. Expense related to the PSUs is accrued based on the price of common shares at the end of the period and the anticipated performance factor. This expense is recognized on a straight-line basis over the term of the grant. Pretax expense recognized for PSUs during 2007 was $60 million (2006 – $42 million; 2005 – $21 million).

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 83

13. EARNINGS PER COMMON SHARE

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

($ millions)		2007	2006	2005

Net earnings attributable to common shareholders		2 832	2 971	1 158

(millions of common shares)
Weighted-average number of common shares		461	459	456
Dilutive securities:
	Shares issued under stock-based compensation plans	10	11	10

Weighted-average number of diluted common shares		471	470	466

(dollars per common share)
Basic earnings per share ^(a)		6.14	6.47	2.54
Diluted earnings per share ^(b)		6.02	6.32	2.48

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.

14. ACQUISITION OF REFINERY AND RELATED ASSETS

On May 31, 2005, the company acquired all of the issued shares of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero Energy Corp. for cash consideration of $37 million. Additional payments for working capital and associated inventory brought the total purchase price to $62 million. The acquired company's principal assets are a Commerce City refinery and a products terminal located in Grand Junction, Colorado. The allocation of fair value to the assets acquired and liabilities assumed was $79 million for property, plant and equipment, $30 million for inventory and $41 million for environmental liabilities assumed. The fair value assigned to other liabilities was $6 million. The acquisition was accounted for by the purchase method of accounting.

The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition. The new operations have been reported as part of the refining and marketing segment in the Schedules of Segmented Data.

15. FINANCING EXPENSES (INCOME)

($ millions)		2007		2006		2005

Interest on debt		189		150		151
Capitalized interest		(189	)	(129	)	(119	)

	Net interest expense	—		21		32
	Foreign exchange gain on long-term debt	(252	)	—		(37	)
	Other foreign exchange loss (gain)	41		18		(10	)

Total financing (income) expenses		(211	)	39		(15	)

Cash interest payments in 2007 totaled $183 million (2006 – $146 million; 2005 – $149 million).

84 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

16. INVENTORIES

($ millions)	2007	2006

Crude oil	332	249
Refined products	126	200
Materials, supplies and merchandise	150	140

Total	608	589

The replacement cost of crude oil and refined product inventories exceeded their LIFO carrying value by $415 million (2006 – $243 million) as at December 31, 2007.

During 2007, the company recorded a pretax gain of $57 million related to a permanent reduction in LIFO inventory layers, as the LIFO layers were lower than current cost (2006 – $6 million pretax gain).

17. RELATED PARTY TRANSACTIONS

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

($ millions)			2007	2006	2005

Operating revenues
	Sales to refining and marketing segment joint ventures:
		Refined products	329	294	327
		Petrochemicals	163	136	279

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

At December 31, 2007, amounts due from refining and marketing segment joint ventures were $17 million (2006 – $20 million).

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

18. ACCUMULATED OTHER COMPREHENSIVE INCOME

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

As at December 31 ($ millions)	2007		2006

Unrealized foreign currency translation adjustment	(266	)	(71	)
Unrealized gains and losses on derivative hedging activities	13		—

Total	(253	)	(71	)

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 85

19. SUPPLEMENTAL INFORMATION

($ millions)			2007	2006	2005

Geographic areas
	Revenues
		Canada	13 733	12 213	8 037
		U.S.	4 091	3 532	3 090
		Other	109	84	2

			17 933	15 829	11 129
	Total assets
		Canada	21 389	16 087	12 945
		U.S.	2 440	2 379	2 003
		Other	338	293	178

			24 167	18 759	15 126

Export sales ^(a)			876	810	648

Exploration expenses
	Geological and geophysical		26	51	22
	Other		—	1	1

	Cash costs		26	52	23
	Dry hole costs		69	52	33

	Cash and dry hole costs ^(b)		95	104	56
	Leasehold impairment ^(c)		—	2	13

			95	106	69

Taxes other than income taxes
	Excise taxes ^(d)		568	538	482
	Production, property and other taxes		80	57	47

			648	595	529

Allowance for doubtful accounts			3	4	4

(a): Sales of crude oil, natural gas and refined products from Canada to customers in the United States and sales of petrochemicals to customers in the United States and Europe.
(b): Included in the Consolidated Statements of Earnings and Comprehensive Income as exploration expenses.
(c): Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings and Comprehensive Income.
(d): Included in operating revenues in the Consolidated Statements of Earnings and Comprehensive Income.

