EXHIBIT 99.3

Unaudited Interim Consolidated Financial Statements for the First Quarter Ended
March 31, 2011


		Three months ended March 31
($ millions)		2011		2010

Revenues and Other Income
	Operating revenues, net of royalties (note 7)	9 256		7 130
	Energy supply and trading activity income	521		260
	Interest and other income	68		19

		9 845		7 409

Expenses
	Purchases of crude oil and products	3 807		3 429
	Operating, selling and general (note 8)	2 291		1 851
	Energy supply and trading activity expenses	457		278
	Transportation	162		158
	Depreciation, depletion, amortization and impairment	785		848
	Exploration	58		48
	Loss (gain) on disposal of assets	251		(268	)
	Project start-up costs	37		12
	Financing expenses (income) (note 9)	(49	)	(131	)

		7 799		6 225

Earnings Before Income Taxes		2 046		1 184

Provisions for Income Taxes(note 13)
	Current	416		247
	Deferred	602		158

		1 018		405

Net Earnings		1 028		779

Other Comprehensive Income (Loss)
	Foreign currency translation adjustment	37		(375	)
	Foreign currency translation adjustment relating to assets held for sale	—		(57	)
	Foreign currency translation reclassified to net earnings	14		1
	Actuarial gain (loss) on employee retirement benefit plans, net of income taxes of $4 (2010 – $29)	18		(84	)

Other Comprehensive Income (Loss)		69		(515	)

Total Comprehensive Income		1 097		264

Net Earnings per Common Share (dollars) (note 10)
	Basic	0.65		0.50
	Diluted	0.65		0.46

Cash dividends		0.10		0.10


($ millions)			March 31 2011	December 31 2010	January 1 2010

Assets
	Current assets
		Cash and cash equivalents	3 465	1 077	505
		Accounts receivable	4 828	5 253	3 936
		Inventories	3 948	3 141	2 971
		Income taxes receivable	720	734	587

			12 961	10 205	7 999
		Assets held for sale (note 11)	94	762	—

	Total current assets		13 055	10 967	7 999
	Property, plant and equipment, net		48 632	49 958	51 556
	Exploration and evaluation		4 496	3 961	4 342
	Other assets		273	230	259
	Goodwill and other intangible assets (note 12)		3 144	3 422	3 433
	Deferred income taxes		43	69	210

	Total assets		69 643	68 607	67 799

Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	752	1 984	2 317
		Current portion of long-term debt	514	518	25
		Accounts payable and accrued liabilities	7 775	6 524	5 796
		Current portion of provisions	354	527	859
		Income taxes payable	984	929	1 274

			10 379	10 482	10 271
		Liabilities associated with assets held for sale (note 11)	35	586	—

	Total current liabilities		10 414	11 068	10 271
	Long-term debt		9 637	9 829	11 679
	Other long-term liabilities		2 000	2 103	2 050
	Provisions		2 532	2 504	3 328
	Deferred income taxes		8 660	7 911	7 986
	Shareholders' equity		36 400	35 192	32 485

	Total liabilities and shareholders' equity		69 643	68 607	67 799

Suncor Energy Inc.
048 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com


		Three months ended March 31
($ millions)		2011		2010

Operating Activities
Net earnings		1 028		779
Adjustments for:
	Depreciation, depletion, amortization and impairment	785		848
	Deferred income taxes	602		158
	Accretion of liabilities	38		48
	Unrealized foreign exchange gain on U.S. dollar denominated long-term debt (note 9)	(186	)	(260	)
	Change in fair value of derivative contracts	(55	)	(80	)
	Loss (gain) on disposal of assets	251		(268	)
	Share-based compensation	173		(75	)
	Exploration	2		16
	Other	(245	)	(42	)
Decrease (increase) in non-cash working capital		125		(858	)

Cash flow provided by operating activities		2 518		266

Investing Activities
Capital and exploration expenditures		(1 602	)	(1 121	)
Other investments		5		—
Proceeds from disposal of assets		2 690		942

Cash flow provided by (used in) investing activities		1 093		(179	)

Financing Activities
Net change in short-term debt		(1 232	)	5
Net change in long-term debt		(4	)	146
Issuance of common shares under share option plans		168		15
Dividends paid on common shares		(153	)	(153	)

Cash flow provided by (used in) financing activities		(1 221	)	13

Increase in Cash and Cash Equivalents		2 390		100
Effect of foreign exchange on cash and cash equivalents		(2	)	(3	)
Cash and cash equivalents at beginning of period		1 077		505

Cash and Cash Equivalents at End of Period		3 465		602

Supplementary Cash Flow Information
Interest paid		101		92
Income taxes paid		308		231


($ millions)	Share Capital	Contributed Surplus		Foreign Currency Translation		Cash Flow Hedge	Retained Earnings		Total		Number of Common Shares (thousands)

At January 1, 2010	20 053	536		—		15	11 881		32 485		1 559 778

Net earnings	—	—		—		—	779		779		—
Foreign currency translation adjustment	—	—		(431	)	—	—		(431	)	—
Actuarial loss on employee retirement benefit plans	—	—		—		—	(84	)	(84	)	—

Total comprehensive income (loss)	—	—		(431	)	—	695		264		—
Dividends paid on common shares	—	—		—		—	(153	)	(153	)	—
Issued under share option plans	20	(5	)	—		—	—		15		1 230
Issued under dividend reinvestment plan	3	—		—		—	(3	)	—		96
Share-based payment expense	—	11		—		—	—		11		—

At March 31, 2010	20 076	542		(431	)	15	12 420		32 622		1 561 104



At December 31, 2010	20 188	507		(451	)	14	14 934		35 192		1 565 489

Net earnings	—	—		—		—	1 028		1 028		—
Foreign currency translation adjustment	—	—		51		—	—		51		—
Actuarial gain on employee retirement benefit plans	—	—		—		—	18		18		—

Total comprehensive income	—	—		51		—	1 046		1 097		—
Dividends paid on common shares	—	—		—		—	(153	)	(153	)	—
Issued under share option plans	262	(41	)	—		—	—		221		7 405
Issued under dividend reinvestment plan	4	—		—		—	(4	)	—		99
Share-based payment expense	—	43		—		—	—		43		—

At March 31, 2011	20 454	509		(400	)	14	15 823		36 400		1 572 993

Suncor Energy Inc.
050 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Suncor Energy Inc. (Suncor or the company) is an integrated energy company headquartered in Canada. Suncor's operations include oil sands development and upgrading, onshore and offshore oil and gas production, petroleum refining and product marketing primarily under the Petro-Canada brand. The consolidated financial statements of the company comprise the company and its subsidiaries and the company's interests in associates and jointly controlled entities.

The address of the company's registered office is 150 - 6th Avenue S.W., Calgary, Alberta, Canada, T2P 3E3.

These condensed consolidated interim financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP), specifically International Accounting Standard 34 Interim Financial Reporting within Part 1 of the Canadian Institute of Chartered Accountants (CICA) Handbook. They are condensed as they do not include all of the information required for full annual financial statements, and they should be read in conjunction with the consolidated financial statements of the company as at and for the year ended December 31, 2010.

