6-K

FORM 6-K

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C.   20549

Report of Foreign Private Issuer

Pursuant to Rule 13a - 16 or 15d - 16 of
the Securities Exchange Act of 1934

For the month of: January 2006 Commission File Number: 1-12384

SUNCOR ENERGY INC.

(Name of registrant)

112 Fourth Avenue S.W.

P.O. Box 38

Calgary, Alberta

Canada, T2P 2V5

Indicate by check mark whether the registrant files or will file annual reports under cover of Form 20-F or Form 40-F:

Form 20-F o Form 40-F ý

Indicate by check mark whether the registrant by furnishing the information contained in this Form is also thereby furnishing the information to the SEC pursuant to Rule 12g3-2(b) under the Securities Exchange Act of 1934:

Yes o No ý

If “Yes” is marked, indicate the number assigned to the registrant in connection with Rule 12g3-2(b):

N/A

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned, thereunto duly authorized.

	SUNCOR ENERGY INC.
Date:	By:
January 26, 2006		/s/ “JANICE B. ODEGAARD”
		JANICE B. ODEGAARD   Vice President, Associate   General Counsel and   Corporate Secretary

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EXHIBIT INDEX

Exhibit	Description of Exhibit
99.1	Press Release Including 2006 Outlook and Interim Unaudited Financial Statements of Suncor Energy Inc. for the fourth fiscal quarter ended December 31, 2005.

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EX-99.1

Exhibit 99.1

News Release

FOR IMMEDIATE RELEASE

Suncor Energy finishes 2005 with strong fourth quarter results

Stage set for record oil production in 2006

All financial figures are unaudited and in Canadian dollars unless noted otherwise. Certain prior period amounts have been restated to conform to the current year’s presentation. 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” in this document. 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. Base operations refer to oil sands mining and upgrading operations.

Calgary, Alberta (January 26, 2006) – Suncor Energy Inc. today announced 2005 earnings of $1.245 billion ($2.73 per common share), an increase from $1.088 billion ($2.40 per common share) in 2004. Excluding the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt, 2005 net earnings were $1.214 billion ($2.66 per common share) compared to $1.020 billion ($2.25 per common share) in 2004. Cash flow from operations in 2005 was $2.476 billion compared to $2.013 billion in 2004.

Net earnings in 2005 compared to 2004 reflect higher benchmark crude oil and natural gas prices, the receipt of insurance payments relating to a January 2005 fire at Suncor’s oil sands facilities and lower hedging losses. These positive impacts were largely offset by lower production due to the impact of the fire, higher maintenance expenses, higher energy costs in the oil sands operation and the impact of a stronger Canadian dollar. The increase in cash flow from operations in 2005 compared to 2004 was due to the same factors that impacted net earnings.

“We got past a difficult start to 2005 and had a strong finish to the year by making major progress on our growth plans and achieving record quarterly production in the fourth quarter,” said Rick George, president and chief executive officer. “We are well positioned to carry that momentum into a strong 2006.”

2005 Overview

•In September, Suncor completed rebuilding portions of its oil sands facility damaged in a January fire, returning to full production capacity.

•In October, Suncor successfully commissioned an expansion of its oil sands facilities, increasing production capacity to 260,000 barrels per day (bpd) from the previous capacity of 225,000 bpd. The expansion was completed on schedule and on budget at a total cost of approximately $450 million(1). Work throughout 2005 to further increase production capacity to a planned 350,000 bpd in 2008 continued on schedule and on budget.

•Suncor’s combined oil sands and natural gas production in 2005 was 206,100 barrels of oil equivalent (boe) per day, compared to 263,300 boe per day in 2004. Oil sands production

Suncor Energy Inc.

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

Website: www.suncor.com

averaged 171,300 bpd in 2005, compared to 226,500 bpd in 2004. Natural gas production averaged 190 million cubic feet (mmcf) per day, about 10% below target due to unplanned maintenance, and to weather related drilling delays that impacted the western Canadian industry. In 2004, Suncor produced an average 200 mmcf of natural gas per day.

•By mid-October 2005, all bitumen production from Suncor’s in-situ operations was being upgraded to higher-value synthetic crude products.

•Cash operating costs from oil sands base operations averaged $19.50 per barrel during 2005 compared to $11.95 per barrel in 2004. The increase in 2005 was primarily due to fixed operating costs being spread over lower production volumes, higher maintenance related expenses and the impact of higher natural gas costs.

•Suncor continued to advance plans to modify both its Sarnia and Commerce City refineries to meet low-sulphur fuels regulations and to enable the facilities to process higher volumes of oil sands sour crude blends. The Commerce City facility was expanded in May with the acquisition of a neighbouring refinery from Valero Energy Corporation.

•Refining margins averaged 7.6 cents per litre (cpl) for Canadian operations and 9.0 cpl for U.S. operations. This compares to 8.0 cpl for Canadian operations and 6.7 cpl for U.S. operations during 2004. Retail gasoline margins averaged 5.1 cpl for both Canadian and U.S. operations in 2005, compared to 4.4 cpl for Canadian operations and 5.4 cpl for U.S. operations the year before.

•Maintaining a strong balance sheet remained a priority in 2005. Despite the impact of costs associated with the fire recovery and a $2.8 billion capital spending program, Suncor’s net debt (including cash and cash equivalents) at December 31, 2005 was $2.9 billion (approximately 1.2 times cash flow from operations).  Year-end net debt in 2004 was $2.2 billion (approximately 1.1 times cash flow from operations).

•Suncor achieved a company-wide return on capital employed of 20.9% in 2005 (excluding capitalized costs for major projects in progress), compared to 19% in 2004.

(1)Generally, when projects receive final Board of Directors approval, cost estimates have a range of uncertainty of -10% / +10% or similar range. These ranges establish an expected high and low capital cost estimate for a project. When Suncor says that a project is completed “on budget”, it means the final project capital cost falls within the range of uncertainty for the project.

Fourth Quarter 2005

Suncor’s net earnings for the fourth quarter of 2005 were $694 million ($1.52 per common share) compared to $333 million ($0.73 per common share) in the fourth quarter of 2004. Excluding the effects of unrealized foreign exchange gains on the company’s U.S. dollar denominated long-term debt, fourth quarter net earnings were $698 million ($1.53 per common share) compared to $283 million ($0.62 per common share) during the fourth quarter, 2004. Cash flow from operations for the fourth quarter of 2005 was $1.226 billion, compared to $524 million in the fourth quarter of 2004.

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Net earnings increased in the fourth quarter of 2005 compared to 2004 due to increased production, higher benchmark crude oil and natural gas prices, the receipt of fire insurance proceeds and lower hedging losses, partially offset by higher maintenance related costs, higher energy costs in our oil sands operation and the impact of a stronger Canadian dollar. The increase in cash flow from operations in the fourth quarter of 2005 compared to the fourth quarter of 2004 was due to the same factors that impacted net earnings.

