EXHIBIT 99.3

Interim Unaudited Financial Statements of Suncor Energy Inc. for the three and six months
ended June 30, 2006

Exhibit 99.3

CONSOLIDATED STATEMENTS OF EARNINGS

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2006		2005 (restated) (note 2)		2006		2005 (restated) (note 2)
Revenues	4 070		2 385		7 928		4 459
Expenses
Purchases of crude oil and products	1 233		1 039		2 184		1 855
Operating, selling and general (notes 2 and 6)	654		537		1 426		1 080
Energy marketing and trading activities (note 3)	354		214		616		361
Transportation and other costs	47		33		98		67
Depreciation, depletion and amortization (note 2)	166		137		324		274
Accretion of asset retirement obligations	9		7		17		15
Exploration	31		2		62		19
Royalties (note 10)	299		123		628		238
Taxes other than income taxes	142		126		282		246
Loss (gain) on disposal of assets	1		(1	)	(3	)	(1	)
Project start-up costs	5		3		26		6
Financing expenses (income) (note 4)	(20	)	21		(13	)	28
	2 921		2 241		5 647		4 188
Earnings Before Income Taxes	1 149		144		2 281		271
Provision for (Recovery of) Income Taxes (notes 2 and 9)
Current	(8	)	24		(9	)	53
Future	(61	)	37		359		68
	(69	)	61		350		121
Net Earnings	1 218		83		1 931		150
Per Common Share (dollars), (note 5)
Basic	2.65		0.18		4.21		0.33
Diluted	2.59		0.18		4.10		0.32
Cash dividends	0.08		0.06		0.14		0.12

See accompanying notes.

16

CONSOLIDATED BALANCE SHEETS

(unaudited)

($ millions)	June 30 2006	December 31 2005 (restated) (note 2)
Assets
Current assets
Cash and cash equivalents	158	165
Accounts receivable	1 260	1 139
Inventories	550	523
Income taxes receivable	32	6
Future income taxes	66	83
Total current assets	2 066	1 916
Property, plant and equipment, net	14 214	12 966
Deferred charges and other (note 2)	278	267
Total assets	16 558	15 149
Liabilities and Shareholders’ Equity
Current liabilities
Short-term debt	8	49
Accounts payable and accrued liabilities (note 10)	1 626	1 830
Taxes other than income taxes	105	56
Total current liabilities	1 739	1 935
Long-term debt	2 340	3 007
Accrued liabilities and other	1 049	1 005
Future income taxes (notes 2 and 9)	3 545	3 206
Shareholders’ equity (see below)	7 885	5 996
Total liabilities and shareholders’ equity	16 558	15 149

Shareholders’ Equity

	Number			Number
	(thousands)			(thousands)
Share capital	459 196	774		457 665	732
Contributed surplus		65			50
Cumulative foreign currency translation		(117	)		(81	)
Retained earnings (note 2)		7 163			5 295
		7 885			5 996

See accompanying notes.

17

CONSOLIDATED STATEMENTS OF CASH FLOWS

(unaudited)

	Second quarter				Six months ended June 30
($ millions)	2006		2005 (restated) (note 2)		2006		2005 (restated) (note 2)
Operating Activities
Cash flow from operations	1 320		305		2 634		599
Decrease (increase) in operating working capital
Accounts receivable	268		51		(149	)	(175	)
Inventories	(103	)	(36	)	(27	)	(40	)
Accounts payable and accrued liabilities	(125	)	207		(366	)	382
Taxes payable	39		(5	)	23		(28	)
Cash flow from operating activities	1 399		522		2 115		738
Cash Used in Investing Activities	(797	)	(871	)	(1 454)		(1 447)
Net Cash Surplus (Deficiency) Before Financing Activities	602		(349	)	661		(709	)
Financing Activities
Increase (decrease) in short-term debt	(21	)	2		(41	)	(20	)
Net increase (decrease) in other long-term debt	(522	)	347		(616	)	658
Issuance of common shares under stock option plan	11		21		33		52
Dividends paid on common shares	(33	)	(26	)	(58	)	(51	)
Deferred revenue	6		14		16		30
Cash provided by (used in) financing activities	(559	)	358		(666	)	669
Increase (Decrease) in Cash and Cash Equivalents	43		9		(5	)	(40	)
Effect of Foreign Exchange on Cash and Cash Equivalents	(2	)	—		(2	)	—
Cash and Cash Equivalents at Beginning of Period	117		39		165		88
Cash and Cash Equivalents at End of Period	158		48		158		48

See accompanying notes.

