EXHIBIT 99.3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the three
months ended March 31, 2007

Consolidated statements of earnings
(unaudited)

	Three months ended March 31
($ millions)	2007		2006
Revenues (note 4)	3 951		3 858
Expenses
Purchases of crude oil and products	1 138		951
Operating, selling and general (notes 4 and 7)	840		772
Energy marketing and trading activities (note 4)	571		262
Transportation and other costs	46		51
Depreciation, depletion and amortization	190		158
Accretion of asset retirement obligations	12		8
Exploration	32		31
Royalties (note 10)	189		329
Taxes other than income taxes	158		140
Gain on disposal of assets	—		(4	)
Project start-up costs	3		21
Financing expenses (note 5)	(11	)	7
	3 168		2 726
Earnings Before Income Taxes	783		1 132
Provision for (Recovery of) Income Taxes
Current	162		(1	)
Future	70		420
	232		419
Net Earnings	551		713
Per Common Share (dollars), (note 6)
Basic	1.20		1.56
Diluted	1.17		1.52
Cash dividends	0.08		0.06

See accompanying notes.

Consolidated balance sheets
(unaudited)

	March 31	December 31
	2007	2006
($ millions)		(note 2)
Assets
Current assets
Cash and cash equivalents	468	521
Accounts receivable (notes 2 and 4)	1 194	1 050
Inventories	600	589
Income taxes receivable	—	33
Future income taxes	64	109
Total current assets	2 326	2 302
Property, plant and equipment, net	17 122	16 189
Deferred charges and other (notes 2 and 4)	306	290
Total assets	19 754	18 781
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	6	7
Accounts payable and accrued liabilities (notes 2, 4 and 10)	2 082	2 111
Taxes other than income taxes	50	40
Income taxes payable	109	—
Total current liabilities	2 247	2 158
Long-term debt	2 740	2 385
Accrued liabilities and other (notes 2 and 4)	1 178	1 214
Future income taxes (notes 2 and 4)	4 100	4 072
Shareholders’ equity (see below)	9 489	8 952
Total liabilities and shareholders’ equity	19 754	18 781

Shareholders’ Equity

	Number			Number
	(thousands)			(thousands)
Share capital	460 219	804		459 944	794
Contributed surplus		116			100
Accumulated other comprehensive income (notes 2 and 4)		(80	)		(71	)
Retained earnings (note 2)		8 649			8 129
Total shareholders’ equity		9 489			8 952

See accompanying notes.

Consolidated statements of cash flows
(unaudited)

	Three months ended March 31
($ millions)	2007		2006
Operating Activities
Cash flow from operations	790		1 314
Decrease (increase) in operating working capital
Accounts receivable	(139	)	(417	)
Inventories	(11	)	76
Accounts payable and accrued liabilities	(87	)	(241	)
Taxes payable	152		(16	)
Cash flow from operating activities	705		716
Cash Used in Investing Activities	(1 100)		(657	)
Net Cash Surplus (Deficiency) Before Financing Activities	(395	)	59
Financing Activities
Decrease in short-term debt	(1	)	(20	)
Proceeds from issuance of long-term debt	601		—
Net decrease in long-term debt	(231	)	(94	)
Issuance of common shares under stock option plan	5		22
Dividends paid on common shares	(33	)	(25	)
Deferred revenue	3		10
Cash provided by (used in) financing activities	344		(107	)
Increase (Decrease) in Cash and Cash Equivalents	(51	)	(48	)
Effect of Foreign Exchange on Cash and Cash Equivalents	(2	)	—
Cash and Cash Equivalents at Beginning of Period	521		165
Cash and Cash Equivalents at End of Period	468		117

See accompanying notes.

