EXHIBIT 99.1

Press Release Including 2008 Outlook and Interim Unaudited Financial
Statements of Suncor Energy Inc. for the fourth fiscal quarter ended December 31, 2007.

Suncor Energy reports financial results for 2007 and operational goals for 2008

(All financial figures are approximate and in Canadian dollars unless otherwise noted.)

Certain financial measures referred to in this document are not prescribed by Canadian generally accepted accounting principles (GAAP). For a description of these measures, see “Non-GAAP Financial Measures” on page 5. This document makes reference to barrels of oil equivalent (boe). A boe conversion ratio of six thousand cubic feet of natural gas: one barrel of crude oil is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. Accordingly, boe measures may be misleading, particularly if used in isolation.

Calgary, Alberta (January 22, 2008) – Suncor Energy Inc. today reported 2007 net earnings of $2.832 billion ($6.14 per common share), compared to $2.971 billion ($6.47 per common share) in 2006. Excluding the effects of the reduction of federal and Alberta income tax rates, net insurance proceeds (relating to a January 2005 fire), unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt and project start-up costs, 2007 net earnings were $2.239 billion ($4.86 per common share), compared to $2.350 billion ($5.12 per common share) in 2006. Cash flow from operations in 2007 was $3.805 billion, compared to $4.533 billion in 2006.

The decrease in net earnings primarily reflects the impact of scheduled and unscheduled maintenance that reduced crude oil production and increased operating expenses. The largest impacts on financial results were a scheduled 50-day maintenance shutdown to portions of Suncor’s oil sands operation to tie in new facilities related to a planned expansion and a scheduled 120-day shutdown to portions of the Sarnia refinery to tie in new sour crude processing facilities. These impacts were partly offset by higher benchmark crude oil prices. The decrease in cash flow from operations was due to the same factors that impacted net earnings as well as an increase in cash income taxes during 2007.

“Suncor’s goal in 2007 was to continue to build the financial and physical foundation for future growth and profitability,” said Rick George, president and chief executive officer. “And we’re on track to increase production capacity by 35% in 2008.”

2007 Overview

·Combined oil sands and natural gas production in 2007 was 271,400 barrels of oil equivalent (boe) per day, compared to 294,800 boe per day in 2006. Oil sands production averaged 235,600 barrels per day (bpd) in 2007, compared to 260,000 bpd in 2006. Natural gas production averaged 215 million cubic feet equivalent (mmcfe) per day, compared to an average 209 mmcfe per day in 2006.

·Oil sands cash operating costs averaged $27.80 per barrel during 2007, compared to $21.70 per barrel in 2006. The increase in 2007 was primarily due to fixed costs being spread over lower production, as well as higher maintenance costs related to planned and unplanned shutdowns.

·Suncor continued to make progress on plans to expand Upgrader 2 and increase production capacity to 350,000 bpd, with completion targeted in 2008. As of December 31, the project was 95% complete.

Suncor Energy Inc.

P.O. Box 38, 112 4 Avenue S.W., Calgary, Alberta T2P 2V5

Website: www.suncor.com

·In July, Suncor filed a regulatory application for the Voyageur South mine extension. Bitumen produced at the proposed project is expected to provide additional feedstock flexibility.

·In Suncor’s downstream operations, investments were made to enable the company’s Sarnia refinery to integrate up to 40,000 bpd of oil sands sour crude into the facility.

·In September, Suncor commissioned its fourth wind power project. The 76 megawatt facility located near Ripley, Ontario is the company’s largest wind power project.

·Capital spending in 2007 totalled $5.4 billion. Net debt at year-end 2007 was $3.2 billion, compared to $1.8 billion at the end of 2006.

·Suncor achieved a company-wide return on capital employed of 28.3% in 2007 (excluding capitalized costs for major projects in progress), compared to 40.7% in 2006.

Fourth Quarter 2007

Suncor’s net earnings for the fourth quarter of 2007 were $963 million ($2.08 per common share), compared to $358 million ($0.78 per common share) in the fourth quarter of 2006. Excluding the reduction of federal income tax rates, net insurance proceeds (relating to a January 2005 fire), the impacts of unrealized foreign exchange gains/losses on the company’s U.S. dollar denominated long-term debt and project start-up costs, net earnings for the fourth quarter of 2007 were $598 million ($1.29 per common share), compared to $378 million ($0.82 per common share) during the fourth quarter of 2006. Cash flow from operations for the fourth quarter of 2007 was $1.104 billion, compared to $746 million in the fourth quarter of 2006.

The increase in net earnings primarily reflects higher oil sands operating revenues, as stronger price realizations more than offset lower production in the quarter. Net earnings were also positively impacted by lower oil sands royalty expense that primarily resulted from an increase in capital expenditures incurred. These factors were partially offset by lower earnings in refining and marketing due to the planned outage at the Sarnia refinery that resulted in increased product purchases to meet customer commitments. The increase in cash flow from operations in the fourth quarter of 2007, compared to the fourth quarter of 2006, was due to the same factors that impacted net earnings, partially offset by an increase in cash income taxes during the quarter.

Suncor’s combined oil sands and natural gas production for the fourth quarter was 290,700 boe per day, compared to 301,100 boe per day in the same period of 2006. Natural gas production increased to an average of 229 mmcfe per day in the fourth quarter of 2007, compared to the 208 mmcfe per day recorded in the fourth quarter of 2006. Oil sands production in the fourth quarter of 2007 averaged 252,500 bpd, compared to fourth quarter 2006 production of 266,400 bpd.

Fourth quarter 2007 oil sands cash operating costs were $27.90 per barrel, compared to $25.65 per barrel in the same period of 2006. Cash operating costs per barrel were higher in the fourth quarter of 2007 primarily due to the operating costs being allocated across reduced production volumes.

In the downstream, a shutdown of the Sarnia refinery to tie in modified facilities was completed in November. During commissioning of the new facilities in December, operational difficulties were encountered resulting in a lengthier than planned start-up period. As a result, full production from the

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new facilities has not yet been achieved. Work is ongoing at the refinery to address this issue. Planned maintenance work was also conducted at the company’s Commerce City refinery in the fourth quarter of 2007.

Operational Outlook

“We plan on establishing new milestones for our company in 2008 and anticipate a record-setting year for production,” said George. “Safe, reliable, cost effective and environmentally responsible operations will be the focus.”

Suncor’s outlook provides management’s targets for 2008 in certain key areas of the company’s business. Outlook forecasts are subject to change.

	2008 Full Year Outlook
Oil Sands
Production (bpd)	275,000 bpd  to 300,000 bpd
Diesel	11%
Sweet	36%
Sour	49%
Bitumen	2%
Third-party processing	2%
Realization on crude sales basket	WTI @ Cushing less
	Cdn$4.25 to Cdn$5.25 per barrel
Cash operating costs (1)	$25.00 to $27.00 per barrel
Natural Gas
Production (2)	205 to 215
(mmcf equivalent per day)
Natural gas	93%
Liquids	7%

1.Cash operating cost estimates are based on the following assumptions: i) production volumes and sales mix as described in the table above; and ii) a natural gas price of $6.70 per gigajoule at AECO. This goal also includes costs incurred for third-party bitumen processing. Cash operating costs per barrel are not prescribed by Canadian generally accepted accounting principles (GAAP). This non-GAAP financial measure does not have any standardized meaning and therefore is unlikely to be comparable to similar measures presented by other companies. Suncor includes this non-GAAP financial measure because investors may use this information to analyze operating performance. This information should not be considered in isolation or as a substitute for measures of performance prepared in accordance with GAAP. See “Non-GAAP Financial Measures”.