18

CONSOLIDATED STATEMENTS OF CHANGES IN SHAREHOLDERS’ EQUITY

(unaudited)

($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings
At December 31, 2004, as previously reported	651	32		(55	)	4 293
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—	—		—		(47	)
At December 31, 2004, as restated	651	32		(55	)	4 246
Net earnings	—	—		—		150
Dividends paid on common shares	—	—		—		(51	)
Issued for cash under stock option plan	52	—		—		—
Issued under dividend reinvestment plan	4	—		—		(4	)
Stock-based compensation expense	—	10		—		—
Foreign currency translation adjustment	—	—		3		—
At June 30, 2005	707	42		(52	)	4 341
At December 31, 2005, as previously reported	732	50		(81	)	5 429
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—	—		—		(134	)
At December 31, 2005, as restated	732	50		(81	)	5 295
Net earnings	—	—		—		1 931
Dividends paid on common shares	—	—		—		(58	)
Issued for cash under stock option plan	37	(4	)	—		—
Issued under dividend reinvestment plan	5	—		—		(5	)
Stock-based compensation expense	—	19		—		—
Foreign currency translation adjustment	—	—		(36	)	—
At June 30, 2006	774	65		(117	)	7 163

See accompanying notes.

19

SCHEDULES OF SEGMENTED DATA

(unaudited)

	Second quarter
	Oil Sands			Natural Gas			Energy Marketing and Refining— Canada				Refining and Marketing— U.S.A.				Corporate and Eliminations				Total
($ millions)	2006	2005		2006	2005		2006		2005		2006		2005		2006		2005		2006		2005
EARNINGS
Revenues
Operating revenues	1 642	460		120	117		1 048		887		890		575		1		—		3 701		2 039
Energy marketing and trading activities	—	—		—	—		383		232		—		—		(18	)	—		365		232
Net insurance proceeds	—	113		—	—		—		—		—		—		—		—		—		113
Intersegment revenues	261	76		11	20		—		—		—		—		(272	)	(96	)	—		—
Interest	—	—		—	—		—		—		1		1		3		—		4		1
	1 903	649		131	137		1 431		1 119		891		576		(286	)	(96	)	4 070		2 385
Expenses
Purchases of crude oil and products	14	12		—	—		768		658		713		453		(262	)	(84	)	1 233		1 039
Operating, selling and general	456	292		27	23		97		117		41		39		33		66		654		537
Energy marketing and trading activities	—	—		—	—		377		227		—		—		(23	)	(13	)	354		214
Transportation and other costs	36	21		5	6		3		2		3		4		—		—		47		33
Depreciation, depletion and amortization	92	79		38	30		22		18		8		6		6		4		166		137
Accretion of asset retirement obligations	7	5		2	1		—		1		—		—		—		—		9		7
Exploration	—	—		31	2		—		—		—		—		—		—		31		2
Royalties (note 10)	278	94		21	29		—		—		—		—		—		—		299		123
Taxes other than income taxes	20	7		2	1		84		89		36		29		—		—		142		126
Loss (gain) on disposal of assets	—	—		—	—		—		(1	)	1		—		—		—		1		(1	)
Project start-up costs	3	3		—	—		2		—		—		—		—		—		5		3
Financing expenses (income)	—	—		—	—		—		—		—		—		(20	)	21		(20	)	21
	906	513		126	92		1 353		1 111		802		531		(266	)	(6	)	2 921		2 241
Earnings (loss) before income taxes	997	136		5	45		78		8		89		45		(20	)	(90	)	1 149		144
Income taxes	112	(51	)	55	(18	)	(15	)	(3	)	(32	)	(14	)	(51	)	25		69		(61	)
Net earnings (loss)	1 109	85		60	27		63		5		57		31		(71	)	(65	)	1 218		83