Consolidated statements of changes in shareholders’ equity
(unaudited)

($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings		Accumulated Other Comprehensive Income (AOCI)
At December 31, 2005, as previously reported	732	50		(81	)	5 295		—
Retroactive adjustment for change in accounting policy (note 2)	—	—		81		—		(81	)
At December 31, 2005, as restated	732	50		—		5 295		(81	)
Net earnings	—	—		—		713		—
Dividends paid on common shares	—	—		—		(25	)	—
Issued for cash under stock option plan	25	(3	)	—		—		—
Issued under dividend reinvestment plan	2	—		—		(2	)	—
Stock-based compensation expense	—	9		—		—		—
Change in AOCI related to foreign currency translation	—	—		—		—		3
At March 31, 2006	759	56		—		5 981		(78	)
At December 31, 2006, as previously reported	794	100		(71	)	8 129		—
Retroactive adjustment for change in accounting policy (note 2)	—	—		71		—		(71	)
At December 31, 2006, as restated	794	100		—		8 129		(71	)
Net earnings	—	—		—		551		—
Dividends paid on common shares	—	—		—		(33	)	—
Issued for cash under stock option plan	7	(2	)	—		—		—
Issued under dividend reinvestment plan	3	—		—		(3	)	—
Stock-based compensation expense	—	18		—		—		—
Adjustment to opening retained earnings arising from ineffective portion of cash flow hedges at January 1, 2007	—	—		—		5		—
Adjustment to opening AOCI arising from effective portion of cash flow hedges at January 1, 2007	—	—		—		—		8
Change in AOCI related to foreign currency translation	—	—		—		—		(13	)
Change in AOCI related to derivative hedging activities	—	—		—		—		(4	)
At March 31, 2007	804	116		—		8 649		(80	)

See accompanying notes.

Schedules of segmented data
(unaudited)

	Three months ended March 31
	Oil Sands				Natural Gas				Refining and Marketing (note 3)				Corporate and Eliminations				Total
($ millions)	2007		2006		2007		2006		2007		2006		2007		2006		2007		2006
EARNINGS
Revenues
Operating revenues	1 443		1 550		144		174		1 786		1 478		2		1		3 375		3 203
Energy marketing and trading activities	—		—		—		—		571		274		(1	)	(5	)	570		269
Net insurance proceeds	—		385		—		—		—		—		—		—		—		385
Intersegment revenues	151		185		—		6		—		—		(151	)	(191	)	—		—
Interest	—		—		—		—		3		—		3		1		6		1
	1 594		2 120		144		180		2 360		1 752		(147	)	(194	)	3 951		3 858
Expenses
Purchases of crude oil and products	9		3		—		—		1 279		1 141		(150	)	(193	)	1 138		951
Operating, selling and general (note 3)	612		526		38		26		175		174		15		46		840		772
Energy marketing and trading activities	—		—		—		—		573		266		(2	)	(4	)	571		262
Transportation and other costs	32		37		7		6		7		8		—		—		46		51
Depreciation, depletion and amortization	100		93		41		34		39		24		10		7		190		158
Accretion of asset retirement obligations	10		7		2		1		—		—		—		—		12		8
Exploration	13		22		19		9		—		—		—		—		32		31
Royalties (note 10)	157		285		32		44		—		—		—		—		189		329
Taxes other than income taxes	21		21		—		—		137		119		—		—		158		140
Gain on disposal of assets	—		—		—		(4	)	—		—		—		—		—		(4	)
Project start-up costs	2		21		—		—		1		—		—		—		3		21
Financing expenses	—		—		—		—		—		—		(11	)	7		(11	)	7
	956		1 015		139		116		2 211		1 732		(138	)	(137	)	3 168		2 726
Earnings (loss) before income taxes	638		1 105		5		64		149		20		(9	)	(57	)	783		1 132
Income taxes	(185	)	(398	)	(1	)	(24	)	(50	)	(9	)	4		12		(232	)	(419	)
Net earnings (loss)	453		707		4		40		99		11		(5	)	(45	)	551		713

As at March 31

TOTAL ASSETS	14 365		12 096		1 716		1 367		4 040		3 352		(367	)	(734	)	19 754		16 081

Schedules of segmented data (continued)
(unaudited)

