Exhibit 99.1

Suncor Energy Inc.	061
2006 Annual Report

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 65 to 103 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 65 to 69. 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.

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 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	Senior Vice President and
Chief Executive Officer	Chief Financial Officer
February 28, 2007

062	Suncor Energy Inc.
	2006 Annual Report

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 the Company’s internal control over financial reporting as of December 31, 2006, 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, 2006.

4.Management’s assessment of the effectiveness of the Company’s internal control over financial reporting as of December 31, 2006, has been audited by PricewaterhouseCoopers LLP, independent auditors, as stated in their report, which appears herein.

Richard L. George	J. Kenneth Alley
President and	Senior Vice President and
Chief Executive Officer	Chief Financial Officer
February 28, 2007

Suncor Energy Inc.	063
2006 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. as of December 31, 2006 and December 31, 2004 and an audit of its December 31, 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, 2006 and December 31, 2005 and the related consolidated statements of income, cash flows and changes in shareholders’ equity for each of the three years in the period ended December 31, 2006. 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, 2006 and December 31, 2004 and for 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 as at December 31, 2005 and 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.

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, 2006 and December 31, 2005 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2006 in accordance with Canadian generally accepted accounting principles.

Internal Control Over Financial Reporting

We have also audited management’s assessment, included in the accompanying Management’s Report on Internal Control over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December31,2006, 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. Our responsibility is to express opinions on management’s assessment and 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, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

064	Suncor Energy Inc.
	2006 Annual Report

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

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

In our opinion, management’s assessment that the Company maintained effective internal control over financial reporting as of December 31, 2006 is fairly stated, in all material respects, based on criteria established in Internal Control – Integrated Framework issued by the COSO. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2006 based on criteria established in Internal Control – Integrated Framework issued by the COSO.

PricewaterhouseCoopers LLP

Chartered Accountants

Calgary, Alberta

February 28, 2007

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 28, 2007 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

February 28, 2007

Suncor Energy Inc.	065
2006 Annual Report

Summary of significant accounting policies

Suncor Energy Inc. is a Canadian integrated energy company comprised of four operating segments: Oil Sands, Natural Gas, Energy Marketing and Refining – Canada, and Refining and Marketing – U.S.A.

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.

Energy Marketing and Refining – Canada includes the manufacture, transportation and marketing of petroleum, petrochemical and biofuel products, primarily in Ontario and Quebec.

Refining and Marketing – U.S.A. includes the manufacture, transportation and marketing of petroleum and petrochemical products, 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 18.

The consolidated financial statements include the accounts of Suncor Energy Inc. and its subsidiaries and the company’s proportionate share of the assets, liabilities, 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 (Energy Marketing and Refining – Canada and Refining and Marketing – U.S.A.) 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 a portion of 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.

066	Suncor Energy Inc.
	2006 Annual Report

(d) Property, Plant and Equipment and Intangible Assets

Cost

Property, plant and equipment and intangible assets 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.

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.

Suncor Energy Inc.	067
2006 Annual Report

DOWNSTREAM OPERATIONS (INCLUDING ENERGY MARKETING AND REFINING – CANADA AND REFINING AND MARKETING – U.S.A.) 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. Intangible assets with determinable useful lives are amortized over a maximum period of four years. The amortization of intangible assets is included within depreciation expense in the Consolidated Statements of Earnings.

Asset Retirement Obligations

A liability is recognized for future retirement obligations associated with the company’ 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.

A significant portion of the company’s assets have retirement obligations for which the fair value cannot be reasonably determined because the assets currently have an indeterminate life. The asset retirement obligation for these assets is reviewed regularly, and will be recorded in the first period in which the lives of the assets become determinable.

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

Deferred charges and other are primarily comprised of deferred maintenance shutdown costs and deferred financing costs.

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 seven years. Normal maintenance and repair costs are charged to expense as incurred.

Financing costs related to the issuance of long-term debt are amortized over the term of the related debt.

(f) Employee Future Benefits

The company’s employee future benefit programs consist of 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 ratably 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.

068	Suncor Energy Inc.
	2006 Annual Report

(h) Derivative Financial Instruments

The company periodically enters into derivative financial instrument 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 financial instrument 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.

These derivative contracts are initiated within the guidelines of the company’s risk management policies, which require stringent authorities for approval and commitment of contracts, designation of the contracts by management as hedges of the related transactions, and monitoring of the effectiveness of such contracts in reducing the related risks. Contract maturities are consistent with the settlement dates of the related hedged transactions.

Derivative contracts accounted for as hedges are not recognized in the Consolidated Balance Sheets. Gains or losses on these contracts, including realized gains and losses on hedging derivative contracts settled prior to maturity, are recognized in earnings and cash flows when the related sales revenues, costs, interest expense and cash flows are recognized. Gains or losses resulting from changes in the fair value of derivative contracts that do not qualify for hedge accounting are recognized in earnings and cash flows when those changes occur.

Canadian Accounting Guideline 13 (AcG 13) “Hedging Relationships” is applicable to the company’s hedging relationships. AcG 13 specifies the circumstances in which hedge accounting is appropriate, including the identification, documentation, designation and effectiveness of hedges, as well as the discontinuance of hedge accounting. The Guideline does not specify hedge accounting methods. The company believes that its hedging documentation and tests of effectiveness are prepared in accordance with the provisions of AcG 13.

The company also uses energy derivatives, including physical and financial swaps, forwards and options to earn trading revenues. These energy marketing and trading activities are accounted for at fair value.

Effective January 1, 2007, accounting for financial instruments will change significantly as outlined in Section (l) “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. 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.

The company’s Refining and Marketing – U.S.A. operations, and 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 cumulative foreign currency translation in the Consolidated Statements of Changes in Shareholders’ Equity.

(j) Stock-based Compensation Plans

Under the company’s common share option programs (see note 11), common share options are granted to executives, employees and non-employee directors.

Compensation expense is recorded in the Consolidated Statements of Earnings as operating, selling and general expense for 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 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.

Suncor Energy Inc.	069
2006 Annual Report

For common share options granted prior to January 1, 2003 (“pre-2003 options”), compensation expense is not recognized in the Consolidated Statements of Earnings. 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 over the estimated vesting periods of the respective award.

See also Section (l) “Recently Issued Canadian Accounting Standards.”

(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.

(l) Recently Issued Canadian Accounting Standards

Financial Instruments/Other Comprehensive Income/Hedges

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

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

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

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

•  Financial Assets – $26 million

•  Financial Liabilities – $13 million

•  Retained Earnings – $5 million

•  Cumulative Foreign Currency Translation – $71 million

•  Accumulated Other Comprehensive Loss – $63 million

No restatement of comparative balances is permitted.

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

Accounting Changes

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

Stock-based Compensation

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

070	Suncor Energy Inc.
	2006 Annual Report

Consolidated statements of earnings

For the years ended December 31 ($ millions)	2006		2005		2004
Revenues
Operating revenues (notes 6, 16 and 17)	13 798		9 728		8 270
Energy marketing and trading activities (note 6c)	1 582		827		432
Net insurance proceeds	436		572		—
Interest	13		2		3
	15 829		11 129		8 705
Expenses
Purchases of crude oil and products	4 723		4 184		2 867
Operating, selling and general	2 998		2 417		1 991
Energy marketing and trading activities (note 6c)	1 541		789		413
Transportation and other costs	212		152		132
Depreciation, depletion and amortization (note 1)	695		568		514
Accretion of asset retirement obligations	34		30		26
Exploration (note 17)	104		56		55
Royalties (note 4)	1 038		555		531
Taxes other than income taxes (note 17)	595		529		540
Gain on disposal of assets	(1	)	(13	)	(16	)
Project start-up costs	45		25		26
Financing expenses (income) (note 14)	39		(15	)	24
	12 023		9 277		7 103
Earnings Before Income Taxes	3 806		1 852		1 602
Provision for income taxes (note 9)
Current	20		39		69
Future	815		655		457
	835		694		526
Net Earnings	2 971		1 158		1 076
Per Common Share (dollars) (note 12)
Net earnings attributable to common shareholders
Basic	6.47		2.54		2.38
Diluted	6.32		2.48		2.33
Cash dividends	0.30		0.24		0.23

See accompanying Summary of Significant Accounting Policies and Notes.

Suncor Energy Inc.	071
2006 Annual Report

Consolidated balance sheets

As at December 31 ($ millions)	2006		2005
Assets
Current assets
Cash and cash equivalents	521		165
Accounts receivable (notes 10 and 17)	1 050		1 139
Inventories (note 15)	589		523
Income taxes receivable	33		6
Future income taxes (note 9)	109		83
Total current assets	2 302		1 916
Property, plant and equipment, net (note 2)	16 189		12 966
Deferred charges and other (note 3)	290		267
Total assets	18 781		15 149
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	7		49
Accounts payable and accrued liabilities (notes 7 and 8)	2 111		1 830
Taxes other than income taxes	40		56
Total current liabilities	2 158		1 935
Long-term debt (note 5)	2 385		3 007
Accrued liabilities and other (notes 7 and 8)	1 214		1 005
Future income taxes (note 9)	4 072		3 206
Total liabilities	9 829		9 153
Commitments and contingencies (note 10)
Shareholders’ equity
Share capital (note 11)	794		732
Contributed surplus (note 11)	100		50
Cumulative foreign currency translation	(71	)	(81	)
Retained earnings	8 129		5 295
Total shareholders’ equity	8 952		5 996
Total liabilities and shareholders’ equity	18 781		15 149

See accompanying Summary of Significant Accounting Policies and Notes.

Approved on behalf of the Board of Directors:

Richard L. George	John T. Ferguson
Director	Director

February 28, 2007

072	Suncor Energy Inc.
	2006 Annual Report

Consolidated statements of cash flows

For the years ended December 31 ($ millions)	2006		2005		2004
Operating Activities
Cash flow from operations (a)	4 533		2 476		2 013
Decrease (increase) in operating working capital
Accounts receivable	53		(477	)	(121	)
Inventories	(66	)	(63	)	(51	)
Accounts payable and accrued liabilities	87		435		201
Taxes payable	(43	)	(23	)	16
Cash flow from operating activities	4 564		2 348		2 058
Cash Used in Investing Activities (a)	(3 489	)	(3 113	)	(1 689	)
Net Cash Surplus (Deficiency) Before Financing Activities	1 075		(765	)	369
Financing Activities
Increase (decrease) in short-term debt	(42	)	19		(1	)
Net increase (decrease) in other long-term debt	(622	)	808		(635	)
Issuance of common shares under stock option plans	45		69		41
Dividends paid on common shares	(127	)	(102	)	(97	)
Deferred revenue	27		50		26
Cash flow provided by (used in) financing activities	(719	)	844		(666	)
Increase (Decrease) in Cash and Cash Equivalents	356		79		(297	)
Effect of Foreign Exchange on Cash and Cash Equivalents	—		(2	)	(3	)
Cash and Cash Equivalents at Beginning of Year	165		88		388
Cash and Cash Equivalents at End of Year	521		165		88

(a) See Schedules of Segmented Data on pages 76 and 77.

See accompanying Summary of Significant Accounting Policies and Notes.

Suncor Energy Inc.	073
2006 Annual Report

Consolidated statements of changes in shareholders’ equity

				Cumulative
				Foreign
	Share	Contributed		Currency		Retained
For the years ended December 31 ($ millions)	Capital	Surplus		Translation		Earnings
At December 31, 2003, as previously reported	604	7		(26	)	3 308
Retroactive adjustment for change
in accounting policy, net of tax (note 1)	—	—		—		(35	)
At December 31, 2003, as restated	604	7		(26	)	3 273
Net earnings	—	—		—		1 076
Dividends paid on common shares	—	—		—		(97	)
Issued for cash under stock option plans	41	—		—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	25		—		—
Foreign currency translation adjustment	—	—		(29	)	—
At December 31, 2004, as restated	651	32		(55	)	4 246
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		—		—
Foreign currency translation adjustment	—	—		(26	)	—
At December 31, 2005, as restated	732	50		(81	)	5 295
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		—		—
Foreign currency translation adjustment	—	—		10		—
Income tax benefit of stock option deductions in the U.S.	—	4		—		—
At December 31, 2006	794	100		(71	)	8 129

See accompanying Summary of Significant Accounting Policies and Notes.