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

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

($ millions)		Notes	2007		2006		2005

Net earnings as reported, Canadian GAAP			2 832		2 971		1 158
Adjustments
	Derivatives and hedging activities	(a)	—		11		83
	Stock-based compensation expense	(b)	15		(19	)	(26	)
	Research and development costs	(g)	(34	)	—		—
	Income tax expense		4		(3	)	(28	)

Net earnings from continuing operations, U.S. GAAP			2 817		2 960		1 187
	Cumulative effect of change in accounting principles, net of income taxes of $nil (2006 – $2; 2005 – $nil)	(b)	—		(4	)	—

Net earnings, U.S. GAAP			2 817		2 956		1 187
Derivatives and hedging activities, net of income taxes of $nil (2006 – $3; 2005 – $70)		(a)	5		6		140
Minimum pension liability, net of income taxes of $nil (2006 – $20; 2005 – $8)		(c)	—		39		(15	)
Pension and Post-retirement obligation, net of income taxes of $8		(c)	17		—		—
Foreign currency translation adjustment		(d)	(195	)	10		(26	)

Comprehensive income, U.S. GAAP			2 644		3 011		1 286

86 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

Per common share (dollars)		2007	2006	2005

Net earnings per share from continuing operations, U.S. GAAP
	Basic	6.11	6.45	2.60
	Diluted	5.98	6.29	2.55
Net earnings per share, U.S. GAAP
	Basic	6.11	6.44	2.60
	Diluted	5.98	6.29	2.55

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

December 31, 2007

December 31, 2006

Notes

As Reported

U.S. GAAP

As Reported

U.S. GAAP

Current assets

2 818

2 302

Property, plant and equipment, net

(g)

20 945

20 911

16 160

Deferred charges and other

(a,c)

404

297

323

Total assets

24 167

24 133

18 759

18 785

Current liabilities

3 097

2 158

Long-term borrowings

(a)

3 811

2 363

2 376

Accrued liabilities and other

(b,c)

1 434

1 602

1 214

1 430

Future income taxes

(a,c,g)

4 212

4 147

4 072

4 002

Share capital

(b)

881

944

794

842

Contributed surplus

(b)

194

240

100

153

Retained earnings

(a,b,g)

10 791

10 667

8 129

8 026

Accumulated other comprehensive income

(a,c,d)

(253

)

(375

)

(71

)

(202

)

Total liabilities and shareholders' equity

24 167

24 133

18 759

18 785

(a) Derivative Financial Instruments

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

Under U.S. GAAP, for the year ended December 31, 2006, the company would have recognized $5 million of hedging gains relating to forecasted cash flows in 2007 and 2008. (2005 – $2 million ineffectiveness relating to 2006 and 2007 forecasted cash flows). The net earnings impact of this ineffectiveness was recognized for Canadian GAAP purposes on January 1, 2007 as an adjustment to opening retained earnings.

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

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

($ millions)	2007		2006

AOCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $4 (2006 – $1)	8		2
Current period net changes arising from cash flow hedges, net of income taxes of $1 (2006 – $4)	8		9
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $2 (2006 – $1)	(3	)	(3	)

AOCI attributable to derivatives and hedging activities, end of period, net of income taxes of $4 (2006 – $4)	13		8

For the year ended December 31, 2006, U.S. GAAP net earnings increased by $7 million, net of income taxes of $4 million (2005 – increased net earnings of $55 million, net of income taxes of $28 million) to reflect the impact of ineffectiveness on derivative contracts classified as cash flow hedges.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 87

(b) Stock-Based Compensation

On January 1, 2006, the company adopted the U.S. Financial Accounting Standards Board (FASB) Statement 123(R), "Share-Based Payment", using the modified-prospective approach. FAS 123(R) allows the company to expense common share options issued after January 1, 2003 in a manner consistent with Canadian GAAP. The statement requires the recognition of an expense for employee services received in exchange for an award of equity instruments based on the grant date fair value of the award. The cost is to be recognized over the period for which an employee is required to provide the service in exchange for the award. In addition, the statement requires recognition of compensation expense for the portion of outstanding unvested awards granted prior to the effective date.