2.Production target includes natural gas liquids (NGL) and crude oil converted into mmcf equivalent at a ratio of one barrel of NGL/crude oil: six thousand cubic feet of natural gas. This conversion ratio is based on an energy equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the wellhead. This mmcf equivalent may be misleading, particularly if used in isolation.

Factors that could potentially impact Suncor’s financial performance include:

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·Planned maintenance at oil sands. Upgrader 1 is expected to be shut down for approximately 30 days in the second quarter while scheduled maintenance is underway. Although this shutdown is reflected in operational targets for the year, production estimates could be impacted if unplanned work is identified, or the schedule is impacted by labour or material supply issues. During the outage, Upgrader 2 is expected to continue producing approximately 200,000 bpd.

·Completion and commissioning of an expansion to Upgrader 2 during the second quarter to enable production capacity of 350,000 bpd. Production rates during the ramp-up period are difficult to predict and can be impacted by bitumen supply, as well as planned and unplanned maintenance. However, Suncor expects to move towards the 350,000 bpd capacity in the fourth quarter.

·Regulatory requirements at the company’s oil sands base plant and in-situ operation. Suncor plans to incur maintenance and capital expenditures to construct and commission emission abatement equipment. The timing and scope of this work could impact 2008 results.

·Bitumen supply. If Suncor encounters unexpected issues in meeting regulatory requirements aimed at controlling emissions at both base plant and the in-situ operation, there may be further bitumen supply restrictions that could impact 2008 production targets.

·Production volumes at the Sarnia refinery. Suncor is lining-out new facilities at the refinery and this work could impact future production. In addition, third-party hydrogen is in tight supply and this could also reduce production volumes resulting in increased purchases of products to meet customer requirements.

·Crude oil hedges. Suncor has hedging agreements for 10,000 bpd in 2008. These costless collar hedges have an average floor of US$59.85 per barrel with an average ceiling of US$101.06 per barrel in 2008.

Information on risks, uncertainties and other factors that could affect these plans is included in Suncor’s annual report to shareholders and other documents filed with regulatory authorities.

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Net Earnings Components

This table sets forth some of the factors impacting Suncor’s net earnings.

					Years ended
($ millions after tax)	Fourth Quarter				December 31
(unaudited)	2007		2006		2007		2006
Net earnings before the following items:	598		378		2 239		2 350
Impact of income tax rate changes on opening future income tax liabilities (1)	360		-		427		419
Oil sands fire accrued insurance proceeds (2)	-		27		-		232
Unrealized foreign exchange gain (loss) on
U.S. dollar denominated long-term debt	16		(43	)	215		-
Project start-up costs	(11	)	(4	)	(49	)	(30	)
Net earnings as reported	963		358		2 832		2 971
Net earnings per share attributable to common shareholders as reported	$2.08		$0.78		$6.14		$6.47

(1) Reflects Q4 2007 federal rate reduction of 3.5%, Q2 2007 federal rate reduction of 0.5%, Q2 2006 federal rate reduction of 3.1% and Q2 2006 Alberta rate reduction of 1.5%.

(2) Net accrued property loss and business interruption proceeds net of income taxes and Alberta Crown Royalties.

Non-GAAP Financial Measures

Certain financial measures referred to in this news release, namely cash flow from operations, return on capital employed (ROCE) and oil sands cash and total operating costs per barrel, are not prescribed by GAAP. These non-GAAP financial measures do not have any standardized meaning and therefore are unlikely to be comparable to similar measures presented by other companies. Suncor includes these non-GAAP financial measures 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.

Cash flow from operations is expressed before changes in non-cash working capital. A reconciliation of net earnings to cash flow from operations is provided in the schedules of segmented data, which are an integral part of the company’s fourth quarter financial statements.

A reconciliation of cash flow from operations on a per common share basis is presented in the following table:

Reconciliation of cash flow from operations on a per share basis

    (unaudited)

				Years ended
		Fourth Quarter		December 31
		2007	2006	2007	2006
Cash flow from operations ($ millions)	A	1 104	746	3 805	4 533
Weighted average number of common shares outstanding - basic (millions of shares)	B	462	460	461	459
Cash flow from operations - basic (per share)	A/B	2.39	1.62	8.25	9.87

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The following tables outline the reconciliation of oil sands cash and total operating costs to expenses included in the schedules of segmented data in Suncor’s fourth quarter financial statements.

Oil Sands Operating
Costs - Total Operations		Fourth Quarter						Years ended December 31
(unaudited)		2007			2006			2007			2006
		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general
expenses		652			696			2 435			2 198
Less: natural gas costs, inventory changes and stock-based compensation		(96	)		(134	)		(353	)		(361	)
Less: non-monetary transactions		(21	)		(22	)		(102	)		(126	)
Accretion of asset retirement obligations		10			7			41			28
Taxes other than income taxes		16			8			55			36
Cash costs		561		24.10	555		22.65	2 076		24.15	1 775		18.70
Natural gas		84		3.60	74		3.00	307		3.55	276		2.90
Imported bitumen (net of other reported product purchases)		5		0.20	-		-	8		0.10	6		0.10
Cash operating costs	A	650		27.90	629		25.65	2 391		27.80	2 057		21.70
Project start-up costs	B	13		0.55	6		0.25	60		0.95	38		0.40
Total cash operating costs	A+B	663		28.45	635		25.90	2 451		28.75	2 095		22.10
Depreciation, depletion and amortization		129		5.60	104		4.25	462		5.40	385		4.05
Total operating costs		792		34.05	739		30.15	2 913		34.15	2 480		26.15
Production (thousands of barrels per day)		252.5			266.4			235.6			260.0

Oil Sands Operating Costs - In-		Fourth Quarter						Years ended December 31
situ Bitumen Production Only		2007			2006			2007			2006
(unaudited)		$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses		69			57			273			209
Less: natural gas costs and inventory changes		(34	)		(32	)		(134	)		(103	)
Taxes other than income taxes		2			1			7			4
Cash costs		37		9.95	26		8.05	146		10.85	110		8.95
Natural gas		34		9.15	32		9.90	134		9.90	103		8.35
Cash operating costs	A	71		19.10	58		17.95	280		20.75	213		17.30
In-situ (Firebag) start-up costs	B	-		-	-		-	-		-	21		1.70
Total cash operating costs	A+B	71		19.10	58		17.95	280		20.75	234		19.00
Depreciation, depletion and amortization		25		6.80	20		6.20	83		6.20	68		5.55
Total operating costs		96		25.90	78		24.15	363		26.95	302		24.55
Production (thousands of barrels per day)		40.4			35.1			36.9			33.7

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ROCE is calculated as net earnings (2007 - $2,653 million; 2006 - $2,997 million) adjusted for after-tax financing expense (2007 - income of $179 million; 2006 - loss of $26 million) for the twelve month period ended; divided by average capital employed (2007 - $9,376 million; 2006 - $7,357 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 average annual capitalized costs related to major projects in progress (as applicable). For more detail on how ROCE is calculated, see page 58 of Suncor’s 2006 Annual Report.