074	Suncor Energy Inc.
	2006 Annual Report

Schedules of segmented data ^(a)

														Energy Marketing
		Oil Sands						Natural Gas						and Refining – Canada
For the years ended December 31 ($ millions)		2006		2005		2004		2006		2005		2004		2006		2005		2004
EARNINGS
Revenues (b)
Operating revenues		6 259		2 938		3 215		554		632		499		3 858		3 536		3 060
Energy marketing
and trading activities		—		—		—		—		—		—		1 607		827		440
Net insurance proceeds		436		572		—		—		—		—		—		—		—
Intersegment revenues (c)		712		455		425		23		47		68		—		—		—
Interest		—		—		—		1		—		—		—		—		—
		7 407		3 965		3 640		578		679		567		5 465		4 363		3 500
Expenses
Purchases of crude oil
and products		89		32		75		—		—		—		2 876		2 585		2 115
Operating, selling and general		2 149		1 432		1 179		107		93		100		432		484		418
Energy marketing
and trading activities		—		—		—		—		—		—		1 572		810		421
Transportation and other costs		162		104		88		25		22		21		6		6		3
Depreciation, depletion
and amortization		385		330		299		152		130		115		94		73		69
Accretion of asset
retirement obligations		28		24		21		5		5		4		1		1		1
Exploration		22		10		17		82		46		38		—		—		—
Royalties (note 4)		911		406		407		127		149		124		—		—		—
Taxes other than income taxes		75		51		72		3		3		2		359		338		352
(Gain) loss on disposal of assets		—		—		4		(4	)	(12	)	(19	)	3		(1	)	(2	)
Project start-up costs		38		25		26		—		—		—		2		—		—
Financing expenses (income)		—		—		—		—		—		—		—		—		—
		3 859		2 414		2 188		497		436		385		5 345		4 296		3 377
Earnings (loss) before
income taxes		3 548		1 551		1 452		81		243		182		120		67		123
Income taxes		(724	)	(575	)	(482	)	28		(88	)	(67	)	(34	)	(26	)	(43	)
Net earnings (loss)		2 824		976		970		109		155		115		86		41		80
As at December 31
TOTAL ASSETS	13 692			11 648		9 000		1 503		1 307		967		2 829		1 955		1 321

(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 2006, 2005 or 2004 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.

Suncor Energy Inc.	075
2006 Annual Report

Schedules of segmented data ^(a)  (continued)

	Refining and Marketing
	U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
EARNINGS
Revenues (b)
Operating revenues	3 123		2 619		1 494		4		3		2		13 798		9 728		8 270
Energy marketing
and trading activities	—		—		—		(25	)	—		(8	)	1 582		827		432
Net insurance proceeds	—		—		—		—		—		—		436		572		—
Intersegment revenues (c)	—		—		—		(735	)	(502	)	(493	)	—		—		—
Interest	5		2		1		7		—		2		13		2		3
	3 128		2 621		1 495		(749	)	(499	)	(497	)	15 829		11 129		8 705
Expenses
Purchases of crude oil
and products	2 477		2 048		1 171		(719	)	(481	)	(494	)	4 723		4 184		2 867
Operating, selling and general	170		167		124		140		241		170		2 998		2 417		1 991
Energy marketing
and trading activities	—		—		—		(31	)	(21	)	(8	)	1 541		789		413
Transportation and other costs	19		20		20		—		—		—		212		152		132
Depreciation, depletion
and amortization	38		23		22		26		12		9		695		568		514
Accretion of asset
retirement obligations	—		—		—		—		—		—		34		30		26
Exploration	—		—		—		—		—		—		104		56		55
Royalties (note 4)	—		—		—		—		—		—		1 038		555		531
Taxes other than income taxes	157		137		114		1		—		—		595		529		540
(Gain) loss on disposal of assets	—		—		1		—		—		—		(1	)	(13	)	(16	)
Project start-up costs	5		—		—		—		—		—		45		25		26
Financing expenses (income)	—		—		—		39		(15	)	24		39		(15	)	24
	2 866		2 395		1 452		(544	)	(264	)	(299	)	12 023		9 277		7 103
Earnings (loss) before
income taxes	262		226		43		(205	)	(235	)	(198	)	3 806		1 852		1 602
Income taxes	(94	)	(84	)	(9	)	(11	)	79		75		(835	)	(694	)	(526	)
Net earnings (loss)	168		142		34		(216	)	(156	)	(123	)	2 971		1 158		1 076
As at December 31
TOTAL ASSETS	1 379		1 235		518		(622	)	(996	)	(32	)	18 781		15 149		11 774

076	Suncor Energy Inc.
	2006 Annual Report

Schedules of segmented data ^(a) (continued)

													Energy Marketing
	Oil Sands						Natural Gas						and Refining – Canada
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
CASH FLOW BEFORE
FINANCING ACTIVITIES
Cash from (used in)
operating activities:
Cash flow from (used in) operations
Net earnings (loss)	2 824		976		970		109		155		115		86		41		80
Exploration expenses	—		—		—		52		46		38		—		—		—
Non-cash items included
in earnings
Depreciation, depletion
and amortization	385		330		299		152		130		115		94		73		69
Income taxes	724		575		482		(28	)	88		67		34		26		43
(Gain) loss on disposal of assets	—		—		4		(4	)	(12	)	(19	)	3		(1	)	(2	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		—
Other	(10	)	11		(29	)	—		5		4		—		13		(3	)
Increase (decrease) in deferred
credits and other	(21	)	(14	)	8		—		—		(1	)	—		—		1
Total cash flow from
(used in) operations	3 902		1 878		1 734		281		412		319		217		152		188
Decrease (increase) in operating
working capital	426		(270	)	24		(27	)	(5	)	(1	)	(87	)	(47	)	(11	)
Total cash from (used in)
operating activities	4 328		1 608		1 758		254		407		318		130		105		177
Cash from (used in)
investing activities:
Capital and exploration
expenditures	(2 463	)	(1 948	)	(1 119	)	(458	)	(363	)	(279	)	(487	)	(442	)	(228	)
Acquisition of Denver refineries
and related assets	—		—		—		—		—		—		—		—		—
Property loss insurance proceeds	36		44		—		—		—		—		—		—		—
Deferred maintenance
shutdown expenditures	—		(65	)	(4	)	—		(2	)	(1	)	(29	)	—		(20	)
Deferred outlays and
other investments	(2	)	(1	)	(9	)	—		—		—		1		3		(14	)
Proceeds from disposals	2		41		45		15		21		29		4		3		3
Decrease (increase) in investing
working capital	197		47		48		—		—		—		(1	)	3		61
Total cash (used in) investing activities	(2 230	)	(1 882	)	(1 039	)	(443	)	(344	)	(251	)	(512	)	(433	)	(198	)
Net cash surplus (deficiency)
before financing activities	2 098		(274	)	719		(189	)	63		67		(382	)	(328	)	(21	)

(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.

Suncor Energy Inc.	077
2006 Annual Report

Schedules of segmented data ^(a) (continued)

	Refining and Marketing
	U.S.A.						Corporate and Eliminations						Total
For the years ended December 31 ($ millions)	2006		2005		2004		2006		2005		2004		2006		2005		2004
CASH FLOW BEFORE
FINANCING ACTIVITIES
Cash from (used in)
operating activities:
Cash flow from (used in) operations
Net earnings (loss)	168		142		34		(216	)	(156	)	(123	)	2 971		1 158		1 076
Exploration expenses	—		—		—		—		—		—		52		46		38
Non-cash items included
in earnings
Depreciation, depletion
and amortization	38		23		22		26		12		9		695		568		514
Income taxes	94		84		9		(9	)	(118	)	(144	)	815		655		457
(Gain) loss on disposal of assets	—		—		1		—		—		—		(1	)	(13	)	(16	)
Stock-based compensation expense	—		—		—		53		23		25		53		23		25
Other	(16	)	(2	)	(8	)	12		(60	)	(71	)	(14	)	(33	)	(107	)
Increase (decrease) in deferred
credits and other	(3	)	—		1		(14	)	86		17		(38	)	72		26
Total cash flow from
(used in) operations	281		247		59		(148	)	(213	)	(287	)	4 533		2 476		2 013
Decrease (increase) in operating
working capital	(15	)	17		41		(266	)	177		(8	)	31		(128	)	45
Total cash from (used in)
operating activities	266		264		100		(414	)	(36	)	(295	)	4 564		2 348		2 058
Cash from (used in)
investing activities:
Capital and exploration
expenditures	(178	)	(337	)	(190	)	(27	)	(63	)	(31	)	(3 613	)	(3 153	)	(1 847	)
Acquisition of Denver refineries
and related assets	—		(62	)	—		—		—		—		—		(62	)	—
Property loss insurance proceeds	—		—		—		—		—		—		36		44		—
Deferred maintenance
shutdown expenditures	(51	)	(10	)	(7	)	—		—		—		(80	)	(77	)	(32	)
Deferred outlays and
other investments	6		1		(1	)	(2	)	(6	)	1		3		(3	)	(23	)
Proceeds from disposals	—		—		—		—		—		—		21		65		77
Decrease (increase) in investing
working capital	(52	)	23		27		—		—		—		144		73		136
Total cash (used in) investing activities	(275	)	(385	)	(171	)	(29	)	(69	)	(30	)	(3 489	)	(3 113	)	(1 689	)
Net cash surplus (deficiency)
before financing activities	(9	)	(121	)	(71	)	(443	)	(105	)	(325	)	1 075		(765	)	369

078	Suncor Energy Inc.
	2006 Annual Report

Notes to the consolidated financial statements

1. CHANGES IN ACCOUNTING POLICIES

(a) Overburden Removal Costs

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

Change in Consolidated Balance Sheets

($ millions, (decrease))	2006		2005
Deferred charges and other	(230	)	(202	)
Total assets	(230	)	(202	)
Future income tax liabilities	(77	)	(68	)
Retained earnings	(153	)	(134	)
Total liabilities and shareholders’ equity	(230	)	(202	)

Change in Consolidated Statements of Earnings

($ millions, increase/(decrease))	2006		2005		2004
Operating, selling and general	337		287		222
Depreciation, depletion and amortization	(309	)	(152	)	(206	)
Future income taxes	(9	)	(48	)	(4	)
Net earnings	(19	)	(87	)	(12	)
Per common share – basic (dollars)	(0.04	)	(0.19	)	(0.03	)
Per common share – diluted (dollars)	(0.04	)	(0.19	)	(0.03	)

(b) Non-monetary Transactions

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

Suncor Energy Inc.	079
2006 Annual Report

2. PROPERTY, PLANT AND EQUIPMENT

	2006		2005
		Accumulated		Accumulated
($ millions)	Cost	Provision	Cost	Provision
Oil Sands
Plant	7 514	1 608	6 042	1 388
Mine and mobile equipment	1 191	320	939	280
In-situ properties	1 946	147	1 608	79
Pipeline	149	34	139	30
Capital leases	38	4	30	6
Major projects in progress	2 887	—	2 484	—
Asset retirement cost	663	94	408	81
	14 388	2 207	11 650	1 864
Natural Gas
Proved properties	1 931	867	1 632	769
Unproved properties	186	21	172	23
Other support facilities and equipment	90	23	53	13
Asset retirement cost	44	7	14	6
	2 251	918	1 871	811
Energy Marketing and Refining – Canada
Refinery	1 441	529	899	481
Marketing	626	250	597	244
Major projects in progress	386	—	464	—
Asset retirement cost	13	7	11	7
	2 466	786	1 971	732
Refining and Marketing – U.S.A.
Refinery and intangible assets	826	55	244	24
Marketing	43	5	36	3
Pipeline	35	3	26	2
Major projects in progress	—	—	453	—
	904	63	759	29
Corporate	208	54	180	29
	20 217	4 028	16 431	3 465
Net property, plant and equipment		16 189		12 966

3. DEFERRED CHARGES AND OTHER

($ millions)	2006	2005
Deferred maintenance shutdown costs	143	160
Deferred government tax credits	74	20
Deferred financing costs	22	23
Other	51	64
Total deferred charges and other	290	267

080	Suncor Energy Inc.
	2006 Annual Report

4. ROYALTIES

Alberta Crown royalties 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. Firebag is treated by the Government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes. During 2004 to 2006, Firebag was subject to the minimum payment of 1% of R. However, for the rest of Oil Sands, the 2004 calendar year was a transitional year, as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed before the 25% R-C royalty applied to 2004 results.

In February 2006, we advised the Government of Alberta we would not proceed with a July 2004 claim we filed against the Crown where we were seeking to overturn the government’s decision on the royalty treatment of our Firebag in-situ operations.

During the fourth quarter of 2006, Suncor exercised its option to move our Oil Sands operations to the bitumen based royalty regime effective January 1, 2009.

Royalty expense for the company’s Oil Sands operations for the year ended December 31, 2006, was $911 million (2005 – $406 million; 2004 – $407 million).