Suncor’s combined oil sands and natural gas production for the fourth quarter was 302,700 boe per day, compared to 258,600 boe per day in the same period of 2004. Oil sands production in the fourth quarter averaged 267,700 bpd at a cash operating cost of $18.00 per barrel for base operations. In 2004, fourth quarter production averaged 222,500 bpd at a cash operating cost of $13.20 per barrel for base operations. Natural gas production averaged 193 mmcf per day in the fourth quarter of 2005, unchanged from the fourth quarter of 2004.

In the downstream, fourth quarter refining margins averaged 9.0 cpl for Canadian operations and 10.4 cpl for U.S. operations. This compares to 7.9 cpl for Canadian operations and 7.7 cpl for U.S. operations during the fourth quarter of 2004. Retail gasoline margins averaged 6.4 cpl for Canadian operations and 5.4 cpl for U.S. operations. This compares to 4.5 cpl for Canadian operations and 6.0 cpl for U.S. operations in the fourth quarter of 2004.

Outlook

“In the year ahead, Suncor intends to continue our proven strategy of staged resource development, expanding upgrading capacity and extending our reach into the North American market,” said George.

Suncor’s outlook provides management’s targets for 2006 in certain key areas of the company’s business. Outlook targets are subject to change.

	2006 Full Year Outlook
Oil Sands
Production (bpd)(1)	260,000
diesel(2)	11%
sweet(2)	45%
sour(2)	44%
Realization on crude sales basket	WTI @ Cushing less Cdn$5.50 to $6.50 per barrel
Cash operating costs(3)	$16.00 to $16.75 per barrel
Natural Gas
natural gas (mmcf/d)	205 to 210

(1)The 260,000 bpd target consists entirely of synthetic crude oil barrels. Suncor’s current plans call for all bitumen produced by the company to be upgraded to synthetic crude oil. However, Suncor-produced bitumen may be sold directly to the market depending on certain market or operational conditions.

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(2)Suncor is still gaining experience in operating facilities that were newly commissioned in late 2005. As a result, there is more uncertainty in providing 2006 targets than in previous years, especially as it relates to sour crude volumes.

(3)Previously, Suncor reported separate cash operating cost calculations for base operations (mining and upgrading) and in-situ bitumen production (see “Non GAAP Financial Measures” for 2005 details). For 2006, cash operating cost projections and results will reflect combined costs for both mining and in-situ operations. Cash operating costs also now include approximately $1.50 per barrel for research and development and self-insurance program costs. In prior years, these costs were not included in cash or total operating costs.

Cash operating costs are sensitive to natural gas prices. The estimate of $16.00 to $16.75 per barrel assumes a natural gas price of US$6.75 per thousand cubic feet (mcf) at Henry Hub. For every U.S. dollar increase in natural gas price per mcf, Suncor expects a $0.50 per barrel increase in operating costs, assuming all other factors remain unchanged. Cash operating costs per barrel are not prescribed by 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. Accordingly, we will also continue to provide cash operating cost calculations for Firebag in-situ operations. 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”.

Factors that could potentially impact Suncor’s financial performance in 2006 include:

•Final timing of the settlement and payment of insurance proceeds related to the January 2005 oil sands fire. There is no specific schedule for the balance of the payments.

•Crude oil hedges. At December 31, 2005, Suncor had entered into previously announced crude oil hedging agreements for 7,000 bpd during 2006 and 2007. In January 2006, the company entered into additional hedging agreements bringing total hedged crude oil production to 25,000 bpd for the remainder of 2006 and 2007. These hedge agreements lock in a minimum price of US$50 per barrel WTI while allowing participation in higher crude prices to an average of approximately US$91 per barrel. Suncor will consider future hedges of up to 30% of crude oil production if strategic opportunities are available.

•Planned maintenance work and tie-in of modified facilities at Suncor’s Sarnia and Commerce City refineries. Should the work take longer than planned or be impacted by labour or material supply issues, capital costs and refined product sales could be impacted.

Net Earnings Components

This table sets forth some of the factors impacting Suncor’s net earnings. For comparability purposes readers should rely on the reported net earnings that are presented in the company’s consolidated financial statements and notes in accordance with Canadian GAAP. The company’s fourth quarter financial statements (unaudited) can be obtained at www.suncor.com or by calling 1-800-558-9071.

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($ millions after tax)	Fourth Quarter					Years ended December 31
(unaudited)	2005			2004		2005			2004
Net earnings before the following items	590			283		858			981
Firebag in-situ start-up costs(1)	(4		)	—		(4		)	(14		)
Oil Sands fire accrued insurance proceeds(1)	112			—		360			—
Impact of income tax rate reductions on opening future income tax liabilities	—			—		—			53
Unrealized foreign exchange gain (loss) on U.S. dollar denominated long-term debt	(4		)	50		31			68
Net earnings as reported	694			333		1 245			1 088
Net earnings per share attributable to common shareholders as reported	$	1.52		$	0.73	$	2.73		$	2.40

(1) Before deduction of Alberta Crown Royalties

Non GAAP Financial Measures

Suncor includes cash and total operating cost per barrel data, return on capital employed (ROCE) and cash flow from operations because investors may use this information to analyze operating performance, leverage and liquidity. The additional information may not be comparable to similar measures presented by other companies and should not be considered in isolation or as a substitute for measures of performance prepared in accordance with generally accepted accounting principles. 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.

The following table outlines the reconciliation of oil sands cash and total operating costs to expenses included in the schedules of segmented data in the company’s fourth quarter 2005 financial statements. Amounts for base and in-situ operations reconcile to the schedules of segmented data when combined.

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Oil Sands Operating Costs - Base Operations

(unaudited)

		Fourth Quarter								Years ended December 31
		2005(1)				2004 (2)				2005 (1)				2004(2)
		$ millions		$/barrel		$ millions		$/barrel		$ millions		$/barrel		$ millions		$/barrel
Operating, selling and general expenses		348				257				978				871
Less: natural gas costs and inventory changes		(48	)			(62	)			(169	)			(142	)
Accretion of asset retirement obligations		6				6				24				21
Taxes other than income taxes		7				7				29				28
Cash costs		313		12.90		208		10.90		862		14.95		778		9.80
Natural gas		83		3.40		41		2.20		216		3.75		158		2.00
Imported bitumen (net of other reported product purchases)		1		0.10		2		0.10		2		0.05		13		0.15
Total cash operating costs - In-situ Operations		47		1.95		—				150		2.60		—
Less: Cost of In-situ production sold directly to market		(8	)	(0.35	)	—				(107	)	(1.85	)	—
Total cash operating costs - Base Operations	A	436		18.00		251		13.20		1 123		19.50		949		11.95
Start-up costs		12		0.50		3		0.15		12		0.20		26		0.35
Add: in-situ inventory changes		—				—				—				2
Less: pre-start-up commissioning costs		(5	)	(0.20	)	(3	)	(0.15	)	(5	)	(0.10	)	(4	)	(0.05	)
In-situ (Firebag) start-up costs	B	7		0.30		—		—		7		0.10		24		0.30
Total cash operating costs	A+B	443		18.30		251		13.20		1 130		19.60		973		12.25
Depreciation, depletion and amortization		142		5.85		120		6.25		448		7.80		484		6.10
Depreciation, depletion and amortization - In-situ Operations		11		0.45		—				34		0.60		—
Less: Cost of In-situ production sold directly to market		(2	)	(0.10	)	—				(24	)	(0.40	)	—
Total operating costs		594		24.50		371		19.45		1 588		27.60		1 457		18.35
Production (thousands of barrels per day)		263.3				206.9				157.6				217.0