This news release contains forward-looking statements that address goals, expectations or projections about the future. These statements are based on Suncor’s current goals, expectations, estimates, projections and assumptions, as well as its current budgets and plans for capital expenditures. Some of the forward-looking statements may be identified by words like “goal”, “targeted”, “expected”, “plans”, “forecasts”, “should”, “estimates”, “may”, “could”, “proposed”, “outlook”, “continues” and similar expressions. These statements are not guarantees of future performance. Actual results could differ materially, as a result of factors, risks and uncertainties, known and unknown, to which Suncor’s business is subject. These could include: changes in general economic, market and business conditions; fluctuations in supply and demand for Suncor’s products; fluctuations in commodity prices and currency exchange rates; the impact of stakeholder consultation; the regulatory process; technical issues; environmental issues; technological capabilities; new legislation; the occurrence of unexpected events; Suncor’s capability to execute and implement its future plans; actions by governmental authorities including the imposition of taxes or increases to fees and royalties, changes in environmental and other regulations (for example, the Government of Alberta’s current negotiation with Suncor in connection with the Crown Royalty regime, the Government of Canada’s current review of greenhouse gas emission regulations and the issuance of government and regulatory control and protection orders); and changes in current plans. Further discussion of the risks, uncertainties and other factors that could affect these plans, and any actual results, is included in Suncor’s annual report to shareholders and other documents filed with regulatory authorities.

Suncor Energy Inc. is an integrated energy company headquartered in Calgary, Alberta. Suncor’s oil sands business, located near Fort McMurray, Alberta, extracts and upgrades oil sands and markets refinery feedstock and diesel fuel, while operations throughout western Canada produce natural gas. Suncor operates a refining and marketing business in Ontario with retail distribution under the Sunoco brand. U.S.A. downstream assets include pipeline and refining operations in Colorado and Wyoming and retail sales in the Denver area under the Phillips 66® brand. Suncor’s common shares (symbol: SU) are listed on the Toronto and New York stock exchanges.

Suncor Energy (U.S.A.) Inc. is an authorized licensee of the Phillips 66® brand and marks in the state of Colorado. Sunoco in Canada is separate and unrelated to Sunoco in the United States, which is owned by Sunoco, Inc. of Philadelphia.

- 30 -

Investor inquiries: John Rogers 403-269-8670

Media inquiries: Brad Bellows 403-269-8717

To listen to the conference call discussing Suncor’s fourth quarter results, visit www.suncor.com/webcasts.

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Suncor Energy Inc.

Consolidated Statements of Earnings and Comprehensive Income

(unaudited)

	Fourth Quarter			Years ended Dec 31
	2007		2006	2007		2006
($ millions)			(restated)			(restated)
REVENUES (note 4)	4 958		3 787	17 933		15 829
EXPENSES
Purchases of crude oil and products	1 546		1 055	5 935		4 678
Operating, selling and general (notes 4 and 7)	921		928	3 375		3 043
Energy marketing and trading activities (note 4)	943		498	2 870		1 541
Transportation and other costs	54		60	198		212
Depreciation, depletion and amortization	254		191	864		695
Accretion of asset retirement obligations	12		8	48		34
Exploration	17		24	95		104
Royalties (note 11)	201		267	691		1 038
Taxes other than income taxes	161		157	648		595
Loss (gain) on disposal of assets	7		4	7		(1	)
Project start-up costs	16		6	68		45
Financing expenses (income) (note 5)	(26	)	52	(211	)	39
	4 106		3 250	14 588		12 023
EARNINGS BEFORE INCOME TAXES	852		537	3 345		3 806
PROVISION FOR (RECOVERY OF) INCOME TAXES (note 10)
Current	68		31	382		20
Future	(179	)	148	131		815
	(111	)	179	513		835
NET EARNINGS	963		358	2 832		2 971
Other comprehensive income (loss) (notes 2 and 4)	(20	)	46	(190	)	10
COMPREHENSIVE INCOME	943		404	2 642		2 981
NET EARNINGS PER COMMON SHARE (dollars), (note 6)
- Basic	2.08		0.78	6.14		6.47
- Diluted	2.04		0.76	6.02		6.32
Cash dividends	0.10		0.08	0.38		0.30

See accompanying notes

Suncor Energy Inc.

Consolidated Balance Sheets

(unaudited)

		December 31			December 31
		2007			2006
					(restated)
($ millions)					(note 2)
ASSETS
Current assets
Cash and cash equivalents		569			521
Accounts receivable (notes 2 and 4)		1 416			1 050
Inventories		608			589
Income taxes receivable		95			33
Future income taxes		130			109
Total current assets		2 818			2 302
Property, plant and equipment, net		20 945			16 160
Deferred charges and other (notes 2 and 4)		404			297
Total assets		24 167			18 759
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt		6			7
Accounts payable and accrued liabilities (notes 2, 4 and 11)		2 775			2 111
Taxes other than income taxes		72			40
Income taxes payable		244			-
Total current liabilities		3 097			2 158
Long-term debt (note 12)		3 811			2 363
Accrued liabilities and other (notes 2 and 4)		1 434			1 214
Future income taxes (notes 2, 4 and 10)		4 212			4 072
Shareholders’ equity (see below)		11 613			8 952
Total liabilities and shareholders’ equity		24 167			18 759
SHAREHOLDERS’ EQUITY
	Number			Number
	(thousands)			(thousands)
Share capital	462 783	881		459 944	794
Contributed surplus		194			100
Accumulated other comprehensive income (notes 2 and 4)		(253	)		(71	)
Retained earnings (note 2)		10 791			8 129
Total shareholders’ equity		11 613			8 952

See accompanying notes

Suncor Energy Inc.

Consolidated Statements of Cash Flows

(unaudited)

	Fourth Quarter				Years ended Dec 31
($ millions)	2007		2006		2007		2006
OPERATING ACTIVITIES
Cash flow from operations	1 104		746		3 805		4 533
Decrease (increase) in operating working capital
Accounts receivable	(168	)	153		(365	)	53
Inventories	66		59		(19	)	(66	)
Accounts payable and accrued liabilities	172		234		226		87
Taxes payable/receivable	94		(28	)	246		(43	)
Cash flow from operating activities	1 268		1 164		3 893		4 564
CASH USED IN INVESTING ACTIVITIES	(1 684	)	(1 169	)	(5 362	)	(3 489	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	(416	)	(5	)	(1 469	)	1 075
FINANCING ACTIVITIES
Decrease in short-term debt	(2	)	(1	)	(4	)	(42	)
Net proceeds from issuance of long-term debt	-		-		1 835		-
Net increase (decrease) in long-term debt	298		264		(171	)	(622	)
Issuance of common shares under stock option plan	18		5		62		45
Dividends paid on common shares	(42	)	(35	)	(162	)	(127	)
Deferred revenue	-		-		4		27
Cash provided by (used in) financing activities	272		233		1 564		(719	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	(144	)	228		95		356
EFFECT OF FOREIGN EXCHANGE ON CASH AND CASH EQUIVALENTS	(3	)	3		(47	)	-
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	716		290		521		165
CASH AND CASH EQUIVALENTS AT END OF PERIOD	569		521		569		521

See accompanying notes

Suncor Energy Inc.