20

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

	Second quarter
	Oil Sands				Natural Gas				Energy Marketing and Refining— Canada				Refining and Marketing— U.S.A.				Corporate and Eliminations				Total
($ millions)	2006		2005		2006		2005		2006		2005		2006		2005		2006		2005		2006		2005
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	1 109		85		60		27		63		5		57		31		(71	)	(65	)	1 218		83
Exploration expenses	—		—		20		2		—		—		—		—		—		—		20		2
Non-cash items included in earnings
Depreciation, depletion and amortization	92		79		38		30		22		18		8		6		6		4		166		137
Income taxes	(112	)	51		(55	)	18		15		3		32		14		59		(49	)	(61	)	37
Loss (gain) on disposal of assets	—		—		—		—		—		(1	)	1		—		—		—		1		(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		10		6		10		6
Other	16		(2	)	2		4		2		1		(2	)	1		(47	)	19		(29	)	23
Increase (decrease) in deferred credits and other	(6	)	(3	)	—		—		—		—		—		—		1		21		(5	)	18
Total cash flow from (used in) operations	1 099		210		65		81		102		26		96		52		(42	)	(64	)	1 320		305
Decrease (increase) in operating working capital	(22	)	108		(59	)	(11	)	7		19		12		15		141		86		79		217
Total cash flow from (used in) operating activities	1 077		318		6		70		109		45		108		67		99		22		1 399		522
Cash from (used in) investing activities:
Capital and exploration expenditures	(555	)	(510	)	(127	)	(72	)	(117	)	(114	)	(56	)	(96	)	(10	)	(12	)	(865	)	(804	)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		—		(62	)	—		—		—		(62	)
Deferred maintenance shutdown expenditures	—		(35	)	—		—		(1	)	—		(9	)	(1	)	—		—		(10	)	(36	)
Deferred outlays and other investments	(2	)	—		—		—		—		(1	)	5		—		9		(1	)	12		(2	)
Proceeds from disposals	—		—		1		—		3		1		—		—		—		—		4		1
Proceeds from property loss	29		—		—		—		—		—		—		—		—		—		29		—
Decrease (increase) in investing working capital	66		17		—		—		7		1		(40	)	14		—		—		33		32
Total cash (used in) investing activities	(462	)	(528	)	(126	)	(72	)	(108	)	(113	)	(100	)	(145	)	(1	)	(13	)	(797	)	(871	)
Net cash surplus (deficiency) before financing activities	615		(210	)	(120	)	(2	)	1		(68	)	8		(78	)	98		9		602		(349	)

21

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

	Six months ended June 30
	Oil Sands				Natural Gas				Energy Marketing and Refining— Canada				Refining and Marketing— U.S.A.				Corporate and Eliminations				Total
($ millions)	2006		2005		2006		2005		2006		2005		2006		2005		2006		2005		2006		2005
EARNINGS
Revenues
Operating revenues	3 192		1 013		294		248		1 940		1 652		1 476		986		2		1		6 904		3 900
Energy marketing and trading activities	—		—		—		—		657		382		—		—		(23	)	—		634		382
Net insurance proceeds	385		176		—		—		—		—		—		—		—		—		385		176
Intersegment revenues	446		153		17		26		—		—		—		—		(463	)	(179	)	—		—
Interest	—		—		—		—		—		—		1		1		4		—		5		1
	4 023		1 342		311		274		2 597		2 034		1 477		987		(480	)	(178	)	7 928		4 459
Expenses
Purchases of crude oil and products	17		21		—		—		1 414		1 219		1 208		782		(455	)	(167	)	2 184		1 855
Operating, selling and general	964		613		51		44		221		225		84		71		106		127		1 426		1 080
Energy marketing and trading activities	—		—		—		—		643		374		—		—		(27	)	(13	)	616		361
Transportation and other costs	73		45		11		11		4		3		10		8		—		—		98		67
Depreciation, depletion and amortization	185		158		72		61		42		36		12		12		13		7		324		274
Accretion of asset retirement obligations	14		11		3		3		—		1		—		—		—		—		17		15
Exploration	22		10		40		9		—		—		—		—		—		—		62		19
Royalties (note 10)	563		181		65		57		—		—		—		—		—		—		628		238
Taxes other than income taxes	41		14		2		1		163		172		76		59		—		—		282		246
Loss (gain) on disposal of assets	—		—		(4	)	—		—		(1	)	1		—		—		—		(3	)	(1	)
Project start-up costs	24		6		—		—		2		—		—		—		—		—		26		6
Financing expenses (income)	—		—		—		—		—		—		—		—		(13	)	28		(13	)	28
	1 903		1 059		240		186		2 489		2 029		1 391		932		(376	)	(18	)	5 647		4 188
Earnings (loss) before income taxes	2 120		283		71		88		108		5		86		55		(104	)	(160	)	2 281		271
Income taxes	(291	)	(115	)	31		(35	)	(27	)	(3	)	(31	)	(18	)	(32	)	50		(350	)	(121	)
Net earnings (loss)	1 829		168		102		53		81		2		55		37		(136	)	(110	)	1 931		150
As at June 30
TOTAL ASSETS	12 649		10 005		1 390		1 089		2 850		1 574		1 257		1 092		(1 588)		(479	)	16 558		13 281

22

SCHEDULES OF SEGMENTED DATA (continued)

(unaudited)