These are the company's first consolidated financial statements prepared in accordance with International Financial Reporting Standards (IFRS), and IFRS 1 First-Time Adoption of International Financial Reporting Standards (IFRS 1) has been applied. In previous years, the company prepared its consolidated financial statements in accordance with Canadian generally accepted accounting principles in effect prior to January 1, 2011 (Previous GAAP). Comparative information has been restated from Previous GAAP to IFRS. The impact of the transition to IFRS on the company's previously reported financial statements is presented in note 5.

The policies applied in these condensed interim consolidated financial statements are based on IFRS issued and outstanding as of May 2, 2011, the date the Board of Directors approved the statements. Any subsequent changes to IFRS that are given effect in the company's annual consolidated financial statements for the year ending December 31, 2011 could result in restatement of these interim consolidated financial statements, including the adjustments recognized on transition to IFRS.

The consolidated financial statements are prepared on a historical cost basis except as detailed in the company's accounting policies disclosed in note 3. The accounting policies described in note 3 have been applied consistently to all periods presented in these financial statements except for the opening IFRS consolidated balance sheet, which has utilized certain exemptions available under IFRS 1.

These consolidated financial statements are presented in Canadian dollars (Cdn$), which is the company's functional currency.

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 at the date of the financial statements. Accordingly, actual results may differ from estimated amounts as future confirming events occur. Significant estimates and judgment used in the preparation of the financial statements are described in note 4.

The company consolidates its interest in entities in which it controls. Control comprises the power to govern an entity's financial and operating policies so as to obtain benefits from its activities. Suncor recognizes its share of assets, liabilities, income and expenses, on a line-by-line basis, of its jointly controlled entities and jointly controlled assets. Investments in entities over which the company has significant influence are accounted for using the equity method. All intercompany balances and transactions have been eliminated.

Functional currencies of the company's individual entities represent the currency of the primary economic environment in which the entity operates. Transactions in foreign currencies are translated to the appropriate functional currency at foreign exchange rates that approximate those on the date of transaction. Monetary assets and liabilities denominated in foreign currencies are translated to the appropriate functional currency at foreign exchange rates at the balance sheet date. Foreign exchange differences arising on translation are recognized in earnings. Non-monetary assets that are measured in a foreign currency at historical cost are translated using the exchange rate at the date of the transaction.

In preparing the company's consolidated financial statements, the financial statements of each entity are translated into Canadian dollars. The assets and liabilities of foreign operations are translated into Canadian dollars at exchange rates at the balance sheet date. Revenues and expenses of foreign operations are translated into Canadian dollars using foreign exchange rates that approximate those on the date of the underlying transaction. Foreign exchange differences are recognized in other comprehensive income.

If an entity disposes of its entire interest in a foreign operation, or loses control, joint control, or significant influence over a foreign operation, the accumulated foreign currency translation gains or losses related to the foreign operation are recognized in net earnings.

Revenue from the sale of crude oil, natural gas, natural gas liquids, purchased products and refined petroleum products is recorded when title passes to the customer and collection is reasonably assured. Revenue from properties in which the company has an interest with other producers is recognized on the basis of the company's net working interest. Crude oil and natural gas sold below or above the company's working interest share of production results in production underlifts or overlifts. Underlifts are recorded as a receivable at market value with a corresponding increase to revenues while overlifts are recorded as a payable at market value with a corresponding decrease to revenues. Revenue from oil and natural gas production is recorded net of royalty obligations.

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

Physical and financial contracts entered into for trading purposes are considered to be derivative financial instruments, and any changes in fair value are recorded on a net basis in Energy Supply and Trading Activity Income. Settlement of physical purchase

Suncor Energy Inc.
052 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

and sales contracts entered into for the company's own usage are recorded on a gross basis in Energy Supply and Trading Activity Income and Energy Supply and Trading Activity Expense.

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

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

Inventories held for trading purposes in the company's energy supply and trading operations are carried at fair value less costs to sell, and any changes in fair value are recognized within Energy Supply and Trading Activity Income.

The costs to acquire non-producing oil and gas properties or licenses to explore, exploratory well expenditures and the costs to evaluate the commercial potential of underlying resources, including related borrowing costs, are initially capitalized as Exploration and Evaluation assets. Certain exploration costs, including geological, geophysical, seismic, and sampling on oil sands properties, are charged to Exploration expense as incurred.

Exploration and evaluation assets are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. If an area or exploration well is no longer considered commercially viable, the related capitalized costs are charged to net earnings.

When management determines with reasonable certainty that an exploration and evaluation asset will be developed, as evidenced by the classification of proved or probable reserves and the appropriate internal and external approvals, the asset is transferred to Property, Plant and Equipment.

The costs to acquire developed or producing oil and gas properties and to develop oil and gas properties, including completing geological and geophysical surveys and drilling development wells, and the costs to construct and install dedicated infrastructure, such as wellhead equipment and supporting assets, mine development, offshore platforms and subsea structures, are capitalized as oil and gas properties within Property, Plant and Equipment.

The costs to construct, install and commission, or acquire, oil and gas production equipment, including oil sands upgraders, extraction plants, mine equipment, in situ processing facilities, power generation, utility plants, and natural gas processing plants, and all renewable energy, refining, distribution, marketing assets and related decommissioning and restoration obligations, are capitalized as Property, Plant and Equipment. Where an asset or part of an asset that was separately depreciated is replaced and it is probable that future economic benefits associated with the item will flow to the company, the expenditure is capitalized and the carrying amount of the replaced asset is derecognized.

Stripping activity required to access oil sands mining resources incurred in the initial development phase are capitalized as part of the investment in the construction cost of the mine. Stripping costs incurred in the production phase are charged to expense as they relate to production for the period.

The costs of major inspection, overhaul and turnaround activities that maintain property, plant and equipment and benefit future years of operations are capitalized. Similar recurring planned maintenance managed on shorter intervals are expensed as operating costs. Replacements outside of a major inspection, overhaul or turnaround are capitalized when it is probable that future economic benefits will flow to the company and the associated carrying amount of the replaced asset is derecognized.

Leases that transfer substantially all the benefits and risks of ownership to the company are recorded as finance lease assets within Property, Plant and Equipment. Costs for all other leases are recorded as operating expense as incurred.

Borrowing costs relating to qualifying assets are capitalized as part of Property, Plant and Equipment. Capitalization of borrowing costs ceases when the asset is in the location and condition necessary for it to be capable of operating as intended. Capitalization of borrowing costs is suspended when construction of an asset is ceased for extended periods.

Exploration and evaluation assets are not subject to depreciation, depletion and amortization, with the exception of leases acquired for conventional oil and gas operations. Once transferred to Property, Plant and Equipment, these costs are depleted on a unit-of-production basis. Property acquisition costs are depleted over proved reserves, while all other exploration and evaluation costs are depleted over proved developed reserves.

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

Costs to develop oil and gas properties, and costs of dedicated infrastructure, such as wellhead equipment, offshore platforms and subsea structures, are depleted on a unit-of-production basis over proved developed reserves. A portion of these costs may not be depleted if they relate to undeveloped reserves.

Major components of Property, Plant and Equipment are depreciated on a straight-line basis over their expected useful lives.