5. LONG-TERM DEBT

A. Fixed-term Debt, Redeemable at the Option of the Company

($ millions)	2006	2005
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	583	583
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	583	583
6.70% Series 2 Medium-term Notes, due in 2011 (i)	500	500
6.80% Medium-term Notes, due in 2007 (i)	250	250
6.10% Medium-term Notes, due in 2007 (i)	150	150
	2 066	2 066
Revolving-term debt, with interest at variable rates (see B. Credit Facilities)
Commercial Paper (interest at December 31, 2006 – 4.3%; 2005 – 3.2%) (ii)	280	890
Total unsecured long-term debt	2 346	2 956
Secured long-term debt with interest rates averaging 6.6% (2005 – 5.2%)	1	1
Capital leases (iii), (iv)	38	30
Variable interest entity long-term debt – See note 10	—	20
Total long-term debt	2 385	3 007

(i)  The company entered into various interest rate swap transactions in 2004. The swap transactions result in an average effective interest rate that is different from the stated interest rate of the related underlying long-term debt instruments.

	Principal
	Swapped		Swap	Effective Interest Rate
Description of Swap Transaction	($ millions	)	Maturity	2006	2005
Swap of 6.70% Medium-term Notes to floating rates	200		2011	5.2%	4.0%
Swap of 6.80% Medium-term Notes to floating rates	250		2007	6.0%	4.6%
Swap of 6.10% Medium-term Notes to floating rates	150		2007	5.3%	4.0%

(ii)  The company is authorized to issue commercial paper to a maximum of $1,200 million having a term not to exceed 364 days. Commercial paper is supported by unutilized credit and term loan facilities (see B. Credit Facilities).

(iii)  Obligations under capital leases are as follows:

($ millions)	2006	2005
Equipment leases with interest rates between prime plus 0.5% and 12.4%
and maturity dates ranging from 2008 to 2035	38	30

Suncor Energy Inc.	081
2006 Annual Report

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

	Capital	Other Long-
($ millions)	Leases	term Debt
2007	3	681	(a)
2008	3	—
2009	3	—
2010	4	—
2011	4	500
Later years	72	1 166
Total minimum payments	89	2 347
Less amount representing imputed interest	51
Present value of obligation under capital leases	38
Long-term Debt (per cent)	2006	2005
Variable rate	37	50
Fixed rate	63	50

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

B. Credit Facilities

During 2006, a $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five-year term maturing in June 2011. The credit limit of this facility was also increased by $500 million to $2 billion. In addition, a $200million credit facility agreement was renegotiated and increased by $100 million to $300 million. As well, a $600 million credit facility agreement matured during the second quarter and was not renewed. At December 31, 2006, the company had available credit facilities of $2,330 million, of which $1,813 million was undrawn, as follows:

($ millions)
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2008	300
Facility that is fully revolving for a period of five years and expires in 2011	2 000
Facilities that can be terminated at any time at the option of the lenders	30
Total available credit facilities	2 330
Credit facilities supporting outstanding commercial paper and standby letters of credit	517
Total undrawn credit facilities	1 813

At December 31, 2006, the company had issued $237 million (2005 – $185 million) in letters of credit to various third parties and had outstanding commercial paper of $280 million (2005 – $890 million).

082	Suncor Energy Inc.
	2006 Annual Report

6. 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 change 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.

(a) Balance Sheet Financial Instruments

The company’s financial instruments recognized in the Consolidated Balance Sheets consist of cash and cash equivalents, accounts receivable, derivative contracts not accounted for as hedges, substantially all current liabilities (except for the current portions of asset retirement and pension obligations), and long-term debt.

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

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

		2006			2005
	Carrying		Fair	Carrying		Fair
($ millions)	Amount		Value	Amount		Value
Cash and cash equivalents	521		521	165		165
Accounts receivable	1 050		1 050	1 139		1 139
Current liabilities	1 987		1 987	1 826		1 826
Long-term debt
Fixed-term	2 066		2 208	2 066		2 299
Revolving-term	280		280	890		890
Other	1		1	21		21
Capital leases	38		38	30		30

The fair values of the company’s fixed and revolving-term long-term debt, capital leases, and other long-term debt were determined through comparisons to similar debt instruments.

Suncor Energy Inc.	083
2006 Annual Report

(b) Unrecognized Derivative Financial Instruments

The company is also a party to certain derivative financial instruments that are not recognized in the Consolidated Balance Sheets, as follows:

Revenue, Cost and Margin Hedges

Suncor operates in a global industry where the market price of its petroleum and natural gas products is determined based on floating benchmark indices denominated in U.S. dollars. The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude sales price variability by entering into West Texas Intermediate (WTI) derivative transactions. As at December 31, 2006, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2007 and 2008. As at December 31, 2006, the company had outstanding costless collar agreements covering 60,000 barrels per day (bpd) in 2007 and 10,000 bpd in 2008. Prices for these barrels are fixed within a range of US$51.64 to US$93.26 per barrel in 2007 and US$59.85 to US$101.06 per barrel in 2008. The company has not hedged any portion of the foreign exchange component of these forecasted cash flows.

At December 31, 2006, the company had hedged a portion of its forecasted cash flows related to natural gas production and refinery operations, as well as a portion of its Euro dollar exposure created by the anticipated purchase of equipment payable in Euros in 2007.

The financial instrument contracts do not require the payment of premiums or cash margin deposits prior to settlement. On settlement, these contracts result in cash receipts or payments by the company for the difference between the contract and market rates for the applicable dollars and volumes hedged during the contract term. Such cash receipts or payments offset corresponding decreases or increases in the company’s sales revenues or crude oil purchase costs. For collars, if market rates are not different than, or are within the range of contract prices, the options contracts making up the collar will expire with no exchange of cash. For accounting purposes, amounts received or paid on settlement are recorded as part of the related hedged sales or purchase transactions.

Contracts outstanding at December 31 were as follows:

		Average		Revenue
Revenue Hedges	Quantity	Price		Hedged		Hedge
Strategic Crude Oil	(bpd)	(US$/bbl)	(a)	(Cdn$ millions)	(b)	Period	(c)
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
As at December 31, 2004
Crude oil swaps	36 000	23		364		2005

		Average	Revenue
	Quantity	Price	Hedged	Hedge
Natural Gas	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period	(c)
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
As at December 31, 2004
Natural Gas Swaps	4 000	7	10	2005
Natural Gas Swaps	4 000	7	10	2006
Natural Gas Swaps	4 000	6	9	2007
Costless collars	10 000	8 – 9	7 – 8	2005	(f)

084	Suncor Energy Inc.
	2006 Annual Report

		Average	Margin
	Quantity	Margin	Hedged		Hedge
Margin Hedges	(bpd)	US$/bbl	(Cdn$ millions)	(b)	Period	(c)
Refined product sale and crude purchase swaps
As at December 31, 2006	—	—	—		—
As at December 31, 2005	5 100	11.69	10		2006	(g)
As at December 31, 2004	6 300	7	15		2005	(h)

		Average	Dollars
	Notional	Forward	Hedged	Hedge
Foreign Currency Hedges	(Euro millions)	Rate	(Cdn$ millions)	Period
As at December 31, 2006
Euro/Cdn forward	20.6	1.41	29.0	2007	(i)
As at December 31, 2005
Euro/Cdn forward	9.9	1.39	13.8	2006	(j)
Euro/Cdn forward	20.6	1.41	29.0	2007	(i)

(a)   Average price for crude oil swaps and 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 for convenience purposes.

(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 March 2005, inclusive.

(g)   For the period January to May 2006, inclusive.

(h)   For the period January to September 2005, inclusive.

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

(j)    Settlement for applicable forward was March 2006.

Interest Rate Hedges

The company periodically enters into interest rate swap contracts as part of its risk management strategy to manage its exposure to interest rates. The interest rate swap contracts involve an exchange of floating rate and fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense.

The notional amounts of interest rate swap contracts outstanding at December 31, 2006, are detailed in note 5, Long-term Debt.

Fair Value of Hedging Derivative Financial Instruments

The fair value of hedging derivative financial instruments is the estimated amount, based on broker quotes and/ or internal valuation models that the company would receive (pay) to terminate the contracts. Such amounts, which also represent the unrecognized and unrecorded gain (loss) on the contracts, were as follows at December 31:

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

Suncor Energy Inc.	085
2006 Annual Report

(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 trading activities are accounted for using the mark-to-market method and as such, all financial instruments are recorded at fair value at each balance sheet date. Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. The results of these activities are reported as revenue and as energy trading and marketing expenses in the Consolidated Statements of Earnings. The net pretax earnings (loss) for the years ended December 31 were as follows:

Net Pretax Earnings (Loss)

($ millions)	2006		2005		2004
Physical energy contracts trading activity	41		15		12
Financial energy contracts trading activity	(3	)	5		11
General and administrative costs	(3	)	(3	)	(4	)
Total	35		17		19

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

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

Change in Fair Value of Net Assets

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

The 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 entering into agreements with counterparties, of which substantially all are 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)	2006	2005
Derivative contracts not accounted for as hedges	16	82
Unrecognized derivative contracts accounted for as a hedge	35	30
Total	51	112

086	Suncor Energy Inc.
	2006 Annual Report

7. ACCRUED LIABILITIES AND OTHER

($ millions)	2006	2005
Asset retirement obligations (a)	704	489
Employee future benefits liability (see note 8)	170	190
Employee and director incentive plans (b)	143	110
Deferred revenue	143	140
Environmental remediation costs (c)	26	33
Other	28	43
Total	1 214	1 005

(a) Asset Retirement Obligations (ARO)

The asset retirement obligation also includes an additional $104 million in current liabilities (2005 – $54 million). 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)	2006		2005
Asset retirement obligations, beginning of year	543		476
Liabilities incurred	286		71
Liabilities settled	(54	)	(34	)
Accretion of asset retirement obligations	33		30
Asset retirement obligations, end of year	808		543

The total undiscounted amount of estimated future cash flows required to settle the obligations at December 31, 2006, was approximately $1.7 billion (2005 – $1.2 billion). The liability recognized in 2006 was discounted using the Company’s credit-adjusted risk-free rate of 5.5% (2005 – 5.6%). Payments to settle the ARO occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 35 years.

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

(b) Employee and Director Incentive Plans

Total employee and director incentive plans also include an additional $32 million in current liabilities (2005 – $4 million).

(c) Environmental Remediation Costs

Total accrued environmental remediation costs also include an additional $17 million in current liabilities (2005 – $14 million). Environmental remediation costs are obligations assumed through the purchase of the Commerce City refineries.

Suncor Energy Inc.	087
2006 Annual Report

8. 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, 2006, was $1,024 million (2005 – $889 million).

As required by government regulations, Suncor sets aside funds with an independent trustee to meet certain of these obligations. In addition, commencing in 2005, the company began to fund its unregistered supplementary pension plan and supplementary 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 2006, Plan Assets to meet the Benefit Obligation were $616 million (2005 – $479 million).

The excess of the Benefit Obligation over Plan Assets of $408 million (2005 – $410 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, commencing in 2005, 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 disburing agents of the benefits to recipients. Plan assets are managed by an employee 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 in 2004. A valuation of the Canadian plan will be performed in 2007.

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 dependents.

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.

088	Suncor Energy Inc.
	2006 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)	2006		2005		2006		2005
Change in benefit obligation
Benefit obligation at beginning of year	745		624		144		128
Service costs	44		32		5		5
Interest costs	40		38		8		6
Plan participants’ contributions	4		3		—		—
Acquisition (a)	—		1		—		1
Foreign exchange	(2	)	—		—		—
Actuarial loss	67		75		5		8
Benefits paid	(32	)	(28	)	(4	)	(4	)
Benefit obligation at end of year (b), (e)	866		745		158		144
Change in plan assets (c)
Fair value of plan assets at beginning of year	479		399		—		—
Actual return on plan assets	60		41		—		—
Employer contributions	103		61		—		—
Plan participants’ contributions	4		3		—		—
Benefits paid	(30	)	(25	)	—		—
Fair value of plan assets at end of year (e)	616		479		—		—
Net unfunded obligation	(250	)	(266	)	(158	)	(144	)
Items not yet recognized in earnings:
Unamortized net actuarial loss (d)	177		167		52		53
Unamortized past service costs	—		—		(23	)	(26	)
Accrued benefit liability	(73	)	(99	)	(129	)	(117	)
Current liability	(46	)	(37	)	(3	)	(3	)
Long-term liability	(44	)	(76	)	(126	)	(114	)
Long-term asset	17		14		—		—
Total accrued benefit liability	(73	)	(99	)	(129	)	(117	)

(a)   In 2005, in connection with the acquisition of the Colorado Refining Company, the company assumed pension obligations of $1 million and other post-retirement benefit obligations of $1 million. No pension plan assets were acquired.