	Six months ended June 30
	Oil Sands				Natural Gas				Energy Marketing and Refining— Canada				Refining and Marketing— U.S.A.				Corporate and Eliminations				Total
($ millions)	2006		2005		2006		2005		2006		2005		2006		2005		2006		2005		2006		2005
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings (loss)	1 829		168		102		53		81		2		55		37		(136	)	(110	)	1 931		150
Exploration expenses	—		—		25		9		—		—		—		—		—		—		25		9
Non-cash items included in earnings
Depreciation, depletion and amortization	185		158		72		61		42		36		12		12		13		7		324		274
Income taxes	291		115		(31	)	35		27		3		31		18		41		(103	)	359		68
Loss (gain) on disposal of assets	—		—		(4	)	—		—		(1	)	1		—		—		—		(3	)	(1	)
Stock-based compensation expense	—		—		—		—		—		—		—		—		19		10		19		10
Other	14		23		1		6		3		8		—		3		(26	)	7		(8	)	47
Increase (decrease) in deferred credits and other	(11	)	(6	)	—		—		—		—		(3	)	—		1		48		(13	)	42
Total cash flow from (used in) operations	2 308		458		165		164		153		48		96		70		(88	)	(141	)	2 634		599
Decrease (increase) in operating working capital	(222	)	72		(41	)	(27	)	(76	)	(42	)	32		(58	)	(212	)	194		(519	)	139
Total cash flow from (used in) operating activities	2 086		530		124		137		77		6		128		12		(300	)	53		2 115		738
Cash from (used in) investing activities:
Capital and exploration expenditures	(962	)	(880	)	(242	)	(154	)	(235	)	(192	)	(164	)	(163	)	(14	)	(24	)	(1 617)		(1 413)
Acquisition of Denver refinery and related assets	—		—		—		—		—		—		—		(62	)	—		—		—		(62	)
Deferred maintenance shutdown expenditures	—		(60	)	—		—		(1	)	—		(51	)	(1	)	—		—		(52	)	(61	)
Deferred outlays and other investments	(2	)	(1	)	—		—		—		(2	)	5		—		7		(1	)	10		(4	)
Proceeds from disposals	—		21		14		—		3		1		—		—		—		—		17		22
Proceeds from property loss	29		—		—		—		—		—		—		—		—		—		29		—
Decrease (increase) in investing working capital	183		48		—		—		14		9		(38	)	14		—		—		159		71
Total cash (used in) investing activities	(752	)	(872	)	(228	)	(154	)	(219	)	(184	)	(248	)	(212	)	(7	)	(25	)	(1 454)		(1 447)
Net cash surplus (deficiency) before financing activities	1 334		(342	)	(104	)	(17	)	(142	)	(178	)	(120	)	(200	)	(307	)	28		661		(709	)

23

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.

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 June 30, 2006 and the results of its operations and cash flows for the three and six month periods ended June 30, 2006 and 2005.

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

2. CHANGES IN ACCOUNTING POLICIES

(a) Overburden Removal Costs

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

Change in Consolidated Balance Sheets

	As at June 30
($ millions, (decrease))	2006		2005
Deferred charges and other	(244	)	(160	)
Total assets	(244	)	(160	)
Future income tax liabilities	(81	)	(53	)
Retained earnings	(163	)	(107	)
Total liabilities and shareholders’ equity	(244	)	(160	)

Change in Consolidated Statements of Earnings

	Second quarter				Six months ended June 30
($ millions, increase/(decrease))	2006		2005		2006		2005
Operating, selling and general	77		77		159		152
Depreciation, depletion and amortization	(64	)	(31	)	(117	)	(59	)
Future income taxes	(3	)	(17	)	(13	)	(33	)
Net earnings	(10	)	(29	)	(29	)	(60	)
Per common share — basic (dollars)	(0.02	)	(0.06	)	(0.06	)	(0.13	)
Per common share — diluted (dollars)	(0.02	)	(0.06	)	(0.06	)	(0.13	)

24

(b) Non-monetary Transactions

On January 1, 2006, the company prospectively adopted CICA Handbook section 3831 “Non-monetary Transactions”. The standard requires all non-monetary transactions to be measured at fair value (if determinable) unless future cash flows are not expected to change significantly as a result of a transaction or the transaction is an exchange of a product held for sale in the ordinary course of business. The company was required to record the effects of an existing contract at Oil Sands that exchanges off-gas produced as a by-product of the upgrading operations for natural gas. An equal amount of revenues for the sale of the off-gas and purchases of crude oil and products for the purchase of the natural gas are recorded. The amount of the gross-up of revenues and purchases of crude oil and products for the three and six month periods ending June 30, 2006 was $31 million and $79 million respectively.

3. ENERGY MARKETING AND TRADING ACTIVITIES

The company uses physical and financial energy contracts, including swaps, forwards and options to gain market information and 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. The results of these activities are reported as revenue and as energy marketing and trading expenses in the Consolidated Statements of Earnings.

Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers. For the quarter ended June 30, 2006, these activities resulted in net pretax earnings of $6 million (2005 — pretax earnings of $7 million). For the six months ended June 30, 2006, physical energy marketing contracts resulted in net pretax earnings of $16 million (2005 — pretax earnings of $9 million).