													Three months ended March 31
	Oil Sands				Natural Gas				Refining and Marketing (note 3)				Corporate and Eliminations				Total
($ millions)	2007		2006		2007		2006		2007		2006		2007		2006		2007		2006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	453		707		4		40		99		11		(5	)	(45	)	551		713
Exploration expenses	—		—		15		5		—		—		—		—		15		5
Non-cash items included in earnings
Depreciation, depletion and amortization	100		93		41		34		39		24		10		7		190		158
Future income taxes	42		398		—		24		27		9		1		(11	)	70		420
Gain on disposal of assets	—		—		—		(4	)	—		—		—		—		—		(4	)
Stock-based compensation expense	8		4		1		1		5		2		4		2		18		9
Other	(20	)	12		3		—		2		8		(33	)	1		(48	)	21
Increase (decrease) in deferred credits and other	(5	)	(5	)	—		—		(1	)	(3	)	—		—		(6	)	(8	)
Total cash flow from (used in) operations	578		1 209		64		100		171		51		(23	)	(46	)	790		1314
Decrease (increase) in operating working capital	13		(200	)	13		18		(36	)	(63	)	(75	)	(353	)	(85	)	(598	)
Total cash flow from (used in) operating activities	591		1 009		77		118		135		(12	)	(98	)	(399	)	705		716
Cash from (used in) investing activities:
Capital and exploration expenditures	(793	)	(407	)	(275	)	(115	)	(57	)	(226	)	(6	)	(4	)	(1 131	)	(752	)
Deferred maintenance shutdown expenditures	—		—		(1	)	—		(1	)	(42	)	—		—		(2	)	(42	)
Deferred outlays and other investments	—		—		—		—		—		—		(1	)	(2	)	(1	)	(2	)
Proceeds from disposals	—		—		—		13		—		—		—		—		—		13
Decrease (increase) in investing working capital	73		117		—		—		(39	)	9		—		—		34		126
Total cash (used in) investing activities	(720	)	(290	)	(276	)	(102	)	(97	)	(259	)	(7	)	(6	)	(1 100)		(657	)
Net cash surplus (deficiency) before financing activities	(129	)	719		(199	)	16		38		(271	)	(105	)	(405	)	(395	)	59

Notes to the consolidated financial statements
(unaudited)

1. ACCOUNTING POLICIES

These interim consolidated financial statements have been prepared in accordance with Canadian generally accepted accounting principles and follow the same accounting policies and methods of computation as, and should be read in conjunction with, the most recent annual financial statements, except for the accounting policy changes as described in note 2, Changes in Accounting Policies and note 3, Change in Segmented Disclosures.

In the opinion of management, these interim consolidated financial statements contain all adjustments of a normal and recurring nature necessary to present fairly Suncor Energy Inc.’s (Suncor) financial position at March 31, 2007 and the results of its operations and cash flows for the three month periods ended March 31, 2007 and 2006.

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

2. CHANGES IN ACCOUNTING POLICIES

Financial Instruments

On January 1, 2007 the company adopted CICA Handbook Section 3855 “Financial Instruments, Recognition and Measurement”, Section 1530 “Comprehensive Income” and Section 3865 “Hedging”. These sections establish the accounting and reporting standards for financial instruments and hedging activities, and require the initial recognition of financial instruments at fair value on the balance sheet. The comparative interim consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment.

Transaction costs and the related cash flow impacts are included in the fair value assessments of each financial asset and financial liability instrument.

Generally, all derivatives, whether designated in hedging relationships or not, excluding those considered as normal purchases and normal sales, are required to be recorded on the balance sheet at fair value. If the derivative is designated as a fair value hedge each period, 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 the Consolidated Statements of Earnings. If the derivative is designated as a cash flow hedge each period, the effective portions of the changes in fair value of the derivative are initially recorded in other comprehensive income and are recognized in the Consolidated Statements of Earnings when the hedged item is recognized. Ineffective portions of changes in the fair value of hedging instruments are recognized in the Consolidated Statements of 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 Consolidated Statement of Earnings caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations. The company uses these valuations to estimate the fair values of the underlying physical commodity contracts.

