IMPERIAL OIL LTD - Annual Report: 2005 (Form 10-K)

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UNITED STATES SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, D.C. 20549

FORM 10-K

ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THE
SECURITIES EXCHANGE ACT OF 1934


For the fiscal year ended December 31, 2005		Commission file number: 0-12014

IMPERIAL OIL LIMITED

(Exact name of registrant as specified in its charter)


CANADA		98-0017682
(State or other jurisdiction of		(I.R.S. Employer
incorporation or organization)		Identification No.)

237 FOURTH AVENUE S.W., CALGARY, AB, CANADA		T2P 3M9
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code:
1-800-567-3776

Securities registered pursuant to Section 12(b) of the Act:


		Name of each exchange on
Title of each class		which registered
None		None

Securities registered pursuant to Section 12(g) of the Act:
Common Shares (without par value)

(Title of Class)

The registrant is a well-known seasoned issuer (as defined in Rule 405 of the Securities Exchange Act of 1934).
Yes þ No o

The registrant is not required to file reports pursuant to Section 13 or Section 15(d) of the Securities Exchange Act of 1934.
Yes o No þ

The registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.
Yes þ No o

Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
Yes þ No o

The registrant is a large accelerated filer, an accelerated filer, or a non-accelerated filer (see definition of “accelerated filer” and “large accelerated filer” in Rule 12b-2 of the Securities Exchange Act of 1934).

Large accelerated filer þ Accelerated filer o Non-accelerated filer o

The registrant is a shell company (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).
Yes o No þ

As of the last business day of the 2005 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $10,570,561,124 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

The number of common shares outstanding, as of February 15, 2006, was 331,344,044.


	Page
PART I
Item 1. Business
Financial Information by Operating Segments		3
Natural Resources		4
Petroleum and Natural Gas Production		4
Land Holdings		9
Exploration and Development		9
Petroleum Products		11
Supply		11
Refining		11
Distribution		12
Marketing		12
Chemicals		13
Research		13
Environmental Protection		14
Human Resources		14
Competition		14
Government Regulation		14
The Company Online		15
Item 1A. Risk Factors		15
Item 2. Properties		17
Item 3. Legal Proceedings		17
Item 4. Submission of Matters to a Vote of Security Holders		17
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities		18
Item 6. Selected Financial Data		19
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation		19
Item 7A. Quantitative and Qualitative Disclosures about Market Risk		31
Item 8. Financial Statements and Supplementary Data		31
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure		37
Item 9A. Controls and Procedures		37
PART III
Item 10. Directors and Executive Officers of the Registrant		38
Item 11. Executive Compensation		41
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters		49
Item 13. Certain Relationships and Related Transactions		49
Item 14. Principal Accountant Fees and Services		50
PART IV
Item 15. Exhibits and Financial Statement Schedules		51
Index to Financial Statements		F-1
Management’s Report on Internal Control over Financial Reporting		F-2
Report of Independent Registered Public Accounting Firm		F-2

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated.
Note that numbers may not add due to rounding.

The following table sets forth (i) the rates of exchange for the Canadian dollar, expressed in U.S. dollars, in effect at the end of each of the periods indicated, (ii) the average of exchange rates in effect on the last day of each month during such periods, and (iii) the high and low exchange rates during such periods, in each case based on the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.


	2005		2004		2003		2002		2001
	(dollars)
Rate at end of period		0.8579		0.8310		0.7738		0.6329		0.6279
Average rate during period		0.8276		0.7702		0.7186		0.6368		0.6444
High		0.8690		0.8493		0.7738		0.6619		0.6697
Low		0.7872		0.7158		0.6349		0.6200		0.6241

On February 15, 2006, the noon buying rate in New York City for wire transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.8665 U.S. = $1.00 Canadian.

This report contains forward looking information on future production, project start ups and future capital spending. Actual results could differ materially as a result of market conditions or changes in law, government policy, operating conditions, costs, project schedules, operating performance, demand for oil and natural gas, commercial negotiations or other technical and economic factors.

PART I

Item 1. Business.

Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the “CBCA”) by certificate of continuance dated April 24, 1978. The head and principal office of the Company is located at 237 Fourth Avenue S.W. Calgary, Alberta, Canada T2P 3M9; telephone 1-800-567-3776. Exxon Mobil Corporation owns approximately 69.6 percent of the outstanding shares of the Company with the remaining shares being publicly held, with the majority of shareholders having Canadian addresses of record. In this report, unless the context otherwise indicates, reference to the “Company” includes Imperial Oil Limited and its subsidiaries.

The Company is one of Canada’s largest integrated oil companies. It is active in all phases of the petroleum industry in Canada, including the exploration for, and production and sale of, crude oil and natural gas. In Canada, it is one of the largest producers of crude oil and natural gas liquids and a major producer of natural gas, and the largest refiner and marketer of petroleum products. It is also a major supplier of petrochemicals.

The Company’s operations are conducted in three main segments: natural resources (“upstream”), petroleum products (“downstream”) and chemicals. Natural resources operations include the exploration for, and production of, crude oil and natural gas, including upgraded crude oil and crude bitumen. Petroleum products operations consist of the transportation, refining and blending of crude oil and refined products and the distribution and marketing thereof. The chemicals operations consist of the manufacturing and marketing of various petrochemicals.

Financial Information by Operating Segments (under U.S. GAAP)


	2005			2004			2003		2002			2001
	(millions)
External sales (1):
Natural resources	$	4,702		$	3,689		$	3,390	$	2,573		$	3,144
Petroleum products		21,793			17,503			14,710		13,362			13,079
Chemicals		1,302			1,216			994		955			930
Corporate and other		—			—			—		—			—

	$	27,797		$	22,408		$	19,094	$	16,890		$	17,153

Intersegment sales:
Natural resources	$	3,487		$	2,891		$	2,224	$	2,217		$	2,166
Petroleum products		2,224			1,666			1,294		1,038			1,300
Chemicals		363			293			238		209			245

Net income (2)(3):
Natural resources	$	2,008		$	1,517		$	1,174	$	1,052		$	953
Petroleum products		694			556			462		147			376
Chemicals		121			109			44		54			26
Corporate and other (4)/eliminations		(223	)		(130	)		25		(39	)		(132	)

	$	2,600		$	2,052		$	1,705	$	1,214		$	1,223

Identifiable assets at December 31 (3)(5):
Natural resources	$	7,347		$	6,866		$	6,417	$	6,007		$	5,384
Petroleum products		6,287			5,555			5,287		5,113			4,414
Chemicals		504			497			440		427			383
Corporate and other/eliminations		1,444			1,109			193		456			707

	$	15,582		$	14,027		$	12,337	$	12,003		$	10,888

Capital and exploration expenditures:
Natural resources	$	937		$	1,113		$	1,007	$	986		$	746
Petroleum products		478			283			478		589			339
Chemicals		19			15			41		25			30
Corporate and other		41			34			33		12			—

	$	1,475		$	1,445		$	1,559	$	1,612		$	1,115


(1)		Export sales are reported in note 2 to the consolidated financial statements on page F-11.
(2)		These amounts are presented as if each segment were a separate business entity and, accordingly, include the financial effect of transactions between the segments. Intersegment sales are made essentially at prevailing market prices.
(3)		Previous years’ data has been reclassified to reflect that incentive compensation expenses, previously included in the operating segments, are now reported in the “corporate and other” segment.
(4)		Includes primarily interest charges on the debt obligations of the Company, interest income on investments, incentive compensation expenses, and intersegment consolidating adjustments.
(5)		The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment.

Natural Resources

Petroleum and Natural Gas Production

The Company’s average daily production of crude oil and natural gas liquids during the five years ended December 31, 2005, was as follows:


		2005		2004		2003		2002		2001
		(thousands a day)
Conventional (including natural gas liquids):
Cubic metres	— Gross (1)		11.0		12.1		11.8		12.4		13.2
	— Net (2)		8.6		9.4		9.1		9.5		10.2
Barrels	— Gross (1)		69		76		74		78		83
	— Net (2)		54		59		57		60		64
Oil Sands (Cold Lake):
Cubic metres	— Gross (1)		22.1		20.0		20.5		17.8		20.4
	— Net (2)		19.7		17.7		18.4		16.9		19.2
Barrels	— Gross (1)		139		126		129		112		128
	— Net (2)		124		112		116		106		121
Tar Sands (Syncrude):
Cubic metres	— Gross (1)		8.4		9.5		8.4		9.1		8.9
	— Net (2)		8.4		9.4		8.3		9.1		8.3
Barrels	— Gross (1)		53		60		53		57		56
	— Net (2)		53		59		52		57		52
Total:
Cubic metres	— Gross (1)		41.5		41.6		40.7		39.3		42.5
	— Net (2)		36.7		36.5		35.8		35.5		37.7
Barrels	— Gross (1)		261		262		256		247		267
	— Net (2)		231		230		225		223		237


(1)		Gross production of crude oil is the Company’s share of production from conventional wells, Syncrude tar sands and Cold Lake oil sands, and gross production of natural gas liquids is the amount derived from processing the Company’s share of production of natural gas (excluding purchased gas), in each case before deduction of the mineral owners’ or governments’ share or both.
(2)		Net production is gross production less the mineral owners’ or governments’ share or both.

In 2002 and 2003, conventional production declined mainly due to natural decline of the Company’s conventional oil fields. In 2004, conventional production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap. In 2005, conventional production declined mainly due to the natural decline of the Company’s conventional fields. In 2002, Cold Lake production decreased mainly due to the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties. In 2003, Cold Lake net production increased as a result of a full year of production of stages 11 to 13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude production decreased in 2003 due to extended maintenance of upgrading facilities. In 2004, Cold Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude production increased due to fewer disruptions in upgrading operations than in 2003. In 2005, Cold Lake production increased due to the timing of steaming cycles and increased volumes from the ongoing development drilling program, and Syncrude production declined primarily due to greater maintenance downtime for upgrading facilities.

The Company’s average daily production and sales of natural gas during the five years ended December 31, 2005 are set forth below. All gas volumes in this report are calculated at a pressure base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in the case of cubic feet, 14.73 pounds per square inch at 60 degrees Fahrenheit.


	2005		2004		2003		2002		2001
	(millions a day)
Sales (1):
Cubic metres		15.2		14.7		13.0		14.1		14.2
Cubic feet		536		520		460		499		502
Gross Production (2):
Cubic metres		16.4		16.1		14.5		15.0		16.2
Cubic feet		580		569		513		530		572
Net Production (2):
Cubic metres		14.6		14.7		12.9		13.1		13.2
Cubic feet		514		518		457		463		466


(1)		Sales are sales of the Company’s share of production (before deduction of the mineral owners’ and/or governments’ share) and sales of gas purchased, processed and/or resold.
(2)		Gross production of natural gas is the Company’s share of production (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production excludes those shares. Production data include amounts used for internal consumption with the exception of amounts reinjected.

In 2002 and 2003, natural gas production decreased primarily due to the depletion of gas caps in Alberta. In 2003 natural gas production decreased due to increased maintenance activity at gas processing facilities. In 2004 natural gas production increased primarily due to increased production from the Wizard Lake gas cap. In 2005, gross natural gas production increased due to increased production from the Nisku and Wizard Lake gas caps and the Medicine Hat gas field.

Most of the Company’s natural gas sales are made under short term contracts.

The Company’s average sales price and production (lifting) costs for conventional and Cold Lake crude oil and natural gas liquids and natural gas for the five years ended December 31, 2005, were as follows:


	2005		2004		2003		2002		2001

Average Sales Price:
Crude oil and natural gas liquids:
Per cubic metre	$	234.04	$	207.26	$	181.92	$	174.72	$	134.16
Per barrel		37.21		32.95		28.92		27.78		21.33
Natural gas:
Per thousand cubic metres	$	317.71	$	239.34	$	232.99	$	141.91	$	201.92
Per thousand cubic feet		9.00		6.78		6.60		4.02		5.72
Average Production (Lifting) Costs Per
Unit of Net Production (1)(2):
Per cubic metre	$	67.82	$	58.16	$	60.78	$	53.09	$	48.55
Per barrel	$	10.78		9.25		9.66		8.44		7.72


(1)		Average production (lifting) costs do not include depreciation and depletion of capitalized acquisition, exploration and development costs. Administrative expenses are included. Average production (lifting) costs per unit of net production were computed after converting gas production into equivalent units of oil on the basis of relative energy content.
(2)		Previous year’s data has been reclassified to reflect that incentive compensation expenses, previously included in the natural resource segment, are now reported in the “corporate and other” segment. The data is computed using production expenses disclosed pursuant to Statement of Financial Accounting Standards No. 69, ‘Disclosures about Oil and Gas Producing Activities’.

Canadian crude oil prices are mainly determined by international crude oil markets which are volatile.

Canadian natural gas prices are determined by North American gas markets and are also volatile. Canadian natural gas prices decreased in 2002 primarily due to a weaker U.S. economy and warmer weather. Natural gas prices throughout North America increased in the second half of 2005 due to supply disruptions from hurricane damage to facilities in the U.S. Gulf Coast.

In 2002, average production (lifting) costs increased mainly due to lower net production at Cold Lake. In 2003, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake. In 2004, average production (lifting) costs decreased mainly due to higher production from the Wizard Lake gas cap.

In 2005, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake.

The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 25 plants that process natural gas to produce marketable gas and recover natural gas liquids or sulphur. The Company is the principal owner and operator of 10 of the plants.

The Company’s production of conventional and Cold Lake crude oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the Company had interests at December 31, 2005, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.


	Crude Oil				Natural Gas				Total
	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)

Conventional wells		1,446		836		4,570		2,445		6,016		3,281
Oil Sands (Cold Lake) wells		3,923		3,923		—		—		3,923		3,923


(1)		Gross wells are wells in which the Company owns a working interest.
(2)		Net wells are the sum of the fractional working interests owned by the Company in gross wells, rounded to the nearest whole number.

Conventional Oil and Gas

The Company has major interests in the Norman Wells oil field in the Northwest Territories and the West Pembina oil field in Alberta. Together they currently account for approximately 59 percent of the Company’s net production of conventional crude oil (approximately 64 percent of gross production).

Norman Wells is the Company’s largest producing conventional oil field. In 2005, net production of crude oil and natural gas liquids was about 2,200 cubic metres (13,700 barrels) per day and gross production was about 3,100 cubic metres (19,400 barrels) per day. The Government of Canada has a one-third carried interest and receives a production royalty of five percent in the Norman Wells oil field. The Government of Canada’s carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs. Under a shipping agreement, the Company pays for the construction, operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil and natural gas liquids from the project. In 2005, those costs were about $34 million. Most of the larger oil fields in the Western Provinces have been in production for several decades, and the amount of oil that is produced from conventional fields is declining. In some cases, however, additional oil can be recovered by using various methods of enhanced recovery. The Company’s largest enhanced recovery projects are located at the West Pembina oil field. In December 2005, the Company sold its interest in the Redwater and North Pembina fields. Gross oil production from these two properties averaged approximately 700 cubic metres (4,400 barrels) a day during the third quarter of 2005.

The Company produces natural gas from a large number of gas fields located in the Western Provinces, primarily in Alberta.

The Company has a nine percent interest in a project to develop natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia. About $5 billion has been spent by the participants to the end of 2005 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 12 million cubic metres (420 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids through the end of the decade.

Cold Lake

The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the technology necessary to produce this oil commercially, the Company has conducted experimental pilot operations since 1964 to recover the crude bitumen from wells by means of new drilling and production techniques including steam injection. Research at, and operation of, the Cold Lake pilots is continuing.

In late 1983, the Company commenced the development, in stages, of its oil sands resources at Cold Lake. During 2005, average net production at Cold Lake was about 19,700 cubic metres (123,500 barrels) per day and gross production was about 22,100 cubic metres (138,700 barrels) per day.

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2005, the Company spent $117 million and executed a development drilling program of 87 wells on existing stages. In 2006, a development drilling program of more than 100 wells is planned within the currently approved development area to add productive capacity from undeveloped areas of existing Cold Lake stages. In addition, opportunities are also being evaluated to improve utilization of the existing infrastructure.

In 2004, the Company received regulatory approval for further expansion of its operations at Cold Lake. Production is expected to begin in 2006 from part of the approved expansion, the development of which is expected to cost about $300 million and is expected to have gross production of about 4,800 cubic metres (30,000 barrels) per day by the end of the decade. Development plans for the remainder of the approved expansion are being examined to reduce development costs through increased integration with existing infrastructure. Most of the production from Cold Lake is sold to refineries in the northern United States. The remainder of the Cold Lake production is shipped to certain of the Company’s refineries and to a heavy oil upgrader in Lloydminster, Saskatchewan.

The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is entitled to a royalty on production from the Cold Lake production project. In late 2000, the Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the Company’s current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for royalties that apply to all other oil sands development in the Province will take effect. This transition will bring all phases of the Company’s Cold Lake operations under one royalty agreement with common terms and conditions. The transition is not expected to materially change the amount of royalties that the Company would have otherwise paid under the pre-existing royalty arrangements. The effective royalty on gross production was 11 percent in 2005 and 2004, 10 percent in 2003 and five percent in 2002 and 2001. The Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake production project and the pilot operations.

Other Oil Sands Activity

The Company has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of very heavy crude oil (crude bitumen) in place. The Company continues to evaluate these leases to determine their potential for future development.

The Company holds varying interests in lands totalling about 68,000 leased net hectares (168,000 net acres) in the Athabasca area where the oil sands are buried too deeply to permit recovery by surface mining methods. The Company, as part of an industry consortium and several joint ventures, has been involved in recovery research and pilot studies and in evaluating the quality and extent of the oil sands.

Syncrude Mining Operations

The Company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. Since startup in 1978, Syncrude has produced about 1.6 billion barrels of synthetic crude oil.

Syncrude has an operating license issued by the Province of Alberta which is effective until 2035. This license permits Syncrude to mine tar sands and produce synthetic crude oil from approved development areas on tar sands leases. Syncrude holds eight tar sands leases covering about 102,000 hectares (252,000 acres) in the Athabasca Oil Sands Deposit. Issued by the Province of Alberta, the leases are automatically renewable as long as tar sands operations are ongoing or the leases are part of an approved development plan. Syncrude leases 10, 12, 17, 22 and 34 (containing proven reserves) and leases 29, 30 and 31 (containing no proven reserves) are included within a development plan approved by the Province of Alberta.

As of January 1, 2002, a greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all Syncrude production after the deduction of new capital expenditures.

The Government of Canada had issued an order that expired at the end of 2003 which provided for the remission of any federal income tax otherwise payable by the participants as the result of the non-deductibility from the income of the participants of amounts receivable by the Province of Alberta as a royalty or otherwise with respect to Syncrude. That remission order excluded royalty payable on production for the Aurora project.

Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 495,000 tonnes (545,000 tons) of tar sands a day, producing about 18 million cubic metres (110 million barrels) of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2005, the upgrading process yielded 0.853 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.853 barrels of synthetic crude oil per barrel of crude bitumen). In 2005, about 49 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 51 percent was pipelined to refineries in eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. The Company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $3.2 billion.

In 2005, Syncrude’s net production of synthetic crude oil was about 33,700 cubic metres (211,800 barrels) per day and gross production was about 34,000 cubic metres (213,900 barrels) per day. The Company’s share of net production in 2005 was about 8,400 cubic metres (52,900 barrels) per day.

In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 35 kilometres (22 miles) from the main Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major expansion of upgrading capacity and further development of the Aurora mine. The second Aurora mining and extraction development became fully operational in 2004. The increased upgrading capacity is scheduled to come on stream in 2006. These projects are expected to lead to a total production capacity of about 56,500 cubic metres (355,000 barrels) of synthetic crude oil a day when completed. The Company’s share of project costs is expected to be about $2.1 billion of which about $2.0 billion has been incurred to the end of 2005.

The following table sets forth certain operating statistics for the Syncrude operations:


	2005		2004		2003		2002		2001

Total mined overburden (1)
millions of cubic metres		74.2		76.6		83.5		77.9		90.3
millions of cubic yards		97.1		100.3		109.2		102.0		118.3
Mined overburden to tar sands ratio (1)		1.02		0.94		1.15		1.05		1.15
Tar sands mined
millions of tonnes		152.7		170.9		152.4		156.5		164.8
millions of tons		168.0		188.0		168.0		172.1		181.2
Average bitumen grade (weight percent)		11.1		11.1		11.0		11.2		11.0
Crude bitumen in mined tar sands
millions of tonnes		16.9		19.0		16.8		17.5		18.1
millions of tons		18.6		20.9		18.5		19.2		19.9
Average extraction recovery (percent)		89.1		87.3		88.6		89.9		87.0
Crude bitumen production (2)
millions of cubic metres		15.1		16.4		14.7		15.5		15.5
millions of barrels		94.2		103.3		92.3		97.8		97.6
Average upgrading yield (percent)		85.3		85.5		86.0		86.3		84.5
Gross synthetic crude oil produced
millions of cubic metres		12.6		14.1		12.5		13.5		13.1
millions of barrels		79.3		88.4		78.4		84.8		82.4
Company’s net share (3)
millions of cubic metres		3.1		3.4		3.0		3.3		3.0
millions of barrels		19.3		21.6		19.1		20.7		18.9


(1)		Includes pre-stripping of mine areas and reclamation volumes.
(2)		Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.
(3)		Reflects the Company’s 25 percent interest in production, less applicable royalties payable to the Province of Alberta.