Oil Sands Operating Costs - Firebag In-situ Bitumen Production

(unaudited)

	Fourth Quarter						Years ended December 31
	2005 (1)			2004 (2)			2005 (1)			2004 (2)
	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel	$ millions		$/barrel
Operating, selling and general expenses	47			25			150			68
Less: natural gas costs and inventory changes	(32	)		(15	)		(91	)		(39	)
Accretion of asset retirement obligations	—			—			—			—
Taxes other than income taxes	—			—			—			—
Cash costs	15		6.25	10		7.00	59		8.45	29		8.30
Natural gas	32		13.40	15		10.45	91		13.05	39		11.20
Cash operating costs	47		19.65	25		17.45	150		21.50	68		19.50
Depreciation, depletion and amortization	11		4.60	8		5.55	34		4.90	21		6.00
Total operating costs	58		24.25	33		23.00	184		26.40	89		25.50
Production (thousands of barrels per day)	26.0			15.6			19.1			12.7

(1) Production in the base operations for the year ended December 31, 2005 includes Firebag in-situ volumes of 775 bpd produced in the fourth quarter of 2005 during the Firebag stage 2 start-up period.

(2) Production in the base operations for the year ended December 31, 2004 includes Firebag in-situ volumes of 5,900 bpd produced in the first quarter of 2004 during the Firebag stage 1 start-up period.

Return on Capital Employed

Net earnings (2005 – $1.245 billion; 2004 – $1.088 billion) adjusted for after-tax financing expenses (2005 – income of $16 million; 2004 – expense of $1 million) for the twelve month period ended; divided by average capital employed (2005 – $5.876 billion; 2004 – $5.721 billion). 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 51 of Suncor’s 2004 Annual Report.

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Reconciliation of cash flow from operations on a per share basis

(unaudited)

		Fourth Quarter		Years ended December 31
		2005	2004	2005	2004
Cash flow from operations ($ millions)	A	1 226	524	2 476	2 013
Weighted average number of common shares outstanding - basic (millions of shares)	B	457	454	456	453
Cash flow from operations - basic (per share)	A/B	2.68	1.15	5.43	4.44

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 refining operations in Colorado 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.

This document 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 “positioned”, “planned”, outlook”, “target”, “expect”, “intends”, “call for” ,”stage set”, “may” 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; potential labour and material supply issues; 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; 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, Annual Information Form/Form 40-F and other documents filed with regulatory authorities. Suncor disclaims any intentions or obligations to update or reuse any forward-looking statements whether as a result of new information, future events or otherwise.

- 30 -

Investor inquiries	Media inquiries
John Rogers	Brad Bellows
tel: 403-269-8670	tel: 403-269-8717

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Suncor Energy Inc.

Consolidated Statements of Earnings

(unaudited)

	Fourth Quarter				Years ended Dec 31
($ millions)	2005		2004		2005		2004
REVENUES (note 13)	3 503		2 321		11 086		8 665
EXPENSES
Purchases of crude oil and products	1 018		753		4 184		2 867
Operating, selling and general (note 6)	668		528		2 130		1 769
Energy marketing and trading activities (note 3)	173		78		746		373
Transportation and other costs	50		36		152		132
Depreciation, depletion and amortization (note 2)	213		184		720		720
Accretion of asset retirement obligations	7		7		30		26
Exploration	8		7		56		55
Royalties (note 11)	145		150		555		531
Taxes other than income taxes	123		136		529		540
Gain on disposal of assets	(12	)	(19	)	(13	)	(16	)
Project start-up costs	12		3		25		26
Financing expenses (income) (notes 2 and 4)	15		(41	)	(15	)	24
	2 420		1 822		9 099		7 047
EARNINGS BEFORE INCOME TAXES	1 083		499		1 987		1 618
PROVISION FOR INCOME TAXES (note 2)
Current	2		26		39		69
Future	387		140		703		461
	389		166		742		530
NET EARNINGS	694		333		1 245		1 088
PER COMMON SHARE (dollars), (note 5)
- basic	1.52		0.73		2.73		2.40
- diluted	1.48		0.72		2.67		2.36
Cash dividends	0.06		0.06		0.24		0.23

See accompanying notes.

Suncor Energy Inc.

Consolidated Balance Sheets

(unaudited)

	December 31	December 31
($ millions)	2005	2004
ASSETS
Current assets
Cash and cash equivalents	165	88
Accounts receivable (note 9)	1 139	627
Inventories	523	423
Income taxes receivable	6	—
Future income taxes	83	57
Total current assets	1 916	1 195
Property, plant and equipment, net (note 2)	12 966	10 326
Deferred charges and other	469	320
Total assets	15 351	11 841
LIABILITIES AND SHAREHOLDERS’ EQUITY
Current liabilities
Short-term debt	49	30
Accounts payable and accrued liabilities (note 11)	1 830	1 306
Income taxes payable	—	32
Taxes other than income taxes	56	41
Total current liabilities	1 935	1 409
Long-term debt (note 10)	3 007	2 217
Accrued liabilities and other	1 005	749
Future income taxes (note 2)	3 274	2 545
Shareholders’ equity (see below)	6 130	4 921
Total liabilities and shareholders’ equity	15 351	11 841

SHAREHOLDERS’ EQUITY

	Number			Number
	(thousands)			(thousands)
Share capital	457 665	732		454 241	651
Contributed surplus		50			32
Cumulative foreign currency translation		(81	)		(55	)
Retained earnings (note 2)		5 429			4 293
		6 130			4 921

See accompanying notes.

Suncor Energy Inc.

Consolidated Statements of Cash Flows

(unaudited)

	Fourth Quarter				Years ended Dec 31
($ millions)	2005		2004		2005		2004
OPERATING ACTIVITIES
Cash flow from operations	1 226		524		2 476		2 013
Decrease (increase) in operating working capital
Accounts receivable	127		55		(477	)	(121	)
Inventories	(67	)	15		(63	)	(51	)
Accounts payable and accrued liabilities	(99	)	36		508		337
Taxes payable	24		10		(23	)	16
Cash flow from operating activities	1 211		640		2 421		2 194
CASH USED IN INVESTING ACTIVITIES	(832	)	(650	)	(3 186	)	(1 825	)
NET CASH SURPLUS (DEFICIENCY) BEFORE FINANCING ACTIVITIES	379		(10	)	(765	)	369
FINANCING ACTIVITIES
Increase (decrease) in short-term debt	45		18		19		(1	)
Net increase (decrease) in other long-term debt	(333	)	(58	)	808		(635	)
Issuance of common shares under stock option plan	7		14		69		41
Dividends paid on common shares	(25	)	(25	)	(102	)	(97	)
Deferred revenue	9		15		50		26
Cash provided by (used in) financing activities	(297	)	(36	)	844		(666	)
INCREASE (DECREASE) IN CASH AND CASH EQUIVALENTS	82		(46	)	79		(297	)
EFFECT OF FOREIGN EXCHANGE ON CASH AND CASH EQUIVALENTS	(2	)	(1	)	(2	)	(3	)
CASH AND CASH EQUIVALENTS AT BEGINNING OF PERIOD	85		135		88		388
CASH AND CASH EQUIVALENTS AT END OF PERIOD	165		88		165		88

See accompanying notes.