In addition to containing the effective portions of the gains/losses on our cash flow hedges, the accumulated other comprehensive income account will also contain the cumulative foreign currency translation adjustment of our foreign operations.

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

Financial Assets		$42 million
Financial Liabilities		$29 million
Retained Earnings		$5 million
Accumulated Other Comprehensive Loss		$63 million

The comparative interim consolidated financial statements have not been restated, except for the presentation of the cumulative foreign currency translation adjustment of $71 million.

Additional disclosure requirements for financial instruments have been approved by the CICA, and will be required disclosure for the company beginning January 1, 2008.

See Note 4 for a summary of financial instrument disclosures at March 31, 2007.

3. CHANGE IN SEGMENTED DISCLOSURES

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

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

4. FINANCIAL INSTRUMENTS

Balance Sheet Financial Instruments

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

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

The company’s fixed-term debt is accounted for under the amortized cost method. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. At March 31, 2007, the carrying value of our fixed-term debt was $2.4 billion (fair value – $2.6 billion).

Hedges

Fair Value Hedges

The company periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to minimize exposure to changes in cash flows of interest-bearing debt. At March 31, 2007, the company had interest rate derivatives classified as fair value hedges outstanding for up to five years relating to fixed rate debt.

There was no ineffectiveness recognized on derivative contracts designated as fair value hedges during the three month period ended March 31, 2007.

Cash Flow Hedges

Suncor operates in a global industry where the market price of its produced 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. The company also manages variability in market interest rates during periods of debt issuance through the use of interest rate swap transactions.

At March 31, 2007, the company had hedged a portion of its forecasted Canadian and U.S. dollar denominated cash flows subject to U.S. dollar WTI commodity risk for 2007 and 2008, as well as cash flows related to natural gas production and refinery operations in 2007 and 2008, and a portion of its Euro currency exposure created by the anticipated purchase of equipment payable in Euros in 2007.

The earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the three month period ended March 31, 2007 was a gain of $2 million.

For the three month period ended March 31, 2007, assets increased by $20 million and liabilities increased by $9 million as a result of recording derivative instruments at fair value in accordance with the new standards.

The fair value of hedging derivative financial instruments as recorded, is the estimated amount, based on broker quotes and/or internal valuation models, that the company would receive (pay) to terminate the contracts. Such amounts were as follows:

	March 31	December 31
($ millions)	2007	2006
Revenue hedge swaps and collars	6	22
Interest rate and cross-currency interest rate swaps	13	16
Specific cash flow hedges of individual transactions	2	(4)
Fair value of outstanding hedging derivative financial instruments	21	34

Accumulated Other Comprehensive Income (OCI)

A reconciliation of changes in accumulated OCI attributable to derivative hedging activities for the three month period ending March 31, 2007 is as follows:

($ millions)		2007
OCI attributable to derivatives and hedging activities, recorded upon initial adoption, net of income taxes of $5		8
Current period net changes arising from cash flow hedges, net of income taxes of $5		(5)
Net unrealized hedging gains at the beginning of the period reclassified to earnings during the period, net of income taxes of $1		1
OCI attributable to derivatives and hedging activities, end of period, net of income taxes of $1		4

Energy Marketing and Trading Activities

In addition to the financial derivatives used for hedging activities, the company uses physical and financial energy contracts, including swaps, forwards and options, to earn trading and marketing revenues. These energy 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 three month period ended March 31 were as follows:

Net Pretax Earnings (Loss)

	Three months ended March 31
($ millions)	2007		2006
Physical energy contracts trading activity	3		10
Financial energy contracts trading activity	(4	)	(1)
General and administrative costs	(1	)	(1)
Total	(2	)	8

The fair value of unsettled (unrealized) financial energy trading assets and liabilities are as follows:

	March 31	December 31
($ millions)	2007	2006
Energy trading assets	3	16
Energy trading liabilities	10	13
Net energy trading assets (liabilities)	(7)	3

Change in Fair Value of Net Assets

($ millions)		2007
Fair value of contracts outstanding at December 31, 2006		3
Fair value of contracts realized during the period		(6)
Fair value of contracts entered into during the period		(5)
Changes in values attributable to market price and other market changes		1
Fair value of contracts outstanding at March 31, 2007		(7)

The source of the valuations of the above contracts is based on actively quoted prices and/or internal model valuations.

5. FINANCING EXPENSES

	Three months ended March 31
($ millions)	2007		2006
Interest on debt	38		39
Capitalized interest	(38	)	(33	)
Net interest expense	—		6
Foreign exchange loss (gain) on long-term debt	(12	)	1
Other foreign exchange gain	1		—
Total financing expenses (income)	(11	)	7

6. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Three months ended March 31
($ millions)	2007	2006
Net earnings	551	713

(millions of common shares)
Weighted-average number of common shares	460	458
Dilutive securities:
Options issued under stock-based compensation plans	11	12
Weighted-average number of diluted common shares	471	470

(dollars per common share)
Basic earnings per share(a)	1.20	1.56
Diluted earnings per share(b)	1.17	1.52

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 net earnings divided by the weighted-average number of common shares.

(b) Diluted earnings per share is net earnings, divided by the weighted-average number of diluted common shares.

7. STOCK-BASED COMPENSATION

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

After the date of grant, employees that hold options must earn the right to exercise them. This is done by the employee fulfilling a time requirement for service to the company, and with respect to certain options, is subject to accelerated vesting should the company meet predetermined performance criteria. 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 option is granted.

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

(a) Stock Option Plans

Under the SunShare long-term incentive plan, the company granted 312,000 options to new employees in the first quarter of 2007 (260,000 options granted during the first quarter of 2006).

On April 30, 2008, 50% of the outstanding, unvested SunShare options will vest. 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 criteria 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 therefore vest. Stock-based compensation expense has been recorded to reflect this assumption.

Under the company’s other plans, 1,615,000 options were granted in the first quarter of 2007 (1,509,000 options granted during the first quarter of 2006).

The fair values of all common share options granted during the period 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 various periods and the weighted-average assumptions used in their determination are as noted below:

	Three months ended March 31
	2007		2006
Quarterly dividend per share	$	0.08	$	0.06
Risk-free interest rate	4.08%		4.08%
Expected life	6 years		6 years
Expected volatility	28%		29%
Weighted-average fair value per option	$	28.85	$	32.30

Stock-based compensation expense recognized in the first quarter of 2007 related to stock options plans was $18 million (2006 – $9 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:

	Three months ended March 31
($ millions, except per share amounts)	2007	2006
Net earnings – as reported	551	713
Less: compensation cost under the fair value method for pre-2003 options	3	2
Pro forma net earnings	548	711
Basic earnings per share
As reported	1.20	1.56
Pro forma	1.19	1.55
Diluted earnings per share
As reported	1.17	1.52
Pro forma	1.16	1.51

(b) Performance Share Units (PSUs)

In the first quarter of 2007 the company issued 399,000 (2006 – 390,000) PSUs. Expense recognized in the first quarter of 2007 was $19 million (2006 – $24 million).

8. EMPLOYEE FUTURE BENEFITS LIABILITY

The company’s pension plans and other post-retirement benefits programs are described in note 8 of the company’s 2006 Annual Report. The following is the status of the net periodic benefit cost for the three months ended March 31.