In addition to the financial derivatives used for hedging activities, the company also enters into various financial energy contracts for trading activities. The following information presents all positions for the financial instruments only. For the quarter ended June 30, 2006, net pretax earnings of $nil (2005 — pretax loss of $1 million) resulted from the settlement and revaluation of the financial energy contracts. For the six months ended June 30, 2006 a net pretax loss of $1 million (2005 — pretax earnings of $1 million) was recorded. The above amounts do not include the impact of related general and administrative costs.

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

($ millions)	June 30 2006	December 31 2005
Energy trading assets	21	82
Energy trading liabilities	13	70
Net energy trading assets	8	12

Change in Fair Value of Net Assets

($ millions)	2006
Fair value of contracts outstanding at December 31, 2005	12
Fair value of contracts realized during 2006	(4	)
Fair value of contracts entered into during the period	2
Changes in values attributable to market price and other market changes	(2	)
Fair value of contracts outstanding at June 30, 2006	8

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

4. FINANCING EXPENSES (INCOME)

	Second quarter				Six months ended June 30
($ millions)	2006		2005		2006		2005
Interest on debt	38		38		77		71
Capitalized interest	(31	)	(31	)	(64	)	(57	)
Net interest expense	7		7		13		14
Foreign exchange loss (gain) on long-term debt	(52	)	16		(51	)	22
Other foreign exchange loss (gain)	25		(2	)	25		(8	)
Total financing expenses (income)	(20	)	21		(13	)	28

25

5. RECONCILIATION OF BASIC AND DILUTED EARNINGS PER COMMON SHARE

	Second quarter		Six months ended June 30
($ millions)	2006	2005	2006	2005
Net earnings	1 218	83	1 931	150
(millions of common shares)
Weighted-average number of common shares	459	456	459	455
Options issued under stock-based compensation plans	12	10	12	11
Weighted-average number of diluted common shares	471	466	471	466
(dollars per common share)
Basic earnings per share (a)	2.65	0.18	4.21	0.33
Diluted earnings per share (b)	2.59	0.18	4.10	0.32

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.

6. 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 338,000 options to new employees in the second quarter of 2006, for a total of 598,000 options granted in the six months ended June 30, 2006 (413,000 options granted during the second  quarter of 2005; 677,000 options granted in the six months ended June 30, 2005).

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.

Under the company’s other plans, 62,000 options were granted in the second quarter of 2006, for a total of 1,571,000 options granted in the six months ended June 30, 2006 (64,000 options granted during the second quarter of 2005; 1,355,000 granted in the six months ended June 30, 2005).

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:

	Second quarter						Six months ended June 30
	2006			2005			2006			2005
Quarterly dividend per share	$	0.08		$	0.06		$	0.08	*	$	0.06
Risk-free interest rate	4.25		%	3.59		%	4.11		%	3.73		%
Expected life	5 years			5 years			6 years			6 years
Expected volatility	29		%	28		%	29		%	28		%
Weighted-average fair value per option	$	28.32		$	14.76		$	31.57		$	14.09

*In 2006, quarterly dividends of $0.06 per share were paid in the first quarter and $0.08 per share were paid in the second quarter.

Stock-based compensation expense recognized in the second quarter of 2006 related to stock options plans was $10 million (2005 — $6 million). For the six months ended June 30, 2006 stock-based compensation expense recognized was $19 million (2005 — $10 million).

26

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:

	Second quarter		Six months ended June 30
($ millions, except per share amounts)	2006	2005	2006	2005
Net earnings — as reported	1 218	83	1 931	150
Less: compensation cost under the fair value method for pre-2003 options	3	7	5	9
Pro forma net earnings	1 215	76	1 926	141
Basic earnings per share
As reported	2.65	0.18	4.21	0.33
Pro forma	2.65	0.17	4.20	0.31
Diluted earnings per share
As reported	2.59	0.18	4.10	0.32
Pro forma	2.58	0.16	4.09	0.30

(b) Performance Share Units (PSUs)

In the second quarter of 2006 the company issued 2,000 PSUs (2005 — 9,000). For the six months ended June 30, 2006, the company issued 392,000 PSUs (2005 — 445,000). Expense recognized in the second quarter of 2006 was $11 million (2005 — $5 million). Expense recognized for the six months ended June 30, 2006 was $35 million (2005 — $8 million).

7. EMPLOYEE FUTURE BENEFITS LIABILITY

The company’s pension plans and other post-retirement benefits programs are described in note 8 of the company’s 2005 Annual Report. The following is the status of the net periodic benefit cost for the quarter and six months ended June 30.