Other Tar Sands Activity

The Company holds a 100 percent interest in approximately 16,600 hectares (41,000 acres) of surface mineable tar sands in the Kearl area in the Athabasca area of northern Alberta. The Company is assessing a potential phased development of its tar sands in the area as part of the Kearl oil sands mining project. The Company would hold a 70 percent interest and would act as operator in the potential joint project with ExxonMobil Canada. A 400 well delineation drilling program to better define the available resource within the project area began in 2003 and was completed in 2005. The Company filed a regulatory application with the Alberta Energy and Utilities Board for the Kearl oil sands project in July 2005.

Land Holdings

At December 31, 2005 and 2004, the Company held the following oil and gas rights, and tar sands leases:


	Hectares												Acres
	Developed				Undeveloped				Total				Developed				Undeveloped				Total
	2005		2004		2005		2004		2005		2004		2005		2004		2005		2004		2005		2004
	(thousands)
Western Provinces
Conventional —
Gross (1)		1,055		1,080		181		173		1,236		1,253		2,607		2,669		447		427		3,054		3,096
Net (2)		430		446		109		118		539		564		1,063		1,102		269		292		1,332		1,394
Oil Sands (Cold Lake and other) —
Gross (1)		41		42		193		193		234		235		101		104		477		477		578		581
Net (2)		41		41		105		104		146		145		101		101		260		257		361		358
Tar Sands (Syncrude and other) —
Gross (1)		47		45		72		73		119		118		116		111		178		180		294		291
Net (2)		11		11		31		31		42		42		27		27		77		77		104		104
Canada Lands (3):
Conventional —
Gross (1)		31		31		322		321		353		352		77		77		795		793		872		870
Net (2)		3		3		98		98		101		101		7		7		242		242		249		249
Atlantic Offshore
Conventional —
Gross (1)		17		17		2,600		2,603		2,617		2,620		42		42		6,425		6,432		6,467		6,474
Net (2)		2		2		616		832		618		834		5		5		1,522		2,056		1,527		2,061
Total (4):
Gross (1)		1,191		1,215		3,368		3,363		4,559		4,578		2,943		3,003		8,322		8,309		11,265		11,312
Net (2)		487		503		959		1,183		1,446		1,686		1,203		1,242		2,370		2,924		3,573		4,166


(1)		Gross hectares or acres include the interests of others.
(2)		Net hectares or acres exclude the interests of others.
(3)		Canada Lands include the Arctic Islands, Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon.
(4)		Certain land holdings are subject to modification under agreements whereby others may earn interests in the Company’s holdings by performing certain exploratory work (farm-out) and whereby the Company may earn interests in others’ holdings by performing certain exploratory work (farm-in).

Exploration and Development

The Company has been involved in the exploration for and development of petroleum and natural gas in the Western Provinces, in the Canada Lands (which include the Arctic Islands, the Beaufort Sea/Mackenzie Delta, and Other Northwest Territories, Nunavut and the Yukon) and in the Atlantic Offshore.

The Company’s exploration strategy in the Western Provinces is to search for hydrocarbons on its existing land holdings and especially near established facilities. Higher risk areas are evaluated through shared ventures with other companies.

The following table sets forth the conventional and oil sands net exploratory and development wells that were drilled or participated in by the Company during the five years ended December 31, 2005.


	2005		2004		2003		2002		2001

Western and Atlantic Provinces:
Conventional
Exploratory —
Oil		—		—		—		—		—
Gas		—		2		3		1		1
Dry Holes		—		1		1		2		—
Development —
Oil		2		3		4		1		17
Gas		155		207		89		42		68
Dry Holes		1		1		3		3		—
Oil Sands (Cold Lake and other)
Development —
Oil		87		218		118		332		307

Total		245		432		218		381		393

The 87 oil sands development wells in 2005 were drilled to add new productive capacity from undeveloped areas of existing stages at Cold Lake. In 2004, there was an increase in gas development wells related to an increase in drilling in shallow gas fields. Weather related delays in 2005 resulted in a reduction in the number of wells drilled in the ongoing shallow gas development program.

At December 31, 2005, the Company was participating in the drilling of 138 gross (86 net) exploratory and development wells.

Western Provinces

In 2005, the Company had a working interest in three gross (zero net) exploratory wells and 351 gross (158 net) development wells, while retaining an overriding royalty in an additional 19 gross exploratory wells drilled by others. The majority of the exploratory wells were directed toward extending reserves around existing fields.

Beaufort Sea/Mackenzie Delta

Substantial quantities of gas have been found by the Company and others in the Beaufort Sea/Mackenzie Delta.

In 1999, the Company and three other companies entered into an agreement to study the feasibility of developing Mackenzie Delta gas, anchored by three large onshore natural gas fields. The Company retains a 100 percent interest in one of these fields.

The commercial viability of these natural gas resources, and the pipeline required to transport this natural gas to markets, is dependent on a number of factors. These factors include natural gas markets, support from northern parties, regulatory approvals, environmental considerations, pipeline participation, fiscal terms, and the cost of constructing, operating and abandoning the field production and pipeline facilities. There are complex issues to be resolved and many interested parties to be consulted, before any development could proceed.

In October 2001, the four companies and the Aboriginal Pipeline Group (“APG”), which represents aboriginal peoples of the Northwest Territories, signed a memorandum of understanding to pursue economic and timely development of a Mackenzie Valley pipeline. In 2002, the four companies completed a preliminary study of the feasibility of developing existing discoveries of Mackenzie Delta gas and based on the results of the study announced, together with the APG, their intention to begin preparing the regulatory applications needed to develop the gas resources, including construction of a Mackenzie Valley pipeline. In 2003, the Preliminary Information Package for the Mackenzie Gas Project was submitted to the regulatory authorities, and funding and participation agreements among the four companies, the APG and TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley pipeline. In late 2004, the four companies and the APG signed agreements covering the development and operations of the Mackenzie Valley pipeline. In October 2004, the main regulatory applications and environmental impact statement for the project were filed with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. Public hearings by the Joint Review Panel and National Energy Board, the next phase of the remaining two-year regulatory review process commenced in early 2006. The initial cost for the project is estimated to be about $7 billion with the Company’s share of the cost estimated to be about $3 billion.

Other land holdings include majority interests in 20 and minority interests in six “significant discovery” licences granted by the Government of Canada as the result of previous oil and gas discoveries, all of which are managed by the Company and majority interests in two and minority interests in 16 other “significant discovery” licences and one production licence, managed by others.

Arctic Islands

The Company has an interest in 16 “significant discovery” licences and one production licence granted by the Government of Canada in the Arctic Islands. These licences are managed by another company on behalf of all participants. The Company has not participated in wells drilled in this area since 1984.

Atlantic Offshore

The Company manages five “significant discovery” licences granted by the Government of Canada in the Atlantic offshore. The Company also has minority interests in 27 “significant discovery” licences, and five production licences, managed by others.

The Company retains a 20 percent interest in two exploration licences for about 45,000 gross hectares (110,000 gross acres) acquired in 1998 and 1999 in the Sable Island area. One exploratory well was completed on each licence, without commercial success.

Also, the Company retains a 70 percent interest in one exploration licence for about 113,000 gross hectares (279,000 gross acres) farther offshore in deeper water. In 2003, one exploratory well was drilled on this licence, without commercial success. The Company is not planning further exploration in these areas.

In early 2004, the Company acquired a 25 percent interest in eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 2,125,000 gross hectares (5,251,000 gross acres). In February 2005, the Company reduced its interest to 15 percent through an agreement with another company. The Company’s share of proposed exploration spending is about $100 million with a minimum commitment of about $25 million. In 2004 and 2005, the Company participated in a 3-D seismic survey in this area. A contract agreement for a drilling vessel has been signed and exploration drilling is expected in 2006.

The Company retains 100 percent interest in a single exploration licence for about 192,000 gross hectares (474,000 gross acres) in the Laurentian basin area offshore Newfoundland and Labrador.

Petroleum Products

Supply

To supply the requirements of its own refineries and condensate requirements for blending with crude bitumen, the Company supplements its own production with substantial purchases from others.

The Company purchases domestic crude oil at freely negotiated prices from a number of sources. Domestic purchases of crude oil are generally made under renewable contracts with 30 to 60 day cancellation terms.

Crude oil from foreign sources is purchased by the Company at competitive prices mainly through Exxon Mobil Corporation (which has beneficial access to major market sources of crude oil throughout the world).

Refining

The Company owns and operates four refineries. Two of these, the Sarnia refinery and the Strathcona refinery, have lubricating oil production facilities. The Strathcona refinery processes Canadian crude oil, and the Dartmouth, Sarnia and Nanticoke refineries process a combination of Canadian and foreign crude oil. In addition to crude oil, the Company purchases finished products to supplement its refinery production.

In 2005, capital expenditures of about $340 million were made at the Company’s refineries. About 65 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor fuels with the remaining expenditures being on safety and efficiency improvements, and environmental improvement projects.

The approximate average daily volumes of refinery throughput during the five years ended December 31, 2005, and the daily rated capacities of the refineries at December 31, 2000 and 2005, were as follows:


	Average Daily Volumes of										Daily Rated
	Refinery Throughput (1)										Capacities at
	Year Ended December 31										December 31 (2)
	2005		2004		2003		2002		2001		2005		2000
	(thousands of cubic metres)
Strathcona, Alberta		27.6		27.1		27.6		26.0		25.4		29.8		28.6
Sarnia, Ontario		16.9		17.2		14.7		16.5		16.5		19.2		19.2
Dartmouth, Nova Scotia		12.5		12.7		13.0		12.5		12.3		13.1		13.1
Nanticoke, Ontario		17.2		17.3		16.3		16.2		17.2		17.8		17.8

Total		74.1		74.3		71.6		71.2		71.4		79.9		78.7


	Average Daily Volumes of										Daily Rated
	Refinery Throughput (1)										Capacities at
	Year Ended December 31										December 31 (2)
	2005		2004		2003		2002		2001		2005		2000
	(thousands of barrels)
Strathcona, Alberta		174		170		174		163		160		187		180
Sarnia, Ontario		106		108		92		104		104		121		121
Dartmouth, Nova Scotia		79		80		82		78		77		82		82
Nanticoke, Ontario		108		109		102		102		108		112		112

Total		466		467		450		447		449		502		495


(1)		Refinery throughput is the volume of crude oil and feedstocks that is processed in the refinery atmospheric distillation units.
(2)		Rated capacities are based on definite specifications as to types of crude oil and feedstocks that are processed in the refinery atmospheric distillation units, the products to be obtained and the refinery process, adjusted to include an estimated allowance for normal maintenance shutdowns. Accordingly, actual capacities may be higher or lower than rated capacities due to changes in refinery operation and the type of crude oil available for processing.

Refinery throughput was 93 percent of capacity in 2005, the same as the previous year.

Distribution

The Company maintains a nation-wide distribution system, including 30 primary terminals, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail and road transport. The Company owns and operates crude oil, natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products and three crude oil pipeline companies.

At December 31, 2005, the Company did not own and operate any vessels other than one barge used primarily for domestic transportation of refined petroleum products.

Marketing

The Company markets more than 700 petroleum products throughout Canada under well known brand names, notably Esso, to all types of customers.

The Company sells to the motoring public through approximately 2,000 Esso service stations, of which about 700 are Company owned or leased, but none of which are Company operated. The Company continues to improve its Esso service station network, providing more customer services such as car washes and convenience stores, primarily at high volume sites in urban centres.

The Canadian farm, residential heating and small commercial markets are served through about 100 sales facilities. Heating oil is provided through authorized dealers as well as through three Company operated Home Comfort facilities in urban markets. The Company also sells petroleum products to large industrial and commercial accounts as well as to other refiners and marketers. In 2005, the Company divested its Western Canada fertilizer distribution assets to Agrium Inc. The transaction did not have a material impact on the financial results of the petroleum products segment.

The approximate daily volumes of petroleum products sold during the five years ended December 31, 2005, are set out in the following table:


	2005		2004		2003		2002		2001
	(thousands a day)
Gasolines:
Cubic metres		33.4		33.2		33.0		32.9		32.3
Barrels		210		209		208		207		203
Heating, Diesel and Jet Fuels:
Cubic metres		26.9		27.3		26.2		25.0		26.5
Barrels		169		172		165		157		166
Heavy Fuel Oils:
Cubic metres		6.0		5.9		5.4		4.9		5.4
Barrels		38		37		34		31		34
Lube Oils and Other Products (1)
Cubic metres		7.6		7.0		5.8		6.4		5.4
Barrels		48		44		36		41		34
Net petroleum product sales:
Cubic metres		73.9		73.4		70.4		69.2		69.6
Barrels		465		462		443		436		437
Sales under purchase and sale agreements:
Cubic metres		15.2		14.2		14.6		13.9		11.6
Barrels		95		89		92		87		73
Total:
Cubic metres		89.1		87.6		85.0		83.1		81.2
Barrels		560		551		535		523		510


(1)		Includes about one thousand cubic metres (six thousand barrels) per day of butane commencing in 2002. Butane is not included in 2001.

The total domestic sales of petroleum products as a percentage of total sales of petroleum products during the five years ended December 31, 2005, were as follows:


2005			2004			2003			2002			2001

	93.8	%		93.0	%		93.3	%		91.5	%		93.4	%

The Company continues to evaluate and adjust its Esso service station and distribution system to increase productivity and efficiency. During 2005, the Company closed or debranded about 70 Esso service stations, about 20 of which were Company owned, and added about 70 sites. The Company’s average annual throughput in 2005 per Esso service station was 3.6 million litres, 0.2 million litres higher than 2004. Average throughput per Company owned or leased Esso service station was 5.8 million litres in 2005, an increase of about 0.3 million litres from 2004.

Chemicals

The Company’s Chemicals operations manufacture and market ethylene, benzene, aromatic and aliphatic solvents, plasticizer intermediates and polyethylene resin. Its major petrochemical and polyethylene manufacturing operations are located in Sarnia, Ontario, adjacent to the Company’s petroleum refinery. There is also a heptene and octene plant located in Dartmouth, Nova Scotia.

The Company’s average daily sales of petrochemicals during the five years ended December 31, 2005, were as follows:


	2005		2004		2003		2002		2001
	(thousands a day)
Petrochemicals:
Tonnes		3.0		3.3		3.3		3.5		3.3
Tons		3.3		3.6		3.6		3.9		3.6

Research

In 2005, the Company’s research expenditures in Canada, before deduction of investment tax credits, were $50 million, as compared with $40 million in 2004 and $36 million in 2003. Those funds were used mainly for developing improved heavy crude oil recovery methods and better lubricants.

A research facility to support the Company’s natural resources operations is located in Calgary, Alberta. Research in these laboratories is aimed at developing new technology for the production and processing of crude bitumen. About 40 people were involved in this type of research in 2005. The Company also participated in bitumen recovery and processing research for tar sands development through its interest in Syncrude, which maintains research facilities in Edmonton, Alberta and through research arrangements with others.

In Company laboratories in Sarnia, Ontario, research is mainly conducted on the development and improvement of lubricants and fuels. About 120 people were employed in this type of research at the end of 2005. Also in Sarnia, there are about 15 people engaged in new product development for the Company’s and Exxon Mobil Corporation’s polyethylene injection and rotational molding businesses.

The Company has scientific research agreements with affiliates of Exxon Mobil Corporation which provide for technical and engineering work to be performed by all parties, the exchange of technical information and the assignment and licensing of patents and patent rights. These agreements provide mutual access to scientific and operating data related to nearly every phase of the petroleum and petrochemical operations of the parties.

Environmental Protection

The Company is concerned with and active in protecting the environment in connection with its various operations. The Company works in cooperation with government agencies and industry associations to deal with existing and to anticipate potential environmental protection issues. In the past five years, the Company has made capital expenditures of about $1.1 billion on environmental protection and facilities. In 2005, the Company’s capital expenditures relating to environmental protection totalled approximately $270 million, and are expected to be about $200 million in 2006.

The increased environmental expenditures over the past four years primarily reflect spending on two major projects. One project completed in 2004, costing about $650 million, reduced sulphur in motor gasolines, meeting a requirement of the Government of Canada a year in advance. The second project underway in 2004 is to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006. In 2005, there were capital expenditures of about $240 million on this second project, which is expected to cost about $600 million when completed. Capital expenditures on safety related projects in 2005 were approximately $15 million.

Human Resources

At December 31, 2005, the Company employed full-time approximately 5,100 persons compared with about 6,100 at the end of 2004 and 6,300 at the end of 2003. During 2005, the Company transferred about 700 employees to an affiliated company that provides services to the Company and others. About 9 percent of the Company’s employees are members of unions. The Company continues to maintain a broad range of benefits, including illness, disability and survivor benefits, a savings plan and pension plan.

Competition

The Canadian petroleum, natural gas and chemical industries are highly competitive. Competition includes the search for and development of new sources of supply, the construction and operation of crude oil, natural gas and refined products pipelines and facilities and the refining, distribution and marketing of petroleum products and chemicals. The petroleum industry also competes with other industries in supplying energy, fuel and other needs of consumers.

Government Regulation

Petroleum and Natural Gas Rights

Most of the Company’s petroleum and natural gas rights were acquired from governments, either federal or provincial. Reservations, permits or licences are acquired from the provinces for cash and entitle the holder to obtain leases upon completing specified work. Leases may also be acquired for cash. A lease entitles the holder to produce petroleum or natural gas from the leased lands. The holder of a licence relating to Canada Lands and the Atlantic Offshore is generally required to make cash payments or to undertake specified work or amounts of exploration expenditures in order to retain the holder’s interest in the land and may become entitled to produce petroleum or natural gas from the licenced land.

Crude Oil

Production

The maximum allowable gross production of crude oil from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles.

Exports

Export contracts of more than one year for light crude oil and petroleum products and two years for heavy crude oil (including crude bitumen) require the prior approval of the National Energy Board (the “NEB”) and the Government of Canada.

Natural Gas

Production

The maximum allowable gross production of natural gas from wells in Canada is subject to limitation by various regulatory authorities on the basis of engineering and conservation principles. A permit is required from the Alberta Energy and Utilities Board, subject to the approval of the Province of Alberta, for the removal from Alberta of natural gas produced in that province.

Exports

The Government of Canada has the authority to regulate the export price for natural gas and has a gas export pricing policy which accommodates export prices for natural gas negotiated between Canadian exporters and U.S. importers.

Exports of natural gas from Canada require approval by the NEB and the Government of Canada. The Government of Canada allows the export of natural gas by NEB order without volume limitation for terms not exceeding 24 months.

Royalties

The Government of Canada and the provinces in which the Company produces crude oil and natural gas impose royalties on production from lands where they own the mineral rights. Some producing provinces also receive revenue by imposing taxes on production from lands where they do not own the mineral rights.

Different royalties are imposed by the Government of Canada and each of the producing provinces. Royalties imposed by the producing provinces on crude oil vary depending on well production volumes, selling prices, recovery methods and the date of initial production. Royalties imposed by the producing provinces on natural gas and natural gas liquids vary depending on well production volumes, selling prices and the date of initial production. For information with respect to royalty rates for Norman Wells, Cold Lake and Syncrude, see “Natural Resources — Petroleum and Natural Gas Production”.

Investment Canada Act

The Investment Canada Act requires Government of Canada approval, in certain cases, of the acquisition of control of a Canadian business by an entity that is not controlled by Canadians. In certain circumstances, the acquisition of natural resource properties may be considered to be a transaction that constitutes an acquisition of control of a Canadian business requiring Government of Canada approval.

The Act requires notification of the establishment of new unrelated businesses in Canada by entities not controlled by Canadians, but does not require Government of Canada approval except when the new business is related to Canada’s cultural heritage or national identity. By virtue of the majority stock ownership of the Company by Exxon Mobil Corporation, the Company is considered to be an entity which is not controlled by Canadians.

The Company Online

The Company’s website www.imperialoil.ca contains a variety of corporate and investor information which is available free of charge, including the Company’s annual report on Form 10-K, quarterly reports on Form 10-Q and current reports on Form 8-K and amendments to these reports. These reports are made available as soon as reasonably practicable after they are filed or furnished to the U.S. Securities and Exchange Commission.

Item 1A. Risk Factors.

Volatility of Oil and Natural Gas Prices

The Company’s results of operations and financial condition are dependent on the prices it receives for its oil and natural gas production. Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. In the past, crude oil and natural gas prices have been volatile, and the Company expects that volatility to continue. Any material decline in oil or natural gas prices could have a material adverse effect on the Company’s operations, financial condition, proven reserves and the amount spent to develop oil and natural gas reserves.

A significant portion of the Company’s production is heavy oil. The market prices for heavy oil differ from the established market indices for light and medium grades of oil principally due to the higher transportation and refining costs associated with heavy oil and limited refining capacity capable of processing heavy oil. As a result, the price received for heavy oil is generally lower than the price for medium and light oil, and the production costs associated with heavy oil are often relatively higher than for lighter grades. Future differentials are uncertain and increases in the heavy oil differentials could have a material adverse effect on the Company’s business.