Suncor Energy Inc.

Consolidated Statements of Changes in Shareholders’ Equity

(unaudited)

($ millions)	Share Capital	Contributed Surplus		Cumulative Foreign Currency Translation		Retained Earnings
At December 31, 2003, as previously reported	604	7		(26	)	3 294
Retroactive adjustment for change in accounting policy, net of tax (note 2)	—	—		—		14
At December 31, 2003, as restated	604	7		(26	)	3 308
Net earnings	—	—		—		1 088
Dividends paid on common shares	—	—		—		(97	)
Issued for cash under stock option plan	41	—		—		—
Issued under dividend reinvestment plan	6	—		—		(6	)
Stock-based compensation expense	—	25		—		—
Foreign currency translation adjustment	—	—		(29	)	—
At December 31, 2004, as restated	651	32		(55	)	4 293
Net earnings	—	—		—		1 245
Dividends paid on common shares	—	—		—		(102	)
Issued for cash under stock option plan	74	(5	)	—		—
Issued under dividend reinvestment plan	7	—		—		(7	)
Stock-based compensation expense	—	23		—		—
Foreign currency translation adjustment	—	—		(26	)	—
At December 31, 2005	732	50		(81	)	5 429

See accompanying notes.

Suncor Energy Inc.

Schedules of Segmented Data

(unaudited)

Fourth Quarter

									Energy
									Marketing and				Refining and
									Refining –				Marketing –				Corporate and
	Oil Sands				Natural Gas				Canada				U.S.A				Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
EARNINGS
Revenues
Operating revenues	1 302		865		224		141		902		833		709		396		2		1		3 139		2 236
Energy marketing and trading activities	—		—		—		—		178		84		—		—		—		—		178		84
Net insurance proceeds (note 13)	185		—		—		—		—		—		—		—		—		—		185		—
Intersegment revenues	139		123		7		5		—		—		—		—		(146	)	(128	)	—		—
Interest	—		—		—		—		—		—		1		—		—		1		1		1
	1 626		988		231		146		1 080		917		710		396		(144	)	(126	)	3 503		2 321
Expenses
Purchases of crude oil and products	3		—		—		—		626		571		535		312		(146	)	(130	)	1 018		753
Operating, selling and general	395		282		24		39		145		121		48		30		56		56		668		528
Energy marketing and trading activities	—		—		—		—		173		78		—		—		—		—		173		78
Transportation and other costs	36		25		6		5		2		1		6		5		—		—		50		36
Depreciation, depletion and amortization	153		128		33		29		19		18		5		6		3		3		213		184
Accretion of asset retirement obligations	6		6		1		1		—		—		—		—		—		—		7		7
Exploration	—		2		8		5		—		—		—		—		—		—		8		7
Royalties	89		118		56		32		—		—		—		—		—		—		145		150
Taxes other than income taxes	17		18		1		—		80		92		25		26		—		—		123		136
Loss (gain) on disposal of assets	—		(3	)	(12	)	(16	)	—		(1	)	—		1		—		—		(12	)	(19	)
Project start-up costs	12		3		—		—		—		—		—		—		—		—		12		3
Financing expenses	—		—		—		—		—		—		—		—		15		(41	)	15		(41	)
	711		579		117		95		1 045		880		619		380		(72	)	(112	)	2 420		1 822
Earnings (loss) before income taxes	915		409		114		51		35		37		91		16		(72	)	(14	)	1 083		499
Income taxes	(329	)	(148	)	(36	)	(16	)	(13	)	(13	)	(36	)	(6	)	25		17		(389	)	(166	)
Net earnings (loss)	586		261		78		35		22		24		55		10		(47	)	3		694		333

Suncor Energy Inc.

Schedules of Segmented Data (continued)

(unaudited)

Fourth Quarter

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
CASH FLOW BEFORE  FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from  (used in) operations
Net earnings (loss)	586		261		78		35		22		24		55		10		(47	)	3		694		333
Exploration expenses	—		—		8		5		—		—		—		—		—		—		8		5
Non-cash items included  in earnings
Depreciation, depletion  and amortization	153		128		33		29		19		18		5		6		3		3		213		184
Income taxes	329		148		36		16		13		13		36		6		(27	)	(43	)	387		140
Loss (gain) on disposal of assets	—		(3	)	(12	)	(16	)	—		(1	)	—		1		—		—		(12	)	(19	)
Stock-based compensation  Expense	—		—		—		—		—		—		—		—		7		6		7		6
Other	(14	)	(16	)	1		(2	)	6		2		(1	)	1		(6	)	(52	)	(14	)	(67	)
Overburden removal outlays	(67	)	(59	)	—		—		—		—		—		—		—		—		(67	)	(59	)
Increase (decrease) in  deferred credits and other	(4	)	(2	)	—		(1	)	—		1		—		(1	)	14		4		10		1
Total cash flow from  (used in) operations	983		457		144		66		60		57		95		23		(56	)	(79	)	1 226		524
Decrease (increase) in operating  working capital	(113	)	46		36		10		(33	)	50		(34	)	30		129		(20	)	(15	)	116
Total cash flow from (used in) operating activities	870		503		180		76		27		107		61		53		73		(99	)	1 211		640
Cash from (used in) investing activities:
Capital and exploration  Expenditures	(505	)	(340	)	(122	)	(119	)	(136	)	(96	)	(79	)	(93	)	(22	)	(6	)	(864	)	(654	)
Acquisition of Denver refinery  and related assets	—		—		—		—		—		—		—		—		—		—		—		—
Proceeds from property loss	—		—		—		—		—		—		—		—		—		—		—		—
Deferred maintenance  shutdown expenditures	(1	)	(3	)	1		(1	)	—		1		(6	)	—		—		—		(6	)	(3	)
Deferred outlays and  other investments	—		(6	)	—		—		4		(2	)	1		(1	)	(7	)	(7	)	(2	)	(16	)
Proceeds from disposals	20		3		19		19		1		1		—		—		—		—		40		23
Total cash (used in) investing activities	(486	)	(346	)	(102	)	(101	)	(131	)	(96	)	(84	)	(94	)	(29	)	(13	)	(832	)	(650	)
Net cash surplus (deficiency) before financing activities	384		157		78		(25	)	(104	)	11		(23	)	(41	)	44		(112	)	379		(10	)

Suncor Energy Inc.