	Pension Benefits
	Second quarter				Six months ended June 30
($ millions)	2006		2005		2006		2005
Current service costs	11		8		22		16
Interest costs	10		9		20		19
Expected return on plan assets	(8	)	(7	)	(16	)	(14	)
Amortization of net actuarial loss	7		6		14		11
Net periodic benefit cost	20		16		40		32

	Other Post-retirement Benefits
	Second quarter		Six months ended June 30
($ millions)	2006	2005	2006	2005
Current service costs	2	1	3	3
Interest costs	2	2	4	4
Net periodic benefit cost	4	3	7	7

8. SUPPLEMENTAL INFORMATION

	Second quarter		Six months ended June 30
($ millions)	2006	2005	2006	2005
Interest paid	22	23	75	69
Income taxes paid	6	21	17	55

27

Revenue Hedges

Strategic Crude Oil at June 30, 2006

	Quantity (bpd)	Average Price (US$/bbl) (a)	Revenue Hedged (Cdn$ millions) (b)	Hedge Period (c)
Costless collars	50 000	50.00 - 91.70	513 - 941	2006
Costless collars	50 000	50.00 - 91.70	1 017 - 1 866	2007

Natural Gas at June 30, 2006

	Quantity (GJ/day)	Average Price (Cdn$/GJ)	Revenue Hedged (Cdn$ millions)	Hedge Period (c)
Swaps	4 000	6.58	5	2006
Costless collars	10 000	8.75 - 13.38	11 - 16	2006	(d)
Swaps	4 000	6.11	9	2007

Foreign Currency Hedges at June 30, 2006

	Notional (Euro millions)	Average Forward Rate	Dollars Hedged (Cdn$ millions)	Hedge Period
Euro/Cdn forward	20.6	1.40	29	2007	(e)

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

(b)The revenue hedged is translated to Cdn$ at the June 30, 2006 exchange rate and is subject to change as the Cdn$/US$ exchange rate fluctuates during the hedge period.

(c)Original hedge term is for the full year unless otherwise noted.

(d)For the period July to October 2006, inclusive.

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

9. INCOME TAXES

During the second quarter of 2006 the federal government substantively enacted a 3.1% reduction to its federal corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $292 million related to the revaluation of its opening future income tax balances.

During the second quarter of 2006 the provincial government of Alberta substantively enacted a 1.5% reduction to its provincial corporate tax rates. Accordingly, the company recognized a reduction in future income tax expense of $127 million related to the revaluation of its opening future income tax balances.

28

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. Firebag is being treated by the Government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes.

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

Oil Sands royalties payable in 2006 are highly sensitive to, among other factors, changes in crude oil and natural gas pricing, timing of the receipt of property damage insurance proceeds, foreign exchange rates and total capital and operating costs for each project. Oil Sands pretax royalty estimate was $563 million ($373 million after tax) for the first six months of 2006 compared to $181 million ($110 million after tax) for the first six months of 2005. We estimate 2006 annualized oil sands royalties to be approximately $1,019 million ($675 million after tax) based on six months of actual results including the final $385 million in business interruption insurance proceeds, together with 2006 forward crude oil pricing of US$75.21 as at June 30, 2006, current forecasts of production, capital and operating costs for the remainder of 2006, a Canadian/US foreign exchange rate of $0.90, and no further receipts of property loss insurance proceeds other than those recorded to date. Accordingly, actual results will differ, and these differences may be material. The balance of the royalty expense is in respect of natural gas royalties of $65 million ($43 million after tax).

11. CREDIT FACILITIES

During the second quarter, a $1.5 billion credit facility agreement was renegotiated and extended by two years, to have a five year term maturing in June 2011. The credit limit of this facility was also increased by $500 million to $2 billion. In addition, a $200 million credit facility agreement was renegotiated and increased by $100 million to $300 million. As well, a $600 million credit facility agreement matured during the second quarter and was not renewed. At June 30, 2006, the company had available facilities 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

As at June 30, 2006, undrawn lines of credit were approximately $1,820 million.