Under Canadian GAAP, the company's Performance Share Units (PSUs) are measured using an intrinsic approach, a fair-value technique not permitted under U.S. GAAP. After adoption of FAS 123(R), our PSUs for U.S. GAAP have been measured using a Monte Carlo Simulation approach to determine fair value. The impact on net earnings for the year ended December 31, 2007 is a recovery of previously recognized stock-based compensation expense of $17 million, net of income taxes of $6 million (2006 – $3 million expense, net of income taxes of $1 million).

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

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

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

For the comparative period, prior to the adoption of FAS 158 on December 31, 2006, recognition of an additional minimum pension liability was required when the accumulated benefit obligation exceeded the fair value of plan assets to the extent that such excess was greater than accrued pension costs otherwise recorded. For the purpose of determining the additional minimum pension liability, the accumulated benefit obligation does not incorporate projections of future compensation increases in the determination of the obligation. No such adjustment was required under Canadian GAAP. As required under FAS 158, the minimum pension liability adjustment recorded in 2006 was reversed in that year.

At December 31, 2006, the company would have recognized a minimum pension liability of $35 million, an intangible asset of $16 million and an accumulated other comprehensive loss of $12 million, net of income taxes of $7 million. Other comprehensive income for the year ended December 31, 2006 would have increased by $39 million, net of income taxes of $20 million (2005 – a decrease of $15 million, net of taxes of $8 million).

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

($ millions)	2007		2006

AOCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $67 million (2006 – $27 million)	(139	)	(51	)
Minimum pension liability (2006 – net of income taxes of $20 million)	—		39
Reversal of minimum pension liability upon adoption of FAS 158, (2006 – net of income taxes of $7 million)	—		12
Amortization of net actuarial loss, net of income taxes of $10 million	21		—
Amortization of past service costs, net of income taxes of $1 million	(2	)	—
Additions to unamortized net actuarial loss, net of income taxes of $2 million (2006 – $74 million)	(2	)	(155	)
Additions to unamortized past service costs (2006 – net of income taxes of $7 million)	—		16

AOCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $59 million (2006 – $67 million)	(122	)	(139	)

88 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

Total amount included in AOCI expected to be recognized as components of net periodic benefit cost during 2008 are as follows:

Amortization of net actuarial loss		$31 million
Amortization of past service costs		$(3) million

(d) Cumulative Foreign Currency Translation

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

(e) Suspended Exploratory Well Costs

Effective January 1, 2005, Suncor adopted Financial Accounting Standards Board Staff Position 19-1 (FSP 19-1), "Accounting for Suspended Well Costs". FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (FAS 19), "Financial Accounting and Reporting by Oil and Gas Producing Companies", to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. There were no capitalized exploratory well costs charged to expense upon the adoption of FSP 19-1.

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

Change in capitalized suspended exploratory well costs

($ millions)		2007		2006		2005

Balance, beginning of year		23		15		5
	Additions pending determination of proved reserves	14		21		14
	Charged to dry hole expense	(6	)	—		(2	)
	Reclassifications to proved properties	(10	)	(13	)	(2	)

Balance, end of year		21		23		15

Capitalized for a period greater than one year ($ millions)		7		2		1
Number of projects that have exploratory well costs capitalized for a period greater than 12 months		3		3		2

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

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

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

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 89

The purchase/sale of contract amounts included in revenue for 2007, 2006 and 2005 are shown below.

($ millions)	2007	2006	2005

Consolidated revenues	17 933	15 829	11 129
Amounts included in revenues for purchase/sale contracts with the same counterparty ⁽¹⁾	—	5	16

(1): Associated costs are in "purchases of crude oil and products".