Schedules of Segmented Data

(unaudited)

Years ended December 31

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
EARNINGS
Revenues
Operating revenues	2 938		3 215		653		499		3 536		3 060		2 619		1 494		3		2		9 749		8 270
Energy marketing and  trading activities	—		—		—		—		763		400		—		—		—		(8	)	763		392
Net insurance  proceeds (note 13)	572		—		—		—		—		—		—		—		—		—		572		—
Intersegment revenues	455		425		26		68		—		—		—		—		(481	)	(493	)	—		—
Interest	—		—		—		—		—		—		2		1		—		2		2		3
	3 965		3 640		679		567		4 299		3 460		2 621		1 495		(478	)	(497	)	11 086		8 665
Expenses
Purchases of crude  oil and products	32		75		—		—		2 585		2 115		2 048		1 171		(481	)	(494	)	4 184		2 867
Operating, selling  and general	1 128		939		93		100		484		418		167		124		258		188		2 130		1 769
Energy marketing and  trading activities	—		—		—		—		746		381		—		—		—		(8	)	746		373
Transportation and  other costs	104		88		22		21		6		3		20		20		—		—		152		132
Depreciation, depletion  and amortization	482		505		130		115		73		69		23		22		12		9		720		720
Accretion of asset retirement  obligations	24		21		5		4		1		1		—		—		—		—		30		26
Exploration	10		17		46		38		—		—		—		—		—		—		56		55
Royalties	406		407		149		124		—		—		—		—		—		—		555		531
Taxes other than  income taxes	51		72		3		2		338		352		137		114		—		—		529		540
Loss (gain) on disposal  of assets	—		4		(12	)	(19	)	(1	)	(2	)	—		1		—		—		(13	)	(16	)
Project start-up costs	25		26		—		—		—		—		—		—		—		—		25		26
Financing expenses	—		—		—		—		—		—		—		—		(15	)	24		(15	)	24
	2 262		2 154		436		385		4 232		3 337		2 395		1 452		(226	)	(281	)	9 099		7 047
Earnings (loss) before  income taxes	1 703		1 486		243		182		67		123		226		43		(252	)	(216	)	1 987		1 618
Income taxes	(630	)	(492	)	(88	)	(67	)	(26	)	(43	)	(84	)	(9	)	86		81		(742	)	(530	)
Net earnings (loss)	1 073		994		155		115		41		80		142		34		(166	)	(135	)	1 245		1 088
As at December 31
TOTAL ASSETS	11 850		9 067		1 307		967		1 955		1 321		1 235		518		(996	)	(32	)	15 351		11 841

Suncor Energy Inc.

Schedules of Segmented Data (continued)

(unaudited)

Years ended December 31

	Oil Sands				Natural Gas				Energy Marketing and Refining - Canada				Refining and Marketing - U.S.A.				Corporate and Eliminations				Total
($ millions)	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
CASH FLOW BEFORE  FINANCING ACTIVITIES
Cash flow from (used in) operating activities:
Cash flow from  (used in) operations
Net earnings (loss)	1 073		994		155		115		41		80		142		34		(166	)	(135	)	1 245		1 088
Exploration expenses	—		—		46		38		—		—		—		—		—		—		46		38
Non-cash items included  in earnings
Depreciation, depletion  and amortization	482		505		130		115		73		69		23		22		12		9		720		720
Income taxes	630		492		88		67		26		43		84		9		(125	)	(150	)	703		461
Loss (gain) on disposal of assets	—		4		(12	)	(19	)	(1	)	(2	)	—		1		—		—		(13	)	(16	)
Stock-based compensation  expense	—		—		—		—		—		—		—		—		23		25		23		25
Other	11		(29	)	5		4		13		(3	)	(2	)	(8	)	(60	)	(71	)	(33	)	(107	)
Overburden removal outlays	(287	)	(222	)	—		—		—		—		—		—		—		—		(287	)	(222	)
Increase (decrease) in  deferred credits and other	(14	)	8		—		(1	)	—		1		—		1		86		17		72		26
Total cash flow from  (used in) operations	1 895		1 752		412		319		152		188		247		59		(230	)	(305	)	2 476		2 013
Decrease (increase) in operating  working capital	(223	)	72		(5	)	(1	)	(44	)	50		40		68		177		(8	)	(55	)	181
Total cash flow from (used in) operating activities	1 672		1 824		407		318		108		238		287		127		(53	)	(313	)	2 421		2 194
Cash from (used in) investing activities:
Capital and exploration  Expenditures	(1 948	)	(1 119	)	(363	)	(279	)	(442	)	(228	)	(337	)	(190	)	(63	)	(31	)	(3 153	)	(1 847	)
Acquisition of Denver refinery  and related assets	—		—		—		—		—		—		(62	)	—		—		—		(62	)	—
Proceeds from property loss	44		—		—		—		—		—		—		—		—		—		44		—
Deferred maintenance  shutdown expenditures	(65	)	(4	)	(2	)	(1	)	—		(20	)	(10	)	(7	)	—		—		(77	)	(32	)
Deferred outlays and  other investments	(1	)	(9	)	—		—		3		(14	)	1		(1	)	(6	)	1		(3	)	(23	)
Proceeds from disposals	41		45		21		29		3		3		—		—		—		—		65		77
Total cash (used in) investing activities	(1 929	)	(1 087	)	(344	)	(251	)	(436	)	(259	)	(408	)	(198	)	(69	)	(30	)	(3 186	)	(1 825	)
Net cash surplus (deficiency) before financing activities	(257	)	737		63		67		(328	)	(21	)	(121	)	(71	)	(122	)	(343	)	(765	)	369

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 December 31, 2005 and the results of its operations and cash flows for the three and twelve month periods ended December 31, 2005 and 2004.

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

2.Changes in Accounting Policies

(a) Preferred Securities

On January 1, 2005 the company retroactively adopted the Canadian accounting standard related to disclosure and presentation of financial instruments. Accordingly, the company’s preferred securities, which were redeemed in March, 2004, have been reclassified as long-term debt. The company has also restated its property, plant and equipment and depreciation, depletion and amortization to reflect the capitalized interest that would have been incurred and amortized had the preferred securities been classified as debt during the period in which they were outstanding. The impact of adopting this accounting standard is as follows:

Change in Consolidated Balance Sheets
	As at December 31
($ millions, increase)	2005	2004
Property, plant and equipment	35	37
Total assets	35	37
Future income tax liabilities	12	13
Retained earnings	23	24
Total liabilities and shareholders’ equity	35	37

Change in Consolidated Statements of Earnings
	Fourth Quarter				Years ended December 31
($ millions, increase/(decrease))	2005		2004		2005		2004
Depreciation, depletion and amortization	1		1		2		3
Financing expenses	—		—		—		15
Future income taxes	(1	)	(1	)	(1	)	(6	)
Net earnings	—		—		(1	)	(12	)
Per common share – basic (dollars)	—		—		—		—
Per common share – diluted (dollars)	—		—		—		—

(b) Consolidation of Variable Interest Entities

On January 1, 2005 the company prospectively adopted Canadian Accounting Guideline 15 — “Consolidation of Variable Interest Entities (VIEs)”.  Accordingly, the company has consolidated the VIE related to the sale of equipment as described in note 11(c) of the company’s 2004 Annual Report. The impact of adopting this standard was an increase to property, plant and equipment of $14 million, an increase to materials and supplies inventory of $8 million and an increase to long-term debt of $22 million.

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.  The results of these activities are reported as revenue and as energy marketing and trading expenses in the Consolidated Statement of Earnings.