	Pension Benefits				Other Post-retirement Benefits
	2007		2006		2007	2006
Current service costs	13		11		1	1
Interest costs	11		10		2	2
Expected return on plan assets	(11	)	(8	)	—	—
Amortization of net actuarial loss	6		7		—	—
Net periodic benefit cost	19		20		3	3

9. SUPPLEMENTAL INFORMATION

	Three months ended March 31
($ millions)	2007	2006
Interest paid	55	53
Income taxes paid	17	11

Revenue Hedges

Strategic Crude Oil at March 31, 2007

	Quantity	Average Price	Revenue Hedged	Hedge
	(bpd)	(US$/bbl)(a)	(Cdn$ millions)(b)	Period	(c)
Costless collars	60 000	51.64 – 93.26	982 – 1 774	2007
Costless collars	10 000	59.85 – 101.06	253 – 426	2008

Natural Gas at March 31, 2007

	Quantity	Average Price	Revenue Hedged	Hedge
	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period	(c)
Swaps	4 000	6.11	7	2007
Costless collars	10 000	7.00 – 7.90	6 – 7	2007	(d)
Costless collars	5 000	7.00 – 8.05	7 – 9	2007	(e)
Costless collars	5 000	7.25 – 8.92	8 – 10	2007	(f)

Foreign Currency Hedges at March 31, 2007

	Notional	Average	Dollars Hedged	Hedge
	(Euro millions)	Forward Rate	(Cdn$ millions)	Period	(c)
Euro/Cdn forwards	21	1.41	29	2007	(g)

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

(b) The revenue and margin hedged is translated to Cdn$ at the March 31, 2007 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(d) For the period August to October 2007, inclusive.

(e) For the period April to October 2007, inclusive.

(f) For the period April to October 2007, inclusive.

(g) Settlements for applicable forwards occurring within the period April to September 2007.

10. ROYALTY ESTIMATE MEASUREMENT UNCERTAINTY

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.

Oil Sands royalties payable in 2007 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, foreign exchange rates and total capital and operating costs for each project. Oil Sands pretax royalty estimate was $157 million ($110 million after tax) for the first three months of 2007 compared to $285 million ($182 million after tax) for the first three months of 2006. We estimate 2007 annualized Crown Royalties to be approximately $665 million ($465 million after tax) based on three months of actual results together with 2007 forward crude oil pricing of US$63.14 per barrel as at March 31, 2007; current forecasts of production, capital and operating costs for the remainder of 2007; and a Canadian/US foreign exchange rate of $0.87. Accordingly, actual results will differ, and these differences may be material. The balance of the consolidated royalty expense is in respect of natural gas royalties of $32 million ($26 million after tax).

11. LONG-TERM DEBT AND CREDIT FACILITIES

On March 5, 2007, the company repaid maturing 6.80% $250 million Medium Term Notes. The company used commercial paper to repay the notes.

On March 26, 2007, the company issued 5.39% Medium Term Notes with a principal amount of $600 million, under an outstanding $2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on March 26, 2037. The net proceeds received were used to repay commercial paper.

At March 31, 2007, undrawn lines of credit were approximately $1,767 million, 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		563
Total undrawn credit facilities		1 767

As at March 31, 2007, the company had issued $265 million in letters of credit to various third parties and had outstanding commercial paper of $298 million.

Highlights

(unaudited)

	2007		2006
Cash Flow from Operations
(dollars per common share — basic)
For the three months ended March 31
Cash flow from operations(1)	1.72		2.87
Ratios
For the twelve months ended March 31
Return on capital employed (%)(2)	35.1		28.5
Return on capital employed (%)(3)	26.5		21.0
Net debt to cash flow from operations (times)(4)	0.6		0.8
Interest coverage on long-term debt (times)
Net earnings(5)	23.3		18.4
Cash flow from operations(6)	28.2		22.5
As at March 31
Debt to debt plus shareholders’ equity (%)(7)	22.51		30.46
Common Share Information
As at March 31
Share price at end of trading
Toronto Stock Exchange – Cdn	$	87.85	89.63
New York Stock Exchange – US	$	76.35	77.02
Common share options outstanding (thousands)	21 389		19 809
For the three months ended March 31
Average number outstanding, weighted monthly (thousands)	460 074		458 230

Refer to the Quarterly Operating Summary for a discussion of financial measures not prepared in accordance with generally accepted accounting principles (GAAP).