(g) Research and Development Costs

Under Canadian GAAP, development expenditures are eligible to be capitalized when specific criteria are met. Under FAS 2, "Accounting for Research and Development Costs", development costs are required to be charged to expense when incurred. As a result, $24 million, net of income taxes of $10 million, would have been charged to income during 2007 (2006 – nil; 2005 nil).

(h) Accounting for Uncertainties in Income Taxes

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

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

Recently Issued Accounting Standards

In February 2007, FASB issued FAS 159, "The Fair Value Option for Financial Assets and Financial Liabilities". The standard, effective January 1, 2008, affords entities the option to irrevocably choose to measure many financial instruments and certain other items at fair value, at specified election dates. Retrospective application is not permitted. No impact to net earnings or financial position is anticipated.

In September 2006, FASB issued FAS 157 "Fair Value Measurements". The standard, effective January 1, 2008, establishes a recognized framework for measuring fair value, and expands disclosure relating to fair value inputs. No new fair value measurements are required. This Statement is generally to be applied prospectively and does not have an impact on earnings or financial position.

90 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

QUARTERLY SUMMARY (unaudited)

FINANCIAL DATA

		For the Quarter Ended								Total Year		For the Quarter Ended								Total Year
($ millions, except per share amounts)		Mar 31 2007		June 30 2007		Sept 30 2007		Dec 31 2007		2007		Mar 31 2006		June 30 2006		Sept 30 2006		Dec 31 2006		2006

Revenues		3 951		4 358		4 666		4 958		17 933		3 858		4 070		4 114		3 787		15 829

Net earnings (loss)
Oil Sands		453		419		556		1 006		2 434		707		1 100		582		394		2 783
Natural Gas		4		(4	)	—		25		25		40		60		12		(6	)	106
Refining and Marketing		99		206		40		—		345		11		116		85		23		235
Corporate and eliminations		(5	)	20		81		(68	)	28		(45	)	(58	)	3		(53	)	(153	)

		551		641		677		963		2 832		713		1 218		682		358		2 971

Per common share
Net earnings attributable to common shareholders
	– basic	1.20		1.39		1.47		2.08		6.14		1.56		2.65		1.48		0.78		6.47
	– diluted	1.17		1.36		1.43		2.04		6.02		1.52		2.59		1.45		0.76		6.32
Cash dividends		0.08		0.10		0.10		0.10		0.38		0.06		0.08		0.08		0.08		0.30

Cash flow from (used in) operations
Oil Sands		578		576		918		1 020		3 092		1 205		1 116		924		672		3 917
Natural Gas		64		70		47		67		248		99		66		68		48		281
Refining and Marketing		171		292		83		34		580		53		184		162		44		443
Corporate and eliminations		(23	)	(54	)	(21	)	(17	)	(115	)	(43	)	(46	)	(1	)	(18	)	(108	)

		790		884		1 027		1 104		3 805		1 314		1 320		1 153		746		4 533

OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production ⁽¹⁾
	Total production	248.2		202.3		239.1		252.5		235.6		264.4		267.3		242.8		266.4		260.0
	Firebag	35.3		36.2		35.8		40.4		36.9		27.4		35.0		37.2		35.1		33.7
Sales
	Light sweet crude oil	105.5		100.0		99.3		102.2		101.7		119.2		124.7		84.9		113.7		110.5
	Diesel	29.5		20.3		23.9		26.0		25.0		35.1		32.9		20.7		24.0		28.2
	Light sour crude oil	112.7		84.2		94.1		118.2		102.3		121.0		99.2		125.8		126.8		118.2
	Bitumen	6.8		3.8		6.6		5.4		5.7		—		8.5		6.6		9.7		6.2

Total sales		254.5		208.3		223.9		251.8		234.7		275.3		265.3		238.0		274.2		263.1

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 91

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

		For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)		Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007	Mar 31 2006	June 30 2006	Sept 30 2006	Dec 31 2006	2006