Physical energy marketing contracts involve activities intended to enhance prices and satisfy physical deliveries to customers.  For the quarter ended December 31, 2005 these activities resulted in a net pretax gain of $5 million (2004 – pretax gain $5 million).  For the year ended December 31, 2005 physical energy marketing contracts resulted in a net pretax gain of $15 million (2004 – pretax gain of $12 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.  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.  For the quarter ended December 31, 2005, a net pretax gain of $1 million (2004 - pretax gain $2 million) resulted from the settlement and revaluation of the financial energy contracts.  For the year ended December 31, 2005 a net pretax gain of $5 million (2004 – pretax gain $11 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 as at December 31 are as follows:

($ millions)	2005	2004
Energy trading assets	82	26
Energy trading liabilities	70	9

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

4.Financing Expenses (Income)

	Fourth Quarter				Years ended December 31
($ millions)	2005		2004		2005		2004
Interest on debt	41		36		151		157
Capitalized interest	(28	)	(22	)	(119	)	(62	)
Net interest expense	13		14		32		95
Foreign exchange (gain) loss on long-term debt	5		(60	)	(37	)	(82	)
Other foreign exchange (gain) loss	(3	)	5		(10	)	11
Total financing expenses (income)	15		(41	)	(15	)	24

5.Reconciliation of Basic and Diluted Earnings Per Common Share

	Fourth Quarter		Years ended December 31
($ millions)	2005	2004	2005	2004
Net earnings	694	333	1 245	1 088
(millions of common shares)
Weighted-average number of common shares	457	454	456	453
Options issued under stock-based compensation plans	11	8	10	9
Weighted-average number of diluted common shares	468	462	466	462
(dollars per common share)
Basic earnings per share (b)	1.52	0.73	2.73	2.40
Diluted earnings per share (c)	1.48	0.72	2.67	2.36	(a)

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) For the year ended December 31, 2004, diluted earnings per share is net earnings divided by the weighted-average number of diluted common shares.  Interest on subordinated debentures, the revaluation of US$ subordinated debentures and the redemption of subordinated debentures by the issuance of common shares have an anti-dilutive impact, therefore they are not included in the calculation of diluted earnings per share.

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

(c) Diluted earnings per share is the 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 262,000 options to new employees in the fourth quarter of 2005, for a total of 1,253,000 options granted in the year ended December 31, 2005 (290,000 options granted during the fourth quarter of 2004; 1,742,000 options granted in the year ended December 31, 2004).

On January 31, 2005, in connection with the achievement of a predetermined performance criterion, 2,062,000 SunShare options vested, representing approximately 25% of the then outstanding unvested options under the SunShare plan.  On June 30, 2005, we met an additional predetermined performance criterion under the Sunshare plan, resulting in the vesting of 50% of the outstanding, unvested Sunshare options on April 30, 2008. As we had been accruing the costs of these options, the impact on net earnings for the fourth quarter and the year ended December 31, 2005 was not significant.

Under the company’s other plans, 1,000 options were granted in the fourth quarter of 2005, for a total of 1,419,000 options granted in the year ended December 31, 2005 (61,000 options granted during the fourth quarter of 2004; 1,346,000 granted in the year ended December 31, 2004).

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:

	Fourth Quarter						Years ended December 31
	2005			2004			2005			2004
Quarterly dividend per share	$	0.06		$	0.06		$	0.06		$	0.06	*
Risk-free interest rate	3.77		%	4.02		%	3.69		%	3.79		%
Expected life	5 years			6 years			6 years			6 years
Expected volatility	29		%	28		%	28		%	29		%
Weighted-average fair value per option	$	20.47		$	13.70		$	15.42		$	12.02

* In 2004, a quarterly dividend of $0.05 per share was paid in the first quarter, and quarterly dividends of $0.06 per share were paid in the second, third and fourth quarters.

Stock-based compensation expense recognized in the fourth quarter of 2005 related to stock options plans was $7 million (2004 - $6 million).  For the year ended December 31, 2005 stock-based compensation expense recognized was $23 million (2004 - $25 million).

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

($ millions, except per share	Fourth Quarter		Years ended December 31
amounts)	2005	2004	2005	2004
Net earnings - as reported	694	333	1 245	1088
Less: compensation cost under the fair value method for pre- 2003 options	2	6	13	47
Pro forma net earnings	692	327	1 232	1 041
Basic earnings per share
As reported	1.52	0.73	2.73	2.40
Pro forma	1.51	0.72	2.70	2.30
Diluted earnings per share
As reported	1.48	0.72	2.67	2.36
Pro forma	1.48	0.71	2.64	2.26

(b) Performance share units (PSUs)

In the fourth quarter of 2005 the company issued 2,000 PSUs (2004 – 1,000).  For the year ended December 31, 2005, the company issued 453,000 PSUs (2004 – 354,000). Expense recognized in the fourth quarter of 2005 was $5 million (2004 –  $2 million).  Expense recognized for the year ended December 31, 2005 was $21 million (2004 –  $5 million).

7.Employee Future Benefits Liability

The company’s pension plans and other post-retirement benefits programs are described in note 9 of the company’s 2004 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
	2005		2004		2005		2004
Current service costs	8		7		32		25
Interest costs	9		9		38		34
Expected return on plan assets	(7	)	(7	)	(28	)	(25	)
Amortization of net actuarial loss	6		5		21		19
Net periodic benefit cost	16		14		63		53

	Other Post-retirement Benefits
	Fourth quarter		Years ended December 31
	2005	2004	2005	2004
Current service costs	—	1	5	5
Interest costs	1	2	6	7
Amortization of net actuarial loss	—	—	1	1
Net periodic benefit cost	1	3	12	13

8.Supplemental Information

	Fourth Quarter		Years ended December 31
($ millions)	2005	2004	2005	2004
Interest paid	27	18	149	143
Income taxes paid	16	12	77	50

Strategic crude oil hedges at December 31, 2005

	Quantity	Average Price	Revenue Hedged	Hedge
	(bbl/day)	(US$/bbl) (a)	(Cdn$ millions) (b)	Period (c)
Costless Collars	7 000	50.00 – 92.57	149 – 276	2006
Costless Collars	7 000	50.00 – 92.57	149 – 276	2007
Margin hedges at December 31, 2005
	Quantity	Average Margin	Margin Hedged	Hedge
	(bbl/day)	(US$/bbl)	(Cdn$ millions (b)	Period (c)
Refined product and crude swaps	5 100	11.69	10	2006		(d)
Natural gas hedges at December 31, 2005
	Quantity	Average Price	Revenue Hedged	Hedge
	(GJ/day)	(Cdn$/GJ)	(Cdn$ millions)	Period(c)
Swaps	4 000	6.58	10	2006
Costless Collars	25 000	10.76 – 16.13	24 – 36	2006	(e)
Costless Collars	10 000	8.75 – 13.38	19 – 29	2006	(f)
Swaps	4 000	6.11	9	2007
Euro hedges at December 31, 2005
During the fourth quarter of 2005, the company entered into foreign exchange forwards to hedge anticipated equipment purchases payable in Euros in 2006 and 2007.
	Notional	Average	Dollars Hedged	Hedge
	(Euro millions)	Forward Rate	(Cdn$ millions)	Period (c)
Euro/Cdn forward	9.9	1.39	13.8	2006	(g)
Euro/Cdn forwards	20.6	1.41	29.0	2007	(h)

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

(b)The revenue and margin hedged is translated to Cdn$ at the December 30, 2005 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 January to May 2006, inclusive.