(1) Cash flow from operations for the period; divided by the weighted average number of common shares outstanding during the period.

(2) For the twelve month period ended; net earnings (2007 – $2,821 million; 2006 – $1,787 million) adjusted for after-tax financing expenses (2007 – income of $12 million; 2006 – income of $17 million) divided by average capital employed (2007 – $8,040 million; 2006 – $6,279 million). 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 capitalized costs related to major projects in progress (as applicable). Return on capital employed (ROCE) for Suncor operating segments as presented in the Quarterly Operating Summary is calculated in a manner consistent with consolidated ROCE. For a detailed reconciliation of ROCE prepared on an annual basis, see page 58 of Suncor’s 2006 Annual Report to Shareholders.

(3) If capital employed were to include capitalized costs related to major projects in progress (average capital employed including major projects in progress: 2007 – $10,660 million; 2006 – $8,510 million), the return on capital employed would be as stated on this line.

(4) Short-term debt plus long-term debt less cash and cash equivalents, divided by cash flow from operations for the twelve month period then ended.

(5) Net earnings plus income taxes and interest expense, divided by the sum of interest expense and capitalized interest.

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

(7) Short-term debt plus long-term debt; divided by the sum of short-term debt, long-term debt and shareholders’ equity.

Quarterly operating summary

(unaudited)

	For the quarter ended					Total year
	Mar 31	Dec 31	Sept 30	June 30	Mar 31	Dec 31
	2007	2006	2006	2006	2006	2006
OIL SANDS
Production(1),(a)
Total production	248.2	266.4	242.8	267.3	264.4	260.0
Firebag	35.3	35.1	37.2	35.0	27.4	33.7
Sales(a)
Light sweet crude oil	105.5	113.7	84.9	124.7	119.2	110.5
Diesel	29.5	24.0	20.7	32.9	35.1	28.2
Light sour crude oil	112.7	126.8	125.8	99.2	121.0	118.2
Bitumen	6.8	9.7	6.6	8.5	—	6.2
Total sales	254.5	274.2	238.0	265.3	275.3	263.1
Average sales price (2),(b)
Light sweet crude oil	68.63	64.51	78.11	78.27	69.00	71.98
Other (diesel, light sour crude oil and bitumen)	63.62	57.91	68.60	72.75	63.28	65.17
Total	65.70	60.65	71.99	75.34	65.75	68.03
Total *	65.61	60.65	71.99	75.34	65.75	68.03

Cash operating costs and Total operating costs – Total operations
Cash costs	21.75	22.65	21.00	15.65	15.55	18.70
Natural gas	4.50	3.00	2.60	2.55	3.45	2.90
Imported bitumen	0.05	—	0.10	0.10	0.05	0.10
Cash operating costs (3),(c)	26.30	25.65	23.70	18.30	19.05	21.70
Firebag start-up costs	—	—	—	—	0.90	0.20
Total cash operating costs (4),(c)	26.30	25.65	23.70	18.30	19.95	21.90
Depreciation, depletion and amortization	4.45	4.25	4.30	3.80	3.90	4.05
Total operating costs (5),(c)	30.75	29.90	28.00	22.10	23.85	25.95

Cash operating costs and Total operating costs – In-situ bitumen production only
Cash costs	11.05	8.05	5.55	8.50	5.70	8.95
Natural gas	11.05	9.90	7.60	8.15	7.70	8.35
Cash operating costs(6),(c)	22.10	17.95	13.15	16.65	13.40	17.30
Firebag start-up costs	—	—	—	—	8.50	1.70
Total cash operating costs (7),(c)	22.10	17.95	13.15	16.65	21.90	19.00
Depreciation, depletion and amortization	5.35	6.20	5.55	3.75	6.90	5.55
Total operating costs (8),(c)	27.45	24.15	18.70	20.40	28.80	24.55