OIL SANDS (continued)
Average sales price ⁽²⁾
(dollars per barrel)
	Light sweet crude oil	68.63	75.64	81.00	87.34	78.03	69.00	78.27	78.11	64.51	71.98
	Other (diesel, light sour crude oil and bitumen)	63.62	66.74	73.76	78.48	70.86	63.28	72.75	68.60	57.91	65.17
	Total	65.70	71.01	76.97	82.07	74.01	65.75	75.34	71.99	60.65	68.03
	Total^(a)	65.61	71.01	76.97	82.36	74.07	65.75	75.34	71.99	60.65	68.03
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		21.75	28.40	23.00	24.10	24.15	15.55	15.65	21.00	22.65	18.70
Natural gas		4.50	4.20	2.10	3.60	3.55	3.45	2.55	2.60	3.00	2.90
Imported bitumen		0.05	0.10	—	0.20	0.10	0.05	0.10	0.10	—	0.10

Cash operating costs ⁽³⁾		26.30	32.70	25.10	27.90	27.80	19.05	18.30	23.70	25.65	21.70
Project start-up costs		0.10	1.15	1.10	0.55	0.95	0.90	0.10	0.35	0.25	0.40

Total cash operating costs ⁽⁴⁾		26.40	33.85	26.20	28.45	28.75	19.95	18.40	24.05	25.90	22.10
Depreciation, depletion and amortization		4.45	5.85	5.70	5.60	5.40	3.90	3.80	4.30	4.25	4.05

Total operating costs ⁽⁵⁾		30.85	39.70	31.90	34.05	34.15	23.85	22.20	28.35	30.15	26.15

Cash operating costs and total operating costs – In-Situ Bitumen Production Only
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs		11.05	10.60	11.85	9.95	10.85	5.70	8.50	5.55	8.05	8.95
Natural gas		11.05	10.60	9.10	9.15	9.90	7.70	8.15	7.60	9.90	8.35

Cash operating costs ⁽⁶⁾		22.10	21.20	20.95	19.10	20.75	13.40	16.65	13.15	17.95	17.30
Firebag start-up costs		—	—	—	—	—	8.50	—	—	—	1.70

Total cash operating costs ⁽⁷⁾		22.10	21.20	20.95	19.10	20.75	21.90	16.65	13.15	17.95	19.00
Depreciation, depletion and amortization		5.35	5.75	6.70	6.80	6.20	6.90	3.75	5.55	6.20	5.55

Total operating costs ⁽⁸⁾		27.45	26.95	27.65	25.90	26.95	28.80	20.40	18.70	24.15	24.55

92 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

QUARTERLY SUMMARY (unaudited) (continued)

OPERATING DATA (continued)

		For the Quarter Ended				Total Year	For the Quarter Ended				Total Year
($ millions, except per share amounts)		Mar 31 2007	June 30 2007	Sept 30 2007	Dec 31 2007	2007	Mar 31 2006	June 30 2006	Sept 30 2006	Dec 31 2006	2006

NATURAL GAS
Gross production^(b)
	Natural gas (millions of cubic feet per day)	191	191	193	210	196	196	189	191	192	191
	Natural gas liquids and crude oil (thousands of barrels per day)	3.1	3.0	3.1	3.2	3.1	3.2	3.5	2.8	2.6	3.0
	Total gross production (thousands of barrels of oil equivalent per day)	34.9	34.9	35.2	38.2	35.8	35.9	35.1	34.6	34.7	34.8
	Total gross production (millions of cubic feet equivalent per day)	209	209	211	229	215	215	211	208	208	209
Average sales price ⁽²⁾
	Natural gas (dollars per thousand cubic feet)	7.01	6.85	5.39	6.08	6.32	9.03	6.38	6.33	6.55	7.15
	Natural gas^(a) (dollars per thousand cubic feet)	7.14	6.83	5.14	6.02	6.27	8.75	6.22	6.13	6.40	6.95
	Natural gas liquids and crude oil – conventional (dollars per barrel)	56.69	51.21	58.11	60.31	56.64	53.89	63.75	61.07	45.55	51.93
REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)		31.6	34.6	35.1	32.8	33.5	26.6	31.6	31.4	29.1	29.5
Utilization of refining capacity (%)		97	108	102	87	98	74	96	95	76	85

(a): Excludes the impact of hedging activities.
(b): Currently natural gas production is located in the Western Canada Sedimentary Basin.