Natural gas processing plants and transportation assets		15 to 25 years
Oil sands upgraders, extraction plants and mine facilities		20 to 40 years
Oil sands mine equipment		5 to 15 years
Oil sands in situ processing facilities		30 years
Power generation and utility plants		40 years
Refineries, ethanol and lubricants plants		20 to 40 years
Marketing and other distribution assets		20 to 40 years

The costs of major inspection, overhaul and turnaround activities that are capitalized are depreciated on a straight-line basis over the period to the next recurrence of that set of activities, which varies from two to five years.

Depreciation, depletion and amortization rates are reviewed, at least annually, or when events or conditions occur that impact capitalized costs, reserves or estimated service lives.

Intangible assets, other than goodwill, include acquired customer lists and brand value. Brand value and goodwill have indefinite useful lives and are not subject to amortization, while customer lists are amortized over their expected useful lives, which range from five to 10 years. Expected useful lives of intangible assets are reviewed on an annual basis.

Acquisitions are accounted for using the purchase method, whereby the purchase consideration of the business combination is allocated to the identifiable assets, liabilities and contingent liabilities on the basis of fair value as of the date of acquisition.

Suncor Energy Inc.
054 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Goodwill is calculated as the excess of the purchase price over the fair value and is allocated to the group of cash-generating units (CGU) that is expected to benefit from the synergies of the combination.

Goodwill and intangible assets that have an indefinite useful life are tested annually for impairment. Indefinite and definite lived assets are tested for impairment whenever events or changes in circumstance indicate that the carrying amount may not be recoverable. Exploration and evaluation assets are tested for impairment immediately prior to costs being transferred to Property, Plant and Equipment.

For the purposes of assessing impairment, assets are grouped into CGU's, defined as the lowest levels for which there are separately identifiable cash inflows. An impairment loss is recognized in Depreciation, Depletion, Amortization and Impairment for the amount by which the carrying amount of the individual asset or CGU exceeds its recoverable amount. The recoverable amount is the higher of the fair value less costs to sell and value-in-use. In determining fair value less costs to sell, recent market transactions are taken into account, if available. In the absence of such transactions, an appropriate valuation model is used. Value-in-use is assessed using the present value of the expected future cash flows of the relevant asset or CGU. Exploration and evaluation assets are tested with the producing CGU for which the activity can be attributed or separately where a producing CGU does not exist for the exploration and evaluation activity.

Impairments are reversed for all CGUs and individual assets, other than goodwill, to the extent that events or circumstances give rise to changes in the estimate of recoverable amount since the period the impairment was recorded. Impairment reversals are recognized within Depreciation, Depletion, Amortization and Impairment.

At each reporting date, the company assesses whether there is objective evidence that a financial asset is impaired. If a financial asset carried at amortized cost is impaired, the amount of the loss is measured as the difference between the amortized cost of the loan or receivable and the present value of the estimated future cash flows, discounted using the instrument's original effective interest rate. The loss is recognized in Depreciation, Depletion, Amortization and Impairment.

Assets and liabilities are classified as held for sale if their carrying amounts are expected to be recovered through a disposition rather than through continuing use. The assets or disposal groups are measured at the lower of their carrying amount and fair value less costs to sell. Impairment losses on initial classification as held for sale and subsequent gains or losses on remeasurement are recognized in Loss (Gain) on Disposal of Assets. Assets classified as held for sale are not depreciated, depleted or amortized.

Provisions are recognized by the company when it has a legal or constructive obligation as a result of past events, it is probable that an outflow of economic resources will be required to settle the obligation and a reliable estimate can be made of the amount of the obligation.

Provisions are recognized for decommissioning and restoration obligations associated with the company's exploration and evaluation assets and property, plant and equipment. The best estimate of the decommissioning and restoration provision is recorded on a discounted basis using the credit-adjusted risk-free interest rate. The value of the obligation is added to the carrying amount of the associated property, plant and equipment asset and amortized over the useful life of the asset. The provision is accreted over time through charges to Financing Expenses with actual expenditures charged against the accumulated obligation. Changes in the future cash flow estimates resulting from revisions to the estimated timing or amount of undiscounted cash flows are recognized as a change in the decommissioning and restoration provision and related asset.

The company follows the liability method of accounting for income taxes whereby deferred income taxes are recorded for the effect of differences between the accounting and income tax basis of an asset or liability. Deferred income tax assets and liabilities are measured using enacted or substantively enacted income tax rates at the balance sheet date that are anticipated to apply to taxable income in the years in which temporary differences are anticipated to be recovered or settled. Changes to these balances are recognized in income in the period during which they occur. Investment tax credits are recorded as an offset to the related expenditures.

The company sponsors defined benefit pension plans (DB Plans), defined contribution pension plans (DC Plans) and other post-retirement benefits. Company contributions to the DC Plans are expensed as incurred. The cost of the DB Plans and other post-retirement benefits received by employees is actuarially determined separately for each plan using the projected unit credit method based on present pay levels and management's best estimates of demographic and financial assumptions, and such cost is pro-rated based on service. Actuarial gains and losses are recognized in Other Comprehensive Income and transferred directly to Retained Earnings.

The defined benefit pension plan surplus or deficit in the balance sheet comprises the total for each plan of the present value of the defined benefit obligation, less the fair value of plan assets out of which the obligations are to be settled directly. When the calculation results in a benefit to the company, the recognized asset is limited to the total of unrecognized past service costs and the present value of refunds from, and reductions, in future contributions to the plan. The fair value of plan assets is determined using market values.

Past service costs are recognized on a straight-line basis over the post-retirement benefits vesting period.

Under the company's share-based compensation plans, share-based awards are granted to executives, employees and non-employee directors. Compensation expense is recorded to Operating, Selling and General expense.

For common share options, the expense is based on the fair value of the options at the time of grant and is recognized as an expense over the vesting periods of the respective options. A corresponding increase is recorded to Contributed Surplus in Shareholders' Equity. Consideration paid to the company on exercise of options is credited to Share Capital in Shareholders' Equity.

Share-based compensation awards that settle in cash or have the option to settle in cash or shares are measured at fair value each reporting period and recognized as an expense over the vesting period, with a corresponding adjustment to liabilities. When awards are surrendered for cash, the cash settlement paid reduces the outstanding liability. When awards are exercised for common shares, consideration paid by the holder and the previously recognized liability associated with the options are recorded to Share Capital in Shareholders' Equity.

All financial instruments are initially recognized at fair value on the balance sheet. Subsequent measurement of financial instruments is based on their classification. Financial assets are classified as either fair value through profit and loss, loans and receivables, held-to-maturity and available for sale. Financial liabilities are classified as either fair value through profit and loss or other financial liabilities. Transaction costs are included in the initial carrying amount of financial instruments except for fair value through profit and loss items, in which case they are expensed as incurred.

Financial assets and liabilities are classified as fair value through profit and loss if they are held for trading or are designated as such upon initial recognition. This category of financial instruments includes derivative financial assets and liabilities other than those designated as effective hedging instruments. Derivative financial instruments are used by the company to manage certain

Suncor Energy Inc.
056 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

exposures to fluctuations in interest rates, commodity prices and foreign exchange rates, and for trading purposes. Changes in fair value of these financial instruments are recognized in Interest and Other Income and Energy Supply and Trading Activity Income.