Consolidated Statements of Changes in Shareholders’ Equity

(unaudited)

				Cumulative				Accumulated
				Foreign				Other
	Share	Contributed		Currency		Retained		Comprehensive
($ millions)	Capital	Surplus		Translation		Earnings		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	-	-		-		2 971		-
Dividends paid on common shares	-	-		-		(127	)	-
Issued for cash under stock option plan	52	(7	)	-		-		-
Issued under dividend reinvestment plan	10	-		-		(10	)	-
Stock-based compensation expense	-	53		-		-		-
Income tax benefit of stock option deduction in the U.S.	-	4		-		-		-
Change in AOCI related to foreign currency translation	-	-		-		-		10
At December 31, 2006, as restated	794	100		-		8 129		(71	)
Net earnings	-	-		-		2 832		-
Dividends paid on common shares	-	-		-		(162	)	-
Issued for cash under stock option plan	74	(12	)	-		-		-
Issued under dividend reinvestment plan	13	-		-		(13	)	-
Stock-based compensation expense	-	103		-		-		-
Income tax benefit of stock option deduction in the U.S.	-	3		-		-		-
Adjustment to opening retained earnings arising from ineffective portion of cash flow hedges at January 1, 2007	-	-		-		5		-
Adjustment to opening AOCI arising from effective portion of cash flow hedges at January 1, 2007	-	-		-		-		8
Change in AOCI related to foreign currency translation	-	-		-		-		(195	)
Change in AOCI related to derivative hedging activities	-	-		-		-		5
At December 31, 2007	881	194		-		10 791		(253	)

See accompanying notes

Suncor Energy Inc.
Schedules of Segmented Data
(unaudited)
	Fourth Quarter

								Refining and
								Marketing				Corporate and
	Oil Sands			Natural Gas				(note 3)				Eliminations				Total
($ millions)	2007	2006		2007		2006		2007		2006		2007		2006		2007		2006
EARNINGS
Revenues
Operating revenues	1 800	1 494		141		134		2 072		1 594		2		-		4 015		3 222
Energy marketing and trading activities	-	-		-		-		919		510		18		-		937		510
Net insurance proceeds	-	51		-		-		-		-		-		-				51
Intersegment revenues	192	131		3		-		-		-		(195	)	(131	)	-		-
Interest		-		-		-		1		2		5		2		6		4
	1 992	1 676		144		134		2 992		2 106		(170	)	(129	)	4 958		3 787
Expenses
Purchases of crude oil and products	20	1		-		-		1 724		1 195		(198	)	(141	)	1 546		1 055
Operating, selling and general (note 3)	652	696		33		28		182		180		54		24		921		928
Energy marketing and trading activities	-	-		-		-		922		500		21		(2	)	943		498
Transportation and other costs	42	48		6		8		6		4		-		-		54		60
Depreciation, depletion and amortization	128	104		61		42		54		38		11		7		254		191
Accretion of asset retirement obligations	10	7		2		1		-		-		-		-		12		8
Exploration	-	-		17		24		-		-		-		-		17		24
Royalties (note 11)	164	229		37		38		-		-		-		-		201		267
Taxes other than income taxes	25	17		-		-		136		140		-		-		161		157
Loss on disposal of assets	1	-		-		1		6		3		-		-		7		4
Project start-up costs	13	6		-		-		3		-		-		-		16		6
Financing expenses (income)	-	-		-		-		-		-		(26	)	52		(26	)	52
	1 055	1 108		156		142		3 033		2 060		(138	)	(60	)	4 106		3 250
Earnings (loss) before income taxes	937	568		(12	)	(8	)	(41	)	46		(32	)	(69	)	852		537
Income taxes	69	(174	)	37		2		41		(23	)	(36	)	16		111		(179	)
Net earnings (loss)	1 006	394		25		(6	)	-		23		(68	)	(53	)	963		358

Suncor Energy Inc.
Schedules of Segmented Data (continued)
(unaudited)
	Fourth Quarter

									Refining and
									Marketing				Corporate and
	Oil Sands				Natural Gas				(note 3)				Eliminations				Total
($ millions)	2007		2006		2007		2006		2007		2006		2007		2006		2007		2 006
CASH FLOW BEFORE FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from (used in) operations
Net earnings	1 006		394		25		(6	)	-		23		(68	)	(53	)	963		358
Exploration expenses	-		-		13		12		-		-		-		-		13		12
Non-cash items included in earnings
Depreciation, depletion and amortization	128		104		61		42		54		38		11		7		254		191
Future income taxes	(151	)	178		(35	)	(2	)	(32	)	(13	)	39		(15	)	(179	)	148
Loss on disposal of assets	1		-		-		1		6		3		-		-		7		4
Stock-based compensation expense	19		11		2		1		10		5		10		5		41		22
Other	14		(10	)	1		-		(5	)	(11	)	1		37		11		16
Increase (decrease) in deferred credits and other	3		(5	)	-		-		1		(1	)	(10	)	1		(6	)	(5	)
Total cash flow from (used in) operations	1 020		672		67		48		34		44		(17	)	(18	)	1 104		746
Decrease (increase) in operating working capital	201		721		10		(21	)	19		(57	)	(66	)	(225	)	164		418
Total cash flow from (used in) operating activities	1 221		1 393		77		27		53		(13	)	(83	)	(243	)	1 268		1 164
Cash from (used in) investing activities:
Capital and exploration expenditures	(1 293	)	(916	)	(106	)	(117	)	(152	)	(164	)	(35	)	(4	)	(1 586	)	(1 201	)
Deferred maintenance shutdown expenditures	(37	)	-		(5	)	-		(45	)	(24	)	-		-		(87	)	(24	)
Deferred outlays and other investments	(19	)	-		-		-		-		-		2		3		(17	)	3
Proceeds from disposals	3		1		-		2		-		1		-		-		3		4
Proceeds from property loss	-		7		-		-		-		-		-		-		-		7
Decrease (increase) in investing working capital	19		43		-		-		(16	)	(1	)	-		-		3		42
Total cash (used in) investing activities	(1 327	)	(865	)	(111	)	(115	)	(213	)	(188	)	(33	)	(1	)	(1 684	)	(1 169	)
Net cash surplus (deficiency) before financing activities	(106	)	528		(34	)	(88	)	(160	)	(201	)	(116	)	(244	)	(416	)	(5	)

Suncor Energy Inc.
Schedules of Segmented Data (continued)
(unaudited)
	Years ended December 31