Definitions

(1): Total production – Total production includes total production from both mining and in-situ operations.
(2): Average sales price – This operating statistic is calculated before royalties and net of related transportation costs (including or excluding the impact of hedging activities as noted).
(3): Cash operating costs – Total operations – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense, taxes other than income taxes and the cost of bitumen imported from third parties. Per barrel amounts are based on total production volumes. For a reconciliation of this non-GAAP financial measure see Management's Discussion and Analysis.
(4): Total cash operating costs – Total operations – Include cash operating costs – Total operations as defined above and cash start-up costs. Per barrel amounts are based on total production volumes.
(5): Total operating costs – Total operations – Include total cash operating costs – Total operations as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes.
(6): Cash operating costs – In-situ bitumen production – Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes only.
(7): Total cash operating costs – In-situ bitumen production – Include cash operating costs – In-situ bitumen production as defined above and cash start-up costs for in-situ operations. Per barrel amounts are based on in-situ production volumes only.
(8): Total operating costs – In-situ bitumen production – Include total cash operating costs – In-situ bitumen production as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes only.

Metric conversion

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

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 93

FIVE-YEAR FINANCIAL SUMMARY (unaudited)

($ millions, except for ratios)	2007		2006		2005		2004		2003

Revenues
Oil Sands	6 775		7 407		3 965		3 640		3 101
Natural Gas	553		578		679		567		512
Refining and Marketing	11 173		8 593		6 984		4 995		3 451
Corporate and eliminations	(568	)	(749	)	(499	)	(497	)	(453	)

	17 933		15 829		11 129		8 705		6 611

Net earnings (loss)
Oil Sands	2 434		2 783		957		956		892
Natural Gas	25		106		155		114		120
Refining and Marketing	345		235		174		107		70
Corporate and eliminations	28		(153	)	(128	)	(101	)	18

	2 832		2 971		1 158		1 076		1 100

Cash flow from (used in) operations
Oil Sands	3 092		3 917		1 916		1 717		1 780
Natural Gas	248		281		412		314		296
Refining and Marketing	580		443		363		204		158
Corporate and eliminations	(115	)	(108	)	(215	)	(222	)	(194	)

	3 805		4 533		2 476		2 013		2 040

Capital and exploration expenditures
Oil Sands	4 431		2 463		1 948		1 119		953
Natural Gas	531		458		363		279		184
Refining and Marketing	376		665		779		418		153
Corporate	77		27		63		31		32

	5 415		3 613		3 153		1 847		1 322

Total assets	24 167		18 759		15 126		11 749		10 463

Ending capital employed^(a)
Short-term and long-term debt, less cash and cash equivalents	3 248		1 849		2 868		2 134		2 551
Shareholders' equity	11 613		8 952		5 996		4 874		3 858

	14 861		10 801		8 864		7 008		6 409
Less capitalized costs related to major projects in progress	(4 148	)	(2 649	)	(2 938	)	(1 467	)	(1 122	)

	10 713		8 152		5 926		5 541		5 287

Total Suncor employees (number at year-end)	6 465		5 766		5 152		4 605		4 231

94 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

FIVE-YEAR FINANCIAL SUMMARY (unaudited) (continued)

($ millions, except for ratios)		2007	2006	2005	2004	2003

Dollars per common share
	Net earnings attributable to common shareholders	6.14	6.47	2.54	2.38	2.45
	Cash dividends	0.38	0.30	0.24	0.23	0.1925
	Cash flow from operations	8.25	9.87	5.43	4.44	4.54
Ratios
Return on capital employed (%) ^{(a), (b)}		28.3	40.7	19.8	19.0	18.8
Return on capital employed (%) ^(c)		20.7	30.5	14.4	16.1	16.3
Return on shareholders' equity (%) ^(d)		27.5	39.7	21.3	24.6	32.9
Debt to debt plus shareholders' equity (%) ^(e)		24.7	20.9	33.6	31.3	43.2
Net debt to cash flow from operations (times) ^(f)		0.9	0.4	1.2	1.1	1.3
Interest coverage – cash flow basis (times) ^(g)		22.2	30.5	16.9	13.7	11.9
Interest coverage – net earnings basis (times) ^(h)		17.7	25.5	12.5	10.8	10.5