The Company does not use derivative markets to hedge or sell forward any part of production from any business segment.

Competitive Factors

The oil and gas industry is highly competitive, particularly in the following areas: searching for and developing new sources of supply; constructing and operating crude oil, natural gas and refined products pipelines and facilities; and the refining, distribution and marketing of petroleum products and chemicals. The Company’s competitors include major integrated oil and gas companies and numerous other independent oil and gas companies. The petroleum industry also competes with other industries in supplying energy, fuel and related products to customers.

Competitive forces may result in shortages of prospects to drill, services to carry out exploration, development or operating activities and infrastructure to produce and transport production. It may also result in an oversupply of crude oil, natural gas, petroleum products and chemicals. Each of these factors could have a negative impact on costs and prices and, therefore, the Company’s financial results.

Environmental Risks

All phases of the upstream, downstream and chemicals businesses are subject to environmental regulation pursuant to a variety of Canadian federal, provincial and municipal laws and regulations, as well as international conventions (collectively, “environmental legislation”).

Environmental legislation imposes, among other things, restrictions, liabilities and obligations in connection with the generation, handling, storage, transportation, treatment and disposal of hazardous substances and waste and in connection with spills, releases and emissions of various substances to the environment. As well, environmental regulations are imposed on the qualities and compositions of the products sold and imported. Environmental legislation also requires that wells, facility sites and other properties associated with the Company’s operations be operated, maintained, abandoned and reclaimed to the satisfaction of applicable regulatory authorities. In addition, certain types of operations, including exploration and development projects and significant changes to certain existing projects, may require the submission and approval of environmental impact assessments. Compliance with environmental legislation can require significant expenditures and failure to comply with environmental legislation may result in the imposition of fines and penalties and liability for clean up costs and damages. The Company cannot assure that the costs of complying with environmental legislation in the future will not have a material adverse effect on its financial condition or results of operations. The Company anticipates that changes in environmental legislation may require, among other things, reductions in emissions to the air from its operations and result in increased capital expenditures. Future changes in environmental legislation could occur and result in stricter standards and enforcement, larger fines and liability, and increased capital expenditures and operating costs, which could have a material adverse effect on the Company’s financial condition or results of operations.

Kyoto Protocol

Canada is a signatory to the United Nations Framework Convention on Climate Change and has ratified the Kyoto Protocol established thereunder to set legally-binding targets to reduce nation-wide emissions of carbon dioxide, methane, nitrous oxide and other so-called “greenhouse gases”. The Government of Canada has indicated an intent to issue regulations limiting greenhouse gas emissions from various industrial activities, including oil and natural gas exploration and production, petroleum refining, and some chemical manufacturing. The Province of Alberta may also issue regulations under Alberta’s Climate Change and Emissions Management Act limiting greenhouse gas emissions, as might other provinces. Mandatory emissions limits may result in increased operating costs and capital expenditures for oil and natural gas producers, refiners and chemical manufacturers, and also may reduce demand for the Company’s products, possibly adversely affecting the Company’s business, financial condition, results of operations and cash flows. However, while the government has outlined broad guidelines of a possible regulatory framework, it has not determined what specific measures it might impose on companies. Consequently attempts to assess the magnitude of any impact on the Company can only be speculative.

Other Regulatory Risk

The Company is subject to a wide range of legislation and regulation governing its operations over which it has no control. Changes may affect every aspect of Company operations and financial performance.

Need to Replace Reserves

The Company’s future oil, tar sands and natural gas reserves and production, and therefore cash flows, are highly dependent upon the Company’s success in exploiting its current reserve base and acquiring or discovering additional reserves. Without additions to the Company’s reserves through exploration, acquisition or development activities, reserves and production will decline over time as reserves are depleted. The business of exploring for, developing or acquiring reserves is capital intensive. To the extent cash flows from operations are insufficient to fund capital expenditures and external sources of capital become limited or unavailable, the Company’s ability to make the necessary capital investments to maintain and expand oil and natural gas reserves will be impaired. In addition, the Company may be unable to find and develop or acquire additional reserves to replace oil and natural gas production at acceptable costs.

Other Business Risks

Exploring for, producing and transporting petroleum substances involve many risks, which even a combination of experience, knowledge and careful evaluation may not be able to overcome. These activities are subject to a number of hazards which may result in fires, explosions, spills, blow-outs or other unexpected or dangerous conditions causing personal injury, property damage, environmental damage and interruption of operations. The Company’s insurance may not provide adequate coverage in certain unforeseen circumstances.

Uncertainty of Reserve Estimates

There are numerous uncertainties inherent in estimating quantities of reserves, including many factors beyond the Company’s control. In general, estimates of economically recoverable oil and natural gas reserves and the future net cash flow therefrom are based upon a number of factors and assumptions made as of the date on which the reserve estimates were determined, such as geological and engineering estimates which have inherent uncertainties, the assumed effects of regulation by governmental agencies and future commodity prices and operating costs, all of which may vary considerably from actual results. All such estimates are, to some degree, uncertain and classifications of reserves are only attempts to define the degree of uncertainty involved. For these reasons, estimates of the economically recoverable oil and natural gas reserves, the classification of such reserves based on risk of recovery and estimates of future net revenues expected therefrom, prepared by different engineers or by the same engineers at different times, may vary substantially. Actual production, revenues, taxes and development, abandonment and operating expenditures with respect to its reserves will likely vary from such estimates, and such variances could be material.

Estimates with respect to reserves that may be developed and produced in the future are often based upon volumetric calculations and upon analogy to similar types of reserves, rather than upon actual production history. Estimates based on these methods generally are less reliable than those based on actual production history. Subsequent evaluation of the same reserves based upon production history will result in variations, which may be material, in the estimated reserves.

Project Factors

The Company’s results depend on its ability to develop and operate major projects and facilities as planned. The Company’s results will, therefore, be affected by events or conditions that affect the advancement, operation, cost or results of such projects or facilities. These risks include the Company’s ability to obtain the necessary environmental and other regulatory approvals; changes in resources and operating costs including the availability and cost of materials, equipment and qualified personnel; the impact of general economic, business and market conditions; and the occurrence of unforeseen technical difficulties.

Market Risk Factors

See Item 7A for a discussion of the impact of market risks and other uncertainties.

Item 2. Properties.

Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations and oil and gas producing activities, reference is made to Item 8 of this report.

Item 3. Legal Proceedings.

Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.

Not applicable.

PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Information for Security Holders Outside Canada

Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian nonresident withholding tax of 15 percent.

The withholding tax is reduced to five percent on dividends paid to a corporation resident in the United States that owns at least 10 percent of the voting shares of the Company.

The Company is a qualified foreign corporation for purposes of the new reduced U.S. capital gains tax rates (15 percent and 5 percent for certain individuals) which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.

There is no Canadian tax on gains from selling shares or debt instruments owned by nonresidents not carrying on business in Canada.

Quarterly Financial and Stock Trading Data


	2005												2004
	three months ended												three months ended
	Mar. 31			June 30			Sept. 30			Dec. 31			Mar. 31			June 30			Sept. 30			Dec. 31

Financial data (millions of dollars)
Total revenues and other income		5,958			6,802			7,711			7,743			5,067			5,466			5,814			6,113
Total expenses		5,370			5,989			6,753			6,184			4,347			4,767			4,986			5,333

Income before income taxes		588			813			958			1,559			720			699			828			780
Income taxes		(195	)		(274	)		(306	)		(543	)		(254	)		(195	)		(284	)		(242	)

Net income		393			539			652			1,016			466			504			544			538

Per-share information (dollars)
Net earnings — basic		1.13			1.56			1.92			3.01			1.29			1.40			1.53			1.53
Net earnings — diluted		1.12			1.56			1.91			3.00			1.29			1.40			1.53			1.52
Dividends (declared quarterly)		0.22			0.24			0.24			0.24			0.22			0.22			0.22			0.22
Share prices (dollars)
Toronto Stock Exchange
High		94.33			104.97			137.37			136.18			64.45			64.25			66.76			73.65
Low		67.51			82.10			100.00			96.85			56.42			58.40			59.50			65.28
Close		92.02			102.02			134.01			115.41			58.87			62.40			65.48			71.15
American Stock Exchange ($U.S.)
High		77.20			85.15			117.41			116.78			48.70			47.13			52.22			62.45
Low		54.80			64.70			82.38			82.41			42.34			43.17			45.50			51.43
Close		76.14			83.31			115.06			99.60			44.84			46.82			51.71			59.38

The Company’s shares are listed on the Toronto Stock Exchange and are admitted to unlisted trading on the American Stock Exchange in New York. The symbol on these exchanges for the Company’s common shares is IMO. Share prices were obtained from stock exchange records.

As of February 15, 2006, there were 14,011 holders of record of common shares of the Company.

During the period October 1, 2005 to December 31, 2005, the Company issued 185,800 common shares for $46.50 per share as a result of the exercise of stock options by the holders of the stock options, who are all employees or former employees of the Company, in sales of those common shares outside the U.S.A. which were not registered under the Securities Act in reliance on Regulation S thereunder.

Issuer purchases of equity securities (1)

(d) Maximum number

(a) Total number

(c) Total number of shares

(or approximate dollar value)

of shares

(b) Average price

purchased as part of

of shares that may yet be

(or units)

paid per share

publicly announced plans

purchased under the plans or

Period

purchased

(or unit)

or programs

programs

October 2005
(October 1 — October 31)

807,443

$116.01

807,443

10,841,799

November 2005
(November 1 — November 30)

1,948,195

$108.48

1,948,195

8,871,168

December 2005
(December 1 — December 31)

1,067,128

$115.33

1,067,128

7,784,211


(1)		The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 23, 2005 under which the Company may purchase up to 17,080,605 of its outstanding common shares less any shares purchased by the employee savings plan and Company pension fund. If not previously terminated, the program will terminate on June 22, 2006.

Item 6. Selected Financial Data.


	2005		2004		2003		2002		2001
	(millions)
Total operating revenues	$	27,797	$	22,408	$	19,094	$	16,890	$	17,153
Net income		2,600		2,052		1,705		1,214		1,223
Total assets		15,582		14,027		12,337		12,003		10,888
Long term debt		863		367		859		1,466		1,029
Other long term obligations		1,728		1,525		1,314		1,822		1,303
	(dollars)
Net income/share — basic		7.62		5.75		4.58		3.20		3.11
Net income/share — diluted		7.59		5.74		4.58		3.20		3.11
Cash dividends/share		0.94		0.88		0.87		0.84		0.83

Reference is made to the table setting forth exchange rates for the Canadian dollar, expressed in U.S. dollars, on page 2 of this report.

Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation.

Overview

The following discussion and analysis of the Company’s financial results, as well as the accompanying financial statements and related notes to consolidated financial statements to which they refer, are the responsibility of the Company’s management.

The Company’s accounting and financial reporting fairly reflect its straightforward business model involving the extracting, refining and marketing of hydrocarbons and hydrocarbon-based products. The Company’s business involves the production (or purchase), manufacture and sale of physical products, and all commercial activities are directly in support of the underlying physical movement of goods.

With its extensive resource base in Canada, financial strength, disciplined investment approach and technology portfolio, the Company is well positioned to participate in substantial investments to develop new energy supplies. While commodity prices remain volatile on a short-term basis depending upon supply and demand, the Company’s investment decisions are based on long-term outlooks, using a disciplined approach in selecting and pursuing the most attractive investment opportunities. The corporate plan is a fundamental annual management process that is the basis for setting near-term operating and capital objectives in addition to providing the longer-term economic assumptions used for investment evaluation purposes. Annual plan volumes are based on individual field production profiles that are updated annually. Prices for crude oil, natural gas and refined products used for investment evaluation purposes are based on corporate plan assumptions that are developed annually. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed to ensure relevant lessons are learned and improvements are incorporated into future projects.

Business environment and outlook

Natural resources

The Company produces crude oil and natural gas for sale into large North American markets. Economic and population growth are expected to remain the primary drivers of energy demand. The Company expects the global economy to grow at an average rate of almost three percent per year through 2030. World energy demand should grow by about two percent per year, and oil and gas are expected to consistently account for about 60 percent of world energy supply through 2030. Over the same period, the Canadian economy is expected to grow at an average rate of about two percent per year, and Canadian demand for energy at a rate of about one percent per year. Oil and gas are expected to continue to supply two-thirds of Canadian energy demand. It is expected that Canada will also be a growing supplier of energy to U.S. markets through this period.

Oil products are the transportation fuel of choice for the world’s fleet of cars, trucks, trains, ships and airplanes. Primarily because of increased demand in developing countries, oil consumption will increase by 35 percent or about 30 million barrels a day by 2030. Canada’s oil sands represent an important additional source of supply.

Natural gas is expected to be a major primary energy source globally, capturing about one-third of all incremental energy growth and approaching one-quarter of global energy supplies. Natural gas production from mature established regions in the United States and Canada is not expected to meet increasing demand, strengthening the market opportunities for new gas supply from Canada’s frontier areas.

Crude oil and natural gas prices are determined by global and North American markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. In the past, crude oil and natural gas prices have been volatile, and the Company expects that volatility to continue.

The Company has a large and diverse portfolio of oil and gas resources in Canada, both developed and undeveloped, which helps reduce the risks of dependence on potentially limited supply sources in the upstream. With the relative maturity of conventional production in the established producing areas of Western Canada, the Company’s production is expected to come increasingly from frontier and unconventional sources, particularly oil sands and natural gas from the Far North, where the Company has large undeveloped resource opportunities.

Petroleum products

The downstream continues to experience ongoing volatility in industry margins. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale prices it receives for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published international prices. Prices for those commodities are determined by the marketplace, often an international marketplace, and are affected by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, transportation logistics, seasonality and weather. Canadian wholesale prices in particular are largely determined by wholesale prices in adjacent U.S. regions. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.

The Company’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest net unit costs among our competitors, ensure efficient and effective use of capital and capitalize on integration with the Company’s other businesses. The Company owns and operates four refineries in Canada, with distillation capacity of 502,000 barrels a day and lubricant manufacturing capacity of 9,000 barrels a day.

The Company’s fuels marketing business includes retail operations across Canada serving customers through about 2,000 Esso-branded service stations, of which about 700 are Company-owned or leased, and wholesale and industrial operations through a network of 30 primary distribution terminals.

Chemicals

Although the current business environment is favourable, the North American petrochemical industry is cyclical. The Company’s strategy for its chemicals business is to reduce costs and maximize value by continuing to increase the integration of its chemicals plants at Sarnia and Dartmouth with the refineries. The Company also benefits from its integration within ExxonMobil’s North American chemicals businesses, enabling it to maintain a leadership position in its key market segments.

Results of operations

Net income in 2005 was $2,600 million or $7.59 a share — the best year on record — surpassing the previous record of $2,052 million or $5.74 a share in 2004 (2003 — $1,705 million or $4.58 a share). Strong operational performance in 2005 allowed the Company to capture opportunities in an environment of higher commodity prices and industry margins. Higher realizations for crude oil, natural gas and Cold Lake bitumen and stronger refining margins contributed about $1,300 million to earnings when compared to 2004. Also positive to earnings was

increased natural gas and Cold Lake bitumen volumes of about $125 million. These factors were partly offset by a stronger Canadian dollar, lower volumes at Syncrude, the natural decline of conventional crude oil volumes and higher planned maintenance impacting refinery operations. These factors had a combined negative impact of about $590 million on earnings. Operating costs increased and impacted earnings by about $325 million, primarily driven by higher energy costs and higher Syncrude maintenance expenses. In addition, stock-related compensation expenses were $143 million higher than a year earlier and costs associated with the head office relocation of about $45 million were incurred in 2005. Included in net income in 2005 was a $233 million gain on sale of assets, mainly from the Redwater and North Pembina fields. Included in net income in 2004 was a $32 million gain on sale of assets and a write down of $42 million on a north Toronto property.

Total operating revenues were $27.8 billion, up 24 percent from 2004.

Beginning in the third quarter of 2005, incentive compensation expenses previously included in the operating segments are now reported in the “corporate and other” segment. This change has the effect of isolating in one segment all incentive compensation expenses and improving the transparency of operating events in the operating segments. This change has no impact on consolidated total expenses, net income or the cash-flow profile of the Company. Segmented results in previous years have been reclassified for comparative purposes.

Natural Resources

Net income from natural resources was a record $2,008 million, exceeding the previous record achieved in 2004 of $1,517 million (2003 — $1,174 million). Improved realizations for crude oil, natural gas and Cold Lake bitumen of about $910 million, and higher natural gas and Cold Lake bitumen volumes of about $125 million were the main reasons for the increase. Their positive impact on earnings was partially offset by the unfavourable impact of a higher Canadian dollar of about $260 million, lower volumes due to higher maintenance activities at Syncrude of about $100 million and the natural decline of conventional crude oil and NGL volumes of about $90 million. Operating costs were also higher than 2004 by about $275 million, primarily driven by higher energy costs of about $140 million and higher Syncrude maintenance and other expenses of about $75 million. Included in net income in 2005 was a $208 million gain on sale of assets, mainly from the Redwater and North Pembina fields. Included in net income in 2004 was a $25 million gain on sale of assets.

Resource operating revenues were $8.2 billion, up from $6.6 billion in 2004 (2003 — $5.6 billion). The main reasons for the increase were higher realizations primarily for crude oil, natural gas and Cold Lake bitumen and higher natural gas and Cold Lake bitumen volumes.

Financial statistics


	2005		2004		2003		2002		2001
	(millions)
Net income	$	2,008	$	1,517	$	1,174	$	1,052	$	953
Operating revenues		8,189		6,580		5,584		4,790		5,310

U.S. dollar world oil prices were considerably higher in 2005 than in the previous year. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was about $55 (U.S.) a barrel in 2005, a more than 42 percent increase over the average price of $38 in 2004 (2003 — $29). However, the Company’s Canadian dollar realizations for conventional crude oil increased to a lesser extent because of a stronger Canadian dollar. Average realizations for conventional crude oil during the year were $64.48 (Cdn) a barrel, an increase of 32 percent from $48.96 in 2004 (2003 — $40.10).

Average prices for Canadian heavy crude oil were higher in 2005, but by less than the relative increase in light crude oil prices, as increased supply of heavy crude oil widened the average spread between light and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil, was higher by 20 percent in 2005, much less than the increase in prices for Canadian light crude oil.

Prices for Canadian natural gas in 2005 were higher than the previous year. The average of 30-day spot prices for natural gas at the AECO hub in Alberta was about $9.01 a thousand cubic feet in 2005, compared with $6.80 in 2004 (2003 — $6.70). The Company’s average realizations on natural gas sales were $9 a thousand cubic feet, compared with $6.78 in 2004 (2003 — $6.60).

Average realizations and prices


	2005		2004		2003		2002		2001
	(Canadian dollars)
Conventional crude oil realizations (a barrel)	$	64.48	$	48.96	$	40.10	$	36.81	$	35.56
Natural gas liquids realizations (a barrel)		40.00		33.78		32.09		23.38		29.31
Natural gas realizations (a thousand cubic feet)		9.00		6.78		6.60		4.02		5.72
Par crude oil price at Edmonton (a barrel)		69.86		53.26		43.93		40.44		39.64
Heavy crude oil price at Hardisty (Bow River, a barrel)		45.62		37.98		33.00		31.85		25.11

Total gross production of crude oil and NGLs averaged 261,000 barrels a day, compared with 262,000 barrels in 2004 (2003 — 256,000).

Gross bitumen production at the Company’s wholly owned facilities at Cold Lake was a record 139,000 barrels a day, up from 126,000 barrels in 2004 (2003 — 129,000), due to the cyclic nature of production at Cold Lake and increased volumes from the ongoing development drilling program.

Production from the Syncrude operation, in which the Company has a 25 percent interest, was lower during 2005 as a result of planned and unplanned maintenance activities. Gross production of upgraded crude oil decreased to 214,000 barrels a day from 238,000 barrels in 2004 (2003 - 211,000). The Company’s share of average gross production decreased to 53,000 barrels a day from 60,000 barrels in 2004 (2003 — 53,000).

Gross production of conventional oil decreased to 38,000 barrels a day from 43,000 barrels in 2004 (2003 — 46,000) as a result of the natural decline in Western Canadian reservoirs.

Gross production of NGLs available for sale averaged 31,000 barrels a day in 2005, down from 33,000 barrels in 2004 (2003 — 28,000), mainly due to the declining content of Wizard Lake gas production.

Gross production of natural gas increased to 580 million cubic feet a day from 569 million in 2004 (2003 — 513 million). The increased volumes were mainly due to higher production from the Nisku, Wizard Lake and Medicine Hat fields.

In December, the Company sold its wholly owned and operated Redwater field as well as interests in the North Pembina field, both located in Alberta, for net proceeds of $289 million, realizing a gain of $163 million. Oil and natural gas production for the Company’s share of these two properties averaged approximately 4,400 oil-equivalent barrels a day during the third quarter of 2005.