(for the period ended)
Capital employed(i)	5 134	5 015	5 491	5 486	5 401


(for the twelve months ended)
Return on capital employed (j)	47.6	53.5	57.7	53.6	35.1
Return on capital employed (j)****	34.7	40.1	43.6	40.2	25.9

Quarterly operating summary (continued)

(unaudited)

	For the quarter ended					Total year
	Mar 31	Dec 31	Sept 30	June 30	Mar 31	Dec 31
	2007	2006	2006	2006	2006	2006
NATURAL GAS
Gross production **
Natural gas (d)	191	192	191	189	196	191
Natural gas liquids (a)	2.4	2.1	2.1	2.6	2.4	2.3
Crude oil (a)	0.7	0.5	0.7	0.9	0.8	0.7
Total gross production (e)	34.9	34.7	34.6	35.1	35.9	34.8
Total gross production (f)	209	208	208	211	215	209
Average sales price (2)
Natural gas (g)	7.01	6.55	6.33	6.38	9.03	7.15
Natural gas (g)*	7.14	6.40	6.13	6.22	8.75	6.95
Natural gas liquids (b)	54.12	44.20	53.11	60.14	51.75	44.96
Crude oil – Conventional (b)	65.49	51.20	84.95	74.18	60.30	74.83
Net wells drilled
Conventional – Exploratory *******	4	4	1	1	5	11
– Development	8	6	6	2	4	18
	12	10	7	3	9	29

(for the period ended)
Capital employed (i)	1 063	857	775	767	587

(for the twelve months ended)
Return on capital employed (j)	8.5	14.9	27.7	30.4	31.4

REFINING AND MARKETING
Refined product sales (h)
Transportation fuels
Gasoline
Retail	5.4	5.5	5.3	5.3	5.1	5.3
Other	11.8	11.0	11.4	11.9	8.9	10.6
Distillate	10.3	8.8	8.5	9.0	7.9	8.5
Total transportation fuel sales	27.5	25.3	25.2	26.2	21.9	24.4
Petrochemicals	0.8	0.4	1.0	0.9	1.2	0.9
Asphalt	1.3	0.8	1.6	1.3	1.0	1.2
Other	2.0	2.6	3.6	3.2	2.5	3.0
Total refined product sales	31.6	29.1	31.4	31.6	26.6	29.5

Crude oil supply and refining
Processed at refineries (h)	24.6	19.4	24.2	24.5	18.8	21.7
Utilization of refining capacity (j)	97	76	95	96	74	85

(for the period ended)
Capital employed (i)	1 928	1 818	1 629	804	854

(for the twelve months ended)
Return on capital employed (j)	22.7	20.4	30.1	32.0	21.8
Return on capital employed (j)****	15.6	12.5	16.5	16.3	12.4

Quarterly operating summary (continued)

Non-GAAP Financial Measures

Certain financial measures referred to in the Highlights and Quarterly Operating Summary are not prescribed by Canadian generally accepted accounting

principles (GAAP). Suncor includes cash flow from operations, return on capital employed and cash and total operating costs per barrel data because

investors may use this information to analyze operating performance, leverage and liquidity. The additional information should not be considered in

isolation or as a substitute for measures of performance prepared in accordance with GAAP.

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.

Explanatory Notes

*		Excludes the impact of hedging activities.
**		Currently Natural Gas production is located in the Western Canada Sedimentary Basin.
***		Excludes exploratory wells in progress.
****		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.

(a) thousands of barrels per day	(d) millions of cubic feet per day	(g) dollars per thousand cubic feet

(b) dollars per barrel	(e) thousands of barrels of oil equivalent per day	(h) thousands of cubic metres per day

(c) dollars per barrel rounded to the nearest $0.05	(f) millions of cubic feet equivalent per day	(i) $ millions

		(j) percentage

Metric conversion

Crude oil, refined products, etc.

1m3 (cubic metre) = approx. 6.29 barrels