									Refining and
									Marketing				Corporate and
	Oil Sands				Natural Gas				(note 3)				Eliminations				Total
($ millions)	2007		2006		2007		2006		2007		2006		2007		2006		2007		2006
EARNINGS
Revenues
Operating revenues	6 195		6 259		541		554		8 278		6 981		6		4		15 020		13 798
Energy marketing and trading activities	-		-		-		-		2 890		1 607		(7	)	(25	)	2 883		1 582
Net insurance proceeds	-		436		-		-		-		-		-		-		-		436
Intersegment revenues	580		712		12		23		-		-		(592	)	(735	)	-		-
Interest	-		-		-		1		5		5		25		7		30		13
	6 775		7 407		553		578		11 173		8 593		(568	)	(749	)	17 933		15 829
Expenses
Purchases of crude oil and products	157		89		-		-		6 351		5 308		(573	)	(719	)	5 935		4 678
Operating, selling and general (note 3)	2 435		2 198		135		110		693		669		112		66		3 375		3 043
Energy marketing and trading activities	-		-		-		-		2 876		1 572		(6	)	(31	)	2 870		1 541
Transportation and other costs	138		162		31		25		29		25		-		-		198		212
Depreciation, depletion and amortization	462		385		189		152		171		132		42		26		864		695
Accretion of asset retirement obligations	40		28		7		5		1		1		-		-		48		34
Exploration	13		22		82		82		-		-		-		-		95		104
Royalties (note 11)	565		911		126		127		-		-		-		-		691		1 038
Taxes other than income taxes	90		75		4		3		553		516		1		1		648		595
Loss (gain) on disposal of assets	1		-		(1	)	(4	)	7		3		-		-		7		(1	)
Project start-up costs	60		38		-		-		8		7		-		-		68		45
Financing expenses (income)	-		-		-		-		-		-		(211	)	39		(211	)	39
	3 961		3 908		573		500		10 689		8 233		(635	)	(618	)	14 588		12 023
Earnings (loss) before income taxes	2 814		3 499		(20	)	78		484		360		67		(131	)	3 345		3 806
Income taxes	(380	)	(716	)	45		28		(139	)	(125	)	(39	)	(22	)	(513	)	(835	)
Net earnings (loss)	2 434		2 783		25		106		345		235		28		(153	)	2 832		2 971
As at December 31
TOTAL ASSETS	18 108		13 692		1 811		1 503		4 519		4 037		(271	)	(473	)	24 167		18 759

Suncor Energy Inc.
Schedules of Segmented Data (continued)
(unaudited)
	Years ended December 31

									Refining and
									Marketing				Corporate and
	Oil Sands				Natural Gas				(note 3)				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)	2 434		2 783		25		106		345		235		28		(153	)	2 832		2 971
Exploration expenses	-		-		67		52		-		-		-		-		67		52
Non-cash items included in earnings
Depreciation, depletion and amortization	462		385		189		152		171		132		42		26		864		695
Future income taxes	97		731		(43	)	(28	)	40		70		37		42		131		815
Loss (gain) on disposal of assets	1		-		(1	)	(4	)	7		3		-		-		7		(1	)
Stock-based compensation expense	49		25		5		2		25		13		24		13		103		53
Other	1		14		7		1		(5	)	(7	)	(236	)	(22	)	(233	)	(14	)
Increase (decrease) in deferred credits and other	48		(21	)	(1	)	-		(3	)	(3	)	(10	)	(14	)	34		(38	)
Total cash flow from (used in) operations	3 092		3 917		248		281		580		443		(115	)	(108	)	3 805		4 533
Decrease (increase) in operating working capital	637		426		22		(27	)	(118	)	(102	)	(453	)	(266	)	88		31
Total cash flow from (used in) operating activities	3 729		4 343		270		254		462		341		(568	)	(374	)	3 893		4 564
Cash from (used in) investing activities:
Capital and exploration expenditures	(4 431	)	(2 463	)	(531	)	(458	)	(376	)	(665	)	(77	)	(27	)	(5 415	)	(3 613	)
Deferred maintenance shutdown expenditures	(135	)	-		(6	)	-		(73	)	(80	)	-		-		(214	)	(80	)
Deferred outlays and other investments	(18	)	(2	)	-		-		-		7		(14	)	(2	)	(32	)	3
Proceeds from disposals	3		2		5		15		1		4		-		-		9		21
Proceeds from property loss	-		36				-		-		-		-		-		-		36
Decrease (increase) in investing working capital	333		197		-		-		(43	)	(53	)	-		-		290		144
Total cash (used in) investing activities	(4 248	)	(2 230	)	(532	)	(443	)	(491	)	(787	)	(91	)	(29	)	(5 362	)	(3 489	)
Net cash surplus (deficiency) before financing activities	(519	)	2 113		(262	)	(189	)	(29	)	(446	)	(659	)	(403	)	(1 469	)	1 075

Q4/07 ROLLFORWARD

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 December 31, 2007 and the results of its operations and cash flows for the three and twelve month periods ended December 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 3865 “Hedging”, Section 1530 “Comprehensive Income” and Section 3251 “Equity”.

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

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

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

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

Gains or losses arising from hedging activities, including the ineffective portion, are reported in the same caption as the hedged item. The determination of hedge effectiveness and the measurement of hedge ineffectiveness for cash flow hedges are based on internally derived valuations.

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

The company’s equity section now contains a new caption “Accumulated Other Comprehensive Income”. In addition to containing the effective portions of the gains/losses on our cash flow hedges, accumulated other comprehensive income also contains 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, net of income taxes, were recorded to the Consolidated Balance Sheet:

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

(1)Recognition of fair value of derivative financial instruments designated as cash flow hedges and fair value hedges, and the related income tax impacts

(2)Impact on adoption of the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges

(3)Restatement of foreign currency translation adjustment to accumulated other comprehensive loss

(4)Recognition of accumulated other comprehensive loss arising from the restatement of foreign currency translation adjustment, offset by accumulated other comprehensive income arising from the measurement of ineffectiveness on derivative financial instruments designated as cash flow hedges

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

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 December 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

(a) Balance Sheet Financial Instruments

The company’s financial instruments 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 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 with the exception of the portion of debt that has related financial hedges which is accounted for under the fair value hedge methodology outlined below. Upon initial recognition, the cost of the debt is its fair value, adjusted for any associated transaction costs. We do not recognize gains or losses arising from changes in the fair value of this debt until the gains or losses are realized. At December 31, 2007, the carrying value of our fixed-term debt accounted for under the amortized cost method was $3.0 billion (fair value - $3.1 billion).

(b) Hedges

Fair Value Hedges

Suncor periodically enters into derivative financial instrument contracts such as interest rate swaps as part of its risk management strategy to manage its exposure to benchmark interest rate fluctuations. The interest rate swap contracts involve an exchange of floating rate versus fixed rate interest payments between the company and investment grade counterparties. The differentials on the exchange of periodic interest payments are recognized in the accounts as an adjustment to interest expense. The fair value of the underlying debt is adjusted by the fair value change in the derivative financial instrument with the offset to interest expense.  At December

31, 2007, the company had interest rate derivatives classified as fair value hedges outstanding for up to 4 years relating to fixed-rate debt. There was no ineffectiveness recognized on interest rate swaps designated as fair value hedges during the three and twelve month periods ended December 31, 2007.