Crude oil and NGLs — production and sales (a)


	2005				2004				2003				2002				2001
	gross		net		gross		net		gross		net		gross		net		gross		net
	(thousands of barrels a day)
Cold Lake		139		124		126		112		129		116		112		106		128		121
Syncrude		53		53		60		59		53		52		57		57		56		52
Conventional crude oil		38		29		43		33		46		35		51		39		55		42

Total crude oil production		230		206		229		204		228		203		220		202		239		215
NGLs available for sale		31		25		33		26		28		22		27		21		28		22

Total crude oil and NGL production		261		231		262		230		256		225		247		223		267		237
Cold Lake sales, include diluent (b)		183				167				170				145				167
NGL sales		39				42				39				40				43

Natural gas — production and sales (a)


	2005				2004				2003				2002				2001
	gross		net		gross		net		gross		net		gross		net		gross		net
	(millions of cubic feet a day)
Production (c)		580		514		569		518		513		457		530		463		572		466
Sales		536				520				460				499				502


(a)		Daily volumes are calculated by dividing total volumes for the year by the number of days in the year. Gross production is the Company’s share of production (excluding purchases) before deducting the share of mineral owners or governments or both. Net production excludes those shares.
(b)		Includes natural gas condensate added to the Cold Lake bitumen to facilitate transportation to market by pipeline.
(c)		Production of natural gas includes amounts used for internal consumption with the exception of the amounts reinjected.

Operating costs increased by 17 percent in 2005. The main factors were higher energy costs and higher Syncrude maintenance and other expenses.

Effective April 1, 2005, the Company and an affiliate of Exxon Mobil Corporation in Canada agreed to operate their respective Western Canada production organizations as one single organization. Under the consolidation, the Company will operate all Western Canada properties. There are no asset ownership changes. The consolidation is expected to result in efficiencies from a streamlined organization.

Petroleum products

Net income from petroleum products was a record $694 million or 2.1 cents a litre in 2005, improving on the previous record of $556 million or 1.7 cents a litre in 2004 (2003 — $462 million or 1.5 cents a litre). Higher earnings in 2005 were mainly a result of stronger industry refining margins. Marketing margins in 2005 remained at the low levels of 2004. Planned refinery maintenance activities were higher in the year, when compared to 2004, impacting both refinery operations and expenses and reducing earnings by about $75 million. Higher earnings were also partially offset by a stronger Canadian dollar of about $85 million, higher energy costs of about $65 million and costs associated with the head office relocation of about $35 million.

Operating revenues were $24 billion, up from $19.2 billion in 2004 (2003 — $16.1 billion).

Financial statistics


	2005		2004		2003		2002		2001
	(millions)
Net income	$	694	$	556	$	462	$	147	$	376
Operating revenues		24,017		19,169		16,004		14,400		14,379

Sales of petroleum products


	2005		2004		2003		2002		2001
	(millions of litres a day (a))
Gasolines		33.4		33.2		33.0		32.9		32.3
Heating, diesel and jet fuels		26.9		27.3		26.2		25.0		26.5
Heavy fuel oils		6.0		5.9		5.4		4.9		5.4
Lube oils and other products		7.6		7.0		5.8		6.4		5.4

Net petroleum product sales		73.9		73.4		70.4		69.2		69.6
Sales under purchase and sale agreements		15.2		14.2		14.6		13.9		11.6

Total sales of petroleum products		89.1		87.6		85.0		83.1		81.2

Total domestic sales of petroleum products (percent)		93.8		93.0		93.3		91.5		93.4

Refinery utilization


	2005		2004		2003		2002		2001
	(millions of litres a day (a))
Total refinery throughput (b)		74.1		74.3		71.6		71.2		71.4
Refinery capacity at December 31		79.9		79.9		79.9		79.4		79.1
Utilization of total refinery capacity (percent)		93		93		90		90		90


(a)		Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.
(b)		Crude oil and feedstocks sent directly to atmospheric distillation units.

One thousand litres is approximately 6.3 barrels.

Margins were stronger in the refining segment of the industry in 2005 compared with those in 2004, pushed up by increased demand for refined petroleum products that stemmed from generally stronger global economic conditions and the short-term production disruptions along the U.S. Gulf Coast. However, the effects of stronger industry margins were reduced partially by a higher Canadian dollar. Marketing margins in 2005 remained at the low levels of 2004, reflecting the impact of highly competitive markets.

Operating performance of the Company’s four refineries was solid. Despite higher planned maintenance, refinery utilization for 2005 was 93 percent, repeating a record performance level that was established in 2004 (2003 — 90 percent).

The Company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 89.1 million litres a day, compared with 87.6 million litres in 2004 (2003 — 85 million). Excluding sales resulting from reciprocal agreements, sales were 73.9 million litres a day, compared with 73.4 million litres in 2004 (2003 — 70.4 million).

Operating costs increased by about seven percent in 2005 from the previous year, mainly because of higher energy costs and costs associated with the head office relocation.

In 2005, the Company divested its Western Canada fertilizer distribution assets to Agrium Inc. The transaction did not have a material impact on the financial results of the petroleum products segment.

Chemicals

Net income from chemicals operations was $121 million in 2005, compared with $109 million in 2004 (2003 — $44 million). Improved industry margins were partly offset by weaker industry demand for polyethylene products.

Financial statistics


	2005		2004		2003		2002		2001
	(millions of dollars)
Net income	$	121	$	109	$	44	$	54	$	26
Operating revenues		1,665		1,509		1,232		1,164		1,175

Sales volumes


	2005		2004		2003		2002		2001
	(thousands of tonnes a day (a))
Polymers and basic chemicals		2.1		2.4		2.4		2.5		2.4
Intermediate and others		0.9		0.9		0.9		1.0		0.9

Total chemicals		3.0		3.3		3.3		3.5		3.3


(a)		Volumes a day are calculated by dividing total volumes for the year by the number of days in the year.

One tonne is approximately 1.1 short tons or 0.98 long tons.

Total operating revenues from chemical operations were $1,665 million, compared with $1,509 million in 2004 (2003 — $1,232 million). Higher prices for polyethylene and intermediate chemicals were the main contributing factors.

The average industry price of polyethylene was $1,708 a tonne in 2005, up eight percent from $1,584 a tonne in 2004 (2003 — $1,415).

Sales of chemicals were 3,000 tonnes a day, compared with 3,300 tonnes a day in 2004 (2003 - 3,300 tonnes) mainly due to a reduction in lower margin polyethylene resale volumes and weaker industry demand for polyethylene products.

Operating costs in the chemicals segment for 2005 were about four percent higher than 2004. Higher energy costs were the main reason for the increase.

Corporate and other

Net income from corporate and other was negative $223 million in 2005, compared with negative $130 million in 2004 (2003 — positive $25 million). Lower net income in 2005 was mainly due to higher stock-related compensation expenses of about $143 million, largely driven by the increase in the Company’s share price from a year earlier, partially offset by the absence of a write down of $42 million on a north Toronto property previously recorded in 2004.

Liquidity and capital resources

Sources and uses of cash


	2005			2004
	(millions of dollars)
Cash provided by/(used in)
Operating activities	$	3,451		$	3,312
Investing activities		(992	)		(1,306	)
Financing activities		(2,077	)		(1,175	)

Increase/(decrease) in cash and cash equivalents		382			831

Cash and cash equivalents at end of year	$	1,661		$	1,279

Although the Company issues long-term debt from time to time, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Company’s immediate needs is carefully controlled, both to ensure that it is secure and readily available to meet the Company’s cash requirements as they arise and to optimize returns on cash balances.

Cash flows from operating activities are highly dependent on crude oil and natural gas prices and product margins. In addition, the Company will need to continually find and develop new resources, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. Projects are in place or underway to increase production capacity. However, these volume increases are subject to a variety of risks, including project execution, operational outages, reservoir performance and regulatory changes.

The Company’s financial strength enables it to make large, long-term capital expenditures. The Company’s large and diverse portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks of the Company and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Company’s liquidity or ability to generate sufficient cash flows for its operations and fixed commitments.

Cash flow from operating activities

Cash provided by operating activities was $3,451 million, versus $3,312 million in 2004 (2003 — $2,227 million). The increased cash flow was mainly due to higher net income and the impact of higher commodity prices on working capital partially offset by additional funding contributions to the employee pension plan and the timing of income tax payments. The $233 million gain on asset sales is a non-cash item and represented a reduction from net income in the cash from operating activities category. The cash received from asset sales is reported in cash from investing activities.

Capital and exploration expenditures

Total capital and exploration expenditures were $1,475 million in 2005, up from $1,445 million in 2004 (2003 — $1,559 million).

The funds were used mainly to invest in Syncrude and Cold Lake to maintain and expand production capacity, upgrade refineries to meet low-sulphur diesel requirements, improve operating efficiency and upgrade the network of Esso retail outlets. About $280 million was spent on projects related to reducing the environmental impact of its operations and improving safety, including about $240 million on the $500-million capital project to produce low-sulphur diesel.

The following table shows the Company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2005:


	2005		2004		2003		2002		2001
	(millions of dollars)
Exploration	$	43	$	60	$	57	$	39	$	49
Production		232		234		181		143		109
Heavy oil		662		819		769		804		588

Total capital and exploration expenditures	$	937	$	1,113	$	1,007	$	986	$	746

For the natural resources segment, about 90 percent of the capital and exploration expenditures in 2005 was focused on growth opportunities. The single largest investment during the year was the Company’s share of the Syncrude expansion. Construction on the upgrader expansion portion of the Syncrude Stage 3 project was about 98 percent complete at the end of 2005 with remaining activities principally focused on mechanical completion, testing and commissioning. Completion of the project with production of higher quality synthetic crude oil is scheduled to come on stream by mid-2006. Continuing cost and labour pressures in the Fort McMurray area have resulted in the total projected cost for the Stage 3 project growing from $7.8 billion, indicated in March 2004, to $8.4 billion currently. The remainder of 2005 investment was directed to drilling at Cold Lake and conventional fields in Western Canada and advancing the Mackenzie gas project.

In April 2005, the Company, on behalf of the Mackenzie gas project co-venturers, halted project execution activities due to insufficient progress on areas critical to the project — the finalization of benefits and access agreements, the establishment of a clear regulatory process, and appropriate fiscal terms for the project. Sufficient advances were subsequently made in these areas and, in November, the Company notified the National Energy Board of the project proponents’ readiness to proceed to public hearings on the project. Hearings began in January 2006 and are expected to continue through 2006. During 2005, initial applications for fieldwork approvals, including land-use permits and water licences, were filed with regulatory agencies and boards. Additional permit applications will be filed in 2006.

In July 2005, regulatory applications for the development of the Kearl oil sands project, in which the Company holds about a 70 percent interest and would act as operator in a joint venture with ExxonMobil Canada, were filed with the Alberta Energy and Utilities Board and Alberta Environment. Hearings are expected to begin later in 2006.

During the third quarter of 2005, the Company and its partners completed a second 3-D seismic acquisition program in the Orphan Basin on Canada’s East Coast. A contract agreement for a drilling vessel has been signed and exploration drilling in the Orphan Basin, offshore Newfoundland, is expected in mid-2006. The Company holds a 15 percent interest in the eight deepwater exploration licences in the Orphan Basin.

Planned capital and exploration expenditures in natural resources are expected to be about $800 million in 2006, with over 80 percent of the total focused on growth opportunities. Investments are mainly planned for development drilling at Cold Lake and conventional oil and gas operations in Western Canada, facilities improvement at Syncrude, and the Mackenzie gas project.

The following table shows the Company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2005:


	2005		2004		2003		2002		2001
	(millions of dollars)
Marketing	$	91	$	85	$	91	$	133	$	171
Refining and supply		368		178		369		399		118
Other (a)		19		20		18		57		50

Total capital expenditures	$	478	$	283	$	478	$	589	$	339


(a)		Consists primarily of real estate purchases.

For the petroleum products segment, capital expenditures increased to $478 million in 2005, compared with $283 million in 2004 (2003 — $478 million). The Company invested about $240 million in refining operations and other facilities during the year as part of a three-year, $500-million project to reduce sulphur content in diesel. In addition, more than $100 million was spent on other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso service stations during the year.

Capital expenditures for the petroleum products segment in 2006 are expected to be about $350 million. Major items include additional investment in refining facilities to complete the sulphur-reduction project and continued enhancements to the Company’s retail network.

The following table shows the Company’s capital expenditures for its chemicals operations during the five years ending December 31, 2005:


	2005		2004		2003		2002		2001
	(millions of dollars)
Chemicals	$	19	$	15	$	41	$	25	$	30

Of the capital expenditures for chemicals in 2005, the major investment focused on improving energy efficiency, yields and process control technology.

Planned capital expenditures for chemicals in 2006 will be about $15 million.

Total capital and exploration expenditures for the Company in 2006, which will focus mainly on growth and productivity improvements, are expected to total about $1.2 billion and will be financed from internally generated funds.

Cash flow from financing activities

In June, the Company renewed the normal course issuer bid (share-repurchase program) for another 12 months. During 2005, the Company purchased about 17.5 million shares for $1,795 million (2004 — 14 million shares for $872 million). Since the Company initiated its first share-repurchase program in 1995, it has purchased 250 million shares — representing about 43 percent of the total outstanding at the start of the program — with resulting distributions to shareholders in excess of $8.6 billion.

The Company declared dividends totalling 94 cents a share in 2005, up from 88 cents in 2004 (2003 — 87 cents). Regular annual per-share dividends paid have increased in each of the past 11 years and, since 1986, payments per share have grown by more than 76 percent.

Total debt outstanding at the end of 2005, excluding the Company’s share of equity Company debt, was $1,439 million, compared with $1,443 million at the end of 2004 (2003 — $1,432 million). Debt represented 18 percent of the Company’s capital structure at the end of 2005, compared with 19 percent at the end of 2004 (2003 — 21 percent).

Debt-related interest incurred in 2005, before capitalization of interest, was $45 million, up from $37 million in 2004 (2003 — $38 million). The average effective interest rate on the Company’s debt was 3.1 percent in 2005, compared with 2.8 percent in 2004 (2003 — 2.9 percent).

During 2005, the Company’s Canadian dollar variable-rate loans of $500 million and $318 million from Exxon Overseas Corporation, due in 2005 and 2006 were extended to mature in 2007 and 2008 respectively.

Financial percentages and ratios


	2005		2004		2003		2002		2001

Total debt as a percentage of capital (a)		18		19		21		24		26
Interest coverage ratios
Earnings basis (b)		88		83		64		46		26
Cash-flow basis (c)		101		108		80		63		36


(a)		Current and long-term portions of debt (page F-5), divided by debt and shareholder’s equity (page F-5)
(b)		Net income (page F-3), debt-related interest before capitalization (page F-22, note 14) and income taxes (page F-3) divided by debt-related interest before capitalization.
(c)		Cash flow from net-income adjusted for the cumulative effect of accounting change and other non-cash items (page F-4), current income tax expense (page F-13, note 4) and debt-related interest before capitalization (page F-22, note 14) divided by debt-related interest before capitalization.

The Company’s financial strength, as evidenced by the above financial ratios, represents a competitive advantage of strategic importance. The Company’s sound financial position gives it the opportunity to access capital markets in the full range of market conditions and enables the Company to take on large, long-term capital commitments in the pursuit of maximizing shareholder value.

On February 2, 2006, the Company proposed to subdivide the common shares of the Company on a three-for-one basis. The proposed stock split is subject to shareholder and regulatory approvals.

Contractual obligations

The following table shows the Company’s contractual obligations outstanding at December 31, 2005. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to the consolidated financial statements.



	Financial	Payment due by period
	Statement			2007 to		2011 and		Total
	Note Reference	2006		2010		beyond		amount
		(millions of dollars)
Long-term debt and capital leases	Note 3	$	477	$	833	$	30	$	1,340
Company’s share of equity company debt			59		—		—		59
Operating leases	Note 11		48		168		57		273
Unconditional purchase obligations (a)	Note 11		94		145		20		259
Firm capital commitments (b)	Note 11		196		36		—		232
Pension obligations (c)	Note 6		416		80		346		842
Asset retirement obligations (d)	Note 7		36		141		190		367
Other long-term agreements (e)	Note 11		403		1,022		356		1,781


(a)		Unconditional purchase obligations mainly pertain to pipeline throughput agreements.
(b)		Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $232 million at the end of 2005, compared with $171 million at year-end 2004. The largest commitment outstanding at year-end 2005 was associated with the Company’s share of upstream capital projects of $72 million offshore Canada’s East Coast.
(c)		The amount by which accumulated benefit obligations (ABO) exceeded the fair value of fund assets at year-end (page F-14, note 6). For funded pension plans, this difference was $489 million at December 31, 2005. For unfunded plans, this was the ABO amount of $353 million. The payments by period include expected contributions to funded pension plans in 2006 and estimated benefit payments for unfunded plans in all years.
(d)		Asset retirement obligations represent the discounted present value of legal obligations associated with site restoration on the retirement of assets with determinable useful lives.
(e)		Other long-term agreements include primarily raw material supply and transportation services agreements.

The Company was contingently liable at December 31, 2005, for a maximum of $77 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the resignation of the associate. The Company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payments under the guarantees.

Various lawsuits are pending against the Company and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the Company does not believe the ultimate outcome of any currently pending lawsuits against the Company will have a material adverse effect on the Company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

Recently issued Statement of Financial Accounting Standards

Share-based payments

In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), Share-based Payments. SFAS 123R requires compensation costs related to share-based payment arrangements to employees to be recognized in the income statement over the requisite service period. The amount of the compensation cost will be measured based on the grant-date fair value of the instruments issued. In addition, liability awards will be remeasured each reporting period through settlement. SFAS 123R is effective for the Company as of January 1, 2006, for all awards granted or modified after that date and for those awards granted prior to that date that have not vested. SFAS 123R will not have a material impact on the Company’s earnings because in 2003, the Company adopted a policy of expensing all share-based payments that is consistent with the provisions of SFAS 123R and all prior year outstanding stock option awards have vested.

The cumulative compensation expense associated with stock-related awards made in 2002, 2003 and 2004 has been recognized in the consolidated income statement using the “nominal vesting period approach”. The full cost of awards given to employees who have retired before the end of the vesting period has been expensed. The use of a “non-substantive vesting period approach” based on the retirement eligibility age would not be significantly different from the nominal vesting period approach. The non-substantive vesting period approach will be applicable to grants made after the adoption of SFAS 123R on January 1, 2006.

Accounting for purchases and sales of inventory with the same counterparty

At its September 2005 meeting, the Emerging Issues Task Force (EITF) reached a consensus on Issue No. 04-13, Accounting for Purchases and Sales of Inventory with the Same Counterparty. This issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as exchanges measured at the book value of the item sold. The EITF concluded that purchases and sales of inventory with the same counterparty that are entered into in contemplation of one another should be combined and recorded as exchanges measured at the book value of the item sold.

The Company currently records certain crude oil, natural gas, petroleum product and chemical purchases and sales of inventory entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. This accounting treatment is consistent with long standing industry practice (although the Company understands that some companies in the oil and gas industry may be accounting for these transactions as nonmonetary exchanges). The EITF consensus will result in the Company’s accounts “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income being reduced by associated amounts with no impact on net income. All operating segments will be impacted by this change, but the largest effects are in the petroleum products segment. The EITF consensus will become effective for new arrangements entered into, and modifications or renewals of existing agreements, beginning no later than the second quarter of 2006.

The purchase/sale amounts included in revenue for 2005, 2004 and 2003 are shown in note 1 to the consolidated financial statements on page F-7.

Critical accounting policies

The Company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgment. The Company’s accounting and financial reporting fairly reflect its straightforward business model. The Company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The following summary provides further information about the critical accounting policies and the estimates that are made by the Company to apply those policies. It should be read in conjunction with note 1 to the consolidated financial statements on page F-7.

Hydrocarbon reserves

Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of calculating unit-of-production rates for depreciation and evaluating for impairment. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits.

The estimation of proved reserves is controlled by the Company through long-standing approval guidelines. Reserve changes are made with a well-established, disciplined process driven by senior-level geoscience and engineering professionals (assisted by a central reserves group with significant technical experience), culminating in reviews with and approval by senior management and the Company’s board of directors. Key features of the estimation include rigorous peer-reviewed technical evaluations and analysis of well and field performance information, and a requirement that management make a commitment toward the development of the reserves prior to booking. Notably, no employee is compensated based on the levels of proved reserves bookings.

Although the Company is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors, including completion of development projects, reservoir performance and significant changes in long-term oil and gas price levels.

Based on the United States Securities and Exchange Commission regulatory guidance, the Company has reported 2004 and 2005 reserves on the basis of December 31 prices and costs (”year-end prices”).

The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are required based on prices occurring on a single day. The Company believes that this approach is inconsistent with the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Company, and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.

The impact of year-end prices on reserves estimation is most clearly shown at Cold Lake, where proved bitumen and associated natural gas reserves were reduced by about 137 million oil-equivalent barrels as a result of using December 31, 2005, prices, which were seasonally low. Prices of Cold Lake bitumen were strong for most of 2005, however, they began to deteriorate in the middle of the fourth quarter and ended on December 31, 2005, more than 25 percent below the year’s average. Prices quickly rebounded from December 31, and through January 2006 returned to levels that have restored the reserves to the proved category, repeating the same reserves rebooking situation as in January 2005.

Revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of already available geologic, reservoir or production data; new geologic, reservoir or production data; or changes to underlying price assumptions used in the determination of reserves. This category can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity.

The Company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The Company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the Company’s exploration and production activities.