Financial assets classified as loans and receivables are non-derivative financial assets with fixed or determinable payments that are not quoted in an active market. The held-to-maturity classification consists of non-derivative financial assets that the company has the intent and ability to hold until maturity. Financial liabilities classified as other financial liabilities consist of liabilities not classified as fair value through profit and loss. Financial instruments classified as held-to-maturity, loans and receivables and other financial liabilities are measured at amortized cost using the effective interest rate method.

Derivatives embedded in other financial instruments or other host contracts are recorded as separate derivatives when their risks and characteristics are not closely related to those of the host contract. Embedded derivatives are measured at fair value at each balance sheet date and changes in the fair value are recognized in earnings.

Physical commodity contracts considered to be derivative financial instruments are classified as fair value through profit and loss financial instruments and recognized on a net basis in Energy Supply and Trading Activity Income. Physical commodity contracts entered into for the purpose of receipt or delivery in accordance with the company's expected purchase, sale or usage requirements are not considered to be derivative financial instruments. Such contracts are recognized on a gross basis when the associated volumes are delivered in Energy Supply and Trading Activity Income and Energy Supply and Trading Activity Expenses.

The company may apply hedge accounting to arrangements that qualify for hedge accounting treatment, which include fair value and cash flow hedges. Documentation is prepared at the inception of a hedge relationship in order to qualify for hedge accounting. Designated hedges are assessed at each reporting date to determine if the relationship between the derivative and the underlying hedged exposure is still effective and to quantify any ineffectiveness in the relationship.

If the derivative is designated as a fair value hedge, changes in the fair value of the derivative and changes in the fair value of the hedged item attributable to the hedged risk are recognized in earnings. If the derivative is designated as a cash flow hedge, the effective portions of the changes in fair value of the derivative are initially recorded in Other Comprehensive Income and are recognized in earnings when the hedged item is realized. Ineffective portions of changes in the fair value of cash flow hedges are recognized in earnings immediately.

Common shares are classified as equity. Incremental costs directly attributable to the issue of common shares and share options are recognized as a deduction from equity, net of any tax effects.

Dividends on common shares are recognized in the period in which the dividends are approved by the company's Board of Directors.

Basic earnings per share is calculated by dividing the Net Earnings (Loss) for the period by the weighted-average number of common shares outstanding during the period.

Diluted earnings per share is calculated by adjusting the weighted-average number of common shares outstanding for dilutive common shares related to the company's share-based compensation plans. The number of shares included is computed using the treasury stock method. For share-based compensation plans that may be settled in ordinary shares or cash at the holder's option, the more dilutive of cash settlement and share settlement is used in calculating diluted earnings per share.

Certain depletion, depreciation, impairment and decommissioning and restoration charges are measured based on the company's estimate of oil and gas reserves and resources. The estimation of reserves and resources is an inherently complex process and involves the exercise of professional judgment. Reserves and resources have been evaluated at December 31, 2010 by independent petroleum consultants in accordance with National Instrument 51-101 Standards of Disclosure for Oil and Gas Activities. The reserves and resources estimates are based on the definitions and guidelines contained in the Canadian Oil and Gas Evaluation Handbook.

Oil and gas reserves and resources estimates are based on a range of geological, technical and economic factors, including projected future rates of production, estimated commodity prices, engineering data, and the timing and amount of future expenditures, all of which are subject to uncertainty. Assumptions reflect market and regulatory conditions existing at December 31, 2010, which could differ significantly from other points in time throughout the year, or future periods. Changes in market and regulatory conditions and assumptions can materially impact the estimation of net reserves.

Certain exploration and evaluation costs are initially capitalized with the intent to establish commercially viable reserves. The company is required to make estimates and judgment about future events and circumstances regarding the economic viability of extracting the underlying resources. The costs are subject to technical, commercial and management review to confirm the continued intent to develop and extract the underlying resources. Unsuccessful drilling, or changes to project economics, resource quantities, expected production techniques, production costs and required capital expenditures, are important factors when making this determination. If a judgment is made that the extraction of resources is not viable, the associated exploration and evaluation costs are impaired and charged to net earnings.

The company recognizes liabilities for the future decommissioning and restoration of property, plant and equipment. These provisions are based on estimated costs, which take into account the anticipated method and extent of restoration, technological advances and the possible future use of the site. Actual costs are uncertain and estimates can vary as a result of changes to relevant laws and regulations, the emergence of new technology, operating experience and prices. The expected timing of future decommissioning and restoration may change due to certain factors, including reserve life. Changes to assumptions related to future expected costs, discount rates and timing may have a material impact on the amounts presented.

Deferred tax assets are recognized when it is considered probable that deductible temporary differences will be recovered in the foreseeable future. To the extent that future taxable income and the application of existing tax laws in each jurisdiction differ significantly from the company's estimate, the ability of the company to realize the deferred tax assets could be impacted.

Deferred tax liabilities are recognized when there are taxable temporary differences that will reverse and result in a future outflow of funds to a taxation authority. The company records a provision for the amount that is expected to be settled, which requires the application of judgment as to the ultimate outcome. Deferred tax liabilities could be impacted by changes in the company's estimate of the likelihood of a future outflow, the expected settlement amount, and the tax laws in the jurisdictions in which the company operates.

The company provides benefits to employees, including pensions and other post-retirement benefits. The cost of defined benefit pension plans and other post-retirement benefits received by employees is determined based on actuarial valuation methods and assumptions. Changes to assumptions related to discount rates, expected return on plan assets and annual rates of compensation increases may have a material impact on the amounts presented.

Suncor Energy Inc.
058 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

A cash generating unit (CGU) is defined as the lowest grouping of integrated assets that generate identifiable cash inflows that are largely independent of the cash inflows of other assets or groups of assets. The allocation of assets into CGUs requires significant judgment and interpretations with respect to the integration between assets, the existence of active markets, similar exposure to market risks, shared infrastructures, and the way in which management monitors the operations.

The recoverable amounts of CGUs and individual assets have been determined based on the higher of fair value less costs to sell or value-in-use calculations. The key assumptions the company uses in estimating future cash flows for recoverable amounts are anticipated future commodity prices, expected production volumes, future operating and development costs, and refining margins. Changes to these assumptions will affect the recoverable amounts of CGUs and individual assets and may then require a material adjustment to their related carrying value.

When not directly observable in active markets, the company uses third-party models and valuation methodologies that utilize observable market data to estimate the fair value of derivative financial instruments. In addition to market information, the company incorporates transaction specific details that market participants would utilize in a fair value measurement, including the impact of non-performance risk. However, these fair value estimates may not necessarily be indicative of the amounts that could be realized or settled in a current market transaction.

Effective January 1, 2011, the company began reporting under IFRS, and the accounting policies disclosed in note 3 to these consolidated financial statements have been applied in preparing the financial statements for the three month periods ended March 31, 2011 and 2010, for the year ended December 31, 2010, and in the preparation of the company's opening balance sheet at January 1, 2010 (Transition Date).

In previous years, the company prepared its consolidated financial statements in accordance with Previous GAAP. Reconciliations from Previous GAAP to IFRS for comparative periods are provided on the following pages.