(b)   Obligations are based on the following assumptions:

	Pension Benefit Obligations		Other Post-retirement
			Benefits Obligation
(per cent)	2006	2005	2006	2005
Discount rate	5.00	5.00	5.00	5.00
Rate of compensation increase	5.00	4.50	4.75	4.25

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

In order to measure the expected cost of other post-retirement benefits, a 9.5% annual rate of increase in the per capita cost of covered health care benefits was assumed for 2006 (2005 – 10%; 2004 – 11.5%). It is assumed that this rate will decrease by 0.5% annually, to 5% by 2015, and remain at that level thereafter.

Suncor Energy Inc.	089
2006 Annual Report

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

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

(c)  Pension plan assets are not the company’s assets and therefore are not included in the Consolidated Balance Sheets.

(d)  The unamortized net actuarial loss represents annually calculated differences between actual and projected plan performance. These amounts are amortized as part of the net periodic benefit cost over the expected average remaining service life of employees of 11 years for pension benefits (2005 – 11 years; 2004 – 12 years), and over the expected average future service life to full eligibility age of 10 years for other post-retirement benefits (2005 – 9 years; 2004 – 12 years).

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

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

	Pension Benefits		Other Post-retirement Benefits
($ millions)	2006	2005	2006	2005
Partially funded plans	866	745	—	—
Unfunded plans	—	—	158	144
Benefit obligation at end of year	866	745	158	144

Components of Net Periodic Benefit Cost ^(a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2006		2005		2004		2006	2005	2004
Current service costs	44		32		25		5	5	5
Interest costs	40		38		34		8	6	7
Expected return on plan assets (b)	(32	)	(28	)	(25	)	—	—	—
Amortization of net actuarial loss	28		21		19		1	1	1
Net periodic benefit cost recognized (c)	80		63		53		14	12	13

Components of Net Incurred Benefit Cost ^(a)

	Pension Benefits						Other Post-retirement Benefits
($ millions)	2006		2005		2004		2006	2005	2004
Current service costs	44		32		25		5	5	5
Interest costs	40		38		34		8	6	7
Actual (return) loss on plan assets (b)	(60	)	(41	)	(33	)	—	—	—
Actuarial (gain) loss	67		75		21		5	8	4
Net incurred benefit cost	91		104		47		18	19	16

(a)  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.

(b)  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.

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

	Pension Benefit Expense			Other Post-retirement Benefits Expense
(per cent)	2006	2005	2004	2006	2005	2004
Discount rate	5.00	5.75	6.00	5.00	5.75	6.00
Expected return on plan assets	6.50	6.75	7.00	N/A	N/A	N/A
Rate of compensation increase	4.50	4.50	4.00	4.25	4.25	4.00

090	Suncor Energy Inc.
	2006 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, 2006 and 2005.and the target allocation for 2007 are as follows:

	Target Allocation %	Plan Assets %
	2007	2006	2005
Asset Category
Equities	60	61	60
Fixed income	40	39	40
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 2007 will be $82 million, including approximately $7 million for the company’s supplemental executive and supplemental retirement plans. Expected benefit payments from all of the plans are as follows:

		Other Post-
	Pension	retirement
	Benefits	Benefits
2007	35	5
2008	38	5
2009	41	6
2010	44	6
2011	47	7
2012 – 2016	287	44
Total	492	73

Defined Contribution Pension Plan

The company has a Canadian defined contribution plan and two U.S. 401(k) savings plans, under which both the company and employees make contributions. Company contributions and corresponding expense totalled $11 million in 2006 (2005 – $10 million; 2004 – $8 million).

9. INCOME TAXES

The assets and liabilities shown on Suncor’s balance sheets are caculated 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 next page for more technical details and amounts.

Suncor Energy Inc.	091
2006 Annual Report

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:

	2006				2005				2004
($ millions)	Amount		%		Amount		%		Amount		%
Federal tax rate	1 256		33		648		35		577		36
Provincial abatement	(381	)	(10	)	(186	)	(10	)	(161	)	(10	)
Federal surtax	43		1		21		1		18		1
Provincial tax rates	395		10		213		12		188		12
Statutory tax and rate	1 313		34		696		38		622		39
Adjustment of statutory rate for future rate reductions	(146	)	(4	)	(84	)	(5	)	(84	)	(5	)
	1 167		30		612		33		538		34
Add (deduct) the tax effect of:
Crown royalties	125		3		119		6		133		8
Resource allowance (a)	(42	)	(1	)	(48	)	(2	)	(69	)	(4	)
Large corporations tax	2		—		23		1		18		1
Tax rate changes on opening future income taxes (b)	(419	)	(11	)	—		—		(53	)	(3	)
Attributed Canadian royalty income	(23	)	(1	)	(24	)	(1	)	(29	)	(2	)
Stock-based compensation	18		1		8		—		8		—
Assessments and adjustments	(9	)	—		7		—		—		—
Capital gains	—		—		(6	)	—		(18	)	(1	)
Other	16		—		3		—		(2	)	—
Income taxes and effective rate	835		21		694		37		526		33

(a)	The resource allowance is 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.
(b)	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.
	Effective April 1, 2004, the Alberta provincial corporate tax rate decreased by 1%. In 2003, the Ontario government substantively enacted a general corporate tax rate and manufacturing and processing tax rate increase of 1.5% and 1%, respectively, effective January 1, 2004. Accordingly, in 2004, the company revalued its future income tax liabilities and recognized a decrease in future income tax expense of $53 million.

In 2006, net income tax payments totalled $36 million (2005 – $77 million; 2004 – $50 million).

092	Suncor Energy Inc.
	2006 Annual Report

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

	2006			2005
($ millions)	Current	Non-current		Current		Non-current
Future income tax assets:
Employee future benefits	12	—		7		—
Asset retirement obligations	32	—		19		—
Inventories	59	—		67		—
Other	6	—		(10	)	—
	109	—		83		—
Future income tax liabilities:
Excess of book values of assets over tax values	—	4 413		—		3 490
Deferred maintenance shutdown costs	—	43		—		51
Employee future benefits	—	(88	)	—		(87	)
Asset retirement obligations	—	(203	)	—		(162	)
Attributed Canadian royalty income	—	(93	)	—		(86	)
	—	4 072		—		3 206

10. 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, 2006, future minimum amounts payable under these leases and agreements are as follows:

	Pipeline
	Capacity and		Operating
($ millions)	Energy Services	(1)	Leases
2007	242		37
2008	256		32
2009	261		28
2010	264		24
2011	266		20
Later years	3 796		120
	5 085		261

(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.

Suncor Energy Inc.	093
2006 Annual Report

(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 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$1.4 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. The excess coverage of US$1.0 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, effective January 1, 2006, the excess coverage has a ceiling of US$40 WTI and effective January 1, 2007, the excess coverage has a lost production maximum of 150,000 barrels per day in addition to the US$40 WTI ceiling. In addition to this coverage, in December 2005, Suncor formed a self-insurance company which offers business interruption coverage for oil sands with a limit of $150 million and a deductible of the greater of 20 days or US$30 million.

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

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

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

At December 31, 2006, the company had various off-balance sheet arrangements with Variable Interest Entities (VIEs) and 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 (2005 – $340 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, 2006, $170 million (2005 – $340 million) in outstanding accounts receivable had been sold under the program. Although the company does not believe it has any significant exposure to credit losses, under the recourse provisions, the company provided indemnification against potential credit losses for certain counterparties. This indemnification did not exceed $72 million in 2006 and no contingent liability or earnings impact have been recorded for this indemnification as 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, 2006, were $170 million and approximately $623 million, respectively. The company recorded an after-tax loss of approximately $2 million on the securitization program in 2006 (2005 – $4 million; 2004 – $2 million).

In 1999, the company entered into an equipment sale and leaseback arrangement with a VIE for proceeds of $30 million. The VIE’s sole asset is the equipment sold to it and leased back by the company. The VIE was consolidated effective January 1, 2005. The initial lease term 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, 2006, the VIE did not have any assets or liabilities.

The company has agreed to indemnify holders of the 7.15% notes, the 5.95% notes and the company’s credit facility lenders (see note 5) 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.

094	Suncor Energy Inc.
	2006 Annual Report

11. 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.

(b) Issued:	Common Shares
	Number		Amount
	(thousands	)	($ millions	)
Balance as at December 31, 2003	451 184		604
Issued for cash under stock option plans	2 880		41
Issued under dividend reinvestment plan	177		6
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 options plan	2 147		52
Issued under dividend reinvestment plan	132		10
Balance as at December 31, 2006	459 944		794

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:

(i) EXECUTIVE STOCK PLAN Under this plan, the company granted 538,000 common share options in 2006 (2005 – 518,000; 2004 – 1,346,000) to non-employee directors and certain executives and other senior employees of the company. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted have a 10-year life and vest annually over a three-year period.

(ii) SUNSHARE PERFORMANCE STOCK OPTION PLAN During 2006, the company granted 1,637,000 options (2005 – 1,253,000; 2004 – 1,742,000) 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, 2,062,000 SunShare options vested, representing approximately 25% of the then outstanding unvested options 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. The remaining 50% of the outstanding, unvested SunShare options may vest on April 30, 2008 if the final predetermined performance criterion is met. If the performance criterion is not met, the unvested options that have not previously expired or been cancelled will automatically vest on January 1, 2012. Management believes that it is highly likely the final performance criterion will be met and that all unvested SunShare options at April 30, 2008 will vest. During the fourth quarter of 2006, stock-based compensation expense was adjusted to reflect this assumption.

Suncor Energy Inc.	095
2006 Annual Report

(iii) KEY CONTRIBUTOR STOCK OPTION PLAN In 2004, the Board of Directors approved the establishment of the new Key Contributor stock option plan, under which 5,200,000 options were made available for grant to non-insider senior managers and key employees. Under this plan, the company granted 1,050,000 common share options in 2006 (2005 – 901,000; 2004 – nil) to senior managers and key employees. The exercise price of an option is equal to the market value of the common shares at the date of grant. Options granted have a 10-year life and vest annually over a three-year period.

(iv) DEFERRED SHARE UNITS (DSUs) The company had 1,170,000 DSUs outstanding at December 31, 2006 (1,190,000 at December 31, 2005). 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 2006, 59,000 DSUs were redeemed for cash consideration of $5 million (2005 – 81,000 redeemed for cash consideration of $5 million; 2004 – no redemption). 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, 2006, the total liability related to the DSUs was $107 million (2005 – $87 million), of which $2 million (2005 – $4 million) was classified as current.

During 2006, total pretax compensation expense related to DSU’s was $25 million (2005 – $39 million; 2004 – $12 million).

(v) PERFORMANCE SHARE UNITS (PSUs) During 2006, the company issued 397,000 PSUs (2005 – 453,000; 2004 – 354,000) 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 2006 was $42 million (2005 – $21 million; 2004 – $5 million).

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

					Weighted-
			Range of		average
	Number		Exercise Prices		Exercise Price
	(thousands	)	Per Share ($	)	Per Share ($	)
Outstanding, December 31, 2003	21 016		4.11 – 29.85		21.69
Granted	3 088		30.63 – 42.02		34.52
Exercised	(2 880	)	4.11 – 40.67		13.94
Cancelled	(537	)	23.93 – 41.38		28.71
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	)	5.28 – 61.92		20.99
Cancelled	(471	)	25.00 – 96.10		46.66
Outstanding, December 31, 2006	19 809		7.77 – 101.79		38.48
Exercisable, December 31, 2006	8 627		7.77 – 94.08		24.06

096	Suncor Energy Inc.
	2006 Annual Report

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)	2006	2005	2004
	7 970	10 724	4 342

The following table is an analysis of outstanding and exercisable common share options as at December 31, 2006:

			Outstanding			Exercisable
			Weighted-	Weighted-				Weighted-
	Number		average Remaining	average Exercise		Number		average Exercise
Exercise Prices ($)	(thousands	)	Contractual Life	Price Per Share ($	)	(thousands	)	Price Per Share ($	)
7.77 – 10.13	577		2	10.01		577		10.01
12.28 – 21.35	2 329		3	15.65		2 329		15.65
23.93 – 30.53	9 604		5	27.16		4 507		26.46
32.24 – 43.65	3 130		7	37.88		1 161		36.86
45.51 – 77.39	1 099		6	57.99		41		53.14
80.00 – 101.79	3 070		7	90.20		12		92.74
Total	19 809		6	38.48		8 627		24.06

(vi) FAIR VALUE OF OPTIONS GRANTED The fair values of all common share options granted are estimated as at the grant date using the Black-Scholes option-pricing model. The weighted-average fair values of the options granted during the year and the weighted-average assumptions used in their determination are as noted below:

	2006	2005	2004
Annual dividend per share	$0.30	$0.24	$0.23
Risk-free interest rate	4.08%	3.69%	3.79%
Expected life	5 years	6 years	6 years
Expected volatility	29%	28%	29%
Weighted-average fair value per option	$29.17	$15.42	$12.02

Stock-based compensation expense recognized for the year ended December 31, 2006, related to stock option plans was $53 million (2005 – $23 million; 2004 – $25 million).