Impact of reserves on depreciation

The calculation of unit-of-production depreciation is a critical accounting estimate that measures the depreciation of natural resources assets. It is the ratio of actual volumes produced to total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to the asset cost. The volumes produced and asset cost are known and, while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and production. Revisions have averaged eight million oil-equivalent barrels per year over the last five years and have resulted from effective reservoir management and the application of new technology. While the upward revisions the Company has made over the last five years are an indicator of variability, they have had little impact on the unit-of-production rates of depreciation because they have been small compared to the large proved reserves base.

Impact of reserves and prices on testing for impairment

Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the asset’s carrying value exceeds its fair value.

The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected and historical and current operating losses.

In general, the Company does not view temporarily low oil prices as a triggering event for conducting impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, the relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Company performs make use of the Company’s long-term price assumptions for crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the Company’s annual planning and budgeting processes and are also used for capital investment decisions. Any impairment tests that the Company performs also make use of annual volumes based on individual field production profiles, which are also updated as part of the annual plan process.

The standardized measure of discounted future cash flows on page 37 is based on the year-end 2005 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used in the SFAS 69 disclosure and could be lower or higher for any given year.

Retirement benefits

The Company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third-party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long-term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long-term changes in market rates and outlook. The long-term expected rate of return on plan assets of 8.25 percent used in 2005 compares to actual returns of 10 percent and 9.64 percent achieved over the last 10- and 20-year periods ending December 31, 2005. If different assumptions are used, the expense and obligations could increase or decrease as a result. The Company’s potential exposure to changes in assumptions is summarized in note 6 to the consolidated financial statements on page F-14. At the Company, differences between actual returns on plan assets versus long-term expected returns are not recorded in the year the differences occur, but rather are amortized in pension expense as permitted by GAAP, along with other actuarial gains and losses, over the expected remaining service life of employees. The Company uses the fair value of the plan assets at year-end to determine the amount of the actual gain or loss that will be amortized and does not use a moving average value of plan assets. Pension expense represented less than one percent of total expenses in 2005.

Asset retirement obligations and other environmental liabilities

Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long-term changes in market rates and outlook. For 2005, the obligations were discounted at six percent and the accretion expense was $20 million, before tax, which was significantly less than one percent of total expenses in the year. There would be no material impact on the Company’s reported financial results if a different discount rate had been used.

Asset retirement obligations are not recognized for assets with an indeterminate useful life. For these and non-operating assets, the Company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.

Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the Company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the Company’s reported financial results.

Item 7A. Quantitative and Qualitative Disclosures about Market Risk.

The Company is exposed to a variety of financial, operating and market risks in the course of its business. Some of these risks are within the Company’s control, while others are not. For those risks that can be controlled, specific risk management strategies are employed to reduce the likelihood of loss.

Although the Government of Canada, in ratifying the Kyoto Protocol, agreed to restrictions of greenhouse gas emissions by the period 2008-2012, it has not determined what measures it will impose on companies. Consequently, attempts to assess the impact on the Company can only be speculative. The Company will continue to monitor the development of legal requirements in this area.

Other risks, such as changes in international commodity prices and currency-exchange rates, are beyond the Company’s control. The Company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the Company’s exposure to changes in these other risks. The Company’s potential exposure to these types of risk is summarized in the earnings sensitivity table below.

The Company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.

The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the Company’s after tax net income.


	millions of dollars after tax
Six dollars (U.S.) a barrel change in crude oil prices		+(-	)	300
One dollar and ten cents a thousand cubic feet change in natural gas prices		+(-	)	66
One cent a litre change in sales margins for total petroleum products		+(-	)	175
One cent (U.S.) a pound change in sales margins for polyethylene		+(-	)	7
One quarter percent decrease (increase) in short term interest rates		+(-	)	2
Nine cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar		+(-	)	475

The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2005. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations.

The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar increased from year end 2004 by about $20 million (after tax) a year for each one cent change. This is primarily due to the increase in crude oil prices and industry refining margins.

Item 8. Financial Statements and Supplementary Data.

Reference is made to the Index to Financial Statements on page F-1 of this report.

Syncrude Mining Operations

Syncrude’s crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 15 to 45 metres (50 to 150 feet) of overburden, have bitumen grades ranging from four to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160 feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the long range mine plan approved by the Syncrude owners, there are an estimated 1,720 million tonnes (1,890 million tons) of extractable tar sands in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,075 million tonnes (4,485 million tons) of extractable tar sands at an average bitumen grade of 11.2 weight percent. After deducting royalties payable to the Province of Alberta, the Company estimates its 25 percent net share of proven reserves at year end 2005 was equivalent to 117 million cubic metres (738 million barrels) of synthetic crude oil.

The following table sets forth the Company’s share of net proven reserves of Syncrude after deducting royalties payable to the Province of Alberta:


	Synthetic Crude Oil
	Base Mine and
	North Mine			Aurora Mine			Total
	(millions of cubic metres)
Beginning of year 2003		55			72			127
Revision of previous estimate		—			—			—
Production		(2	)		(1	)		(3	)

End of year 2003		53			71			124
Revision of previous estimate		(16	)		16			0
Production		(2	)		(2	)		(4	)

End of year 2004		35			85			120
Revision of previous estimate		—			—			—
Production		(1	)		(2	)		(3	)

End of year 2005		34			83			117


	Synthetic Crude Oil
	Base Mine and
	North Mine			Aurora Mine			Total
	(millions of barrels)
Beginning of year 2003		344			456			800
Revision of previous estimate		—			—			—
Production		(13	)		(6	)		(19	)

End of year 2003		331			450			781
Revision of previous estimate		(103	)		100			(3	)
Production		(11	)		(10	)		(21	)

End of year 2004		217			540			757
Revision of previous estimate		—			—			—
Production		(9	)		(10	)		(19	)

End of year 2005		208			530			738

Oil and Gas Producing Activities

The following information is provided in accordance with the United States’ Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”.

Results of Operations


	2005		2004		2003
	(millions of dollars)
Sales to customers (1)	$	2,739	$	2,160	$	2,067
Intersegment sales (1) (2)		1,013		976		665

	$	3,752	$	3,136	$	2,732
Production expenses		1,035		870		883
Exploration expenses		31		44		55
Depreciation and depletion		583		565		463
Income taxes		716		547		376

Results of operations	$	1,387	$	1,110	$	955

Capital and exploration expenditures


	2005		2004		2003
	(millions of dollars)
Property costs (3)
Proved	$	—	$	—	$	—
Unproved		7		1		2
Exploration costs		37		43		55
Development costs		330		408		339

Total capital and exploration expenditures	$	374	$	452	$	396

Property, plant and equipment


	2005		2004
	(millions of dollars)
Property costs (3)
Proved	$	3,231	$	3,328
Unproved		162		141
Producing assets		6,111		6,099
Support facilities		174		122
Incomplete construction		432		235

Total cost	$	10,110	$	9,925
Accumulated depreciation and depletion		6,934		6,514

Net property, plant and equipment	$	3,176	$	3,411


(1)		Sales to customers or intersegment sales do not include the sale of natural gas and natural gas liquids purchased for resale, as well as royalty payments. These items are reported gross in note 2 in “External sales”, “Intersegment sales” and in “Purchases of crude oil and products”.
(2)		Sales of crude oil to consolidated affiliates are at market value, using posted field prices. Sales of natural gas liquids to consolidated affiliates are at prices estimated to be obtainable in a competitive, arm’s-length transaction.
(3)		“Property costs” are payments for rights to explore for petroleum and natural gas and for purchased reserves (acquired tangible and intangible assets such as gas plants, production facilities and producing-well costs are included under “Producing assets”). “Proved” represents areas where successful drilling has delineated a field capable of production. “Unproved” represents all other areas.

Net proved developed and undeveloped reserves (1)


	Crude oil and natural gas liquids
	Conventional			Cold Lake			Total			Natural Gas
	(millions of cubic metres)									(billions of cubic metres)
Beginning of year 2003		23			127			150			35

Revisions and improved recovery		—			1			1			(1	)
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			—
Production		(3	)		(7	)		(10	)		(5	)

End of year 2003		20			121			141			29

Revisions and improved recovery		1			(3	)		(2	)		1
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			—
Production		(3	)		(6	)		(9	)		(5	)

Total before year end price/cost revisions		18			112			130			25
Year end price/cost revisions		—			(75	)		(75	)		(3	)

End of year 2004		18			37			55			22

Remove 2004 year end price/cost revisions		—			75			75			3

Total before 2004 year end price/cost revisions		18			112			130			25

Revisions and improved recovery		(1	)		1			—			2
(Sale)/purchase of reserves in place		(2	)		—			(2	)		—
Discoveries and extensions		—			3			3			—
Production		(3	)		(7	)		(10	)		(5	)

Total before 2005 year end price/cost revisions		12			109			121			22

Year end price/cost revisions		1			(21	)		(20	)		(1	)

End of year 2005		13			88			101			21


(1)		Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 101.325 kilopascals absolute at 15 degrees Celsius.


	Crude oil and natural gas liquids
	Conventional			Cold Lake			Total			Natural Gas
	(millions of barrels)									(billions of cubic feet)
Beginning of year 2003		146			801			947			1,224

Revisions and improved recovery		1			5			6			(40	)
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			6
Production		(21	)		(43	)		(64	)		(167	)

End of year 2003		126			763			889			1,023

Revisions and improved recovery		6			(20	)		(14	)		57
(Sale)/purchase of reserves in place		—			—			—			(13	)
Discoveries and extensions		—			—			—			3
Production		(22	)		(41	)		(63	)		(190	)

Total before year end price/cost revisions		110			702			812			880
Year end price/cost revisions		5			(470	)		(465	)		(89	)

End of year 2004		115			232			347			791

Remove 2004 year end price/cost revisions		(5	)		470			465			89

Total before 2004 year end price/cost revisions		110			702			812			880

Revisions and improved recovery		(1	)		9			8			65
(Sale)/purchase of reserves in place		(12	)		—			(12	)		(6	)
Discoveries and extensions		—			17			17			14
Production		(20	)		(45	)		(65	)		(188	)

Total before 2005 year end price/cost revisions		77			683			760			765

Year end price/cost revisions		6			(132	)		(126	)		(18	)

End of year 2005		83			551			634			747


(1)		Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both. All reported reserves are located in Canada. Reserves of natural gas are calculated at a pressure of 14.73 pounds per square inch at 60°F.

The information above describes changes during the years and balances of proved oil and gas reserves at year-end 2003, 2004 and 2005. The definitions used for oil and gas reserves are in accordance with the U.S. Securities and Exchange Commission’s (SEC) Rule 4-10 (a) of Regulation S-X, paragraphs (2), (3) and (4).

Crude oil and natural gas reserve estimates, are based on geological and engineering data, which have demonstrated with reasonable certainty that these reserves are recoverable in future years from known reservoirs under existing economic and operating conditions; i.e., prices and costs as of the date the estimate is made. Reserves of crude oil at Cold Lake are those estimated to be recoverable from the Leming plant and commercial phases.

Based on SEC regulatory guidance, the Company has reported 2004 and 2005 reserves on the basis of December 31 prices and costs respectively (“year-end prices”).

The use of year-end prices for reserves estimation introduces short-term price volatility into the process since annual adjustments are required based on prices occurring on a single day. The Company believes that this approach is inconsistent with the long-term nature of the natural resources business where production from individual projects often spans multiple decades. The use of prices from a single date is not relevant to the investment decisions made by the Company and annual variations in reserves based on such year-end prices are not of consequence to how the business is actually managed.

The impact of year-end prices on reserves estimation is most clearly shown at Cold Lake where proved bitumen and associated natural gas reserves were reduced by about 137 million oil-equivalent barrels as a result of using December 31, 2005, prices, which were seasonally low. Prices quickly rebounded from December 31, and through January 2006 returned to levels that have restored the reserves to the proved category, repeating the same reserves rebooking situation as in January 2005.

Net proved reserves are determined by deducting the estimated future share of mineral owners or governments or both. For conventional crude oil (excluding enhanced oil-recovery projects) and natural gas, net proved reserves are based on estimated future royalty rates representative of those existing as of the date the estimate is made. Actual future royalty rates may vary with production and price. For enhanced oil-recovery projects and Cold Lake, net proved reserves are based on the Company’s best estimate of average royalty rates over the life of each project. Actual future royalty rates may vary with production, price and costs.

Reserves data do not include certain resources of crude oil and natural gas such as those discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the resources contained in oil sands other than reserves attributable to the Cold Lake Leming plant and commercial phases of Cold Lake production operations.

Oil-equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel on an energy-equivalent conversion method is primarily applicable at the burner tip and does not represent a value equivalency at the well head. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.

Net proved developed and undeveloped reserves of crude oil and natural gas (1)


	2005		2004		2003		2002		2001
	(millions)
Crude Oil:
Conventional:
Cubic metres		13		18		20		23		26
Barrels		83		115		126		146		165
Oil Sands (Cold Lake crude bitumen):
Cubic metres		88		37		121		127		128
Barrels		551		232		763		801		807
Total:
Cubic metres		101		55		141		150		154
Barrels		634		347		889		947		972
Natural Gas:	(billions)
Cubic metres		21		22		29		35		40
Cubic feet		747		791		1,023		1,224		1,414

Net proved developed reserves of crude oil and natural gas (1)


	2005		2004		2003		2002		2001
	(millions)
Crude Oil:
Conventional:
Cubic metres		13		18		19		22		25
Barrels		81		111		121		139		157
Oil Sands (Cold Lake crude bitumen):
Cubic metres		58		37		63		49		34
Barrels		368		232		398		308		216
Total:
Cubic metres		71		55		82		71		59
Barrels		449		343		519		447		373
Natural Gas:	(billions)
Cubic metres		18		20		24		27		30
Cubic feet		643		704		859		959		1,060


(1)		Net reserves are the Company’s share of reserves after deducting the shares of mineral owners or governments or both.

Standardized measure of discounted future net cash flows related to proved oil and gas reserves

As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change. The table below excludes the Company’s interest in Syncrude.


	2005			2004			2003
	(millions)
Future cash flows	$	21,911		$	11,625		$	27,611
Future production costs		(11,376	)		(3,123	)		(10,871	)
Future development costs		(2,039	)		(1,492	)		(3,084	)
Future income taxes		(2,777	)		(2,260	)		(5,543	)

Future net cash flows		5,719			4,750			8,113
Annual discount of 10 percent for estimated timing of cash flows		(1,405	)		(1,433	)		(3,375	)

Discounted future net cash flows	$	4,314		$	3,317		$	4,738

Changes in standardized measure of discounted future net cash flows related to proved oil and gas reserves


	2005			2004			2003
	(millions)
Balance at beginning of year	$	3,317		$	4,738		$	8,201
Changes resulting from:
Sales and transfers of oil and gas produced, net of production costs		(2,650	)		(2,240	)		(2,075	)
Net changes in prices, development costs and production costs		3,343			(3,692	)		(4,395	)
Extensions, discoveries, additions and improved recovery, less related costs		(513	)		(43	)		22
Development costs incurred during the year		272			345			281
Revisions of previous quantity estimates		660			1,838			(368	)
Accretion of discount		417			663			1,108
Net change in income taxes		(532	)		1,708			1,964

Net change		997			(1,421	)		(3,463	)

Balance at end of year	$	4,314		$	3,317		$	4,738

Within the past 12 months, the Company has not filed oil and gas reserve estimates with any authority or agency of the United States.

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. Controls and Procedures.

As indicated in the certifications in Exhibit 31.1 and 31.2 of this report, the Company’s principal executive officer and principal financial officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2005. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are appropriate and effective for the purpose of ensuring that material information relating to the Company, including its consolidated subsidiaries, is made known to them by others within those entities, particularly during the period in which this annual report is being prepared.

Reference is made to page F-2 of this report for management’s report on internal control over financial reporting.

Reference is made to page F-2 of this report for the report of the independent registered public accounting firm on management’s assessment on internal control over financial reporting.

There has not been any change in the Company’s internal control over financial reporting that occurred during the Company’s fourth fiscal quarter of 2005 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

PART III

Item 10. Directors and Executive Officers of the Registrant.

The Company currently has eight directors. Each director is elected to hold office until the close of the next annual meeting.

Each of the eight directors listed below has been nominated for re-election at the annual meeting of shareholders to be held May 2, 2006. All of the nominees are now directors and have been since the dates indicated.

The following table provides information on the nominees for election as directors.

Last major

position or office with the

Name and current principal

Company or Exxon Mobil

occupation or employment

Corporation

Director since

Holdings (2)(3)

R.L. (Randy) Broiles

Global planning

July 21, 2005

Common shares of

Senior vice-president,

manager,

Imperial Oil Limited

1000

resources division,

ExxonMobil Production

Imperial Oil Limited

Company

Deferred share units of

Imperial Oil Limited

Restricted stock units of

Imperial Oil Limited

Shares of Exxon

Mobil Corporation (4)

53,244

T.J. (Tim) Hearn

President,

January 1, 2002

Common shares of

Chairman, president and

Imperial Oil Limited

30,342

chief executive officer,

Imperial Oil Limited

Deferred share units of

Imperial Oil Limited

101

Restricted stock units of

Imperial Oil Limited

213,800

Shares of Exxon

Mobil Corporation

10,107

J.M. (Jack) Mintz

–

April 21, 2005

Common shares of

President and chief

Imperial Oil Limited

100

executive officer,

The C.D. Howe Institute

Deferred share units of

(public policy institute) and

Imperial Oil Limited

professor, Joseph L. Rotman

School of Management,

Restricted stock units of

University of Toronto (1)

Imperial Oil Limited

1,000

Shares of Exxon

Mobil Corporation

R. (Roger) Phillips

–

April 23, 2002

Common shares of

Retired president and

Imperial Oil Limited

3,000

chief executive officer,

IPSCO Inc.

Deferred share units of

(steel manufacturing) (1)

Imperial Oil Limited

3,943

Restricted stock units of

Imperial Oil Limited

3,375

Shares of Exxon

Mobil Corporation

2,000

(Table continued on following page)

Last major

position or office with the

Name and current principal

Company or Exxon Mobil

occupation or employment

Corporation

Director since

Holdings (2)(3)

J.F. (Jim) Shepard

–

October 21, 1997

Common shares of

Retired chairman and

Imperial Oil Limited

3,000

chief executive officer,

Finning International Inc.

Deferred share units of

(sale, lease, repair and

Imperial Oil Limited

6,564

financing of heavy

equipment) (1)

Restricted stock units of

Imperial Oil Limited

3,375

Shares of Exxon

Mobil Corporation

P.A. (Paul) Smith

Corporate finance

February 1, 2002

Common shares of

Controller and

manager, Exxon

Imperial Oil Limited

4,434

senior vice-president,

Mobil Corporation

finance and

Deferred share units of

administration,

Imperial Oil Limited

Restricted stock units of

Imperial Oil Limited

60,650

Shares of Exxon

Mobil Corporation

1,190

S.D. (Sheelagh) Whittaker

–

April 19, 1996

Common shares of

Retired managing director,

Imperial Oil Limited

3,000

Electronic Data Systems Limited

(business and information

Deferred share units of

technology services) (1)

Imperial Oil Limited

9,053

Restricted stock units of

Imperial Oil Limited

3,375

Shares of Exxon

Mobil Corporation

V.L. (Victor) Young

–

April 23, 2002

Common shares of

Corporate director of

Imperial Oil Limited

3,000

several corporations (1)

Deferred share units of

Imperial Oil Limited

1,379

Restricted stock units of

Imperial Oil Limited

3,375

Shares of Exxon

Mobil Corporation


(1)		Member of audit committee; member of environment, health and safety committee; member of executive resources committee; member of nominations and corporate governance committee; and member of Imperial Oil Foundation board of directors.
(2)		The information includes the beneficial ownership of common shares of Imperial Oil Limited and shares of Exxon Mobil Corporation, which information not being within the knowledge of the Company, has been provided by the nominees individually.
(3)		The Company’s plans for deferred share units and restricted stock units for selected employees and nonemployee directors are described on page 46 and pages 47 and 48, respectively.
(4)		R. L. Broiles holds 16,244 common shares and 37,000 restricted shares of Exxon Mobil Corporation.

The ages of the directors, nominees for election as directors, and the five senior executives of the Company are: Randy L. Broiles 48, Timothy J. Hearn 61, Jack M. Mintz 54, Roger Phillips 66, James F. Shepard 67, Paul A. Smith 52, Sheelagh D. Whittaker 58, Victor L. Young 60, Robert F. Lipsett 59, and John F. Kyle 63.

Certain of the directors hold positions as directors of other Canadian and U.S. reporting issuers as follows: Jack M. Mintz — Brookfield Asset Management Inc. and CHC Helicopter Corporation; Roger Phillips — Canadian

Pacific Railway Limited, Cleveland-Cliffs Inc., Inco Limited and The Toronto-Dominion Bank; Sheelagh D. Whittaker — CanWest Media Works Income Fund; and Victor L. Young — Aliant Inc., BCE Inc. and Royal Bank of Canada. It is anticipated that Timothy J. Hearn will be elected as a director of Royal Bank of Canada at its annual meeting of shareholders to be held on March 3, 2006.