(e)   For the period January to March 2006, inclusive.

(f)    For the period April to October 2006, inclusive.

(g)   Settlement for applicable forward in March 2006.

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

9.Variable Interest Entities

The company has a securitization program in place to sell, on a revolving, fully serviced and limited recourse basis, accounts receivable having a maturity of 45 days or less, to a third-party.  The third-party is a multiple party securitization vehicle that provides funding for numerous asset pools.  The securitization program was increased to $340 million in the fourth quarter of 2005 from $170 million in the third quarter of 2005.  As at December 31, 2005, the program was fully utilized.

10.  Credit Facilities

During the second quarter of 2005, the company entered into a new $600 million credit facility agreement.  The new facility is fully revolving for 364 days and expires in 2006.  During the third quarter of 2005, the company renewed $200 million of its available credit and term loan facilities.  At December 31, 2005, the company had available facilities as follows:

($millions)

Facility that is fully revolving for 364 days and expires in 2006	600
Facility that is fully revolving for 364 days, has a term period of one year and expires in 2007	200
Facility that is fully revolving for a period of three years and expires in 2007	1 500
Facilities that can be terminated at any time at the option of the Lenders	30
Total available credit facilities	2 330

As at December 31, 2005, undrawn lines of credit were approximately $1,255 million.

11.  Alberta Crown Royalties

Alberta Crown royalties in effect for each Oil Sands project require payments to the Government of Alberta based on annual gross revenues less related transportation costs (R) less allowable costs (C), including the deduction of certain capital expenditures (the 25% R-C royalty), subject to a minimum payment of 1% of R.  Firebag is being treated by the government of Alberta as a separate project from the rest of the Oil Sands operations for royalty purposes.  The 2004 calendar year was a transitional year for Oil Sands as the remaining amount of prior years’ allowable costs carried forward of approximately $600 million were claimed before the 25% R-C royalty applied to 2004 results.

Royalty expense for the company’s Oil Sands operations for the fourth quarter was $89 million (2004 - $118 million).  For the year ended December 31, 2005 Crown royalty expense was $406 million (2004 - $407 million).

12.  Acquisition of Refinery and Related Assets

On May 31, 2005, the company acquired all of the issued shares of the Colorado Refining Company, an indirect wholly-owned subsidiary of Valero for cash consideration of $37 million.  Additional payments for working capital and associated inventory brought the total purchase price to $62 million.  The acquired company’s principal assets are a Denver refinery and a products terminal located in Grand Junction, Colorado.  The allocation of fair value to the assets acquired and liabilities assumed was $79 million for property, plant and equipment, $30 million for inventory, and $41 million for environmental liabilities assumed.  The fair value assigned to other liabilities was $6 million.  The acquisition was accounted for by the purchase method of accounting.

The results of operations for these assets have been included in the consolidated financial statements from the date of acquisition.  The new operations have been reported as part of the Refining and Marketing – U.S.A. segment in the Schedules of Segmented Data.

13.  Subsequent Event

In January, 2006, the Company determined that an additional $175 million in proceeds related to its business interruption insurance coverage were unconditionally received or receivable. The proceeds related to business activity during 2005 and have accordingly been recognized as revenue in the fourth quarter.

Suncor Energy Inc.

Highlights

(unaudited)

	2005	2004
CASH FLOW FROM OPERATIONS
For the quarters ended December 31
Cash flow from operations (1), (dollars per common share - basic)	2.68	1.15
For the years ended December 31
Cash flow from operations (1), (dollars per common share - basic)	5.43	4.44
RATIOS
For the years ended December 31
Return on capital employed (%) (2)	20.9	19.0
Return on capital employed (%) (3)	15.3	16.1
Net debt to cash flow from operations (times) (4)	1.2	1.1
Interest coverage on long-term debt (times)
Net earnings (5)	13.4	10.9
Cash flow from operations (6)	16.9	13.8
As at December 31
Debt to debt plus shareholders’ equity (%) (7)	33.3	31.4
COMMON SHARE INFORMATION
As at December 31
Share price at end of trading
Toronto Stock Exchange          - Cdn$	73.32	42.40
New York Stock Exchange      - US$	63.13	35.40
Common share options outstanding (thousands)	19 202	20 687
For the years ended December 31
Average number outstanding, weighted monthly (thousands)	456 312	452 910

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 (2005 - $1,245 million; 2004 - $1,088 million) adjusted for after-tax financing expenses (2005 - income of $16 million; 2004 - expense of $1 million) for the twelve month period ended; divided by average capital employed (2005 - $5,876 million; 2004 - $5,721million).  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 51 of Suncor’s 2004 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: 2005 -$8,051 million; 2004 - $6,775 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		Sept 30	June 30	Mar 31	Dec 31	Dec 31		Dec 31
	2005		2005	2005	2005	2004	2005		2004
OIL SANDS
Production (a)
Base operations	263.3		125.2	119.5	121.2	206.9	157.6		215.6
Firebag	26.0		23.0	8.7	18.7	15.6	19.1		10.9
Total production (1)	267.7	(1)	148.2	128.2	139.9	222.5	171.3	(1)	226.5
Sales (a)
Light sweet crude oil	108.6		69.9	48.3	75.3	115.3	73.3		114.9
Diesel	30.7		10.6	9.0	11.8	25.5	15.6		27.9
Light sour crude oil	104.2		41.7	54.2	38.5	80.9	59.8		75.1
Bitumen	7.2		22.3	9.6	18.4	11.0	16.6		8.4
Total sales	250.7		144.5	121.1	144.0	232.7	165.3		226.3
Average sales price (2), (b)
Light sweet crude oil	55.96		52.08	39.20	45.41	50.55	49.93		45.60
Other (diesel, light sour crude oil and bitumen)	63.84		59.70	50.47	47.31	39.62	56.90		39.13
Total	60.42		56.01	45.98	46.44	44.68	53.81		42.28
Total *	66.68		67.95	57.24	54.80	54.40	62.68		49.78
Cash operating costs and Total operating costs - Base operations
Cash costs	12.90		18.00	16.30	15.10	10.90	14.95		9.80
Natural gas	3.40		4.60	2.65	4.70	2.20	3.75		2.00
Firebag bitumen	1.60		—	—	—	—	0.75		—
Imported bitumen	0.10		—	—	0.10	0.10	0.05		0.15
Cash operating costs (3),(c)	18.00		22.60	18.95	19.90	13.20	19.50		11.95
Firebag start-up costs	0.30		—	—	—	—	0.10		0.30
Total cash operating costs (4),(c)	18.30		22.60	18.95	19.90	13.20	19.60		12.25
Depreciation, depletion and amortization	6.20		9.00	9.45	9.05	6.25	8.00		6.10
Total operating costs (5),(c)	24.50		31.60	28.40	28.95	19.45	27.60		18.35
Cash operating costs and Total operating costs - Firebag
Cash costs	6.25		6.85	18.95	8.90	7.00	8.45		8.30
Natural gas	13.40		13.70	16.40	10.10	10.45	13.05		11.20
Cash operating costs (6),(c)	19.65		20.55	35.35	19.00	17.45	21.50		19.50
Depreciation, depletion and amortization	4.60		4.10	7.60	4.75	5.55	4.90		6.00
Total operating costs (7),(c)	24.25		24.65	42.95	23.75	23.00	26.40		25.50
(for the period ended) Capital employed (i)	4 633		4 492	4 303	4 231	4 169
(for the twelve months ended) Return on capital employed (j)	24.3		17.1	17.2	19.6	22.9
Return on capital employed (j) ****	17.6		12.8	13.4	15.9	18.8

Suncor Energy Inc.