($ millions)			Previous GAAP ⁽¹⁾	Presentation Changes for Discontinued Operations ⁽²⁾		Other Presentation Changes ⁽³⁾		IFRS Adjustments ⁽⁴⁾		IFRS

Assets
	Current assets
		Cash and cash equivalents	1 077	—		—		—		1 077
		Accounts receivable	5 253	—		—		—		5 253
		Inventories	3 141	—		—		—		3 141
		Income taxes receivable	734	—		—		—		734
		Deferred income taxes	210	—		(210	)	—		—
		Assets held for sale ⁽⁵⁾	98	658		—		6		762

	Total current assets		10 513	658		(210	)	6		10 967
	Property, plant and equipment, net ⁽⁵⁾⁽⁶⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹⁰⁾⁽¹⁴⁾		55 290	—		(3 961	)	(1 371	)	49 958
	Exploration and evaluation		—	—		3 961		—		3 961
	Other assets		451	—		(221	)	—		230
	Goodwill		3 201	—		(3 201	)	—		—
	Goodwill and other intangible assets		—	—		3 422		—		3 422
	Deferred income taxes		56	—		13		—		69
	Assets of discontinued operations		658	(658	)	—		—		—

	Total assets		70 169	—		(197	)	(1 365	)	68 607

Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	2	—		1 982		—		1 984
		Current portion of long-term debt	518	—		—		—		518
		Accounts payable and accrued liabilities ⁽¹¹⁾⁽¹²⁾	6 942	—		(523	)	105		6 524
		Current portion of provisions	—	—		523		4		527
		Income taxes payable	929	—		—		—		929
		Deferred income taxes	37	—		(37	)	—		—
		Liabilities associated with assets held for sale ⁽⁵⁾⁽⁶⁾⁽¹⁴⁾	98	484		—		4		586

		Total current liabilities	8 526	484		1 945		113		11 068
	Long-term debt ⁽⁷⁾		11 669	—		(1 982	)	142		9 829
	Accrued liabilities and other		4 154	—		(4 154	)	—		—
	Other long-term liabilities ⁽¹¹⁾⁽¹²⁾		—	—		1 861		242		2 103
	Provisions ⁽⁵⁾⁽⁶⁾		—	—		2 293		211		2 504
	Deferred income taxes ⁽¹⁴⁾		8 615	—		(160	)	(544	)	7 911
	Liabilities of discontinued operations		484	(484	)	—		—		—
	Shareholders' equity ⁽⁵⁾⁽⁶⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹⁰⁾⁽¹¹⁾⁽¹²⁾⁽¹³⁾⁽¹⁴⁾		36 721	—		—		(1 529	)	35 192

	Total liabilities and shareholders' equity		70 169	—		(197	)	(1 365	)	68 607

Suncor Energy Inc.
060 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com


($ millions)			Previous GAAP ⁽¹⁾	Presentation Changes for Discontinued Operations ⁽²⁾		Other Presentation Changes ⁽³⁾		IFRS Adjustments ⁽⁴⁾		IFRS

Assets
	Current assets
		Cash and cash equivalents	602	—		—		—		602
		Accounts receivable	4 263	—		—		—		4 263
		Inventories	3 019	—		—		—		3 019
		Income taxes receivable	525	—		—		—		525
		Deferred income taxes	362	—		(362	)	—		—
		Assets held for sale	289	1 739		—		—		2 028

	Total current assets		9 060	1 739		(362	)	—		10 437
	Property, plant and equipment, net ⁽⁵⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹⁴⁾		54 473	—		(3 934	)	(1 566	)	48 973
	Exploration and evaluation		—	—		3 934		—		3 934
	Other assets		470	—		(229	)	—		241
	Goodwill		3 201	—		(3 201	)	—		—
	Goodwill and other intangible assets		—	—		3 430		—		3 430
	Deferred income taxes		2	—		17		—		19
	Assets of discontinued operations		1 739	(1 739	)	—		—		—

	Total assets		68 945	—		(345	)	(1 566	)	67 034

Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	2	—		2 320		—		2 322
		Current portion of long-term debt	39	—		—		—		39
		Accounts payable and accrued liabilities ⁽¹¹⁾⁽¹²⁾	6 040	—		(620	)	125		5 545
		Current portion of provisions	—	—		620		—		620
		Income taxes payable	1 151	—		—		—		1 151
		Deferred income taxes	26	—		(26	)	—		—
		Liabilities associated with assets held for sale ⁽⁵⁾⁽⁶⁾⁽¹⁴⁾	201	848		—		9		1 058

		Total current liabilities	7 459	848		2 294		134		10 735
	Long-term debt ⁽⁷⁾		13 730	—		(2 320	)	142		11 552
	Accrued liabilities and other		4 480	—		(4 480	)	—		—
	Other long-term liabilities ⁽¹¹⁾⁽¹²⁾		—	—		2 076		132		2 208
	Provisions ⁽⁵⁾⁽⁶⁾		—	—		2 404		266		2 670
	Deferred income taxes ⁽¹⁴⁾		8 155	—		(319	)	(589	)	7 247
	Liabilities of discontinued operations		848	(848	)	—		—		—
	Shareholders' equity ⁽⁵⁾⁽⁶⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹¹⁾⁽¹²⁾⁽¹³⁾⁽¹⁴⁾		34 273	—		—		(1 651	)	32 622

	Total liabilities and shareholders' equity		68 945	—		(345	)	(1 566	)	67 034


($ millions)			Previous GAAP ⁽¹⁾	Presentation Changes ⁽³⁾		IFRS Adjustments ⁽⁴⁾		IFRS

Assets
	Current assets
		Cash and cash equivalents	505	—		—		505
		Accounts receivable	3 936	—		—		3 936
		Inventories	2 971	—		—		2 971
		Income taxes receivable	587	—		—		587
		Deferred income taxes	332	(332	)	—		—

	Total current assets		8 331	(332	)	—		7 999
	Property, plant and equipment, net ⁽⁵⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹⁴⁾		57 485	(4 297	)	(1 632	)	51 556
	Exploration and evaluation		—	4 342		—		4 342
	Other assets		536	(277	)	—		259
	Goodwill		3 201	(3 201	)	—		—
	Goodwill and other intangible assets		—	3 433		—		3 433
	Deferred income taxes		193	17		—		210

	Total assets		69 746	(315	)	(1 632	)	67 799

Liabilities and Shareholders' Equity
	Current liabilities
		Short-term debt	2	2 315		—		2 317
		Current portion of long-term debt	25	—		—		25
		Accounts payable and accrued liabilities ⁽¹¹⁾⁽¹²⁾	6 529	(859	)	126		5 796
		Current portion of provisions	—	859		—		859
		Income taxes payable	1 274	—		—		1 274
		Deferred income taxes	18	(18	)	—		—

		Total current liabilities	7 848	2 297		126		10 271
	Long-term debt ⁽⁷⁾		13 855	(2 315	)	139		11 679
	Accrued liabilities and other		5 062	(5 062	)	—		—
	Other long-term liabilities ⁽¹¹⁾⁽¹²⁾		—	2 030		20		2 050
	Provisions ⁽⁵⁾		—	3 032		296		3 328
	Deferred income taxes ⁽¹⁴⁾		8 870	(297	)	(587	)	7 986
	Shareholders' equity ⁽⁵⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹¹⁾⁽¹²⁾⁽¹³⁾⁽¹⁴⁾		34 111	—		(1 626	)	32 485

	Total liabilities and shareholders' equity		69 746	(315	)	(1 632	)	67 799

Suncor Energy Inc.
062 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com


($ millions)		Previous GAAP ⁽¹⁾		Presentation Changes for Discontinued Operations ⁽²⁾		Other Presentation Changes ⁽³⁾		IFRS Adjustments ⁽⁴⁾		IFRS