All of the directors and nominees for election as directors, except for Roger Phillips, Sheelagh D. Whittaker and Victor L. Young have been engaged for more than five years in their present principal occupations or in other executive capacities with the same firm or affiliated firms. During the five preceding years, Roger Phillips was president and chief executive officer of IPSCO Inc. (steel manufacturing) until he retired in January 2002. During the five preceding years, Sheelagh D. Whittaker was managing director of Electronic Data Systems until she retired in November 2005. During the five preceding years, Victor L. Young was chairman and chief executive officer of Fishery Products International Limited (seafood products), until May 2001.

The following table provides information on the senior executives of the Company.


Name and Office		Office held since
Timothy J. Hearn chairman of the board, president and chief executive officer		April 23, 2002

Paul A. Smith controller and senior vice-president, finance and administration		February 1, 2002

Randy L. Broiles senior vice-president, resources division		July 1, 2005

Robert F. Lipsett vice-president, human resources		October 1, 1999

John F. Kyle vice-president and treasurer		June 1, 1991

All of the above senior executives have been engaged for more than five years at their current occupations or in other executive capacities with the Company or its affiliates. All senior executives hold office until their appointment is rescinded by the directors, or by the chief executive officer.

Audit committee

The Company has an audit committee of the board of directors. The following directors are the members of the audit committee: P. Des Marais II until his retirement on April 21, 2005, R. Phillips, J.F. Shepard, S.D. Whittaker, V.L. Young, and J.M. Mintz, from his appointment on April 21, 2005.

Audit committee financial expert

The Company’s board of directors has determined that R. Phillips, S.D. Whittaker and V.L. Young meet the definition of “audit committee financial expert” and that they, J.F. Shepard and J.M. Mintz are independent, as that term is defined in Multilateral Instrument 52-110, the Securities and Exchange Commission rules and the listing standards of the American Stock Exchange and the New York Stock Exchange. The Securities and Exchange Commission has indicated that the designation of an audit committee financial expert does not make that person an expert for any purpose, or impose any duties, obligations or liability on that person that are greater than those imposed on members of the audit committee and board of directors in the absence of such designation or identification.

Code of ethics

The Company has a code of ethics that applies to all employees, including its principal executive officer, principal financial officer and principal accounting officer. The code of ethics consists of the Company’s ethics policy, conflicts of interest policy, corporate assets policy, directorships policy and procedures and open door communication. Those documents are available at the Company’s web site www.imperialoil.ca.

Item 11. Executive Compensation.

Composition of the Company’s compensation committee

The executive resources committee of the board of directors, composed of the independent directors, is responsible for decisions on the compensation of senior management above the level of vice-president including all officers of the Company, and for reviewing the executive development system, including specific succession plans for senior management positions. It also reviews corporate policy on compensation. During 2005, the membership of the executive resources committee was as follows:

P. Des Marais II — Chair (until April 2005)
R. Phillips — Chair (from May 2005)
R. Phillips — Vice-chair (until April 2005)
V.L. Young — Vice-chair (from May 2005)
J.F. Shepard
S.D. Whittaker
J.M. Mintz (from April 2005)

T.J. Hearn periodically attends meetings at the request of the committee.

Executive Resources Committee Report on Executive Compensation

The Company’s executive compensation policy is designed to reinforce the Company’s orientation toward career employment and its emphasis on performance as the primary determinant of advancement. This acknowledges the long-term nature of the Company’s business and its philosophy that the experience, skill and motivation of its senior executives are significant determinants of future business success. The compensation program emphasizes competitive salaries and performance-based incentives as the primary instruments to develop and retain key personnel.

In establishing levels of compensation for its senior executives, the executive resources committee relies on market comparisons to other leading Canadian employers, typically in the group of major companies with revenues in excess of $1 billion a year. These market comparisons are prepared by independent external compensation consultants. However, no consultant or advisor was retained to assist in determining compensation for any of the Company’s directors or officers or any other senior executives. On a case-by-case basis, depending on the scope of market coverage represented by a particular comparison, compensation is targeted to a range between the mid-point and the upper quartile of comparable employers, reflecting the Company’s emphasis on quality of management.

The Company’s senior executive compensation policy has three main elements: base salary, cash bonus and long-term incentive compensation. While these elements are related to the extent that compensation policy is compared in total to the competitive practices of other major Canadian employers, individual decisions on base salary, cash bonus and long-term incentive compensation are made independently of each other.

Base Salary

The Company’s salary ranges for executives were increased by two and one-half percent in 2004, one and one-half percent in 2005 and two and one-half percent in 2006. High-performing executives, and those recently promoted, whose salaries were low relative to their level of responsibility, were given limited additional salary increases. This included senior executives.

T.J. Hearn’s salary is currently assessed to be within the range of the competitive target for the Company’s chairman, president and chief executive officer which is between the median and upper quartile. The target is consistent with the executive resources committee’s view that the chairman, president and chief executive officer’s salary should be above the average of salaries for chief executive officers of major Canadian companies, reflecting the Company’s executive development philosophy and the significance placed on experience and judgment in leading a large, complex operation.

Cash Bonus

Cash bonuses are typically granted to about 80 executives to reward their contributions to the business during the past year. Earnings bonus units, which are described on page 47, are generally granted in tandem as incentives for strong, medium-term Company performance. These bonuses are drawn from an aggregate bonus amount established annually by the executive resources committee based on the Company’s financial and operating performance.

In 2005, the executive resources committee increased the overall bonus awards pool including the grant of earnings bonus units to reflect the Company’s record financial results, outstanding operating performance and in response to comparisons to other leading Canadian employers.

In the case of T.J. Hearn, the committee’s approach to cash bonuses is based on the Company’s financial and operating performance and on the committee’s assessment of T.J. Hearn’s effectiveness in leading the organization. The continuing progress being made in focusing the organization on advancing key strategic interests, safety, environmental performance, productivity, cost effectiveness and asset management were primary considerations in determining a cash bonus for the chairman, president and chief executive officer. T.J. Hearn’s bonus including the grant of earnings bonus units was increased in 2005 to reflect his effectiveness in the position, the Company’s record financial results, and comparisons to other leading Canadian employers.

Long-Term Incentive Compensation

Each year, the executive resources committee has approved long-term incentive awards for selected key employees. These awards were an added incentive to promote individual contribution to sustained improvement in business performance and shareholder value, and to encourage key employees to remain with the Company. Individual awards reflected both level of responsibility and performance, with an emphasis on ability to influence longer-term results. In each case, including senior executives and the chairman, president and chief executive officer, award amounts took into account the competitive practices of other major Canadian employers and were not influenced by prior-years’ results or by an individual’s holdings of unexercised long-term incentive compensation units.

Incentive awards also have been awarded selectively to the general managerial, professional and technical (non-executive) workforce as a way of delivering added financial incentive to selected high-performing employees.

Currently, restricted stock units, which are described in more detail on pages 47 and 48, form the bases of awards under this program. A total of 579 employees, including executives, were granted restricted stock units in 2005.

For many years, the Company’s long-term incentive compensation programs have been cash-based programs tied to earnings and share performance, and incentive awards have been reported as expenses in the consolidated statement of earnings. In 2002, to meet competitive practices, the Company introduced a stock option program. However, recognizing current concerns over stock option incentive programs, the Company decided to return to straightforward, primarily cash based incentive compensation programs that will again be reported as expenses against earnings. There are no plans to issue stock options in the future.

Two elements of the Company’s compensation programs are awarded in the current year but do not pay out until a future date. These elements are the earnings bonus unit plan and the restricted stock unit plan which are described in detail on pages 47 and 48. The amounts that are paid out in the future could be more or could be less than the face values shown on pages 43 and 45 and are not strictly part of the total compensation received in the current year.

The committee is aware that regulatory authorities and shareholder groups have recently made recommendations to modify the disclosure of compensation, but since these recommendations are still in the discussion stages and could change materially prior to approval, the committee has elected to adhere to all currently required disclosure requirements. The Company intends to fully implement any new disclosure requirements approved by the regulatory authorities.

Directors’ compensation

Directors’ fees are paid only to non-employee directors. For 2005, non-employee directors were paid an annual retainer of $35,000 and 1,000 restricted stock units for their services as directors, plus an annual retainer of $4,500 for each committee on which they served, an additional $5,000 for serving as chair of a committee and $2,000 for each board and board committee meeting attended. The restricted stock units issued to non-employee directors have the same features as the restricted stock units for selected key employees described on pages 47 and 48.

Starting in 1999, the non-employee directors have been able to receive all or part of their directors’ fees in the form of deferred share units for non-employee directors. The purpose of the deferred share unit plan for non-employee directors is to provide them with additional motivation to promote sustained improvement in the Company’s business performance and shareholder value by allowing them to have all or part of their directors’ fees tied to the future growth in value of the Company’s common shares. This plan is described on page 46.

While serving as directors in 2005, the aggregate cash remuneration paid to non-employee directors, as a group, was $365,333, and they received an additional 2,193 deferred share units, based on an aggregate of $234,375 of cash remuneration elected to be received as deferred share units. The non-employee directors, as a group, received an additional 194 deferred share units granted as the equivalent to the cash dividend paid on Company shares during 2005 for previously granted deferred share units. In addition, the non-employee directors received 5,000 restricted stock units.

Senior executive compensation
Summary Compensation Table

The following table shows the compensation for the chairman, president and chief executive officer and the four other senior executives of the Company who were serving as senior executives at the end of 2005. This information includes the dollar value of base salaries, cash bonus awards, and units of other long term incentive compensation and certain other compensation.


		Annual Compensation					Long Term Compensation
						Awards				Payouts
							Securities	Shares or Units	Shares or Units
					Other Annual		Under	Subject to Resale	Subject to Resale	LTIP	All Other
Name and					Compensation		Options/SARs	Restrictions	Restrictions	Payouts	Compensation
Principal			Salary	Bonus (2)	(3)		Granted (4)	(5) (6)	(5) (6)	(7)	(8)
Position	Year		($)	($)	($)		(#)	(#)	(#)	(8) ($)	($)

T.J. Hearn	2005		1,100,000	900,000	385,028		–	64,400	7,432,404	870,000	33,000
Chairman, president								restricted stock units
and chief executive								1	94
officer								deferred share unit
	2004		1,000,000	872,266	246,249		–	64,400	4,582,060	750,000	30,000
								restricted stock units
								100	7,034
								deferred share units
	2003		825,000	750,000	182,072		–	60,000	3,451,800	738,000	24,750
					U.S. 293,450			restricted stock units
								0	0
								deferred share units

P.A. Smith	2005		398,333	193,675	87,198		–	18,400	2,123,544	193,125	23,900
Controller and senior								restricted stock units
vice-president, finance	2004		378,333	193,600	67,022		–	19,300	1,373,195	183,000	22,700
and administration								restricted stock units
	2003		357,917	183,000	11,083		–	16,700	960,751	204,510	21,475
					U.S. 72,891			restricted stock units

R.L. Broiles (1)	2005		U.S. 159,000	U.S. 140,500	U.S. 112,214		–	11,000	U.S. 641,740	U.S. 116,253	U.S. 10,175
Senior vice-president, resources								restricted stock units
division (from July 1, 2005)

R.F. Lipsett	2005		360,000	178,850	107,810		–	14,100	1,627,281	178,500	10,800
Vice-President,								restricted stock units
human resources	2004		340,000	179,000	78,581		–	15,700	1,117,055	166,700	10,200
								restricted stock units
	2003		330,000	166,800	42,229		–	13,400	770,902	227,010	9,900
								restricted stock units

J.F. Kyle	2005		364,166	112,500	90,821		–	11,300	1,304,133	171,375	21,850
Vice-president								restricted stock units
and treasurer	2004		359,583	172,105	74,585		–	13,200	939,180	171,000	21,575
								restricted stock units
	2003		355,000	171,000	41,391		–	11,400	655,842	261,000	21,300
								restricted stock units


(1)		R.L. Broiles has been on a loan assignment from Exxon Mobil Corporation since July 1, 2005. His compensation was paid to him directly by Exxon Mobil Corporation in United States dollars, and is disclosed in United States dollars. Also, he received employee benefits under Exxon Mobil Corporation’s employee benefit plans, and not under the Company’s employee benefit plans. The Company reimburses Exxon Mobil Corporation for the compensation paid and employee benefits provided to him.
(2)		Any part of bonus elected to be received as deferred share units is excluded.
(3)		Amounts under “Other Annual Compensation”, except for R.L. Broiles, consist of interest paid in respect of deferred payments for long-term incentive compensation, other than the Company’s plan for deferred share units for selected executives, described on page 46, dividend equivalent payments on restricted stock units, interest paid in respect of deferred payments of bonuses and any costs associated with the personal use of the Company aircraft. There is no tax assistance from the Company for taxes related to personal use of the Company aircraft. In 2005, the dividend equivalent payments were $146,280 for T.J. Hearn, $40,374 for P.A. Smith, $33,346 for R.F. Lipsett and $29,480 for J.F. Kyle. Also included is an earned benefits allowance. The earned benefits allowance in 2005 was $90,000 for T.J. Hearn, $45,000 for P.A. Smith, $35,000 for R.F. Lipsett and $35,000 for J.F. Kyle. For T.J. Hearn and P.A. Smith, the U.S. dollar amounts were payments by the Company on account of U.S. income taxes incurred while on assignment in the U.S. For R.L. Broiles, the amounts are the net payments by Exxon Mobil Corporation on account of Canadian income taxes and other compensation for assignment outside of the United States. Each year, while on assignment, T.J. Hearn and P.A. Smith paid to the Company and R.L. Broiles paid to Exxon Mobil Corporation, amounts that were approximate to the income taxes that would have been imposed if they were resident in their originating country of employment. For R.L. Broiles the amount also includes dividend equivalent payments on restricted stock units from Exxon Mobil Corporation.
(4)		The Company has not granted stock options since 2002. The stock option plan is described on page 47.
(5)		These values include the number of units granted under the Company’s restricted stock unit plan and deferred share unit plan for selected executives described on pages 47 and 48 and page 46, respectively. The values of the restricted stock units shown are the number of units multiplied by the closing price of the Company’s shares on the date of grant. The closing price on the date of grant of the restricted stock units was $57.53 in 2003, $71.15 in 2004 and $115.41 in 2005. The values of the deferred share units shown are the number of units multiplied by the closing price of the Company’s shares for the five consecutive days before the grant of the deferred share unit. T.J. Hearn is the only senior executive who holds deferred share units. R.L. Broiles participates in Exxon Mobil Corporation’s restricted stock plan, which is similar to the Company’s restricted stock unit plan. Under that plan, R.L. Broiles was granted 11,000 restricted shares in 2005 whose value on the date of grant (November 29, 2005) was $641,740, based on a closing price of Exxon Mobil Corporation shares on the date of grant of $58.34 (U.S.).
(6)		The table below shows the number and value of restricted stock units and deferred share units held as of December 31, 2005. The closing price on December 31, 2005 was $115.41.


	Restricted Stock Units				Deferred Share Units
Name	Total (#)		Total ($)		Total (#)		Total ($)
T.J. Hearn		213,800		24,674,658		101		11,622
P.A. Smith		60,650		6,999,616		0		0
R.L. Broiles		—		—		—		—
R.F. Lipsett		48,650		5,614,696		0		0
J.F. Kyle		41,200		4,754,892		0		0

R.L. Broiles participates in Exxon Mobil Corporation’s restricted stock plan, which is similar to the Company’s restricted stock unit plan. Under that plan, R.L. Broiles holds 37,000 restricted shares whose value on December 31, 2005 was $2,078,290 (U.S.) based on a closing price for Exxon Mobil Corporation shares on December 31, 2005 of $56.17 (U.S.).


(7)		Payouts were from 2004 earnings bonus units that reached maximum value of $3.75 per unit in 2005. That plan is described on page 47. R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan, which is similar to the Company’s earnings bonus unit plan.
(8)		Amounts under “All Other Compensation”, except for R.L. Broiles, are the Company’s contributions to the savings plan, which is a plan available to all employees. Under one of the options of that plan to which the senior executives subscribe, except for R.L. Broiles, the Company matched employee contributions up to six percent of base salary per year; however, an employee may elect to receive an enhanced pension under the Company’s pension plan by foregoing three percent of the Company’s matching contributions. The plan is intended to be primarily for retirement savings, although employees may withdraw their contributions prior to retirement. For R.L. Broiles, the amount is Exxon Mobil Corporation’s contributions to its employee savings plan.

Earnings Bonus Unit Plan — awards in most recently completed financial year

The following table provides information on earnings bonus units granted in 2005 to the named senior executives. The earnings bonus unit plan is described in more detail on page 47.


			Performance
	Securities		or Other		Estimated Future Payouts Under
	Units or		Period Until		Non-Securities-Price Based Plans
	Other Rights		Maturation or		Threshold		Target		Maximum
Name	(#)		Payout (1)		($)		($)(2)		($)(2)
T.J. Hearn		200,000	Nov. 16, 2010			0		4.50		4.50
P.A. Smith		42,900	Nov. 16, 2010			0		4.50		4.50
R.L. Broiles (3)		—		—		—		—		—
R.F. Lipsett		39,700	Nov. 16, 2010			0		4.50		4.50
J.F. Kyle		25,000	Nov. 16, 2010			0		4.50		4.50


(1)		Payment will be made earlier when the cumulative net earnings per outstanding common share reach the maximum settlement value per unit prior to the fifth anniversary of the grant date.
(2)		This is the maximum settlement value payable per earnings bonus unit granted in 2005.
(3)		R.L. Broiles participates in Exxon Mobil Corporation’s earnings bonus unit plan which is similar to the Company’s earnings bonus unit plan. In 2005, R.L. Broiles was granted 37,470 units under that plan for which the maximum settlement value payable per earnings bonus unit is U.S. $3.75.

Aggregated option/SAR exercises during the most recently completed financial year and financial year end option/SAR values

The following table provides information on the exercise in 2005 and the aggregate holdings at the end of 2005 of incentive share units (referred to in the table as “SARs”) by the named senior executives. The incentive share unit plan is described in more detail on page 46.


									Value of
									Unexercised
					Unexercised				in-the-Money
					Options/SARs				Options/SARs
					at Financial				at Financial
	Securities		Aggregate		Year End				Year End
	Acquired		Value		(#)				($)
	on Exercise		Realized				Unexercisable				Unexercisable
Name	(#)		($)		Exercisable		(1)		Exercisable		(1)
T.J. Hearn		—		743,000		40,000		0		3,056,400		0
P.A. Smith		—		1,708,300		45,000		0		3,600,450		0
R.L. Broiles		—		—		—		—		—		—
R.F. Lipsett		—		2,861,235		25,000		0		1,910,250		0
J.F. Kyle		—		6,197,460		0		0		0		0


(1)		Unexercisable units are units for which the conditions for exercise have not been met.

The following table provides information on the exercise in 2005 and the aggregate holdings at the end of 2005 of stock options by named senior executives. The stock option plan is described in more detail on page 47.


									Value of
									Unexercised
					Unexercised				in-the-Money
					Options/SARs				Options/SARs
					at Financial				at Financial
	Securities		Aggregate		Year End				Year End
	Acquired		Value		(#)				($)
	on Exercise		Realized								Unexercisable
Name	(#)		($)		Exercisable		Unexercisable(2)		Exercisable		(2)
T.J. Hearn		1,000		34,030		59,000		0		4,065,690		0
P.A. Smith		0		0		25,000		0		1,722,750		0
R.L. Broiles (1)		—		—		—		—		—		—
R.F. Lipsett		0		0		25,000		0		1,722,750		0
J.F. Kyle		0		0		29,000		0		1,998,390		0


(1)		At the end of 2005, R.L. Broiles held options to acquire 123,074 Exxon Mobil Corporation shares of which all options were exercisable. The value of R.L. Broiles’ exercisable options was U.S. $2,429,836 at the end of 2005. In 2005, R.L. Broiles exercised 4,258 options and realized an aggregate value of U.S. $119,596.
(2)		Unexercisable units are units for which the conditions for exercise have not been met.

Details of long-term and medium-term incentive compensation

Consistent with the Company’s compensation philosophy of being performance driven, long-term incentive compensation is granted to retain selected employees and reward them for high performance.

The assessment of employee performance is conducted through the Company’s appraisal program. The appraisal program is a disciplined annual program that incorporates business performance measures relevant to eligible employees, and involves ranking of employee performance using a consistent process throughout the organization at all levels. The number of units received by each employee is tied to the performance of the employee in achieving these business performance measures. The scope of the Company program is determined by the overall performance of the Company each year.

The Company’s incentive share units give the recipient a right to receive cash equal to the amount by which the market price of the Company’s common shares at the time of exercise exceeds the issue price of the units. These units were granted prior to 2002. The issue price of the units granted to executives was the closing price of the Company’s shares on the Toronto Stock Exchange on the grant date. Incentive share units are eligible for exercise up to 10 years from issuance.

In 1998, an additional form of long-term incentive compensation (“deferred share units”) was made available to selected executives whose decisions are considered to have a direct effect on the long-term financial performance of the Company. They can elect to receive all or part of their cash bonus compensation in the form of such units. The number of units granted to an executive is determined by dividing the amount of the executive’s bonus elected to be received as deferred share units by the average of the closing prices of the Company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the date that the bonus would have been paid to the executive. Additional units will be granted to recipients of these units, in respect of unexercised units, based on the cash dividend payable on the Company shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient. An executive may not exercise these units until after termination of employment with the Company and must exercise the units no later than December 31 of the year following termination of employment with the Company. The units held must all be exercised on the same date. On the date of exercise, the cash value to be received for the units will be determined by multiplying the number of units exercised by the average closing price immediately prior to the date of exercise. In 2005, no executive elected to receive deferred share units.