29

HIGHLIGHTS

(unaudited)

	2006	2005
Cash Flow from Operations
(dollars per common share)
For the three months ended June 30
Cash flow from operations (1)	2.88	0.67
For the six months ended June 30
Cash flow from operations (1)	5.74	1.32
Ratios
For the twelve months ended June 30
Return on capital employed (%) (2)	43.9	12.9
Return on capital employed (%) (3)	32.0	10.3
Net debt to cash flow from operations (times) (4)	0.5	1.7
Interest coverage on long-term debt (times)
Net earnings (5)	24.8	9.3
Cash flow from operations (6)	28.8	13.0
As at June 30
Debt to debt plus shareholders’ equity (%) (7)	23.0	36.8
Common Share Information
As at June 30
Share price at end of trading
Toronto Stock Exchange — Cdn$	90.34	57.92
New York Stock Exchange — US$	81.01	47.32
Common share options outstanding (thousands)	19 610	19 630
For the six months ended June 30
Average number outstanding, weighted monthly (thousands)	458 596	455 486

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)Net earnings (2006 — $2,883 million; 2005 — $814 million) adjusted for after-tax financing expenses (2006 — income of $56 million; 2005 — income of $60 million) for the twelve month period ended; divided by average capital employed (2006 — $6,573 million; 2005 — $5,834 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 56 of Suncor’s 2005 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: 2006 — $8,997 million; 2005 — $7,322 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.

30

QUARTERLY OPERATING SUMMARY

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30 2006	Mar 31 2006	Dec 31 2005	Sep 30 2005	June 30 2005	June 30 2006	June 30 2005	Dec 31 2005
OIL SANDS
Production (1),(a)
Total production	267.3	264.4	267.7	148.2	128.2	266.0	134.1	171.3
Firebag	35.0	27.4	26.0	23.0	8.7	31.3	13.7	19.1
Sales (a)
Light sweet crude oil	124.7	119.2	108.6	69.9	48.3	121.9	61.8	73.3
Diesel	32.9	35.1	30.7	10.6	9.0	34.1	10.4	15.6
Light sour crude oil	99.2	121	104.2	41.7	54.2	110.0	46.4	59.8
Bitumen	8.5	—	7.2	22.3	9.6	4.3	13.9	16.6
Total sales	265.3	275.3	250.7	144.5	121.1	270.3	132.5	165.3
Average sales price (2),(b)
Light sweet crude oil	78.27	69.00	55.96	52.08	39.20	73.76	42.80	49.93
Other (diesel, light sour
crude oil and bitumen)	72.75	63.28	63.84	59.70	50.47	67.80	48.80	56.90
Total	75.34	65.75	60.42	56.01	45.98	70.49	46.23	53.81
Total *	75.34	65.75	66.68	67.95	57.24	70.49	55.92	62.68
CASH OPERATING COSTS AND TOTAL OPERATING COSTS — TOTAL OPERATIONS
Cash costs	15.65	15.55	16.20	21.65	23.50	15.60	21.95	19.60
Natural gas	2.55	3.45	4.65	6.00	3.60	3.00	4.55	4.90
Imported bitumen	0.10	0.05	0.05	—	—	0.05	0.05	0.05
Cash operating costs (3),(c)	18.30	19.05	20.90	27.65	27.10	18.65	26.55	24.55
Firebag start-up costs	—	0.90	0.30	—	—	0.45	—	0.10
Total cash operating costs (4),(c)	18.30	19.95	21.20	27.65	27.10	19.10	26.55	24.65
Depreciation, depletion and amortization	3.80	3.90	3.60	6.10	6.75	3.85	6.50	5.30
Total operating costs (5),(c)	22.10	23.85	24.80	33.75	33.85	22.95	33.05	29.95
CASH OPERATING COSTS AND TOTAL OPERATING COSTS — IN-SITU BITUMEN PRODUCTION
Cash costs	8.50	14.20	6.70	7.55	21.50	10.95	12.90	9.15
Natural gas	8.15	7.70	13.80	13.25	16.40	7.95	12.10	13.05
Cash operating costs (6),(c)	16.65	21.90	20.50	20.80	37.90	18.90	25.00	22.20
Depreciation, depletion and amortization	3.75	6.90	4.60	4.25	7.60	5.10	5.65	4.90
Total operating costs (7),(c)	20.40	28.80	25.10	25.05	45.50	24.00	30.65	27.10
(for the period ended)
Capital employed (h)	5 544	5 450	4 472	4 334	4 173
(for the twelve months ended)
Return on capital employed (i)	53.8	35.5	22.7	15.1	15.7
Return on capital employed (i) ****	40.5	26.3	16.3	11.2	12.2