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

Cash Flow Hedges

Suncor operates in a global industry where the market price of its petroleum and natural gas products is largely determined based on floating benchmark indices. The company periodically enters into derivative financial instrument contracts such as forwards, futures, swaps, options and costless collars to hedge against the potential adverse impact of changing market prices due to changes in the underlying indices. Specifically, the company manages crude sales price variability by entering into West Texas Intermediate (WTI) derivative transactions, and manages variability in market interest rates during periods of debt issuance through the use of interest rate swap transactions.

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

The earnings impact associated with realized and unrealized hedge ineffectiveness on derivative contracts designated as cash flow hedges during the three month period ended December 31, 2007 was a loss of $1 million. During the twelve month period ended December 31, 2007, the earnings impact was a loss of $5 million, net of income taxes of $2 million.

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

Fair Value of Hedging Derivative Financial Instruments

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

($ millions)	2007		2006
Revenue hedge swaps and collars	(11	)	22
Fixed to floating interest rate swaps	8		16
Specific hedges of individual transactions	12		(4	)
Fair value of outstanding hedging derivative financial instruments	9		34

Accumulated Other Comprehensive Income (AOCI)

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

($ millions)	2007
AOCI attributable to derivatives and hedging activities, recorded upon initial adoption on January 1, 2007, net of income taxes of $5	8
Current year net changes, net of income taxes of $1	8
Net unrealized hedging gains at the beginning of the period reclassified to earnings during the year, net of income taxes of $2	(3	)
AOCI attributable to derivatives and hedging activities, at December 31, 2007, net of income taxes of $4	13

(c) Energy Marketing and Trading Activities

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

Net Pretax Earnings (Loss)

	Fourth quarter						Years ended
							December 31
($ millions)	2007		2006		2007		2006
Physical energy contracts trading activity	(5	)	11		21		41
Financial energy contracts trading activity	4		-		(3	)	(3	)
General and administrative costs	(2	)	(1	)	(4	)	(3	)
Total	(3	)	10		14		35

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

($ millions)	2007		2006
Energy trading assets	18		16
Energy trading liabilities	21		13
Net energy trading assets (liabilities)	(3	)	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	29
Fair value of contracts entered into during the period	(56	)
Changes in values attributable to market price and other market changes	21
Fair value of contracts outstanding at December 31, 2007	(3	)

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

5.Financing Expenses (Income)

	Fourth Quarter				Years ended December 31
($ millions)	2007		2006		2007		2006
Interest expense on debt	58		38		189		150
Capitalized interest	(58	)	(35	)	(189	)	(129	)
Net interest expense	-		3		-		21
Foreign exchange (gain) loss on long-term debt	(19	)	51		(252	)	-
Other foreign exchange (gain) loss	(7	)	(2	)	41		18
Total financing expenses (income)	(26	)	52		(211	)	39

6.Reconciliation of Basic and Diluted Net Earnings Per Common Share

	Fourth Quarter		Years ended December 31
($ millions)	2007	2006	2007	2006
Net earnings	963	358	2 832	2 971
(millions of common shares)
Weighted-average number of common shares	462	460	461	459
Dilutive securities:
Options issued under stock-based compensation plans	11	11	10	11
Weighted-average number of diluted common shares	473	471	471	470
(dollars per common share)
Basic earnings per share (a)	2.08	0.78	6.14	6.47
Diluted earnings per share (b)	2.04	0.76	6.02	6.32

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 the 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 criterion. Once this right has been earned, these options are considered vested.

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

A performance share unit is an award entitling employees to receive a payment ranging from zero to a maximum of 150% of the value of a common share contingent upon Suncor’s shareholder return over a three year period relative to a peer group of companies.

(a) Stock Option Plans:

(i) SunShare 2012 Performance Stock Option Plan

The company granted 147,000 options in the fourth quarter of 2007, for a total of 7,843,000 options granted in the year ended December 31, 2007, under its new employee stock option incentive plan (“SunShare 2012”). Under this plan, meeting specified performance targets may accelerate the vesting of some options, such that 25% of outstanding options may vest on January 1, 2010, and the remaining 75% of outstanding options may vest on January 1, 2013. All unvested options at January 1, 2013, which have not previously expired or been cancelled, will automatically expire.

(ii) SunShare Performance Stock Option Plan

Under the SunShare long-term incentive plan, the company granted 12,000 options to new and existing employees in the fourth quarter of 2007, for a total of 1,045,000 options granted in the year ended December 31, 2007 (405,000 options granted during the fourth quarter of 2006; 1,637,000 options granted in the year ended December 31, 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 criterion is not met, the unvested options that have not previously expired or been cancelled, will automatically vest on January 1, 2012. Management believes that it is highly likely the final performance criterion will be met and that all unvested SunShare options at April 30, 2008 will therefore vest. Stock-based compensation expense has been recorded to reflect this assumption.

(iii) Executive Stock Option Plan

Under this plan, the company granted no common share options in the fourth quarter of 2007, for a total of 479,000 options granted in the twelve months ended December 31, 2007 (5,000 options granted during the fourth quarter of 2006; 538,000 granted in the twelve months ended December 31, 2006) to non-employee directors and certain executives and other senior members of the company. Options granted have a ten-year life and vest annually over a three-year period.

(iv) Key Contributor Stock Option Plan

Under this plan, the company granted 3,000 common share options in the fourth quarter of 2007, for a total of 1,185,000 options granted in the twelve months ended December 31, 2007 (1,000 options granted during the fourth quarter of 2006; 1,050,000 granted in the twelve months ended December 31, 2006) to non-insider senior managers and key employees.  Options granted have a ten-year life and vest annually over a three-year period.

Fair Value of Options Granted

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

	Fourth Quarter				Years ended December 31
	2007		2006		2007		2006
Quarterly dividend per share	$0.10		$0.08		$0.10	*	$0.08	**
Risk-free interest rate	4.24	%	3.88	%	4.22	%	4.08	%
Expected life	5 years		3 years		6 years		5 years
Expected volatility	30	%	29	%	30	%	29	%
Weighted-average fair value per option	$29.67		$22.39		$29.77		$29.17

* In 2007, quarterly dividends of $0.08 per share were paid in the first quarter and $0.10 per share were paid in the second, third and fourth quarters.

** In 2006, a quarterly dividend of $0.06 per share was paid in the first quarter, and quarterly dividends of $0.08 per share were paid in the second, third and fourth quarters.

Stock-based compensation expense recognized in the fourth quarter of 2007 related to stock options plans was $41 million (2006 - $22 million).  For the year ended December 31, 2007 stock-based compensation expense recognized was $103 million (2006 - $53 million).