Common share options granted prior to January 1, 2003, are not recognized as compensation expense in the Consolidated Statements of Earnings. 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)	2006	2005	2004
Net earnings attributable to common shareholders – as reported	2 971	1 158	1 076
Less: compensation cost under the fair value method for pre-2003 options	15	13	47
Pro forma net earnings attributable to common shareholders for pre-2003 options	2 956	1 145	1 029
Basic earnings per share
As reported	6.47	2.54	2.38
Pro forma	6.44	2.51	2.27
Diluted earnings per share
As reported	6.32	2.48	2.33
Pro forma	6.29	2.46	2.23

Suncor Energy Inc.	097
2006 Annual Report

12. EARNINGS PER COMMON SHARE

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

($ millions)	2006	2005	2004
Net earnings attributable to common shareholders	2 971	1 158	1 076
(millions of common shares)
Weighted-average number of common shares	459	456	453
Dilutive securities:
Shares issued under stock-based compensation plans	11	10	9
Weighted-average number of diluted common shares	470	466	462
(dollars per common share)
Basic earnings per share (a)	6.47	2.54	2.38
Diluted earnings per share (b)	6.32	2.48	2.33

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.

13. 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 – U.S.A. segment in the Schedules of Segmented Data.

14. FINANCING EXPENSES (INCOME)

($ millions)	2006		2005		2004
Interest on debt	150		151		157
Capitalized interest	(129	)	(119	)	(62	)
Net interest expense	21		32		95
Foreign exchange (gain) on long-term debt	—		(37	)	(82	)
Other foreign exchange (gain) loss	18		(10	)	11
Total financing expenses (income)	39		(15	)	24

Cash interest payments in 2006 totalled $146 million (2005 – $149 million; 2004 – $152 million).

098	Suncor Energy Inc.
	2006 Annual Report

15. INVENTORIES

($ millions)	2006	2005
Crude oil	249	279
Refined products	200	124
Materials, supplies and merchandise	140	120
Total	589	523

The replacement cost of crude oil and refined product inventories exceeded their LIFO carrying value by $243 million (2005 – $202 million) as at December 31, 2006.

During 2006, the company recorded a pretax gain of $6 million related to a permanent reduction in LIFO inventory layers (2005 – $16 million pretax gain).

16. 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)	2006	2005	2004
Operating revenues
Sales to Energy Marketing and Refining – Canada segment joint ventures:
Refined products	294	327	320
Petrochemicals	136	279	272

The company has supply agreements with two Energy Marketing and Refining – Canada segment joint ventures for the sale of refined products. The company also has a supply agreement with an Energy Marketing and Refining – Canada segment joint venture for the sale of petrochemicals.

At December 31, 2006, amounts due from Energy Marketing and Refining – Canada segment joint ventures were $20 million (2005 – $22 million).

Sales to and balances with Energy Marketing and Refining – Canada segment joint ventures are established and agreed to by the various parties and approximate fair value.

Suncor Energy Inc.	099
2006 Annual Report

17. SUPPLEMENTAL INFORMATION

($ millions)	2006	2005	2004
Export sales (a)	810	648	693
Exploration expenses
Geological and geophysical	51	22	33
Other	1	1	1
Cash costs	52	23	34
Dry hole costs	52	33	21
Cash and dry hole costs (b)	104	56	55
Leasehold impairment (c)	2	13	8
	106	69	63
Taxes other than income taxes
Excise taxes (d)	538	482	496
Production, property and other taxes	57	47	44
	595	529	540
Allowance for doubtful accounts	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 exploration expenses in the Consolidated Statements of Earnings.

(c) Included in depreciation, depletion and amortization in the Consolidated Statements of Earnings.

(d) Included in operating revenues in the Consolidated Statements of Earnings.

18. 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	2006		2005		2004
Net earnings as reported, Canadian GAAP		2 971		1 158		1 076
Adjustments
Derivatives and hedging activities	(a)	11		83		92
Stock-based compensation	(b)	(19	)	(26	)	(10	)
Income tax expense		(3	)	(28	)	(27	)
Net earnings from continuing operations, U.S. GAAP		2 960		1 187		1 131
Cumulative effect of change in accounting principles, net of income taxes of $2 (2005 – $nil; 2004 – $nil)	(b)	(4	)	—		—
Net earnings, U.S. GAAP		2 956		1 187		1 131
Derivatives and hedging activities, net of income taxes of $3 (2005 – $70; 2004 – $35)	(a)	6		140		(67	)
Minimum pension liability, net of income taxes of $20 (2005 – $8; 2004 – $3)	(c)	39		(15	)	5
Unfunded pension obligation, net of income taxes of $60	(c)	(127	)	—		—
Foreign currency translation adjustment	(d)	10		(26	)	(29	)
Comprehensive income, U.S. GAAP		2 884		1 286		1 040

per common share (dollars)	2006	2005	2004
Net earnings per share from continuing operations, U.S. GAAP
Basic	6.45	2.60	2.50
Diluted	6.29	2.55	2.45
Net earnings per share, U.S. GAAP
Basic	6.44	2.60	2.50
Diluted	6.29	2.55	2.45

100	Suncor Energy Inc.
	2006 Annual Report

The application of U.S. GAAP would have the following effects on the Consolidated Balance Sheets as reported:

		December 31, 2006				December 31, 2005
		As		U.S.		As		U.S.
	Notes	Reported		GAAP		Reported		GAAP
Current assets		2 302		2 302		1 916		1 916
Property, plant and equipment, net		16 189		16 189		12 966		12 966
Deferred charges and other	(a,c)	290		316		267		298
Total assets		18 781		18 807		15 149		15 180
Current liabilities		2 158		2 158		1 935		1 935
Long-term borrowings	(a)	2 385		2 398		3 007		3 029
Accrued liabilities and other	(b,c)	1 214		1 430		1 005		1 092
Future income taxes	(a,c)	4 072		4 002		3 206		3 179
Share capital	(b)	794		842		732		780
Contributed surplus	(b)	100		153		50		88
Cumulative foreign currency translation	(d)	(71	)	—		(81	)	—
Retained earnings	(a,b)	8 129		8 026		5 295		5 207
Accumulated other comprehensive income	(a,c,d)	—		(202	)	—		(130	)
Total liabilities and shareholders’ equity		18 781		18 807		15 149		15 180

(a) Derivative Financial Instruments

The company accounts for its derivative financial instruments under Canadian GAAP as described in note 6. Financial Accounting Standards Board Statement (Statement) 133 “Accounting for Derivative Instruments and Hedging Activities,” as amended by Statements 138 and 149 (the Standards), establishes U.S. GAAP accounting and reporting standards for derivative instruments, including certain derivative instruments embedded in other contracts, and for hedging activities. Generally, all derivatives, whether designated in hedging relationships or not, and excluding 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 each period are recognized in the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income (OCI) each period and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Accordingly, 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 earnings statement caption as the hedged item.

The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges is based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

Commodity Price Risk

As described in note 6, Suncor manages crude price variability by entering into WTI derivative transactions and has historically, in certain instances, combined U.S. dollar WTI derivative transactions and Canadian/U.S. foreign exchange derivative contracts. As at December 31, 2006, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity price risk for 2007 and 2008.

U.S. GAAP requires the company to consider all cash flows arising from forecasted Canadian dollar denominated crude oil sales when measuring the ineffectiveness of its cash flow hedges. In periods of significant Canadian/U.S. dollar foreign exchange fluctuations, material hedge ineffectiveness can result from unhedged foreign exchange exposures. This ineffectiveness arises despite the company’s assessment that its U.S. dollar WTI hedging instruments are highly effective in achieving offsetting changes in cash flows attributable to its forecasted Canadian dollar denominated crude oil sales.

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 will not be recognized for Canadian GAAP purposes until the related forecasted sales occur.

Suncor Energy Inc.	101
2006 Annual Report

Interest Rate Risk

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest-bearing debt. At December 31, 2006, the company had interest rate derivatives classified as fair value hedges outstanding for up to five years relating to fixed rate debt.

Non-designated Hedging Instruments

In 1999, the company sold inventory and subsequently entered into a derivative contract with an option to repurchase the inventory at the end of five years. The company realized an economic benefit as a result of liquidating a portion of its inventory. The derivative did not qualify for hedge accounting as the company did not have purchase price risk associated with the repurchase of the inventory. This derivative did not represent a U.S. GAAP difference as the company recorded this derivative at fair value for Canadian purposes. The inventory was repurchased in 2004.

Accumulated OCI 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)	2006		2005
OCI attributable to derivatives and hedging activities, beginning of the period, net of income taxes of $1 (2005 – $69)	2		(138	)
Current period net changes arising from cash flow hedges, net of income taxes of $4 (2005 – $2)	9		(3	)
Net hedging losses at the beginning of the period reclassified to earnings during the period, net of income taxes of $1 (2005 – $72)	(3	)	143
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $4 (2005 – $1)	8		2

For the year ended December 31, 2006, assets increased by $26 million and liabilities increased by $13 million as a result of recording all derivative instruments at fair value in accordance with U.S. GAAP.

The earnings gain associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the period was $5 million, net of income taxes of $3 million (2005 – loss of $3 million, net of income taxes of $2 million; 2004 – loss of $130 million, net of income taxes of $66 million). The company estimates that $2 million of after-tax hedging gains will be reclassified from OCI to current period earnings within the next 12 months as a result of forecasted sales occurring.

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; 2004 – increased net earnings of $65 million, net of income taxes of $27 million) to reflect the impact of the above items.

(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. SFAS 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 SFAS 123(R), our PSUs for U.S. GAAP have been measured using a Monte Carlo Simulation approach to determine fair value. This change results in a cumulative effect of a change in accounting policy of $4 million, net of income taxes of $2 million. The impact on net earnings for the year ended December 31, 2006, is an increase in stock-based compensation expense of $3 million, 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. SFAS 123(R) requires the immediate recognition of expense related to the unvested portion of the company’s pre-2003 options. This resulted in an increase to stock-based compensation expense of $15 million (there was no impact on income taxes) for the year ended December 31, 2006.

102	Suncor Energy Inc.
	2006 Annual Report

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

In September 2006, FASB issued SFAS 158 “Employers Accounting for Defined Benefit and Other Post-retirement Plans.” The standard requires the recognition of the overfunded or underfunded 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 tax. This standard has been applied prospectively effective December 31, 2006, as retrospective application is not permitted.

For the current year up to the adoption of SFAS 158 on December 31, 2006, and for prior year comparative balances previously disclosed under U.S. GAAP, recognition of an additional minimum pension liability is required when the accumulated benefit obligation exceeds the fair value of plan assets to the extent that such excess is 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 is required under Canadian GAAP. As required under SFAS 158, the minimum pension liability adjustment from prior years is reversed in the current year.

At December 31, 2006, the company would have recognized a minimum pension liability of $35 million (2005 – $87 million), an intangible asset of $16 million (2005 – $9 million) and an accumulated other comprehensive loss of $12 million, net of income taxes of $7 million (2005 – $51 million, net of income taxes of $27 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; 2004 – an increase in other comprehensive income of $5 million, net of income taxes of $3 million).

Under U.S. GAAP, the impact on future benefit obligations recorded to the balance sheet as at December 31, 2006, as a result of adopting SFAS 158 are as follows:

•   Unfunded pension benefits – $177 million

•   Unfunded other post-retirement benefits – $29 million

In total, other comprehensive income was decreased by $139 million, net of income taxes at December 31, 2006.