Revenues and Other Income
	Operating revenues	33 278		911		(2 186	)	—		32 003
	Less: Royalties	(2 017	)	(41	)	2 058		—		—

	Operating revenues, net of royalties	31 261		870		(128	)	—		32 003
	Energy supply and trading activity income	2 700		—		—		—		2 700
	Interest and other income	389		—		110		—		499

		34 350		870		(18	)	—		35 202

Expenses
	Purchases of crude oil and products	14 911		(62	)	(18	)	—		14 831
	Operating, selling and general ⁽⁷⁾⁽¹¹⁾⁽¹²⁾	7 810		185		—		(11	)	7 984
	Energy supply and trading activity expenses	2 598		—		—		—		2 598
	Transportation	656		47		—		—		703
	Depreciation, depletion, amortization and impairment ⁽⁵⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾⁽¹⁰⁾	3 813		264		—		(274	)	3 803
	Accretion of asset retirement obligations	178		27		(205	)	—		—
	Exploration	197		21		—		—		218
	Gain on disposal of assets ⁽⁶⁾	(107	)	(814	)	—		(54	)	(975	)
	Project start-up costs	77		—		—		—		77
	Financing expenses (income) ⁽⁵⁾⁽⁷⁾	(30	)	18		205		(6	)	187

		30 103		(314	)	(18	)	(345	)	29 426

Earnings Before Income Taxes		4 247		1 184		—		345		5 776

Provisions for Income Taxes
	Current	1 004		192		—		—		1 196
	Deferred ⁽¹⁴⁾	555		109		—		87		751

		1 559		301		—		87		1 947

Net Earnings from Continuing Operations		2 688		883		—		258		3 829
Net Earnings from Discontinued Operations		883		(883	)	—		—		—

Net Earnings		3 571		—		—		258		3 829

Other Comprehensive Loss
	Foreign currency translation adjustment ⁽⁵⁾⁽¹¹⁾	(503	)	—		63		3		(437	)
	Foreign currency translation adjustment relating to assets held for sale ⁽⁶⁾	—		—		(63	)	—		(63	)
	Foreign currency translation reclassified to net earnings ⁽⁶⁾	53		—		—		(4	)	49
	Gain on cash flow hedges reclassified to net earnings	(1	)	—		—		—		(1	)
	Actuarial loss on defined benefit pension plans ⁽¹¹⁾⁽¹⁴⁾	—		—		—		(152	)	(152	)

Other Comprehensive Loss		(451	)	—		—		(153	)	(604	)

Total Comprehensive Income		3 120		—		—		105		3 225

Reconciliation of Comprehensive Income for the Three Months Ended March 31, 2010


($ millions)		Previous GAAP ⁽¹⁾		Presentation Changes for Discontinued Operations ⁽²⁾		Other Presentation Changes ⁽³⁾		IFRS Adjustments ⁽⁴⁾		IFRS

Revenues and Other Income
	Operating revenues	7 327		282		(479	)	—		7 130
	Less: Royalties	(459	)	(13	)	472		—		—

	Operating revenues, net of royalties	6 868		269		(7	)	—		7 130
	Energy supply and trading activity income	260		—		—		—		260
	Interest and other income	8		3		8		—		19

		7 136		272		1		—		7 409

Expenses
	Purchases of crude oil and products	3 428		—		1		—		3 429
	Operating, selling and general ⁽⁷⁾⁽¹¹⁾⁽¹²⁾	1 801		56		—		(6	)	1 851
	Energy supply and trading activity expenses	278		—		—		—		278
	Transportation	148		10		—		—		158
	Depreciation, depletion, amortization and impairment ⁽⁵⁾⁽⁷⁾⁽⁸⁾⁽⁹⁾	850		62		—		(64	)	848
	Accretion of asset retirement obligations	46		7		(53	)	—		—
	Exploration	46		2		—		—		48
	Gain on disposal of assets ⁽⁶⁾	(24	)	(231	)	—		(13	)	(268	)
	Project start-up costs	12		—		—		—		12
	Financing expenses (income) ⁽⁵⁾⁽⁷⁾	(190	)	8		53		(2	)	(131	)

		6 395		(86	)	1		(85	)	6 225

Earnings Before Income Taxes		741		358		—		85		1 184

Provisions for Income Taxes
	Current	168		79		—		—		247
	Deferred ⁽¹⁴⁾	98		38		—		22		158

		266		117		—		22		405

Net Earnings from Continuing Operations		475		241		—		63		779
Net Earnings from Discontinued Operations		241		(241	)	—		—		—

Net Earnings		716		—		—		63		779

Other Comprehensive Loss
	Foreign currency translation adjustment ⁽⁵⁾⁽¹¹⁾	(435	)	—		58		2		(375	)
	Foreign currency translation adjustment relating to assets held for sale ⁽⁶⁾	—		—		(58	)	1		(57	)
	Foreign currency translation reclassified to net earnings ⁽⁶⁾	6		—		—		(5	)	1
	Actuarial loss on employee retirement benefit plans ^(10)(14)	—		—		—		(84	)	(84	)

Other Comprehensive Loss		(429	)	—		—		(86	)	(515	)

Total Comprehensive Income		287		—		—		(23	)	264

Suncor Energy Inc.
064 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

There were no presentation changes made to the Consolidated Statements of Cash Flows.

Under Previous GAAP, increases in the estimated cash flows were discounted using the current credit-adjusted risk-free rate, while downward revisions in the estimated cash flows were discounted using the credit-adjusted risk-free rate that existed when the original liability was recognized. Under IFRS, estimated cash flows are discounted using the credit-adjusted risk-free rate that exists at the balance sheet date.

In accordance with IFRS 1, the company elected to remeasure its decommissioning and restoration costs at the Transition Date and has estimated the related asset by discounting the liability to the date in which the liability arose and recalculated the accumulated depreciation, depletion and amortization under IFRS. The impacts on the financial statements were as follows:


($ millions)	As at and for the year ended Dec 31, 2010		As at and for the three months ended Mar 31, 2010		As at Jan 1, 2010

Assets held for sale	6		—		—
Property, plant and equipment, net	(688	)	(681	)	(690	)
Liabilities associated with assets held for sale	27		14		—
Provisions	217		275		296
Foreign currency translation	1		1		—
Retained earnings	(927	)	(971	)	(986	)
Depreciation, depletion, amortization and impairment	(40	)	(10	)	—
Financing expenses (income)	(19	)	(5	)	—
Foreign currency translation adjustment	1		1		—

The net carrying values of disposed properties have been adjusted to reflect their respective IFRS adjustments, resulting in revised gains or losses upon disposal of the assets. The impacts on the financial statements were as follows:


($ millions)	As at and for the year ended Dec 31, 2010		As at and for the three months ended Mar 31, 2010		As at Jan 1, 2010

Property, plant and equipment, net	22		—		—
Liabilities associated with assets held for sale	(18	)	—		—
Provisions	(10	)	(9	)	—
Foreign currency translation	(4	)	(4	)	—
Retained earnings	54		13		—
Gain on disposal of assets	(54	)	(13	)	—
Foreign currency translation adjustment relating to assets held for sale	—		1		—
Foreign currency translation reclassified to net earnings	(4	)	(5	)	—