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

	Fourth Quarter		Years ended December 31
($ millions, except per share amounts)	2007	2006	2007	2006
Net earnings - as reported	963	358	2 832	2 971
Less: compensation cost under the fair value method for pre-2003 options	-	8	8	15
Pro forma net earnings	963	350	2 824	2 956
Basic earnings per share
As reported	2.08	0.78	6.14	6.47
Pro forma	2.08	0.76	6.12	6.44
Diluted earnings per share
As reported	2.04	0.76	6.02	6.32
Pro forma	2.04	0.74	6.00	6.29

(b) Performance share units (PSUs)

In the fourth quarter of 2007 the company issued no PSUs (2006 – 2,000).  For the year ended December 31, 2007, the company issued 415,000 PSUs (2006 – 397,000). Expense recognized in the fourth quarter of 2007 was $14 million (2006 – $17 million).  Expense recognized for the year ended December 31, 2007 was $60 million (2006 – $42 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 fourth quarter and the twelve months ended December 31.

	Pension Benefits
	Fourth quarter				Years ended December 31
($ millions)	2007		2006		2007		2006
Current service costs	12		11		51		44
Interest costs	11		10		45		40
Expected return on plan assets	(10	)	(8	)	(42	)	(32	)
Amortization of net actuarial loss	7		7		25		28
Net periodic benefit cost	20		20		79		80

	Other Post-retirement Benefits
	Fourth quarter		Years ended December 31
($ millions)	2007	2006	2007	2006
Current service costs	1	1	4	5
Interest costs	2	2	8	8
Amortization of net actuarial loss	1	-	3	1
Net periodic benefit cost	4	3	15	14

9.Supplemental Information

	Fourth Quarter			Years ended December 31
($ millions)	2007		2006	2007	2006
Interest paid	47		23	180	146
Income taxes paid (received)	(15	)	29	152	34

Revenue Hedges

Strategic Crude Oil as at December 31, 2007

	Quantity	Average Price	Revenue Hedged	Hedge
	(bpd)	(US$/bbl) (a)	(Cdn$ millions) (b)	Period (c)
Costless Collars	10 000	59.85 – 101.06	216 – 365	2008

(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 December 31, 2007 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.

10.Income Taxes

During the fourth quarter of 2007 the federal government substantively enacted a 3.5% reduction to its federal corporate tax rates.  Accordingly, the company recognized a reduction in future income tax expense of $360 million related to the revaluation of its opening future income tax balances.

During the second quarter of 2007 the federal government substantively enacted a 0.5% reduction to its federal corporate tax rates.  Accordingly, the company recognized a reduction in future income tax expense of $67 million related to the revaluation of its opening future income tax balances.

During 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.

A summary of the impacts on the tax rate changes for the three and twelve months ended December 31 are as follows:

	Fourth quarter			Years ended December 31
($ millions)	2007		2006	2007	2006
Income taxes before tax rate changes	249		179	940	1 254
Impact of tax rate changes	360		-	427	419
Provision for (recovery of) income taxes (per consolidated statement of earnings)	(111	)	179	513	835

11. Royalties

Our current estimation of Alberta Crown royalties is based on regulations currently in effect. Regime changes proposed by the Government of Alberta will take effect January, 2009 should they be enacted.

Alberta Crown royalties currently in effect for each oil sands project require payments to the Government of Alberta based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R. Royalty expense for the company’s oil sands operations for the fourth quarter was $164 million (2006 - $229 million). For the year ended December 31, 2007, royalty expense for the company’s oil sands operations was $565 million (2006 - $911 million).

Royalty expense for the company’s natural gas operations for the fourth quarter was $37 million (2006 - $38 million). For the year ended December 31, 2007, royalty expense for the company’s natural gas operations was $126 million (2006 - $127 million).

12.  Long-term Debt and Credit Facilities

During the third quarter, the company issued an additional US$400 million principal amount of 6.50% Notes under an outstanding US$2 billion debt shelf prospectus. These notes bear interest, which is paid semi-annually, and mature on June 15, 2038. The net proceeds received were used for general corporate purposes, including repayment of short term borrowing, supporting Suncor’s ongoing capital spending program and for working capital requirements.

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

Also during the second quarter, our $300 million bilateral credit facility was amended and extended by one year to 2008 and the credit limit was increased by $30 million to $330 million total funds available. Our $2 billion syndicated credit facility was renegotiated and extended by one year to have a five year term expiring in June 2012 and the company’s commercial paper program limit was increased by $300 million from $1.2 billion to $1.5 billion.  Additionally, a $15 million revolving demand credit facility was renegotiated and increased by $15 million to $30 million.

During the first quarter, the company repaid maturing 6.80% $250 million Medium Term Notes using commercial paper. Also during the first quarter, 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.

	December 31,		December 31,
($ millions)	2007		2006
Fixed-term debt, redeemable at the option of the Company
6.50% Notes, denominated in U.S. dollars, due in 2038 (US$1150)	1 137		-
5.95% Notes, denominated in U.S. dollars, due in 2034 (US$500)	494		583
7.15% Notes, denominated in U.S. dollars, due in 2032 (US$500)	494		583
5.39% Series 4 Medium Term Notes, due in 2037	600		-
6.70% Series 2 Medium Term Notes, due in 2011	500		500
6.10% Medium Term Notes, due in 2007	-		150
6.80% Medium Term Notes, due in 2007	-		250
	3 225		2 066
Revolving-term debt, with interest at variable rates
Commercial Paper	522		280
Total unsecured long-term debt	3 747		2 346
Secured long-term debt	1		1
Capital leases	102		38
Fair value of interest rate swaps	6		-
Deferred financing costs	(45	)	(22	)
Total long-term debt	3 811		2 363

At December 31, 2007, undrawn credit facilities were approximately $1,579 million, as follows:

($ millions)	2007
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2008	330
Facility that is fully revolving for a period of five years and expires in 2012	2 000
Facilities that can be terminated at any time at the option of the lenders	45
Total available credit facilities	2 375
Credit facilities supporting outstanding commercial paper	522
Credit facilities supporting standby letters of credit	274
Total undrawn credit facilities	1 579

Suncor Energy Inc.

Highlights

(unaudited)

		2007	2006
CASH FLOW FROM OPERATIONS
(dollars per common share - basic)
For the three months ended December 31
Cash flow from operations (1)		2.39	1.62
For the years ended December 31
Cash flow from operations (1)		8.25	9.87
RATIOS
For the years ended December 31
Return on capital employed (%) (2)		28.3	40.7
Return on capital employed (%) (3)		20.7	30.5
Net debt to cash flow from operations (times)(4)		0.9	0.4
Interest coverage on long-term debt (times)
Net earnings (5)		17.7	25.5
Cash flow from operations (6)		22.2	30.5
As at December 31
Debt to debt plus shareholders’ equity (%) (7)		24.7	20.9
COMMON SHARE INFORMATION
As at December 31
Share price at end of trading
Toronto Stock Exchange	- Cdn$	107.91	91.79
New York Stock Exchange	- US$	108.73	78.91
Common share options outstanding (thousands)		27 000	19 810
For the years ended December 31
Average number outstanding, weighted monthly (thousands)		461 187	459 069

Refer to the Quarterly Operating Summary for a discussion of  financial measures not prepared in accordance with Canadian 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 adjusted for after-tax financing expense (2007 - income of $179 million; 2006 - loss of $26 million) for the twelve month period ended net earnings (2007 - $2,653 million; 2006 - $2,997 million); divided by average capital employed (2007 - $9,376 million; 2006 - $7,357 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 average 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 - $12,830 million; 2006 - $9,833 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.