Accumulated OCI and U.S. GAAP Net Earnings Impacts

($ millions)	2006		2005
OCI attributable to defined benefit pension and other post-retirement plans, beginning of period, net of income taxes of $27 million (2005 – $19 million)	(51	)	(36	)
Minimum pension liability, net of income taxes of $20 million (2005 – $8 million)	39		(15	)
Reversal of minimum pension liability upon adoption of SFAS 158, net of income taxes of $7 million	12		—
Unamortized net actuarial loss, net of income taxes of $74 million	(155	)	—
Unamortized past service costs, net of income taxes of $7 million	16		—
OCI attributable to defined benefit pension and other post-retirement plans, end of period, net of income taxes of $67 million (2005 – $27 million)	(139	)	(51	)

Total amount included in accumulated OCI expected to be recognized as components of net periodic benefit cost during 2007 are as follows:

•   Amortization of net actuarial loss – $29 million

•   Amortization of past service costs – $nil

(d) Cumulative Foreign Currency Translation

Under Canadian GAAP, foreign currency gains of $10 million (2005 – losses of $26 million; 2004 – losses of $29 million) arising on translation of the company’s U.S. based foreign operations have been recorded directly to shareholders’ equity. Under U.S. GAAP, these foreign currency translation losses would be 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

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2006 Annual Report

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)	2006		2005		2004
Balance, beginning of year	15		5		1
Additions pending determination of proved reserves	21		14		5
Charged to dry hole expense	—		(2	)	—
Reclassifications to proved properties	(13	)	(2	)	(1	)
Balance, end of year	23		15		5
Capitalized for a period greater than one year ($ millions)	2		1		—
Number of projects that have exploratory well costs capitalized for a period greater than 12 months	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 statements of earnings. 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 downstream operating segments.

In addition, the R&M segment sells finished product and buys 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, are recorded at fair value in “revenue” and “purchases of crude oil and products” in the statements of income in accordance with the consensus for Issue 2 in EITF 04-13.

The purchase/sale of contract amounts included in revenue for 2006, 2005 and 2004 are shown below.

($ millions)	2006	2005	2004
Consolidated revenues	15 829	11 129	8 705
Amounts included in revenues for purchase/sale contracts with the same counterparty (1)	5	16	7

(1) Associated costs are in “purchases of crude oil and products.”

Recently Issued Accounting Standards

In September 2006, FASB issued SFAS 157 “Fair Value Measurements.” The standard, effective January 1, 2008, establishes a recognized framework for measuring fair value, and expands disclosures 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.

In June 2006, FASB issued FIN 48 “Accounting for Uncertainty in Income Taxes.” The standard, effective January 1, 2007, requires recognition of uncertain tax positions only where positions are determined to be more likely than not, defined as greater than 50%, to be sustained on audit. All tax positions will be required to meet the recognition threshold as of the effective date of this standard, with the cumulative effect of application shown as an adjustment to the opening balance of retained earnings. The effect of this standard has not yet been determined.

104	Suncor Energy Inc.
	2006 Annual Report

Quarterly summary (unaudited)

FINANCIAL DATA

									Total										Total
			For the Quarter Ended						Year				For the Quarter Ended						Year
	Mar		June		Sept		Dec				Mar		June		Sept		Dec
	31		30		30		31				31		30		30		31
($ millions except per share amounts)	2006		2006		2006		2006		2006		2005		2005		2005		2005		2005
Revenues	3 858		4 070		4 114		3 787		15 829		2 074		2 385		3 149		3 521		11 129
Net earnings (loss)
Oil Sands	720		1 109		583		412		2 824		83		85		225		583		976
Natural Gas	42		60		12		(5	)	109		26		27		24		78		155
Energy Marketing
and Refining – Canada	18		63		17		(12	)	86		(3	)	5		17		22		41
Refining and Marketing – U.S.A. (c)	(2	)	57		70		43		168		6		31		50		55		142
Corporate and eliminations	(65	)	(71	)	—		(80	)	(216	)	(45	)	(65	)	(1	)	(45	)	(156	)
	713		1 218		682		358		2 971		67		83		315		693		1 158
Per common share
Net earnings attributable
to common shareholders
Basic	1.56		2.65		1.48		0.78		6.47		0.15		0.18		0.69		1.52		2.54
Diluted	1.52		2.59		1.45		0.76		6.32		0.14		0.18		0.67		1.48		2.48
Cash dividends	0.06		0.08		0.08		0.08		0.30		0.06		0.06		0.06		0.06		0.24
Cash flow from (used in) operations
Oil Sands	1 209		1 099		926		668		3902		248		210		441		979		1 878
Natural Gas	100		65		68		48		281		83		81		104		144		412
Energy Marketing and Refining – Canada	51		102		51		13		217		22		26		44		60		152
Refining and Marketing – U.S.A. (c)	—		96		118		67		281		18		52		82		95		247
Corporate and eliminations	(46	)	(42	)	(10	)	(50	)	(148	)	(77	)	(64	)	(20	)	(52	)	(213	)
	1 314		1 320		1 153		746		4 533		294		305		651		1 226		2 476

OPERATING DATA
OIL SANDS
(thousands of barrels per day)
Production (1)
Total operations	264.4	267.3	242.8	266.4	260.0	139.9	128.2	148.2	267.7	171.3
Firebag	27.4	35.0	37.2	35.1	33.7	18.7	8.7	23.0	26.0	19.1
Sales
Light sweet crude oil	119.2	124.7	84.9	113.7	110.5	75.3	48.3	69.9	108.6	73.3
Diesel	35.1	32.9	20.7	24.0	28.2	11.8	9.0	10.6	30.7	15.6
Light sour crude oil	121.0	99.2	125.8	126.8	118.2	38.5	54.2	41.7	104.2	59.8
Bitumen	—	8.5	6.6	9.7	6.2	18.4	9.6	22.3	7.2	16.6
	275.3	265.3	238.0	274.2	263.1	144.0	121.1	144.5	250.7	165.3

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2006 Annual Report

Quarterly summary (unaudited) (continued)

OPERATING DATA (continued)

					Total					Total
	For the Quarter Ended				Year	For the Quarter Ended				Year
	Mar	June	Sept	Dec		Mar	June	Sept	Dec
	31	30	30	31		31	30	30	31
	2006	2006	2006	2006	2006	2005	2005	2005	2005	2005
OIL SANDS (continued)
Average sales price (2)
(dollars per barrel)
Light sweet crude oil	69.00	78.27	78.11	64.51	71.98	45.41	39.20	52.08	55.96	49.93
Other (diesel, light sour crude oil and bitumen)	63.28	72.75	68.60	57.91	65.17	47.31	50.47	59.70	63.84	56.90
Total	65.75	75.34	71.99	60.65	68.03	46.44	45.98	56.01	60.42	53.81
Total (a)	65.75	75.34	71.99	60.65	68.03	54.80	57.24	67.95	66.68	62.68
Cash operating costs and total operating costs – Total Operations
(dollars per barrel sold rounded to the nearest $0.05)
Cash costs	15.55	15.65	21.00	22.65	18.70	20.55	23.50	21.65	16.20	19.60
Natural gas	3.45	2.55	2.60	3.00	2.90	5.40	3.60	6.00	4.65	4.90
Imported bitumen	0.05	0.10	0.10	—	0.10	0.10	—	—	0.05	0.05
Cash operating costs (3)	19.05	18.30	23.70	25.65	21.70	26.05	27.10	27.65	20.90	24.55
Firebag start-up costs	0.90	—	—	—	0.20	—	—	—	0.30	0.10
Total cash operating costs (4)	19.95	18.30	23.70	25.65	21.90	26.05	27.10	27.65	21.20	24.65
Depreciation, depletion and amortization	3.90	3.80	4.30	4.25	4.05	6.25	6.75	6.10	3.60	5.30
Total operating costs (5)	23.85	22.10	28.00	29.90	25.95	32.30	33.85	33.75	24.80	29.95
Cash operating costs and total operating costs – In-situ Bitumen Production Only (excluding upgrading costs)
Cash costs	5.70	8.50	5.55	8.05	8.95	8.90	21.50	7.55	6.70	9.15
Natural gas	7.70	8.15	7.60	9.90	8.35	10.10	16.40	13.25	13.80	13.05
Cash operating costs (6)	13.40	16.65	13.15	17.95	17.30	19.00	37.90	20.80	20.50	22.20
Firebag start-up costs	8.50	—	—	—	1.70	—	—	—	2.90	1.00
Total cash operating costs (7)	21.90	16.65	13.15	17.95	19.00	19.00	37.90	20.80	23.40	23.20
Depreciation, depletion and amortization	6.90	3.75	5.55	6.20	5.55	4.75	7.60	4.25	4.60	4.90
Total operating costs (8)	28.80	20.40	18.70	24.15	24.55	23.75	45.50	25.05	28.00	28.10
NATURAL GAS
Gross production (b)
Natural gas
(millions of cubic feet per day)	196	189	191	192	191	191	175	200	193	190
Natural gas liquids
(thousands of barrels per day)	2.4	2.6	2.1	2.1	2.3	3.0	2.2	2.2	2.3	2.4
Crude oil
(thousands of barrels per day)	0.8	0.9	0.7	0.5	0.7	0.9	1.0	0.7	0.6	0.8
Total (barrels of oil equivalent
per day at 6:1 for natural gas)	35.9	35.1	34.6	34.7	34.8	35.7	32.4	36.3	35.0	34.8
Average sales price (2)
Natural gas
(dollars per thousand cubic feet)	9.03	6.38	6.33	6.55	7.15	6.81	7.29	8.32	11.66	8.57
Natural gas (a) (dollars per
thousand cubic feet)	8.75	6.22	6.13	6.40	6.95	6.74	7.26	8.34	11.83	8.59
Natural gas liquids
(dollars per barrel)	51.75	60.14	53.11	44.20	44.96	38.32	52.52	58.00	57.85	50.70
Crude oil – conventional
(dollars per barrel)	60.30	74.18	84.95	51.20	74.83	61.40	63.86	63.77	72.60	64.85

106	Suncor Energy Inc.
	2006 Annual Report

Quarterly summary (unaudited) (continued)

OPERATING DATA (continued)

					Total					Total
	For the Quarter Ended				Year	For the Quarter Ended				Year
	Mar	June	Sept	Dec		Mar	June	Sept	Dec
	31	30	30	31		31	30	30	31
	2006	2006	2006	2006	2006	2005	2005	2005	2005	2005
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)	15.3	15.4	15.2	14.9	15.1	15.1	16.1	15.6	14.3	15.2
Utilization of refining capacity (%)	86	89	85	51	78	91	100	96	95	95
REFINING AND MARKETING – U.S.A. (c)
Refined product sales (thousands of cubic metres per day)	11.3	16.2	16.2	14.2	14.4	10.1	12.6	17.3	14.5	13.7
Utilization of refining capacity (%)	65	102	104	96	92	96	102	104	91	98

(a)Excludes the impact of hedging activities.

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

(c)Refining and Marketing – U.S.A reflects results of operations from assets acquired May 31, 2005.

Definitions

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

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2006 Annual Report

Five-year financial summary (unaudited)

($ millions except for ratios)	2006		2005	(a)	2004		2003	(a)	2002
Revenues
Oil Sands	7 407		3 965		3 640		3 101		2 655
Natural Gas	578		679		567		512		339
Energy Marketing and Refining – Canada	5 465		4 363		3 500		2 936		2 508
Refining and Marketing – U.S.A.	3 128		2 621		1 495		515		—
Corporate and eliminations	(749	)	(499	)	(497	)	(453	)	(431	)
	15 829		11 129		8 705		6 611		5 071
Net earnings (loss)
Oil Sands	2 824		976		970		895		804
Natural Gas	109		155		115		120		34
Energy Marketing and Refining – Canada	86		41		80		53		61
Refining and Marketing – U.S.A.	168		142		34		18		—
Corporate and eliminations	(216	)	(156	)	(123	)	14		(156	)
	2 971		1 158		1 076		1 100		743
Cash flow from (used in) operations
Oil Sands	3 902		1 878		1 734		1 794		1 475
Natural Gas	281		412		319		298		164
Energy Marketing and Refining – Canada	217		152		188		164		112
Refining and Marketing – U.S.A.	281		247		59		34		—
Corporate and eliminations	(148	)	(213	)	(287	)	(250	)	(358	)
	4 533		2 476		2 013		2 040		1 393
Capital and exploration expenditures
Oil Sands	2 463		1 948		1 119		953		618
Natural Gas	458		363		279		184		163
Energy Marketing and Refining – Canada	487		442		228		122		60
Refining and Marketing – U.S.A.	178		337		190		31		—
Corporate	27		63		31		32		37
	3 613		3 153		1 847		1 322		878
Total assets	18 781		15 149		11 774		10 489		8 978
Capital employed (b)
Short-term and long-term debt, less cash and cash equivalents	1 871		2 891		2 159		2 577		3 204
Shareholders’ equity	8 952		5 996		4 874		3 858		2 838
	10 823		8 887		7 033		6 435		6 042
Less capitalized costs related to major projects in progress	(2 476	)	(2 175	)	(1 467	)	(1 122	)	(511	)
	8 347		6 712		5 566		5 313		5 531
Total Suncor employees (number at year-end)	5 766		5 152		4 605		4 231		3 422

108	Suncor Energy Inc.
	2006 Annual Report

Five-year financial summary (unaudited) (continued)

	2006	2005	(a)	2004	2003	(a)	2002
Dollars per common share
Net earnings attributable to common shareholders	6.47	2.54		2.38	2.45		1.66
Cash dividends	0.30	0.24		0.23	0.1925		0.17
Cash flow from operations	9.87	5.43		4.44	4.54		3.11
Ratios
Return on capital employed (%) (b), (c)	40.6	19.7		18.9	18.7		15.1
Return on capital employed (%) (d)	30.4	14.3		16.0	16.3		14.2
Return on shareholders’ equity (%) (e)	39.7	21.3		24.6	32.9		29.8
Debt to debt plus shareholders’ equity (%) (f)	21.1	33.8		31.6	43.5		53.2
Net debt to cash flow from operations (times) (g)	0.4	1.2		1.1	1.3		2.3
Interest coverage – cash flow basis (times) (h)	30.5	16.9		13.7	11.9		8.1
Interest coverage – net earnings basis (times) (i)	25.5	12.5		10.8	10.5		6.4

(a)	Refining and Marketing – U.S.A. reflects the results of operations since acquisitions on August 1, 2003 and May 31, 2005.
(b)	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).
(c)	Net earnings adjusted for after-tax financing expenses (income) for the 12 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 58 of Management’s Discussion and Analysis.
(d)	If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e)	Net earnings as a percentage of average shareholders’ equity. Average shareholders’ equity is the sum of total shareholders’ equity at the beginning and end of the year divided by two.
(f)	Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders’ equity.
(g)	Short-term debt plus long-term debt less cash and cash equivalents; divided by cash flow from operations for the year then ended.
(h)	Cash flow from operations plus current income taxes and interest expense; divided by the sum of interest expense and capitalized interest.
(i)	Net earnings plus income taxes and interest expense; divided by the sum of interest expense and capitalized interest.