31

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30 2006	Mar 31 2006	Dec 31 2005	Sep 30 2005	June 30 2005	June 30 2006	June 30 2005	Dec 31 2005
NATURAL GAS
Gross production **
Natural gas (d)	189	196	193	200	175	193	183	190
Natural gas liquids (a)	2.6	2.4	2.3	2.2	2.2	2.5	2.6	2.4
Crude oil (a)	0.9	0.8	0.6	0.7	1.0	0.9	0.9	0.8
Total gross production (e)	35.1	35.9	35.0	36.3	32.4	35.5	34.0	34.8
Average sales price (2)
Natural gas (f)	6.38	9.03	11.66	8.32	7.29	7.73	7.04	8.57
Natural gas (f) *	6.22	8.75	11.83	8.34	7.26	7.51	6.99	8.59
Natural gas liquids (b)	60.14	51.75	57.85	58.00	52.52	56.19	44.38	50.70
Crude oil — Conventional (b)	74.18	60.30	72.60	63.77	63.86	67.81	62.68	64.85
Net wells drilled
Conventional   — Exploratory ***	1	5	3	4	0	6	5	12
— Development	2	4	13	2	2	6	7	22
	3	9	16	6	2	12	12	34
(for the period ended)
Capital employed (h)	770	590	563	598	564
(for the twelve months ended)
Return on capital employed (i)	30.6	31.7	30.7	22.7	22.5
ENERGY MARKETING AND REFINING — CANADA
Refined product sales (g)
Transportation fuels
Gasoline
Retail	4.6	4.4	4.5	4.2	4.8	4.5	4.7	4.5
Other	3.9	3.6	3.3	4.2	4.1	3.7	4.0	3.9
Jet fuel	0.8	0.7	0.8	0.9	0.8	0.7	0.9	0.9
Diesel	3.5	3.2	3.4	3.7	3.3	3.4	3.0	3.3
Total transportation fuel sales	12.8	11.9	12.0	13.0	13.0	12.3	12.6	12.6
Petrochemicals	0.9	1.2	0.4	0.7	0.8	1.1	0.8	0.7
Heating oils	0.4	0.6	0.5	0.2	0.3	0.5	0.5	0.4
Heavy fuel oils	0.7	0.9	0.9	0.8	1.4	0.8	1.2	1.0
Other	0.6	0.7	0.5	0.9	0.6	0.6	0.5	0.5
Total refined product sales	15.4	15.3	14.3	15.6	16.1	15.3	15.6	15.2
Crude oil supply and refining
Processed at Sarnia refinery (g)	9.9	9.6	10.6	10.7	11.1	9.7	10.6	10.6
Utilization of refining capacity (i)	89	86	95	96	100	87	95	95
(for the period ended)
Capital employed (h)	490	535	486	547	507
(for the twelve months ended)
Return on capital employed (i)	23.9	11.5	8.1	7.7	10.1
Return on capital employed (i) ****	12.4	6.8	5.2	5.6	8.1

32

QUARTERLY OPERATING SUMMARY (continued)

(unaudited)

	For the quarter ended					Six months ended		Total year
	June 30 2006	Mar 31 2006	Dec 31 2005	Sep 30 2005	June 30 2005	June 30 2006	June 30 2005	Dec 31 2005
REFINING AND MARKETING — U.S.A.
Refined product sales (g)
Transportation fuels
Gasoline
Retail	0.7	0.7	0.7	0.7	0.7	0.7	0.7	0.7
Other	8.0	5.3	7.1	8.9	5.0	6.3	4.4	6.2
Jet fuel	0.9	0.8	0.9	0.8	0.7	0.8	0.7	0.8
Diesel	3.8	3.2	3.6	3.9	3.1	3.5	2.9	3.3
Total transportation fuel sales	13.4	10.0	12.3	14.3	9.5	11.3	8.7	11.0
Asphalt	1.3	1.0	1.2	1.8	1.9	1.1	1.8	1.6
Other	1.5	0.3	1.0	1.2	1.2	1.1	1.0	1.1
Total refined product sales	16.2	11.3	14.5	17.3	12.6	13.5	11.5	13.7
Crude oil supply and refining
Processed at Denver refinery (g)	14.6	9.2	13.0	14.9	11.4	11.9	10.3	12.1
Utilization of refining capacity (i)	102	65	91	104	102	83	100	98
(for the period ended)
Capital employed (h)	340	341	327	354	349
(for the twelve months ended)
Return on capital employed (i)	45.7	42.2	49.4	32.2	17.6
Return on capital employed (i) ****	23.1	22.7	28.9	21.6	13.8

33

QUARTERLY OPERATING SUMMARY (continued)

Non-GAAP Financial Measures

Certain financial measures referred to in the Highlights and Quarterly Operating Summary are not prescribed by 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 production volumes that are processed through the upgrader facilities. 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 all production volumes that are processed through the upgrader facilities.
(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 all production volumes that are processed through the upgrader facilities.
(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.
(7) Total operating costs — In-situ bitumen production	-	Include cash operating costs — Firebag as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes.

Explanatory Notes

*	Excludes the impact of hedging activities.
**	Currently all 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) thousands of cubic metres per day
(b) dollars per barrel	(e) thousands of barrels of oil equivalent per day	(h) $millions
(c) dollars per barrel rounded to the nearest $0.05	(f) dollars per thousand cubic feet	(i) percentage

Metric Conversion

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

34