Suncor Energy Inc.

Quarterly Operating Summary

(unaudited)

	For the quarter ended					Years ended
	Dec 31	Sep 30	Jun 30	Mar 31	Dec 31	Dec 31	Dec 31
	2007	2007	2007	2007	2006	2007	2006
OIL SANDS
Production (1),(a)
Total production	252.5	239.1	202.3	248.2	266.4	235.6	260.0
Firebag	40.4	35.8	36.2	35.3	35.1	36.9	33.7
Sales (a)
Light sweet crude oil	102.2	99.3	100.0	105.5	113.7	101.7	110.5
Diesel	26.0	23.9	20.3	29.5	24.0	25.0	28.2
Light sour crude oil	118.2	94.1	84.2	112.7	126.8	102.3	118.2
Bitumen	5.4	6.6	3.8	6.8	9.7	5.7	6.2
Total sales	251.8	223.9	208.3	254.5	274.2	234.7	263.1
Average sales price (2),(b)
Light sweet crude oil	87.34	81.00	75.64	68.63	64.51	78.03	71.98
Other (diesel, light sour crude oil and bitumen)	78.48	73.76	66.74	63.62	57.91	70.86	65.17
Total	82.07	76.97	71.01	65.70	60.65	74.01	68.03
Total*	82.36	76.97	71.01	65.61	60.65	74.07	68.03
Cash operating costs and
Total operating costs - Total operations (c)
Cash costs	24.10	23.00	28.40	21.75	22.65	24.15	18.70
Natural gas	3.60	2.10	4.20	4.50	3.00	3.55	2.90
Imported bitumen	0.20	-	0.10	0.05	-	0.10	0.10
Cash operating costs (3)	27.90	25.10	32.70	26.30	25.65	27.80	21.70
Project start-up costs	0.55	1.10	1.15	0.10	0.25	0.95	0.40
Total cash operating costs (4)	28.45	26.20	33.85	26.40	25.90	28.75	22.10
Depreciation, depletion and amortization	5.60	5.70	5.85	4.45	4.25	5.40	4.05
Total operating costs (5)	34.05	31.90	39.70	30.85	30.15	34.15	26.15
Cash operating costs and
Total operating costs - In-situ bitumen production only (c)
Cash costs	9.95	11.85	10.60	11.05	8.05	10.85	8.95
Natural gas	9.15	9.10	10.60	11.05	9.90	9.90	8.35
Cash operating costs (6)	19.10	20.95	21.20	22.10	17.95	20.75	17.30
Firebag start-up costs	-	-	-	-	-	-	1.70
Total cash operating costs (7)	19.10	20.95	21.20	22.10	17.95	20.75	19.00
Depreciation, depletion and amortization	6.80	6.70	5.75	5.35	6.20	6.20	5.55
Total operating costs (8)	25.90	27.65	26.95	27.45	24.15	26.95	24.55
(for the period ended)
Capital employed (i)	6 541	6 037	5 016	5 134	5 015
(for the twelve months ended)
Return on capital employed (j)	42.6	32.8	34.4	47.6	53.5
Return on capital employed (j)****	27.6	22.0	23.6	34.7	40.1

Suncor Energy Inc.

Quarterly Operating Summary (continued)

(unaudited)

	For the quarter ended						Years ended
	Dec 31	Sept 30		Jun 30	Mar 31	Dec 31	Dec 31	Dec 31
	2007	2007		2007	2007	2006	2007	2006
NATURAL GAS
Gross production**
Natural gas (d)	210	193		191	191	192	196	191
Natural gas liquids (a)	2.5	2.4		2.3	2.4	2.1	2.4	2.3
Crude oil (a)	0.7	0.7		0.7	0.7	0.5	0.7	0.7
Total gross production (e)	38.2	35.2		34.9	34.9	34.7	35.8	34.8
Total gross production (f)	229	211		209	209	208	215	209
Average sales price (2)
Natural gas (g)	6.08	5.39		6.85	7.01	6.55	6.32	7.15
Natural gas (g)*	6.02	5.14		6.83	7.14	6.40	6.27	6.95
Natural gas liquids (b)	56.59	54.81		47.41	54.12	44.20	53.32	44.96
Crude oil - conventional (b)	75.19	69.42		63.71	65.49	51.20	68.33	74.83
Net wells drilled
Conventional - exploratory***	6	1		3	4	4	14	11
- development	6	2		1	8	6	17	18
	12	3		4	12	10	31	29
(for the period ended)
Capital employed (i)	1 153	1 090		1 079	1 063	857
(for the twelve months ended)
Return on capital employed (j)	2.5	(0.6	)	0.6	8.5	14.9
REFINING AND MARKETING
Refined product sales (h)
Transportation fuels
Gasoline - retail	4.9	5.1		5.2	5.4	5.5	5.2	5.3
- other	11.0	12.0		11.7	11.8	11.0	11.6	10.6
Distillate	11.0	10.8		10.5	10.3	8.8	10.6	8.5
Total transportation fuel sales	26.9	27.9		27.4	27.5	25.3	27.4	24.4
Petrochemicals	0.7	0.9		1.3	0.8	0.4	0.9	0.9
Asphalt	1.4	2.1		1.8	1.3	0.8	1.7	1.2
Other	3.8	4.2		4.1	2.0	2.6	3.5	3.0
Total refined product sales	32.8	35.1		34.6	31.6	29.1	33.5	29.5
Crude oil supply and refining
Processed at refineries (h)	22.1	25.9		27.6	24.6	19.4	25.1	21.7
Utilization of refining capacity (j)	87	102		108	97	76	98	85
(for the period ended)
Capital employed (i)	2 270	2 144		1 852	1 928	1 818
(for the twelve months ended)
Return on capital employed (j)	16.8	20.0		26.2	22.7	20.4
Return on capital employed (j)****	14.5	16.9		19.7	15.6	12.5

Suncor Energy Inc.

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.
(4) Total cash operating costs - Total operations	Include cash operating costs - Total operations as defined above and cash start-up costs. Per barrel amounts are based on total production volumes.
(5) Total operating costs - Total operations	Include total cash operating costs - Total operations as defined above and non-cash operating costs. Per barrel amounts are based on total production volumes.
(6) Cash operating costs - In-situ bitumen production	Include cash costs that are defined as operating, selling and general expenses (excluding inventory changes), accretion expense and taxes other than income taxes. Per barrel amounts are based on in-situ production volumes only.
(7) Total cash operating costs - In-situ bitumen production	Include cash operating costs - In-situ bitumen production as defined above and cash start-up 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	(h)  thousands of cubic metres per day
(c)  dollars per barrel rounded	equivalent per day	(i)  $ millions
to the nearest $0.05	(f)  millions of cubit feet equivalent per day	(j)  percentage
Metric conversion
Crude oil, refined products, etc.	1m3 (cubic metre) = approx. 6.29 barrels