Starting in 1999, a form of long-term incentive compensation, similar to the deferred share units for executives, was made available to non-employee directors in lieu of their receiving all or part of their directors’ fees. The main differences between the two plans are that all non-employee directors are allowed to participate in the plan for non-employee directors and that the number of units granted to a non-employee director is determined at the end of each calendar quarter by dividing the amount of the directors’ fees for that calendar quarter that the non-employee director elected to receive as deferred share units by the average closing price immediately prior to the last day of the calendar quarter.

Starting in 2001, a medium-term incentive compensation plan was introduced called the earnings bonus unit plan. This plan was made available to selected executives to promote individual contribution to sustained improvement in the Company’s business performance and shareholder value. Each earnings bonus unit entitles the recipient to receive an amount equal to the Company’s cumulative net earnings per common share as announced each quarter beginning after the grant. Payout occurs on the fifth anniversary of the grant or when the maximum settlement value per unit is reached, if earlier. If after five years, the maximum settlement has not been reached, payment will be prorated.

Under the stock option plan, adopted by the Company in April 2002, a total of 3,210,200 options were granted to selected key employees on April 30, 2002 for the purchase of the Company’s common shares at an exercise price of $46.50 per share. All of the options are exercisable. Any unexercised options expire after April 29, 2012.

As of February 15, 2006, there have been 1,153,925 common shares issued upon exercise of stock options and 2,034,825 common shares are issuable upon future exercise of stock options. The common shares that were issued and those that may be issued in the future represent about 0.96 percent of the Company’s currently outstanding common shares.

The Company’s directors, officers and vice-presidents as a group hold 9.5 percent of the unexercised stock options.

The maximum number of common shares that any one person may receive from the exercise of stock options is 60,000 common shares, which is about 0.02 percent of the currently outstanding common shares.

Stock options may be exercised only during employment with the Company except in the event of death, disability or retirement. Also, stock options may be forfeited if the Company believes that the employee intends to terminate employment or if during employment or during the period of 24 months after the termination of employment the employee, without the consent of the Company, engaged in any business that was in competition with the Company or otherwise engaged in any activity that was detrimental to the Company. The Company may determine that stock options will not be forfeited after the cessation of employment. Stock options cannot be assigned except in the case of death.

The Company may amend or terminate the incentive stock option plan as it in its sole discretion determines appropriate. No such amendment or termination can be made to impair any rights of stock option holders under the incentive stock option plan unless the stock option holder consents, except in the event of (a) any adjustments to the share capital of the Company or (b) a take-over bid, amalgamation, combination, merger or other reorganization, sale or lease of assets, or any liquidation, dissolution, or winding-up, involving the Company. Appropriate adjustments may be made by the Company to: (i) the number of common shares that may be acquired on the exercise of outstanding stock options; (ii) the exercise price of outstanding stock options; or (iii) the class of shares that may be acquired in place of common shares on the exercise of outstanding stock options in order to preserve proportionately the rights of the stock option holders and give proper effect to the event.

In December 2002, the Company introduced a restricted stock unit plan, which will be the primary long-term incentive compensation plan in future years. The purpose of the plan is to align the interests of the selected key employees and non-employee directors directly with the interests of shareholders. Each unit entitles the recipient the right to receive from the Company, upon exercise, an amount equal to the closing price of the Company’s shares on the exercise dates. Fifty percent of the units will be exercised on the third anniversary of the grant date, and the remainder will be exercised on the seventh anniversary of the grant date. The Company will pay the recipients cash with respect to each unexercised unit granted to the recipient corresponding in time and amount to the cash dividend that is paid by the Company on a common share of the Company. The restricted stock unit plan was amended for units granted in 2003 and future years by providing that the recipient may receive one common share of the Company per unit or elect to receive the cash payment for the units to be exercised on the seventh anniversary of the grant date. A total of 886,050 units were granted on December 31, 2005.

There are 1,363,510 common shares issuable upon future exercise of restricted stock units, which represent about 0.41 percent of the Company’s currently outstanding common shares. The Company’s directors, officers and vice-presidents have available, as a group, 20 percent of the common shares issuable under outstanding restricted stock units.

The maximum number of common shares that any one person may receive from the exercise of outstanding restricted stock units is 94,400 common shares, which is about 0.03 percent of the currently outstanding common shares.

Restricted stock units will be exercised only during employment except in the event of death, disability or retirement. Also, restricted stock units may be forfeited if the Company believes that the employee intends to terminate employment or if during employment or during the period of 24 months after the termination of employment the employee, without the consent of the Company, engaged in any business that was in competition with the Company or otherwise engaged in any activity that was detrimental to the Company. The Company may determine that restricted stock units will not be forfeited after the cessation of employment. Restricted stock units cannot be assigned.

In the case of any subdivision, consolidation, or reclassification of the shares of the Company or other relevant change in the capitalization of the Company, the Company, in its discretion, may make appropriate adjustments in the number of common shares to be issued and the calculation of the cash amount payable per restricted stock unit.

Effective December 31, 2004, the restricted stock unit plan was amended by the Company to provide that on retirement the Company shall determine whether the employee’s restricted stock units will not be forfeited. Shareholder approval for that change was not required by the Toronto Stock Exchange.

Payments to Employees Who Retire
Pension Plan Table


Remuneration for		Estimated undiscounted payments
determining payments		on retirement at the age of 65 after years of service indicated below ($)
on retirement
($)		20 Years		25 Years		30 Years		35 Years		40 Years
	100,000		32,000		40,000		48,000		56,000		64,000
	200,000		64,000		80,000		96,000		112,000		128,000
	300,000		96,000		120,000		144,000		168,000		192,000
	400,000		128,000		160,000		192,000		224,000		256,000
	500,000		160,000		200,000		240,000		280,000		320,000
	600,000		192,000		240,000		288,000		336,000		384,000
	800,000		256,000		320,000		384,000		448,000		512,000
	1,000,000		320,000		400,000		480,000		560,000		640,000
	1,500,000		480,000		600,000		720,000		840,000		960,000
	2,000,000		640,000		800,000		960,000		1,120,000		1,280,000
	2,500,000		800,000		1,000,000		1,200,000		1,400,000		1,600,000
	3,000,000		960,000		1,200,000		1,440,000		1,680,000		1,920,000

The Company’s pension plan applies to almost all employees. The plan provides an annual pension of a specific percentage of an employee’s “final three year average earnings”, multiplied by the employee’s years of service, subject to certain requirements concerning age and length of service. An employee may elect to forego three of the six percent of the Company’s contributions to the savings plan under one of the options of that plan (except for R.L. Broiles), to receive an enhanced pension equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s years of service while foregoing such Company contributions. In addition to the pension payable under the plan, the Company has paid and may continue to pay a supplemental retirement income to employees who have earned a pension in excess of the maximum pension under the Income Tax Act. The pension plan table on this page shows estimated undiscounted annual payments, consisting of pension and supplemental retirement income, payable on retirement to the senior executives in specified classifications of remuneration and years of service currently applicable to that group.

The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on page 43 corresponds generally to the salary, bonus compensation, and bonus compensation amount elected to be received as deferred share units in that table. The aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 45 is also included in the employee’s “final three year average earnings” for the year of grant of such units.

As of February 15, 2006, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement was 39 for T.J. Hearn, 25 for P.A. Smith, 36 for R.F. Lipsett and 29 for J.F. Kyle.

R.L. Broiles is not a member of the Company’s pension plan, but is a member of Exxon Mobil Corporation’s pension plan. Under that plan, R.L. Broiles has 26 years of service and he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment on retirement to him also corresponds generally to his salary extended on a full year basis and bonus compensation in the summary compensation table on page 43, which total may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

To the knowledge of the management of the Company, the only shareholder who, as of February 15, 2006, owned beneficially, or exercised control or direction over, more than five percent of the outstanding common shares of the Company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 230,613,858 common shares, representing 69.6 percent of the outstanding voting shares of the Company.

Reference is made to the security ownership information under the preceding Items 10 and 11. As of February 15, 2006, Robert F. Lipsett was the owner of 1,470 common shares of the Company and held options to acquire 25,000 common shares of the Company and restricted share units to acquire 21,600 common shares of the Company. As of February 15, 2006, John F. Kyle was the owner of 3,928 common shares of the Company and held options to acquire 29,000 common shares of the Company and restricted share units to acquire 17,950 common shares of the Company.

The directors and the senior executives of the Company consist of 10 persons, who, as a group, own beneficially 53,274 common shares of the Company, being approximately 0.02 percent of the total number of outstanding shares of the Company, and 66,541 shares of Exxon Mobil Corporation. This information not being within the knowledge of the Company has been provided by the directors and the senior executives individually. As a group, the directors and senior executives of the Company held options to acquire 138,000 common shares of the Company and held restricted stock units to acquire 167,650 common shares of the Company, as of February 15, 2006.

Equity Compensation Plan Information as of December 31, 2005

Number of securities

Weighted-average

remaining available for future

Number of securities to

exercise price of

issuance under equity

be issued upon exercise

outstanding options,

compensation plans (excluding

of outstanding options

warrants and rights

securities reflected in

warrants and rights

($)

column (a))

Plan category

(a)

(b)

(c)

Equity compensation plans approved by security holders (1)

2,045,000

46.50

Equity compensation plans not approved by security holders (2)

1,363,510

—

2,136,490

Total

3,408,510

46.50

2,136,490


(1)		This is the stock option plan, which is described on page 47 of this report.
(2)		This is the restricted stock unit plan, which is described on pages 47 and 48 of this report.

Item 13. Certain Relationships and Related Transactions.

On June 23, 2004, the Company implemented another 12-month “normal course” share-purchase program under which it purchased 16,309,490, of its outstanding shares between June 23, 2004, and June 22, 2005. On June 23, 2005, another 12-month “normal course” program was implemented under which the Company may purchase up to 17,080,605 of its outstanding shares, less any shares purchased by the employee savings plan and company pension fund. Exxon Mobil Corporation participated by selling shares to maintain its ownership at 69.6 percent. In 2005, such purchases cost $1,795 million, of which $1,192 million was received by Exxon Mobil Corporation.

During 2003, the Company borrowed $818 million from Exxon Overseas Corporation under two long term loan agreements at interest equivalent to Canadian market rates. Interest on the loans in 2005 was $23 million. The average effective interest rate for the loans was 2.8 percent for 2005.

The amounts of purchases and sales by the Company and its subsidiaries for other transactions in 2005 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,774 million and $1,357 million, respectively. These transactions were conducted on terms as favourable as they would have been with unrelated parties, and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with Exxon Mobil Corporation also included

amounts paid and received in connection with the Company’s participation in a number of natural resources activities conducted jointly in Canada. The Company has agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the Company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems.

During 2005, the Company and an affiliate of Exxon Mobil Corporation in Canada agreed to operate their respective Western Canada production organizations as one single organization. Under the consolidation, the Company will operate all Western Canada properties. There are no asset ownership changes.

Item 14. Principal Accountant Fees and Services.

Audit Fees

The aggregate fees of the Company’s auditors for professional services rendered for the audit of the Company’s financial statements and other services for the fiscal years ended December 31, 2005 and December 31, 2004 were as follows:


Dollars (thousands)	2005		2004

Audit Fees		1,117		1,112
Audit-Related Fees		64		92
Tax Fees		770		545
All Other Fees		Nil		Nil

Total Fees		1,951		1,749

Audit fees include the audit of the Company’s annual financial statements, audit of management’s report on internal control over financial reporting, and a review of the first three quarterly financial statements in 2005.

Audit-related fees include other assurance services including the audit of the Company’s retirement plan, the Imperial Oil Foundation, and royalty statement audits for oil and gas producing entities.

Tax fees are mainly tax services for employees on foreign loan assignments

The Company did not engage the auditors for any other services.

The audit committee recommends the external auditors to be appointed by the shareholders, fixes their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the external auditors, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the external auditors after considering the effect of such services on their independence.

All of the services rendered by the auditors to the Company were approved by the audit committee.

PART IV

Item 15. Exhibits and Financial Statement Schedules.

		Reference is made to the Index to Financial Statements on page F-1 of this report.
		The following exhibits numbered in accordance with Item 601 of Regulation S-K are filed as part of this report:

(3)

(i)

Restated certificate and articles of incorporation of the Company (Incorporated herein by reference to Exhibit (3) to the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 1998 (File No. 0-12014)).

(ii)

By-laws of the Company (Incorporated herein by reference to Exhibit (3)(ii) to the Company’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2003 (File No. 0-12014)).

(4)

The Company’s long term debt authorized under any instrument does not exceed 10 percent of the Company’s consolidated assets. The Company agrees to furnish to the Commission upon request a copy of any such instrument.

(10)(ii)	(1)	Alberta Crown Agreement, dated February 4, 1975, relating to the participation of the Province of Alberta in Syncrude (Incorporated herein by reference to Exhibit 13(a) of the Company’s Registration Statement on Form S-1, as filed with the Securities and Exchange Commission on August 21, 1979 (File No. 2-65290)).
	(2)	Amendment to Alberta Crown Agreement, dated January 1, 1983 (Incorporated herein by reference to Exhibit (10)(ii)(2) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
	(3)	Syncrude Ownership and Management Agreement, dated February 4, 1975 (Incorporated herein by reference to Exhibit 13(b) of the Company’s Registration Statement on Form S-1, as filed with the Securities and Exchange Commission on August 21, 1979 (File No. 2-65290)).
	(4)	Letter Agreement, dated February 8, 1982, between the Government of Canada and Esso Resources Canada Limited, amending Schedule “C” to the Syncrude Ownership and Management Agreement filed as Exhibit (10)(ii)(2) (Incorporated herein by reference to Exhibit (20) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1981 (File No. 2-9259)).
	(5)	Norman Wells Pipeline Agreement, dated January 1, 1980, relating to the operation, tolls and financing of the pipeline system from the Norman Wells field (Incorporated herein by reference to Exhibit 10(a)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1981 (File No. 2-9259)).
	(6)	Norman Wells Pipeline Amending Agreement, dated April 1, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1982 (File No. 2-9259)).
	(7)	Letter Agreement clarifying certain provisions to the Norman Wells Pipeline Agreement, dated August 29, 1983 (Incorporated herein by reference to Exhibit (10)(ii)(7) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
	(8)	Norman Wells Pipeline Amending Agreement, made as of February 1, 1985, relating to certain amendments ordered by the National Energy Board (Incorporated herein by reference to Exhibit (10)(ii)(8) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
	(9)	Norman Wells Pipeline Amending Agreement, made as of April 1, 1985, relating to the definition of “Operating Year” (Incorporated herein by reference to Exhibit (10)(ii)(9) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
	(10)	Norman Wells Expansion Agreement, dated October 6, 1983, relating to the prices and royalties payable for crude oil production at Norman Wells (Incorporated herein by reference to Exhibit (10)(ii)(8) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1983 (File No. 2-9259)).
	(11)	Alberta Cold Lake Crown Agreement, dated June 25, 1984, relating to the royalties payable and the assurances given in respect of the Cold Lake production project (Incorporated herein by reference to Exhibit (10)(ii)(11) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1986 (File No. 0-12014)).
	(12)	Amendment to Alberta Crown Agreement, dated January 1, 1986 (Incorporated herein by reference to Exhibit (10)(ii)(12) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).

	(13)	Amendment to Alberta Crown Agreement, dated November 25, 1987 (Incorporated herein by reference to Exhibit (10)(ii)(13) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1987 (File No. 0-12014)).
	(14)	Amendment to Syncrude Ownership and Management Agreement, dated March 10, 1982 (Incorporated herein by reference to Exhibit (10)(ii)(14) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1989 (File No. 0-12014)).
	(15)	Amendment to Alberta Crown Agreement, dated August 1, 1991 (Incorporated herein by reference to Exhibit (10)(ii)(15) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1991 (File No. 0-12014)).
	(16)	Norman Wells Settlement Agreement, dated July 31, 1996. (Incorporated herein by reference to Exhibit (10)(ii)(16) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)).
	(17)	Amendment to Alberta Crown Agreement, dated January 1, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(17) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014)).
	(18)	Norman Wells Pipeline Amending Agreement, dated December 12, 1997. (Incorporated herein by reference to Exhibit (10)(ii)(18) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
	(19)	Norman Wells Pipeline 1999 Amending Agreement, dated May 1, 1999. (Incorporated herein by reference to Exhibit (10)(ii)(19) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014)).
	(20)	Alberta Cold Lake Transition Agreement, effective January 1, 2000, relating to the royalties payable in respect of the Cold Lake production project and terminating the Alberta Cold Lake Crown Agreement. (Incorporated herein by reference to Exhibit (10)(ii)(20) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001 (File No. 0-12014)).
	(21)	Amendment to Alberta Crown Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(21) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(22)	Amendment to Syncrude Ownership and Management Agreement effective January 1, 2001 (Incorporated herein by reference to Exhibit (10)(ii)(22) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(23)	Amendment to Syncrude Ownership and Management Agreement effective September 16, 1994 (Incorporated herein by reference to Exhibit (10)(ii)(23) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(24)	Amendment to Alberta Crown Agreement dated November 29, 1995 (Incorporated herein by reference to Exhibit (10)(ii)(24) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
(iii)(A)(1)		Form of Letter relating to Supplemental Retirement Income (Incorporated herein by reference to Exhibit (10)(c)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1980 (File No. 2-9259)).
	(2)	Incentive Share Unit Plan and Incentive Share Units granted in 2001 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2001. Units granted in 2000 are incorporated herein by reference to Exhibit (10)(iii)(A)(2) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2000 (File No. 0-12014); units granted in 1999 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1999 (File No. 0-12014); units granted in 1998 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014); units granted in 1997 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1997 (File No. 0-12014); units granted in 1996 are incorporated herein by reference to Exhibit (10)(iii)(A)(3) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1996 (File No. 0-12014).

	(3)		Deferred Share Unit Plan. (Incorporated herein by reference to Exhibit(10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
	(4)		Deferred Share Unit Plan for Nonemployee Directors. (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the Company’s Annual Report on Form 10-K for the year ended December 31, 1998 (File No. 0-12014)).
	(5)		Form of Earnings Bonus Units (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)) and Earnings Bonus Unit Plan (Incorporated herein by reference to Exhibit (10)(iii)(A)(5) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
	(6)		Incentive Stock Option Plan and Incentive Stock Options granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(6) of the Company’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2002 (File No. 0-12014)).
	(7)		Restricted Stock Unit Plan and Restricted Stock Units granted in 2002 (Incorporated herein by reference to Exhibit (10)(iii)(A)(7) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2002 (File No. 0-12014)).
	(8)		Restricted Stock Unit Plan and Restricted Stock Units granted in 2003 (Incorporated herein by reference to Exhibit (10)(iii)(A)(8) of the Company’s Annual Report on Form 10-K for the year ended December 31, 2003 (File No. 0-12014)).
	(9)		Restricted Stock Unit Plan and general form for Restricted Stock Units, as amended effective December 31, 2004 (Incorporated herein by reference to Exhibit 99.1 of the Company’s Form 8-K dated December 31, 2004 (File No. 0-12014)).

(21)

Imperial Oil Resources Limited, McColl-Frontenac Petroleum Inc., Imperial Oil Resources N.W.T. Limited and Imperial Oil Resources Ventures Limited, all incorporated in Canada, are wholly-owned subsidiaries of the Company. The names of all other subsidiaries of the Company are omitted because, considered in the aggregate as a single subsidiary, they would not constitute a significant subsidiary as of December 31, 2004.

(23)(ii)	(A)	Consent of Independent Registered Public Accounting Firm (PricewaterhouseCoopers LLP).
	(B)	Consent of Qualified Reserves Evaluator.
(31.1)		Certification by principal executive officer of Periodic Financial Report pursuant to Rule 13a-14(a)
(31.2)		Certification by principal financial officer of Periodic Financial Report pursuant to Rule 13a-14(a).
(32.1)		Certification by chief executive officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.
(32.2)		Certification by chief financial officer of Periodic Financial Report pursuant to Rule 13a-14(b) and 18 U.S.C. Section 1350.

Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 237 Fourth Avenue S.W., Calgary, Alberta, Canada T2P 3M9, and payment of processing and mailing costs.

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on February 28, 2006 by the undersigned, thereunto duly authorized.


		Imperial Oil Limited

		By		/s/ T.J. Hearn

				(Timothy J. Hearn, Chairman of the Board,
				President and Chief Executive Officer)

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on February 28, 2006 by the following persons on behalf of the registrant and in the capacities indicated.