(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, at the beginning and end of the year, divided by two, less average capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed annual reconciliation of this non-GAAP financial measure see page 46 of MD&A.
(c): If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(d): Net earnings as a percentage of average shareholders' equity. Average shareholders' equity is the sum of total shareholders' equity at the beginning and end of the year divided by two.
(e): Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders' equity.
(f): Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.
(g): Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(h): Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 95

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
2007

June 30
2007

Sept 30
2007

Dec 31
2007

Mar 31
2006

June 30
2006

Sept 30
2006

Dec 31
2006

Share ownership

Average number outstanding, weighted monthly (thousands) ^(a)

460 074

460 422

460 789

461 187

458 230

458 596

458 859

459 069

Share price (dollars)

Toronto Stock Exchange

High

92.85

99.70

101.55

109.47

93.85

102.18

97.12

95.00

Low

79.66

87.58

88.72

91.25

75.58

75.00

71.18

72.26

87.85

95.96

94.46

107.91

89.63

90.34

80.19

91.79

New York Stock Exchange – US$

High

77.79

93.52

100.11

117.98

82.15

89.86

86.78

82.08

Low

67.78

75.71

82.37

91.40

64.00

67.36

63.77

64.06

76.35

89.92

94.81

108.73

77.02

81.01

72.05

78.91

Shares traded (thousands)

Toronto Stock Exchange

109 485

87 784

99 701

100 233

107 797

101 626

106 348

99 704

New York Stock Exchange

97 383

71 365

65 133

58 157

114 031

116 492

100 714

94 676

Per common share information (dollars)

Net earnings attributable to common shareholders

1.20

1.39

1.47

2.08

1.56

2.65

1.48

0.78

Cash dividends

0.08

0.10

0.06

0.08

(a): The company had approximately 2,387 holders of record of common shares as at January 31, 2008.

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.

96 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited)

	2007	2006	2005	2004	2003

OIL SANDS
Production (thousands of barrels per day)	235.6	260.0	171.3	226.5	216.6
Sales (thousands of barrels per day)
Light sweet crude oil	101.7	110.5	73.3	114.9	112.3
Diesel	25.0	28.2	15.6	27.9	26.3
Light sour crude oil	102.3	118.2	59.8	75.1	73.3
Bitumen	5.7	6.2	16.6	8.4	6.4

	234.7	263.1	165.3	226.3	218.3

Average sales price (dollars per barrel)
Light sweet crude oil	78.03	71.98	49.93	45.60	40.26
Other (diesel, light sour crude oil and bitumen)	70.86	65.17	56.90	39.13	33.93
Total	74.01	68.03	53.81	42.28	37.19
Total ^(a)	74.07	68.03	62.68	49.78	40.22
Cash operating costs – total operations ^(b)	27.80	21.70	24.55	15.15	13.80
Total cash operating costs – total operations ^(b)	28.75	22.10	24.65	15.45	13.80
Total operating costs – total operations ^(b)	34.15	26.15	29.95	19.05	17.15
Cash operating costs – in-situ bitumen production ^{(b), (e)}	20.75	17.30	22.20	22.05	—
Total cash operating costs – in-situ bitumen production ^{(b), (e)}	20.75	19.00	23.20	28.90	—
Total operating costs – in-situ bitumen production ^{(b), (e)}	26.95	24.55	28.10	34.90	—
Ending capital employed excluding major projects in progress	6 541	5 015	4 436	4 088	4 007
Return on capital employed (%) ^(c)	42.6	53.5	22.4	22.3	21.1
Return on capital employed (%) ^(d)	27.6	40.1	16.0	18.2	17.7

(a): Excludes the impact of hedging activities.
(b): Dollars per barrel rounded to the nearest $0.05. See definitions on page 93.
(c): See definitions on page 95.
(d): If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e): In-situ bitumen production commenced commerical operations on April 1, 2004.