Quarterly Operating Summary (continued)
(unaudited)

	For the quarter ended					Years ended
	Dec 31	Sept 30	June 30	Mar 31	Dec 31	Dec 31	Dec 31
	2005	2005	2005	2005	2004	2005	2004
NATURAL GAS
Gross production **
Natural gas (d)	193	200	175	191	193	190	200
Natural gas liquids (a)	2.3	2.2	2.2	3.0	2.9	2.4	2.5
Crude oil (a)	0.6	0.7	1.0	0.9	1.0	0.8	1.0
Total gross production (e)	35.0	36.3	32.4	35.7	36.1	34.8	36.8
Average sales price (2)
Natural gas (f)	11.66	8.32	7.29	6.81	7.02	8.57	6.70
Natural gas (f) *	11.83	8.34	7.26	6.74	6.98	8.59	6.73
Natural gas liquids (b)	57.85	58.00	52.52	38.32	46.46	50.70	42.82
Crude oil - conventional(b)	72.60	63.77	63.86	61.40	55.26	64.85	50.41
Net wells drilled
Conventional - exploratory ***	4	4	—	5	—	13	10
- development	13	2	2	5	5	22	16
	17	6	2	10	5	35	26

(for the period ended) Capital employed (i)	563	598	564	490	448
(for the twelve months ended) Return on capital employed (j)	30.7	22.7	22.5	26.2	27.1

ENERGY MARKETING AND REFINING–CANADA
Refined product sales (g)

Transportation fuels
Gasoline - retail	4.5	4.2	4.8	4.6	4.8	4.5	4.6
- other	3.3	4.2	4.1	4.0	4.1	3.9	4.1
Jet fuel	0.8	0.9	0.8	0.9	1.0	0.9	0.9
Diesel	3.4	3.7	3.3	2.7	3.3	3.3	3.1
Total transportation fuel sales	12.0	13.0	13.0	12.2	13.2	12.6	12.7
Petrochemicals	0.4	0.7	0.8	0.8	0.8	0.7	0.8
Heating oils	0.5	0.2	0.3	0.8	0.5	0.4	0.4
Heavy fuel oils	0.9	0.8	1.4	1.0	0.8	1.0	0.7
Other	0.5	0.9	0.6	0.3	0.3	0.5	0.8
Total refined product sales	14.3	15.6	16.1	15.1	15.6	15.2	15.4
Margins (h)
Refining (8)	9.0	9.2	7.3	4.8	7.9	7.6	8.0
Refining (8) *	9.3	10.1	7.6	4.8	7.8	8.0	8.1
Retail (9)	6.4	5.4	3.8	4.7	4.5	5.1	4.4
Crude oil supply and refining
Processed at Sarnia refinery (g)	10.6	10.7	11.1	10.1	11.3	10.6	11.1
Utilization of refining capacity (j)	95	96	100	91	101	95	100

(for the period ended) Capital employed (i)	486	547	507	525	512
(for the twelve months ended) Return on capital employed (j)	8.1	7.7	10.1	8.4	14.6
Return on capital employed (j) ****	5.2	5.6	8.1	7.3	13.6

Suncor Energy Inc.

Quarterly Operating Summary (continued)
(unaudited)

	For the quarter ended					Years ended
	Dec 31 2005	Sept 30 2005	June 30 2005	Mar 31 2005	Dec 31 2004	Dec 31 2005	Dec 31 2004
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
- other	7.1	8.9	5.0	3.8	3.9	6.2	3.8
Jet fuel	0.9	0.8	0.7	0.7	0.6	0.8	0.5
Diesel	3.6	3.9	3.1	2.6	2.5	3.3	2.2
Total transportation fuel sales	12.3	14.3	9.5	7.8	7.7	11.0	7.2
Asphalt	1.2	1.8	1.9	1.6	1.1	1.6	1.5
Other	1.0	1.2	1.2	0.7	0.7	1.1	0.6
Total refined product sales	14.5	17.3	12.6	10.1	9.5	13.7	9.3
Margins (h)
Refining (8)	10.4	8.9	9.5	6.3	7.7	9.0	6.7
Refining (8) *	10.4	8.9	9.5	6.3	7.7	9.0	6.8
Retail (9)	5.4	7.5	4.3	3.3	6.0	5.1	5.4
Crude oil supply and refining
Processed at Denver refinery (g)	13.0	14.9	11.4	9.2	9.5	12.1	8.8
Utilization of refining capacity (j)	91	104	102	96	100	98	92
(for the period ended)
Capital employed (i) (for the twelve months ended)	327	354	349	262	232
Return on capital employed (j)	49.4	32.2	17.6	14.5	12.2
Return on capital employed (j) ****	28.9	21.6	13.8	12.2	11.0

Suncor Energy Inc.

Quarterly Operating Summary (continued)
(unaudited)

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 Production	In the fourth quarter of 2005, base operations production included barrels from both mining and in-situ operations that were upgraded. Firebag production reported in the operating summary includes all in-situ production irrespective of whether it was upgraded or sold to third parties. As such these production figures as reported in the operating summary are not additive in the fourth quarter of 2005 and the year ended December 31, 2005.
(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 - Base 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.
(4) Total cash operating costs - Base operations	Include cash operating costs - Base 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 - Base operations	Include total cash operating costs - Base 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 - Firebag	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 - Firebag	Include cash operating costs - Firebag as defined above and non-cash operating costs. Per barrel amounts are based on in-situ production volumes.
(8) Refining margin	This operating statistic is calculated as the average wholesale unit price from all products less average unit cost of crude oil.
(9) Retail margin	This operating statistic is calculated as the average street price of Sunoco (Energy, Marketing and Refining—Canada) and Phillips 66-branded (Refining and Marketing-U.S.A.) retail gasoline net of federal excise tax, as applicable, and other adjustments, less refining gasoline transfer price.

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

(b)  dollars per barrel

(c)  dollars per barrel rounded to the nearest $0.05

(d)  millions of cubic feet per day

(e)  thousands of barrels of oil equivalent per day

(f)  dollars per thousand cubic feet

(g)  thousands of cubic metres per day

(h)  cents per litre

(i)  $ millions

(j)  percentage

Metric conversion

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