Suncor Energy Inc.	109
2006 Annual Report

Share trading information (unaudited)

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

	For the Quarter Ended				For the Quarter Ended
	Mar 31	June 30	Sept 30	Dec 31	Mar 31	June 30	Sept 30	Dec 31
	2006	2006	2006	2006	2005	2005	2005	2005
Share ownership
Average number outstanding, weighted monthly (thousands) (a)	458 230	458 596	458 859	459 069	454 911	456 141	456 996	457 429
Share price (dollars)
Toronto Stock Exchange
High	93.85	102.18	97.12	95.00	50.07	60.24	73.25	76.05
Low	75.58	75.00	71.18	72.26	38.76	44.00	57.75	57.00
Close	89.63	90.34	80.19	91.79	48.73	57.92	70.42	73.32
New York Stock Exchange – US$
High	82.15	89.86	86.78	82.08	41.70	48.95	62.50	66.00
Low	64.00	67.36	63.77	64.06	31.33	35.38	47.40	48.09
Close	77.02	81.01	72.05	78.91	40.21	47.32	60.53	63.13
Shares traded (thousands)
Toronto Stock Exchange	107 797	101 626	106 348	99 704	107 080	102 317	108 384	107 502
New York Stock Exchange	114 031	116 492	100 714	94 676	84 285	89 244	139 214	175 618
Per common shareinformation (dollars)
Net earnings attributable to common shareholders	1.56	2.65	1.48	0.78	0.15	0.18	0.69	1.52
Cash dividends	0.06	0.08	0.08	0.08	0.06	0.06	0.06	0.06

(a) The company had approximately 2,388 holders of record of common shares as at January 31, 2007.

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 who owns at least 10% of the voting shares of the company.

110	Suncor Energy Inc.
	2006 Annual Report

Supplemental financial and operating information (unaudited)

	2006	2005	2004	2003	2002
OIL SANDS
Production (thousands of barrels per day)	260.0	171.3	226.5	216.6	205.8
Sales (thousands of barrels per day)
Light sweet crude oil	110.5	73.3	114.9	112.3	104.7
Diesel	28.2	15.6	27.9	26.3	23.0
Light sour crude oil	118.2	59.8	75.1	73.3	68.3
Bitumen	6.2	16.6	8.4	6.4	9.3
	263.1	165.3	226.3	218.3	205.3
Average sales price (dollars per barrel)
Light sweet crude oil	71.98	49.93	45.60	40.26	37.56
Other (diesel, light sour crude oil and bitumen)	65.17	56.90	39.13	33.93	29.58
Total	68.03	53.81	42.28	37.19	33.65
Total (a)	68.03	62.68	49.78	40.22	36.94
Cash operating costs – total operations (b)	21.70	24.55	15.15	13.80	13.30
Total cash operating costs – total operations (b)	21.90	24.65	15.45	13.80	13.30
Total operating costs – total operations (b)	25.95	29.95	19.05	17.15	16.80
Cash operating costs – in-situ bitumen production (b), (e), (f)	17.30	22.20	22.05	—	—
Total cash operating costs – in-situ bitumen production (b), (e), (f)	19.00	23.20	28.90	—	—
Total operating costs – in-situ bitumen production (b), (e), (f)	24.55	28.10	34.90	—	—
Capital employed excluding major projects in progress	5 092	4 472	4 105	4 010	4 464
Return on capital employed (%) (c)	53.7	22.7	22.6	21.1	17.4
Return on capital employed (%) (d)	40.4	16.3	18.5	17.7	16.2

(a)	Excludes the impact of hedging activities.
(b)	Dollars per barrel rounded to the nearest $0.05. See definitions on page 106.
(c)	See definitions on page 108.
(d)	If capital employed were to include capitalized costs related to major projects in progress, the return on capital employed would be as stated on this line.
(e)	In-situ bitumen production commenced commercial operations on April 1, 2004.
(f)	In-situ bitumen production costs exclude upgrading costs.

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Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
NATURAL GAS
Production
Natural gas (millions of cubic feet per day)
Gross	191	190	200	187	179
Net	141	137	147	142	124
Natural gas liquids (thousands of barrels per day)
Gross	2.3	2.4	2.5	2.3	2.4
Net	1.7	1.9	1.8	1.7	1.7
Crude oil (thousands of barrels per day)
Gross	0.7	0.8	1.0	1.4	1.5
Net	0.6	0.7	0.8	1.1	1.2
Total (thousands of boe (a) per day)
Gross	34.8	34.8	36.8	34.9	33.7
Net	25.8	25.3	27.1	26.4	23.6
Average sales price
Natural gas (dollars per thousand cubic feet)	7.15	8.57	6.70	6.42	3.91
Natural gas (dollars per thousand cubic feet) (b)	6.95	8.59	6.73	6.42	3.91
Natural gas liquids (dollars per barrel)	44.96	50.70	42.82	36.08	29.35
Crude oil – conventional (dollars per barrel)	74.83	64.85	50.41	40.29	31.72
Capital employed	861	563	448	400	422
Return on capital employed (%) (e)	15.3	30.7	27.1	29.2	9.5
Undeveloped landholdings (c)
Oil and gas (millions of acres)
Western Canada
Gross	1.2	0.6	0.7	0.5	0.5
Net	0.7	0.4	0.5	0.4	0.4
International
Gross	0.1	0.4	0.7	0.9	1.2
Net	—	0.2	0.4	0.2	0.7
Net wells drilled (d)
Exploratory
Oil	—	—	—	—	—
Gas	3	8	5	2	2
Dry	5	4	5	31	19
Development
Oil	1	1	—	1	—
Gas	13	18	16	16	18
Dry	4	3	—	4	4
	26	34	26	54	43

(a)   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.

(b)   Excludes the impact of hedging activities.

(c)   Metric conversion: Landholdings – 1 hectare = approximately 2.5 acres

(d)   Excludes interests in 7 net exploratory wells and 18 net development wells in progress at the end of 2006.

(e)   See definitions on page 108.

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Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
ENERGY MARKETING AND REFINING – CANADA
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail	4.6	4.5	4.6	4.4	4.5
Other	3.8	3.9	4.1	4.2	4.4
Jet fuel	0.7	0.9	0.9	0.7	0.4
Diesel	3.2	3.3	3.1	3.0	2.9
	12.3	12.6	12.7	12.3	12.2
Petrochemicals	0.9	0.7	0.8	0.8	0.6
Heating oils	0.5	0.4	0.4	0.5	0.4
Heavy fuel oils	0.8	1.0	0.7	0.8	0.6
Other	0.6	0.5	0.8	0.6	0.7
	15.1	15.2	15.4	15.0	14.5
Crude oil supply and refining
Processed at Sarnia refinery (thousands of cubic metres per day)	8.6	10.6	11.1	10.5	10.6
Utilization of refining capacity (%)	78	95	100	95	95
Capital employed excluding major projects in progress	1 023	486	512	551	485
Return on capital employed (%) (d)	12.5	8.1	14.6	10.3	12.0
Return on capital employed (%) (d), (e)	7.4	5.2	13.6	10.3	12.0
Retail outlets (f) (number at year-end)	374	374	378	379	384

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Supplemental financial and operating information (unaudited) (continued)

	2006	2005	2004	2003	2002
REFINING AND MARKETING – U.S.A. (a)
Refined product sales (thousands of cubic metres per day)
Transportation fuels
Gasoline
Retail (b)	0.7	0.7	0.7	0.7	—
Other	6.8	6.2	3.8	3.5	—
Jet fuel	1.0	0.8	0.5	0.5	—
Diesel	3.6	3.3	2.2	2.3	—
	12.1	11.0	7.2	7.0	—
Asphalt	1.2	1.6	1.5	1.7	—
Other	1.1	1.1	0.6	0.4	—
	14.4	13.7	9.3	9.1	—
Crude oil supply and refining
Processed at Denver refinery (thousands of cubic metres per day)	13.1	12.1	8.8	9.4	—
Utilization of refining capacity (%)	92	98	92	98	—
Capital employed excluding major projects in progress	831	327	232	270	—
Return on capital employed (%) (d), (h)	34.2	49.4	12.2	—	—
Return on capital employed (%) (d), (e), (h)	22.6	28.9	11.1	—	—
Retail outlets (g) (number at year-end)	43	43	43	43	—

(a) Refining and Marketing – U.S.A. reflects the results of operations since acquisitions on August 1, 2003 and May 31, 2005.

(b) Excludes sales through joint venture interests.

(c) Excludes the impact of hedging activities.

(d) See definitions on page 108.

(e) 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.

(f) Sunoco-branded service stations, other private brands managed by EM&R and EM&R’s interest in service stations managed through joint ventures. Outlets are located mainly in Ontario.

(g) Phillips 66-branded service stations. Outlets are primarily located in the Denver, Colorado area.

(h) For 2003, represents five months of operations since acquisition August 1, 2003, therefore no annual ROCE was calculated.

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Investor information

Stock Trading Symbols and Exchange Listing

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

Dividends

Suncor’s Board of Directors reviews its dividend policy quarterly. In 2006, Suncor paid an aggregate dividend of $0.30 per common share.

Dividend Reinvestment and Common Share Purchase Plan

Suncor’s Dividend Reinvestment and Common Share Purchase Plan enables shareholders to invest cash dividends in common shares or acquire additional shares through cash payments without payment of brokerage commissions, service charges or other costs associated with administration of the plan. To obtain additional information, call Computershare Trust Company of Canada at 1-877-982-8760. Information regarding the purchase plan is also available in the dividend information section of our website at www.suncor.com/dividend.

Stock Transfer Agent and Registrar

In Canada, Suncor’s agent is Computershare Trust Company of Canada. In the United States, Suncor’s agent is Computershare Trust Company, Inc.

Independent Auditors

PricewaterhouseCoopers LLP

Independent Reserve Evaluators

GLJ Petroleum Consultants Ltd.

Annual Meeting

Suncor’s annual and special meeting of shareholders will be held at 10:30 a.m. MT on April 26, 2007, at the Metropolitan Centre, 333 Fourth Avenue S.W., Calgary, Alberta. Presentations from the meeting will be web-cast live at www.suncor.com/webcasts.

Corporate Office

Box 38, 112 – 4th Avenue S.W., Calgary, Alberta, T2P 2V5

Telephone: 403-269-8100  Toll-free number: 1-866-SUNCOR-1

Fax: 403-269-6217  E-mail: info@suncor.com

Analyst and Investor Inquiries

John Rogers, vice president, Investor Relations

Telephone: 403-269-8670  Fax: 403-269-6217  E-mail: invest@suncor.com

For further information, to subscribe or cancel duplicate mailings

In addition to Annual and Quarterly Reports, Suncor publishes a biennial Report on Sustainability. All Suncor publications, as well as updates on company news as it happens, are available on our website at www.suncor.com. To receive Suncor news as it happens, subscribe to E-news, which can be found on our website. To order copies of Suncor’s print materials call 1-800-558-9071.