In accordance with IFRS 1, the company elected to evaluate whether certain arrangements contain a lease based on the facts and circumstances existing at Transition Date. Pursuant to such evaluation, the company has accounted for certain arrangements as finance leases under IFRS. The impacts on the financial statements were as follows:

Under Previous GAAP, carrying amounts of property, plant and equipment assets were derecognized when no future economic benefits were expected from their use. Under IFRS, this derecognition of assets occurs at the component level. The impacts on the financial statements were as follows:

Suncor Energy Inc.
066 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

The company has applied the IFRS 1 election to record certain assets of property, plant and equipment at fair value on the Transition Date. The exemption has been applied to refinery assets located in Eastern Canada and certain natural gas assets in Western Canada. When estimating fair value, market information for similar assets was used, and where market information was not available, management relied on internally generated cash flow models using discount rates specific to the asset and long-term forecasts of commodity prices and refining margins. The aggregate of these fair values was $1.370 billion, resulting in a reduction of the carrying amount of property, plant and equipment as at January 1, 2010. Under Previous GAAP, impairment losses were recorded in the third quarter of 2010 for certain of these natural gas properties. There were no impairment losses recognized during 2010 under IFRS, as these properties were adjusted to fair value at the Transition Date. The impacts on the financial statements were as follows:

Under Previous GAAP, an item of property, plant and equipment is deemed recoverable if the undiscounted future cash flows exceed the net carrying amount of the asset group. Under IFRS, recoverability of property, plant and equipment is based on the higher of fair value less costs to sell and value in use of the CGU.

Under IFRS, the company recognized impairment losses for certain CGUs within the Exploration and Production operating segment during 2010. The impaired natural gas assets are located within the Western Canadian Sedimentary Basin and were grouped into CGUs based on similar geological structure, shared infrastructure and similar exposure to market risks. Declining long-term natural gas prices have resulted in the carrying amounts for these CGUs exceeding their recoverable amounts. Recoverable amounts have been determined using the fair value less costs to sell method and based on internally generated cash flow projections. In determining fair value less costs to sell, the company considered recent transactions within the industry, long-term views of natural gas prices, externally evaluated reserve volumes, and discount rates specific to the asset. The impacts on the financial statements were as follows:

Under Previous GAAP, unamortized actuarial gains and losses in respect of the company's defined benefit pension plans were recognized into earnings over the expected average remaining service life of employees. In accordance with IFRS 1, the company has elected to recognize all cumulative actuarial gains and losses directly in Retained Earnings at the Transition Date. Under IFRS, actuarial gains and losses incurred in the period are recorded in Other Comprehensive Income and then transferred directly to Retained Earnings.

Under Previous GAAP, benefits are attributed to individual accounting periods for other post-retirement benefit plans commencing on the date of hire and ending when further service by the employee will lead to no benefits under the plan. Under IFRS, the company will attribute benefits on a straight-line basis from the date when service by the employee first leads to benefits under the plan and end at the same date as under Previous GAAP. The impacts on the financial statements were as follows:


($ millions)	As at and for the year ended Dec 31, 2010		As at and for the three months ended Mar 31, 2010		As at Jan 1, 2010

Accounts payable and accrued liabilities	10		15		15
Other long-term liabilities	215		122		15
Foreign currency translation	2		1		—
Retained earnings	(227	)	(138	)	(30	)
Operating, selling and general	(4	)	(5	)	—
Foreign currency translation adjustment	2		1		—
Actuarial loss on defined benefit pension plans	(201	)	(113	)	—

Under Previous GAAP, the company recorded obligations for cash-settled share-based compensation plans using the intrinsic value method. Under IFRS, obligations for these same plans are recorded as a liability using the fair value method. For equity-settled share-based compensations plans, the company accrues the cost of employee stock options over the vesting period using the graded method of amortization rather than the straight-line method, which the company used under Previous GAAP. The impacts on the financial statements were as follows:

In accordance with IFRS 1, the company elected at the Transition Date to transfer all foreign currency translation differences in respect of foreign operations that arose prior to the Transition Date to Retained Earnings. The impacts on the financial statements were as follows:

Suncor Energy Inc.
068 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

The company recognized deferred income taxes primarily in respect of the above changes. The impacts on the financial statements were as follows:

In November 2009, as part of the International Accounting Standards Board's (IASB) project to replace International Accounting Standard (IAS) 39 Financial Instruments: Recognition and Measurement, the IASB issued the first phase of IFRS 9 Financial Instruments, that introduces new requirements for the classification and measurement of financial assets. The standard was revised in October 2010 to include requirements regarding classification and measurement of financial liabilities and is applicable for annual periods starting on or after January 1, 2013. The full impact of the changes in accounting for financial instruments will not be known until the IASB's project has been completed.

The company's operating segments are determined based on differences in the nature of their operations, products and services.

In the first quarter of 2011, the company combined its International and Offshore and Natural Gas segments into one new segment, Exploration and Production. All prior periods have been reclassified to conform to these segment definitions.

Intersegment sales of crude oil and natural gas are accounted for at market values and included, for segmented reporting, in revenues of the segment making the transfer and expenses of the segment receiving the transfer. Intersegment amounts are eliminated on consolidation.


Three months ended March 31
	Oil Sands				Exploration and Production				Refining and Marketing				Corporate, Energy Trading and Eliminations				Total
($ millions)	2011		2010		2011		2010		2011		2010		2011		2010		2011		2010

Revenues and Other Income
Operating revenues (including royalties)	2 159		1 168		1 606		1 618		6 037		4 732		9		84		9 811		7 602
Intersegment revenue	1 040		627		209		213		42		86		(1 291	)	(926	)	—		—
Less: Royalties	(123	)	(70	)	(432	)	(402	)	—		—		—		—		(555	)	(472	)

Operating revenues (net of royalties)	3 076		1 725		1 383		1 429		6 079		4 818		(1 282	)	(842	)	9 256		7 130
Energy supply and trading activity income	—		—		—		—		—		—		521		260		521		260
Interest and other income	1		175		3		2		37		(8	)	27		(150	)	68		19

	3 077		1 900		1 386		1 431		6 116		4 810		(734	)	(732	)	9 845		7 409

Expenses
Purchases of crude oil and products	364		245		120		54		4 535		3 936		(1 212	)	(806	)	3 807		3 429
Operating, selling and general	1 320		1 162		236		191		575		505		160		(7	)	2 291		1 851
Energy supply and trading activity expenses	—		—		—		—		—		—		457		278		457		278
Transportation	80		63		32		56		59		45		(9	)	(6	)	162		158
Depreciation, depletion, amortization and impairment	311		259		354		470		102		109		18		10		785		848
Exploration	40		5		18		43		—		—		—		—		58		48
Loss (gain) on disposal of assets	112		9		146		(280	)	(6	)	3		(1	)	—		251		(268	)
Project start-up costs	37		10		—		2		—		—		—		—		37		12
Financing expenses (income)	18		26		25		23		6		5		(98	)	(185	)	(49	)	(131	)

	2 282		1 779		931		559		5 271		4 603		(685	)	(716	)	7 799		6 225

Earnings (Loss) Before Income Taxes	795		121		455		872		845		207		(49	)	(16	)	2 046		1 184
Income taxes	190		32		641		344		218		60		(31	)	(31	)	1 018		405

Net earnings (loss)	605		89		(186	)	528		627		147		(18	)	15		1 028		779

Suncor Energy Inc.
070 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

The following table summarizes the share-based compensation expense (recovery) recorded for all plans within Operating, Selling and General expense in the Consolidated Statements of Comprehensive Income.