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 97

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

			2007	2006	2005	2004	2003

NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
	Gross		196	191	190	200	187
	Net ^(a)		153	141	137	147	142
Natural gas liquids and crude oil (thousands of barrels per day)
	Gross		3.1	3.0	3.2	3.5	3.7
	Net ^(a)		2.4	2.3	2.6	2.6	2.8
Total (thousands of boe ^(b) per day)
	Gross		35.8	34.8	34.8	36.8	34.9
	Net ^(a)		27.9	25.8	25.3	27.1	26.4
Total (millions of cubic feet equivalent per day)
	Gross		215	209	209	221	209
	Net ^(a)		167	155	152	163	158
Average sales price
Natural gas (dollars per thousand cubic feet)			6.32	7.15	8.57	6.70	6.42
Natural gas (dollars per thousand cubic feet) ^(c)			6.27	6.95	8.59	6.73	6.42
Natural gas liquids and crude oil – conventional (dollars per barrel)			56.64	51.93	54.24	44.99	37.67
Ending capital employed			1 153	857	562	447	400
Return on capital employed (%) ^(g)			2.5	14.9	30.7	26.9	29.2
Undeveloped landholdings ^(d)
Oil and gas (millions of acres)
	Western Canada
		Gross	1.3	1.2	0.6	0.7	0.5
		Net ^(e)	0.7	0.7	0.4	0.5	0.4
	International
		Gross	0.1	0.1	0.4	0.7	0.9
		Net ^(e)	—	—	0.2	0.4	0.2
Net wells drilled ^(f)
	Exploratory
		Oil	—	—	—	—	—
		Gas	7	3	8	5	2
		Dry	6	5	4	5	31
	Development
		Oil	1	1	1	—	1
		Gas	14	13	18	16	16
		Dry	3	4	3	—	4

			31	26	34	26	54

(a): Net of royalties.
(b): Barrel of oil equivalent – converts natural gas to oil on the approximate energy equivalent basis that 6,000 cubic feet equals one barrel of oil.
(c): Excludes the impact of hedging activities.
(d): Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres.
(e): Our interest in the undeveloped landholdings.
(f): Excludes interests in eight net exploratory wells and eight net development wells in progress at the end of 2007.
(g): See definitions on page 95.

98 SUNCOR ENERGY INC. 2007 ANNUAL REPORT

SUPPLEMENTAL FINANCIAL AND OPERATING INFORMATION (unaudited) (continued)

		2007	2006	2005	2004	2003

REFINING AND MARKETING
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
	Retail ^(a)	5.2	5.3	5.2	5.3	5.1
	Other	11.6	10.6	10.1	7.9	7.7
Distillate		10.6	8.5	8.3	6.7	6.5

Total transportation fuel sales		27.4	24.4	23.6	19.9	19.3
Petrochemicals		0.9	0.9	0.7	0.8	0.8
Asphalt		1.7	1.2	1.6	1.5	1.7
Other		3.5	3.0	3.0	2.5	2.3

Total refined product sales		33.5	29.5	28.9	24.7	24.1

Crude oil supply and refining
	Processed at refineries (thousands of cubic metres per day)	25.1	21.7	22.7	19.9	19.9
Utilization of refining capacity (%)		98	85	97	96	96
Ending capital employed excluding major projects in progress		2 270	1 818	796	736	820
Return on capital employed (%) ^(b)		16.8	20.4	22.2	13.0	10.7
Return on capital employed (%) ^{(b), (c), (e)}		14.5	12.5	13.8	12.0	10.7
Retail outlets ^(d) (number at year-end)		419	417	417	421	422

(a): Excludes sales through joint venture interests.
(b): See definitions on page 95.
(c): If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(d): Sunoco-branded and Phillips 66®-branded service stations, other private brands managed by refining and marketing, and refining and marketing's interest in service stations managed through joint ventures.
(e): For 2003, return on capital employed calculated for Canadian operations only (U.S. operations acquired during 2003).

SUNCOR ENERGY INC. 2007 ANNUAL REPORT 99

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EXHIBIT 99-1

Audited Consolidated Financial Statements of Suncor Energy Inc. for the fiscal year ended December 31, 2007, including reconciliation to U.S. GAAP (Note 20)

($ millions)

1% increase

1% decrease

Increase (decrease) to total of service and interest cost components of net periodic post-retirement health care benefit cost

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