If you do not receive our Annual or Quarterly Reports, but would like to receive these reports, call Computershare Trust Company of Canada at 1-877-982-8760 or visit their website at www.computershare.com. Computershare will update your account information accordingly.

Shareholders can help reduce mailing costs and paper waste by electing to receive Suncor’s Annual Report and other documents electronically. To register for electronic delivery, registered shareholders should visit www.computershare.com.

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Corporate governance

Providing strategic guidance to the company, setting policy direction and ensuring Suncor is fairly reporting its progress are central to the work of Suncor’s Board of Directors.

The Board’s oversight role encompasses Suncor’s strategic planning process, risk management, standards of business conduct and communication with investors and other stakeholders. Suncor’s Board is also responsible for selecting, monitoring and evaluating executive leadership and aligning management’s decision making with long-term shareholder interest.

There are no significant differences between Suncor’s governance practices and those prescribed by the New York Stock Exchange (NYSE), with the exception of the requirements applicable to equity compensation plans. A comprehensive description of Suncor’s governance practices, including differences between Toronto Stock Exchange (TSX) and NYSE requirements related to equity compensation plans, is available in the company’s Management Proxy Circular on Suncor’s website at www.suncor.com/financialreporting or by calling 1-800-558-9071.

Independence

As of December 31, 2006, Suncor’s Board of Directors comprised 12 directors, 11 of whom have been determined by the Board to be independent of management under the guidelines established by the TSX and NYSE. The role of chair is assumed by an independent director and is separate from the role of chief executive officer. All Board committees are comprised entirely of independent directors.

The selection of new nominees for membership on the Board is conducted by the Board Policy, Strategy Review and Governance Committee, comprised solely of independent directors. The selection process includes an annual assessment of the competencies and skills the Board as a whole should possess, and of current director capabilities. The Board Policy, Strategy Review and Governance Committee utilizes the services of executive search consulting firms to assist with the selection process. Ultimately, the committee provides its recommendation to the full Board, which approves a nominee for submission to shareholders for election to the Board.

Additionally, the committee annually assesses and evaluates the overall performance and effectiveness of the Board, its committees, and individual directors. Each year, a confidential questionnaire including a self-assessment and peer review is completed by each director. The resulting data is analyzed by the Board Policy, Strategy Review and Governance Committee, which then reports to the full Board with any recommendations for enhancing or strengthening effectiveness.

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Committee Key Responsibilities

Committee	Key Responsibilities
Board Policy, Strategy Review and Governance Committee	Oversees Suncor’s values, beliefs and standards of ethical conduct. Reviews key matters pertaining to governance, including organization, composition and effectiveness of the Board. Reviews preliminary stages of key strategic initiatives and projects. Reviews and assesses processes relating to long-range and strategic planning and budgeting.
Human Resources and Compensation Committee	Reviews and ensures Suncor’s overall goals and objectives are supported by appropriate executive compensation philosophy and programs. Annually evaluates the performance of the chief executive officer (CEO) against predetermined goals and criteria, and recommends to the Board the total compensation for the CEO. Annually reviews the CEO’s evaluation and recommendations for total compensation of the other executive roles, the executive succession planning process and results, and all major human resources programs.
Environment, Health and Safety Committee	Reviews the effectiveness with which Suncor meets its obligations pertaining to environment, health and safety, including the establishment of appropriate policies with regard to legal, industry and community standards and related management systems and compliance.
Audit Committee	Assists the Board in matters relating to Suncor’s internal controls, internal and external auditors and the external audit process, oil and natural gas reserves reporting, financial reporting, public communication and certain other key financial matters. Provides an open avenue of communication between management, the internal and external auditors and the Board. Approves Suncor’s interim financial statements and management’s discussion and analysis.

Share Ownership

The Board has set guidelines for its own, as well as executive share ownership. These guidelines, as well as the amount of shares held by each Board member and named executive are reported annually in Suncor’s Management Proxy Circular.

For further information about Suncor’s corporate governance practices and the company’s code of corporate conduct, visit www.suncor.com or call 1-800-558-9071 to order a copy of Suncor’s Management Proxy Circular.

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Board of directors

JR Shaw ^(2,3)

Calgary, Alberta

Chairman of the Board of Directors

Director since 1998

JR Shaw has been the chairman of the Board of Suncor since 2001. He is also the executive chair of Shaw Communications Inc., the company he founded in 1966. Mr. Shaw is also president of the Shaw Foundation and serves as a director of Darian Resources. Mr. Shaw is an Officer of the Order of Canada.

Mel E. Benson ^(3,4)

Calgary, Alberta

Chair, Environment, Health and Safety Committee

Director since 2000

Mel Benson is president of Mel E. Benson Management Services Inc., an international management consulting firm based in Calgary, Alberta. In 2000 Mr. Benson retired from a major international oil company. Mr. Benson is also a director of Kanetax Energy Inc., Tenax Energy Inc., Winalta Homes Inc. and Poplar Point Energy. He is active with several charitable organizations including Hull Family Services, the Council for Advancement of Native Development Officers and the Canadian Aboriginal Professional Association. He is also a member of the Board of Governors for the Northern Alberta Institute of Technology and the National Aboriginal Economic Development Board.

Brian A. Canfield ^(1,2)

Point Roberts, Washington

Director since 1995

Brian Canfield is the chairman of TELUS Corporation, a telecommunications company. Mr. Canfield is also a director and chair of the governance committee of the Canadian Public Accountability Board. In 1998, Mr. Canfield was appointed to the Order of British Columbia. In 2007, he was appointed a Member of the Order of Canada.

Bryan P. Davies ^(3,4)

Etobicoke, Ontario

Chair, Human Resources and Compensation Committee

Director 1991 to 1996 and since 2000

Bryan Davies is chairman of the Canada Deposit Insurance Corporation. He is also a director of the General Insurance Statistical Agency and is past superintendent of the Financial Services Commission of Ontario. Prior to that, he was senior vice president of regulatory affairs with the Royal Bank Financial Group. Mr. Davies serves as past chair of the Canadian Merit Scholarship Foundation and a director of the Foundation for International Training.

Brian A. Felesky ^(1,4)

Calgary, Alberta

Director since 2002

Brian Felesky is counsel to the law firm Felesky Flynn LLP in Calgary, Alberta. Mr. Felesky also serves as a director on the board and is chair of the audit committee of Epcor Power LP. He is also a member of the board of Precision Drilling Trust, Fairquest Energy Ltd. and Resin Systems Inc. He is the co-chair of Homefront on Domestic Violence, vice chair of the Canada West Foundation, member of the senate of Athol Murray College of Notre Dame, and board member of the Calgary Stampede Foundation and the Calgary Arts Development Authority. Mr. Felesky is a Member of the Order of Canada.

John T. Ferguson ^(1,2)

Edmonton, Alberta

Chair, Audit Committee

Director since 1995

John Ferguson is founder and chairman of the board of Princeton Developments Ltd. and Princeton Ventures Ltd. Mr. Ferguson is also a director of Fountain Tire Ltd., the Royal Bank of Canada and Strategy Summit Ltd. He is a director of the C.D. Howe Institute, the Alberta Bone and Joint Institute, an advisory member of the Canadian Institute for Advanced Research, and chancellor emeritus and chairman emeritus of the University of Alberta. Mr. Ferguson is also a fellow of the Alberta Institute of Chartered Accountants and the Institute of Corporate Directors.

W. Douglas (Doug) Ford ^(2,3)

Downers Grove, Illinois

Director since 2004

Doug Ford was chief executive, refining and marketing, for BP p.l.c. from 1998 to 2002 and was responsible for the refining, marketing and transportation network of the company, as well as the aviation fuels business, the marine business and BP shipping. Mr. Ford currently serves as a director of USG Corporation and Air Products and Chemicals, Inc. He is also a member of the board of trustees of the University of Notre Dame.

Richard (Rick) L. George

Calgary, Alberta

Director since 1991

Rick George is the president and chief executive officer of Suncor Energy Inc. Mr. George is also a director of the U.S. offshore and onshore drilling company, GlobalSantaFe Corporation, and chair of the 2008 Governor General’s Canadian Leadership Conference. In 2006, he was named a member of the North American Competitiveness Council by Canadian Prime Minister Stephen Harper. He served as chairman of the Canadian Council of Chief Executives from 2003 to 2006.

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John R. Huff ^(2,3)

Houston, Texas

Chair, Board Policy, Strategy Review

and Governance Committee

Director since 1998

John Huff is chairman of the board of Oceaneering International Inc., an oil field services company. Mr. Huff is also a director of BJ Services Company and Rowan Companies Inc. He is a member of the National Petroleum Council, and is active in the Houston Museum of Natural Science and St. Luke’s Episcopal Hospital System in Houston.

M. Ann McCaig ^(3,4)

Calgary, Alberta

Director since 1995

Ann McCaig is chair of the Alberta Adolescent Recovery Centre, a trustee of the Killam Estate, chair of the Calgary Health Trust, a director of the Calgary Stampede Foundation and honorary chair of the Alberta Bone and Joint Institute. She is also chancellor emeritus of the University of Calgary and a Member of the Order of Canada. She is past co-chair of the Alberta Children’s Hospital Foundation.

Michael W. O’Brien ^(1,4)

Canmore, Alberta

Director since 2002

Michael O’Brien served as executive vice president, corporate development and chief financial officer of Suncor Energy Inc. before his retirement in 2002. Mr. O’Brien serves on the boards of Prime West Energy Inc. and Shaw Communications Inc. and as an advisor to CRA International. As well, he is past chair of the board of trustees for Nature Conservancy of Canada, past chair of the Canadian Petroleum Products Institute and past chair of Canada’s Voluntary Challenge for Global Climate Change.

Eira M. Thomas ^(1,4)

West Vancouver, British Columbia

Director since 2006

Eira Thomas has been president and chief executive officer of Stornoway Diamond Corporation, a mineral exploration company, since July 2003. Previously, Ms. Thomas was president of Navigator Exploration Corporation and chief executive officer and director of Stornoway Ventures Ltd. She is a director of Strongbow Exploration Inc. and Fortress Minerals Corp. As well, Ms. Thomas is a director of the University of Toronto’s Alumni Association, Lassonde Advisory Board of the University of Toronto, Prospectors and Developers Association of Canada and the Northwest Territories and Nunavut Chamber of Mines. She is also a member of the University of Toronto’s President’s Internal Advisory Council.

(1) Audit Committee

(2) Board Policy, Strategy Review and Governance Committee

(3) Human Resources and Compensation Committee

(4) Environment, Health and Safety Committee

Suncor’s most recently filed Form 40-F included, as exhibits, the certifications of our Chief Executive Officer and Chief Financial Officer required by Sections 302 and 906 of the United States Sarbanes-Oxley Act of 2002.

Corporate Officers*

Richard L. George	Sue Lee
President and Chief Executive Officer	Senior Vice President,
	Human Resources and Communications
J. Kenneth Alley
	Kevin D. Nabholz
Senior Vice President
and Chief Financial Officer	Executive Vice President,
	Major Projects
M. (Mike) Ashar
	Janice B. Odegaard
Executive Vice President,
Refining and Marketing – U.S.A.	Vice President,
	Associate General Counsel and Corporate Secretary
David W. Byler
	Thomas L. Ryley
Executive Vice President,
Natural Gas and Renewable Energy	Executive Vice President,
	Energy Marketing and Refining – Canada
Bart W. Demosky
	Jay Thornton
Vice President and Treasurer
	Senior Vice President,
Terrence J. Hopwood	Business Integration
Senior Vice President	Steven W. Williams
and General Counsel
	Executive Vice President,
	Oil Sands

Offices shown are positions held by the officers in relation to businesses of Suncor Energy Inc. and its subsidiaries. On a legal entity basis, Mr. Ashar is president of Suncor Energy (U.S.A.) Inc., Suncor’s U.S.-based downstream subsidiary; Mr. Ryley is the president of Suncor’s Canada-based downstream subsidiaries, Suncor Energy Marketing Inc. and Suncor Energy Products Inc., respectively; and Mr. Nabholz, Ms. Lee and Mr. Thornton are officers of Suncor Energy Services Inc., which provides major projects management, human resources and communication, business integration and other shared services to the Suncor group of companies.

* This information reflects the positions of officers at December 31, 2006. In March 2007, Suncor announced a restructuring of the company’s executive management team. See page 16 for details.

The Dow Jones Sustainability Index (DJSI) follows a best-in-class approach comprising the sustainability leaders from each industry. Suncor has been part of the index since the DJSI was launched in 1999.	As an Imagine Caring Company, Suncor contributes 1% of its domestic pretax profit to registered charities.

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