		Three months ended March 31
($ millions)		2011		2010

Interest on debt		161		187
Capitalized interest		(100	)	(76	)

	Interest expense	61		111
	Accretion of liabilities	38		48
	Foreign exchange gain on U.S. dollar denominated long-term debt	(186	)	(260	)
	Other foreign exchange loss (gain)	38		(30	)

Total financing expenses (income)		(49	)	(131	)


		Three months ended March 31
($ millions)		2011	2010

Net earnings		1 028	779
(millions of common shares)
Weighted-average number of common shares		1 570	1 561
Dilutive securities:
	Effect of share options	11	15

Weighted-average number of diluted common shares		1 581	1 576

(dollars per common share)
Basic earnings per share		0.65	0.50

Diluted earnings per share		0.65	0.46

Options with tandem stock appreciation rights or cash payment alternatives are accounted for as cash-settled plans. As these awards can be exchanged for common shares of the company, they are considered potentially dilutive and are included in the calculation of the company's diluted net earnings per share calculation if they have a dilutive impact in the period.

Accounting for these awards as cash-settled was determined to have the most dilutive impact for the three months ended March 31, 2011, and thus no adjustment to net earnings was required. For the three months ended March 31, 2010, accounting for these awards as equity-settled was more dilutive. As a result, a $47 million reduction to net earnings was made in the diluted earnings per share calculation for that period to account for these awards as if they were equity-settled plans.

During 2011 and 2010, the company divested certain non-core assets as part of its continuing strategic alignment.

In the first quarter of 2011, the company completed the sale of certain non-core U.K. offshore assets for net proceeds of £105 million (Cdn$164 million).

At March 31, 2011, the company classified certain non-core natural gas properties located in Western Canada as assets held for sale.


($ millions)		March 31 2011	December 31 2010	January 1 2010

Assets
	Current assets	6	98	—
	Property, plant and equipment, net	87	635	—
	Exploration and evaluation	1	29	—

	Total assets	94	762	—

Liabilities
	Current liabilities	4	98	—
	Provisions	31	311	—
	Deferred income taxes	—	177	—

	Total liabilities	35	586	—

In the first quarter of 2010, the company completed the sale of its oil and gas producing assets in the U.S. Rockies for net proceeds of US$481 million (Cdn$502 million).

In the second quarter of 2010, the company completed the sale of non-core natural gas properties located in northeast British Columbia (Blueberry and Jedney) for net proceeds of $383 million, and non-core assets in central Alberta (Rosevear and Pine Creek) for net proceeds of $229 million.

In the third quarter of 2010, the company completed the sales of assets in Trinidad and Tobago for net proceeds of US$378 million (Cdn$383 million), and the sale of its shares in Petro-Canada Netherlands BV for net proceeds of €316 million (Cdn$420 million). The company also completed the sale of non-core natural gas properties located in west central Alberta (Bearberry and Ricinus) for net proceeds of $275 million, and non-core assets in southern Alberta (Wildcat Hills) for net proceeds of $351 million.

In the fourth quarter of 2010, the company completed the sale of certain non-core U.K. offshore assets for net proceeds of £55 million (Cdn$86 million).

Suncor Energy Inc.
072 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com

Goodwill acquired through business combinations has been allocated to groups of CGUs within Oil Sands and Refining and Marketing. Indefinite-lived intangible assets acquired through business combinations have been allocated to groups of CGUs within Refining and Marketing. Key assumptions and methodology used to determine recoverable amounts for groups of CGUs with significant amounts of goodwill or intangible assets are discussed below.

The company performed its last annual test for impairment as of July 31, 2010. Recoverable amounts for the Oil Sands CGUs were based on fair value less costs to sell calculated using the present value of the CGUs' expected future cash flows. The primary sources of cash flow information are derived from business plans approved by executives of the company, which were developed based on macroeconomic factors such as forward price curves for benchmark commodities, inflation rates and industry supply-demand fundamentals. When required, the projected cash flows in the business plan have been updated to reflect current market assessments of key assumptions including long-term forecasts of commodity prices, inflation rates, foreign exchange rates and discount rates specific to the asset.

Cash flow forecasts are also based on past experience, historical trends and third-party evaluations of the company's reserves and resources to determine production profiles and volumes, operating costs, maintenance and capital expenditures. Production profiles and reserve volumes are consistent with the estimates approved through the company's annual reserve evaluation process and determine the term of the underlying cash flows used in the discounted cash flow test. The associated operating and capital costs to produce these reserves are based on past experience and specific characteristics of the reservoir.

Future cash flow estimates are adjusted to reflect risks specific to the asset and discounted using after-tax discount rates. The discount rate is calculated based on the weighted-average cost of capital that is implicit in current market transactions for similar assets. The after-tax discount rate applied to cash flow projections was 11% at July 31, 2010 (January 1, 2010 – 11%) with a conservative growth rate equal to the current inflation rate of 2% (January 1, 2010 – 2%). As a result of this analysis, management did not identify impairment within the Oil Sands operating segment and the associated allocated goodwill.

In March 2011, the U.K. government substantively enacted a 12% increase in the supplementary charge on U.K. oil and gas profits. Accordingly, the company recognized an increase in deferred tax expense of $442 million related to the revaluation of deferred income tax balances.

On March 22, 2011, Suncor closed the previously announced transaction to enter into a joint venture with Total E&P Company Ltd. (Total). The two companies plan to develop the Fort Hills and Joslyn oil sands mining projects together with the other project partners, and restart the construction of the Voyageur upgrader.

As a result of this transaction, Suncor acquired a 36.75% interest in Joslyn for consideration of $842 million after closing adjustments. Total acquired a 49% interest in Voyageur, a 19.2% increase in its interest in Fort Hills (reducing Suncor's interest from 60% to 40.8%), and rights to proprietary mining technology, for cash consideration of $2.662 billion after closing adjustments.

Overall, Suncor recognized a loss of $112 million related to the disposition of its interests in Voyageur and Fort Hills and the technology sale. The loss included the derecognition of $267 million of goodwill associated with the disposed interests in Fort Hills and Voyageur.

In March 2011, the company shut-in its Libyan production and ceased operations there as a result of the political violence.

At March 31, 2011, the company had not recorded any impairment adjustments related to these assets. The company is continuing to assess and evaluate its assets in Libya for potential impairment.

The carrying value of the company's net assets in Libya at March 31, 2011 was approximately $900 million.

Suncor Energy Inc.
074 2011 First Quarter For more information about Suncor Energy, visit our website www.suncor.com


Total Assets ($ millions)	Mar 31 2011	Dec 31 2010	Jan 1 2010

Oil Sands	38 723	39 382	36 657
Exploration and Production	14 495	15 899	19 218
Refining and Marketing	12 400	11 292	9 748
Corporate, Energy Trading and Eliminations	4 025	2 034	2 176

Total	69 643	68 607	67 799