Signature				Title

/s/ T.J. Hearn				Chairman of the Board, President,
(Timothy J. Hearn)				Chief Executive Officer and Director (Principal Executive Officer)

/s/ Paul A. Smith				Controller and Senior Vice-President,
(Paul A. Smith)				Finance and Administration and Director (Principal Accounting Officer and Principal Financial Officer)

/s/ R.L. Broiles				Director
(Randy L. Broiles)

/s/ J.M. Mintz				Director
(Jack M. Mintz)

/s/ Roger Phillips				Director
(Roger Phillips)

/s/ J.F. Shepard				Director
(James F. Shepard)

/s/ Sheelagh D. Whittaker				Director
(Sheelagh D. Whittaker)

/s/ V.L. Young				Director
(Victor L. Young)

INDEX TO FINANCIAL STATEMENTS


		Pages in this
		Report
Management’s report on internal control over financial reporting		F-2
Report of independent registered public accounting firm		F-2
Financial statements:
Consolidated statement of income for the years 2003, 2004 and 2005		F-3
Consolidated statement of cash flows for the years 2003, 2004 and 2005		F-4
Consolidated balance sheet as at December 31, 2003, 2004 and 2005		F-5
Consolidated statement of shareholders’ equity as at December 31, 2003, 2004 and 2005		F-6
Notes to the consolidated financial statements		F-7 – F-23

F-1

MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING

Management, including the Company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2005. Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2005, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.


/s/ T.J. Hearn		/s/ Paul A. Smith

T.J. Hearn		P.A. Smith
Chairman, president and chief executive officer		Controller and senior vice-president, finance and administration
		(Principal accounting officer and principal financial officer)

REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM

To the Shareholders of Imperial Oil Limited

We have completed an integrated audit of Imperial Oil Limited’s 2005 and 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2005 and an audit of its 2003 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions on Imperial Oil Limited’s 2005, 2004 and 2003 consolidated financial statements and on its internal control over financial reporting at December 31, 2005, based on our audits, are presented below.

Consolidated financial statements

In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders’ equity and cash flows appearing on pages F-3 through F-23 of this Annual Report present fairly, in all material respects, the financial position of Imperial Oil Limited and its subsidiaries at December 31, 2005 and 2004, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2005 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statements presentation. We believe that our audits provide a reasonable basis for our opinion.

Internal control over financial reporting

Also, in our opinion, management’s assessment, included in the accompanying Management’s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2005 based on criteria established in Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2005, based on criteria established in Internal Control – Integrated Framework issued by the COSO. The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (i) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (ii) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the Company are being made only in accordance with authorizations of management and directors of the Company, and (iii) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the Company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.


/s/ PricewaterhouseCoopers LLP

Chartered Accountants Toronto, Ontario, Canada February 27, 2006

F-2

Consolidated statement of income


millions of Canadian dollars
For the years ended December 31	2005		2004		2003

Revenues and other income
Operating revenues (a)(b)		27,797		22,408		19,094
Investment and other income (note 10)		417		52		114

Total revenues and other income		28,214		22,460		19,208


Expenses
Exploration		43		59		55
Purchases of crude oil and products (b)		17,168		13,094		10,823
Production and manufacturing		3,327		2,820		2,726
Selling and general		1,577		1,281		1,325
Federal excise tax (a)		1,278		1,264		1,254
Depreciation and depletion		895		908		755
Financing costs (note 14)		8		7		(120	)

Total expenses		24,296		19,433		16,818


Income before income taxes		3,918		3,027		2,390

Income taxes (note 4)		1,318		975		689

Income before cumulative effect of accounting change		2,600		2,052		1,701
Cumulative effect of accounting change, after income tax		—		—		4


Net income		2,600		2,052		1,705


Per-share information (Canadian dollars)
Net income per common share — basic (note 12)
Income before cumulative effect of accounting change	7.62			5.75		4.57
Cumulative effect of accounting change, after income tax	—			—		0.01

Net income		7.62		5.75		4.58


Net income per common share — diluted (note 12)
Income before cumulative effect of accounting change	7.59			5.74		4.57
Cumulative effect of accounting change, after income tax	—			—		0.01

Net income		7.59		5.74		4.58


Dividends		0.94		0.88		0.87

(a)

Operating revenues include federal excise tax of $1,278 million (2004 — $1,264 million, 2003 — $1,254 million).

(b)

Operating revenues include amounts for purchase / sale contracts with the same counterparty (associated costs are included in “purchases of crude oil and products”) of $4,894 million (2004 — $3,584 million, 2003 — $2,851 million).

The information on pages F-7 through F-23 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.

F-3

Consolidated statement of cash flows


millions of Canadian dollars
Inflow/(outflow)
For the years ended December 31	2005			2004			2003

Operating activities
Net income		2,600			2,052			1,705
Cumulative effect of accounting change, after tax		—			—			(4	)
Adjustments for non-cash items:
Depreciation and depletion		895			908			755
(Gain)/loss on asset sales, after tax		(233	)		(32	)		(10	)
Deferred income taxes and other		(116	)		(90	)		(59	)
Changes in operating assets and liabilities:
Accounts receivable		(414	)		(311	)		33
Inventories and prepaids		(67	)		(32	)		31
Income taxes payable		304			462			38
Accounts payable		644			308			74
All other items — net (a)		(162	)		47			(336	)

Cash from operating activities		3,451			3,312			2,227


Investing activities
Additions to property, plant and equipment and intangibles		(1,432	)		(1,376	)		(1,482	)
Proceeds from asset sales		440			102			56
Loans to equity company		—			(32	)		—

Cash from (used in) investing activities		(992	)		(1,306	)		(1,426	)


Financing activities
Short-term debt — net		18			9			—
Long-term debt issued		—			—			818
Repayment of long-term debt		(21	)		(8	)		(818	)
Issuance of common shares under stock option plan		38			13			2
Common shares purchased (note 12)		(1,795	)		(872	)		(799	)
Dividends paid		(317	)		(317	)		(322	)

Cash from (used in) financing activities		(2,077	)		(1,175	)		(1,119	)


Increase (decrease) in cash		382			831			(318	)
Cash at beginning of year		1,279			448			766

Cash at end of year (b)		1,661			1,279			448

(a)

Includes contribution to registered pension plans of $350 million (2004 — $114 million, 2003 — $511 million).

(b)

Cash is composed of cash in bank and cash equivalents at cost. Cash equivalents are all highly liquid securities with maturity of three months or less when purchased.

F-4

Consolidated balance sheet


millions of Canadian dollars
At December 31	2005			2004

Assets
Current assets
Cash		1,661			1,279
Accounts receivable, less estimated doubtful amounts		2,040			1,626
Inventories of crude oil and products (note 13)		481			432
Materials, supplies and prepaid expenses		130			112
Deferred income tax assets (note 4)		654			448

Total current assets		4,966			3,897
Investments and other long-term assets		127			130
Property, plant and equipment, less accumulated depreciation and depletion (note 2)		10,132			9,647
Goodwill (note 2)		204			204
Other intangible assets, net		153			149

Total assets (note 2)		15,582			14,027


Liabilities
Current liabilities
Short-term debt		99			81
Accounts payable and accrued liabilities (note 15)		3,170			2,525
Income taxes payable		1,399			1,057
Current portion of long-term debt		477			995

Total current liabilities		5,145			4,658
Long-term debt (note 3)		863			367
Other long-term obligations (note 7)		1,728			1,525
Deferred income tax liabilities (note 4)		1,213			1,155
Commitments and contingent liabilities (note 11)

Total liabilities		8,949			7,705


Shareholders’ equity
Common shares at stated value (note 12)		1,747			1,801
Earnings reinvested		5,466			4,889
Accumulated other nonowner changes in equity		(580	)		(368	)

Total shareholders’ equity		6,633			6,322


Total liabilities and shareholders’ equity		15,582			14,027

Approved by the directors


/s/ T.J. Hearn		/s/ Paul A. Smith

T.J. Hearn		P.A. Smith
Chairman, president and		Controller and senior vice-president,
chief executive officer		finance and administration

F-5

Consolidated statement of shareholders’ equity


millions of Canadian dollars
At December 31	2005			2004			2003

Common shares at stated value (note 12)
At beginning of year		1,801			1,859			1,939
Issued under the stock option plan		38			13			2
Share purchases at stated value		(92	)		(71	)		(82	)

At end of year		1,747			1,801			1,859


Earnings reinvested
At beginning of year		4,889			3,952			3,287
Net income for the year		2,600			2,052			1,705
Share purchases in excess of stated value		(1,703	)		(801	)		(717	)
Dividends		(320	)		(314	)		(323	)

At end of year		5,466			4,889			3,952


Accumulated other nonowner changes in equity
At beginning of year		(368	)		(266	)		(315	)
Minimum pension liability adjustment (note 6)		(212	)		(102	)		49

At end of year		(580	)		(368	)		(266	)


Shareholders’ equity at end of year		6,633			6,322			5,545


Nonowner changes in equity for the year
Net income for the year		2,600			2,052			1,705
Other nonowner changes in equity (note 6)		(212	)		(102	)		49

Total nonowner changes in equity for the year		2,388			1,950			1,754

F-6

Notes to consolidated financial statements

Summary of significant accounting policies

The Company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. The Company is also a major manufacturer and marketer of petrochemicals.

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America. The financial statements include certain estimates that reflect management’s best judgement. All amounts are in Canadian dollars unless otherwise indicated.

Principles of consolidation

The consolidated financial statements include the accounts of Imperial Oil Limited and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic, operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the Company’s activities in natural resources is conducted jointly with other companies. The accounts reflect the Company’s share of undivided interest in such activities, including its 25 percent interest in the Syncrude joint venture and its nine percent interest in the Sable offshore energy project.

Segment reporting

The Company operates its business in Canada in the following segments:

Natural resources includes the exploration for and production of crude oil and natural gas.

Petroleum products comprises the refining of crude oil into petroleum products and the distribution and marketing of these products.

Chemicals includes the manufacturing and marketing of various hydrocarbon-based chemicals and chemical products.

The above functions have been defined as the operating segments of the Company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the Company’s chief operating decision maker to make decisions about resources to be allocated to each segment and assess its performance; and (c) for which discrete financial information is available.

Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, long-term debt and liabilities associated with incentive compensation. Net income in this segment primarily includes financing costs, interest income and incentive compensation expenses.

Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals expenses include amounts allocated from the “corporate and other” segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts.

Inventories

Inventories are recorded at the lower of cost or net realizable value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period.

Inventory costs include expenditures and other charges, including depreciation, directly or indirectly incurred in bringing the inventory to its existing condition and final storage prior to delivery to a customer. Selling and general expenses are reported as period costs and excluded from inventory costs.

Investments

The principal investments in companies other than subsidiaries are accounted for using the equity method. They are recorded at the original cost of the investment plus the Company’s share of earnings since the investment was made, less dividends received. Imperial’s share of the after-tax earnings of these companies is included in “investment and other income” in the consolidated statement of income. Other investments are recorded at cost. Dividends from these other investments are included in “investment and other income.”

These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of crude oil and natural gas in the conduct of company operations. Other parties who also have an equity interest in these companies share in the risks and rewards according to their percentage of ownership. The Company does not invest in these companies in order to remove liabilities from its balance sheet.

F-7

Property, plant and equipment

Property, plant and equipment are recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.

The Company uses the successful-efforts method to account for its exploration and development activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. Effective July 1, 2005, the Company adopted Financial Accounting Standards Board Staff Position FAS 19-1 (FSP 19-1), Accounting for Suspended Well Costs. FSP 19-1 amended Statement of Financial Accounting Standards No. 19 (SFAS 19), Financial Accounting and Reporting by Oil and Gas Producing Companies, to permit the continued capitalization of exploratory well costs beyond one year if (a) the well found a sufficient quantity of reserves to justify its completion as a producing well and (b) the entity is making sufficient progress assessing the reserves and the economic and operating viability of the project. There were no capitalized exploratory well costs charged to expense upon adoption of FSP 19-1. Prior to the adoption of FSP 19-1, the Company carried as an asset the cost of drilling exploratory wells that found sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure was made and drilling of additional exploratory wells was underway or firmly planned for the near future. Once exploration activities demonstrated that sufficient quantities of commercially producible reserves had been discovered, continued capitalization was dependent on project reviews, which took place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria were charged to expense. Capitalized exploratory drilling costs pending the determination of proved reserves or the amount of suspended exploratory well costs were $13 million, negligible and $2 million at December 31, 2005, 2004 and 2003, respectively. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The Company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the Company’s exploration and production activities.

Maintenance and repair costs, including planned major maintenance, are expensed as incurred. Improvements that increase or prolong the service life or capacity of an asset are capitalized.

Production costs are expensed as incurred. Production involves lifting the oil and gas to the surface and gathering, treating, field processing and field storage of the oil and gas. The production function normally terminates at the outlet valve on the lease or field production storage tank. Production costs are those incurred to operate and maintain the Company’s wells and related equipment and facilities. They become part of the cost of oil and gas produced. These costs, sometimes referred to as lifting costs, include such items as labour cost to operate the wells and related equipment; repair and maintenance costs on the wells and equipment; materials, supplies and energy costs required to operate the wells and related equipment; and administrative expenses related to the production activity.

Depreciation and depletion for assets associated with producing properties begin at the time when production commences on a regular basis. Depreciation for other assets begins when the asset is in place and ready for its intended use. Assets under construction are not depreciated or depleted. Depreciation and depletion are calculated using the unit-of-production method for producing properties based on proved developed reserves. Depreciation of other plant and equipment is calculated using the straight-line method, based on the estimated service life of the asset. In general, refineries are depreciated over 25 years; other major assets, including chemical plants and service stations, are depreciated over 20 years.

Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or changes in circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets.

The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. Cash flows used in impairment evaluations are developed using annually updated corporate plan investment evaluation assumptions for crude oil commodity prices and foreign-currency exchange rates. Annual volumes are based on individual field production profiles, which are also updated annually. Prices for natural gas and other products sold under contract are based on corporate plan assumptions developed annually by major contracts and also for investment evaluation purposes.

In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk-adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value.

Accounting policies for the Company’s tar sands operation are the same as those described in this summary of significant accounting policies for the Company’s crude oil and natural gas operations. The capitalization policy for the Company’s tar sands operation is that acquisition costs are capitalized when incurred. Exploration costs are expensed as incurred. The capitalization of development costs begins only after a determination of proven reserves has been made. With a consistently low level of inventory, the Company expenses stripping costs during the production phase on an as incurred basis. The Company’s share of inventory at the Company’s tar sands operation was $20 million, $13 million, $14 million at December 31, 2005, 2004 and 2003, respectively. Recognizing stripping costs during the production phase as inventory costs would not have a significant impact on earnings or inventory value.

F-8

Notes to consolidated financial statements (continued)

Amortization for tar sands assets begins at the time when production commences on a regular basis. Assets under construction are not amortized. Amortization of tar sands assets is a combination of unit-of-production and straight-line methods. Investments in the extraction facilities, which separate crude bitumen from sand, as well as the upgrading facilities, are amortized on a unit-of-production method based on proven developed reserves currently within an area of interest. Investments in the mining and transportation systems are amortized on a straight-line basis. In general, these assets are amortized over 15 years.

Gains or losses on assets sold are included in “investment and other income” in the consolidated statement of income.

Interest capitalization

Interest costs relating to major capital projects under construction are capitalized as part of property, plant, and equipment. Capitalization of interest ceases when the related asset is substantially complete and ready for its intended use.

Goodwill and other intangible assets

Goodwill is not subject to amortization. Goodwill is tested for impairment annually or more frequently if events or circumstances indicate it might be impaired. Impairment losses are recognized in current period earnings. The evaluation for impairment of goodwill is based on a comparison of the carrying values of goodwill and associated operating assets with the estimated present value of net cash flows from those operating assets.

Intangible assets with determinable useful lives are amortized over the estimated service lives of the assets. Computer software development costs are amortized over a maximum of 15 years and customer lists are amortized over a maximum of 10 years. The amortization is included in “depreciation and depletion” in the consolidated statement of income.

Asset retirement obligations and other environmental liabilities

Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. These obligations primarily relate to decommissioning and removal costs of oil and gas wells and related facilities. The obligations are initially measured at fair value and discounted to present value. A corresponding amount equal to that of the initial obligation is added to the capitalized costs of the related asset. Over time the discounted asset retirement obligation amount will be accreted for the change in its present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets.

No asset retirement obligations are set up for those manufacturing, distribution and marketing facilities with an indeterminate useful life, because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. These are primarily currently operated sites. Provision for environmental liabilities of these and non-operating assets is made when it is probable that obligations have been incurred and the amount can be reasonably estimated. These liabilities are not discounted. Asset retirement obligations and other provisions for environmental liabilities are determined based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location.

Foreign-currency translation

Monetary assets and liabilities in foreign currencies have been translated at the rates of exchange prevailing on December 31. Any exchange gains or losses are recognized in income.

Financial instruments

The fair values of cash, accounts receivable and current liabilities approximate recorded amounts because of the short period to receipt or payment of cash. The fair value of the Company’s long-term debt is estimated based on quoted market prices for the same or similar issues or on the current rates offered to the Company for debt of the same duration to maturity. The fair values of the Company’s other financial instruments, which are mainly long-term receivables, are estimated primarily by discounting future cash flows, using current rates for similar financial instruments under similar credit risk and maturity conditions.

The Company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The Company does not use derivative instruments to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment.

Revenues

Revenues associated with sales of crude oil, natural gas, petroleum and chemical products and other items are recorded when the products are delivered. Delivery occurs when the customer has taken title and has assumed the risks and rewards of ownership, prices are fixed or determinable and collectibility is reasonably assured. The Company does not enter into ongoing arrangements whereby it is required to repurchase its products, nor does the Company provide the customer with a right of return.

Revenues include amounts billed to customers for shipping and handling. Shipping and handling costs incurred up to the point of final storage prior to delivery to a customer are included in “purchases of crude oil and products” in the consolidated statement of income. Delivery costs from final storage to customer are recorded as a marketing expense in “selling and general” expenses.

F-9

The Company currently records certain crude oil, natural gas, petroleum product and chemical purchases and sales of inventory entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately in individual contracts. The accounting treatment is consistent with long standing industry practice (although the Company understands that some companies in the oil and gas industry may be accounting for these transactions as nonmonetary exchanges). The EITF consensus will result in the Company’s accounts “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income being reduced by associated amounts with no impact on net income. All operating segments will be impacted by this change, but the largest effects are in the petroleum products segment. The EITF consensus will become effective for new arrangements entered into, and modifications or renewals of existing agreements, beginning no later than the second quarter of 2006.

The purchase/sale amounts included in revenue for 2005, 2004 and 2003 are shown below along with total “operating revenues” to provide context.


millions of dollars	2005			2004			2003

Operating revenues		27,797			22,408			19,094
Amounts included in operating revenues for purchase/sale contracts with the same counterparty (a)		4,894			3,584			2,851

Percent of operating revenues		18	%		16	%		15	%


(a)		Associated costs are in “purchases of crude oil and products”

Stock-based compensation

The Company accounts for its stock-based compensation programs, except for the incentive stock options granted in April 2002, by using the fair-value-based method. Under this method, compensation expense related to the units of these programs is measured each reporting period based on the Company’s current share price and is recorded in the consolidated statement of income over the vesting period.

Compensation expense associated with stock-related awards has been recognized in the consolidated statement of income using the “nominal vesting period approach”. The full cost of awards given to employees who have retired before the end of the vesting period has been expensed. The use of a “non-substantive vesting period approach” reflecting amortization based on the retirement eligibility age would not be significantly different from the nominal vesting period approach.

As permitted by the Statement of Accounting Standard (SFAS) No.123, the Company continues to apply the intrinsic-value-based method of accounting for the incentive stock options granted in April 2002. Under this method, compensation expense is not recognized on the issuance of stock options as the exercise price is equal to the market value at the date of grant. All incentive stock options have vested as of January 1, 2005.

If the provisions of SFAS No.123 had been adopted for all prior years, net income and net income per share would have been as below:


millions of dollars	2005			2004			2003

Net income as shown in financial statements		2,600			2,052			1,705
Add: stock-based compensation expense as reported, net of tax		238			95			93
Deduct: stock-based compensation expense, net of tax, determined under fair-value-based method		(238	)		(97	)		(98	)

Pro forma net income		2,600			2,050			1,700


Net income per share (dollars)
As reported — basic	7.62	5.75	4.58
— diluted	7.59	5.74	4.58
Pro forma — basic	7.62	5.75	4.57
— diluted	7.59	5.73	4.57

Consumer taxes

Taxes levied on the consumer and collected by the Company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels and the federal goods and services tax.

F-10

Notes to consolidated financial statements (continued)

2. Business segments


	Natural resources (a)									Petroleum products										Chemicals
millions of dollars	2005			2004			2003			2005			2004			2003		2005			2004			2003

Revenues and other income
External sales (b)		4,702			3,689			3,390			21,793			17,503			14,710		1,302			1,216			994
Intersegment sales (c)		3,487			2,891			2,224			2,224			1,666			1,294		363			293			238
Investment and other income		331			45			34			60			42			54		—			—			—

		8,520			6,625			5,648			24,077			19,211			16,058		1,665			1,509			1,232

Expenses
Exploration		43			59			55			—			—			—		—			—			—
Purchases of crude oil and products		2,837			2,110			1,873			19,212			14,769			11,822		1,191			1,064			882
Production and manufacturing (d)		1,931			1,581			1,551			1,203			1,064			1,029		195			176			148
Selling and general (d)(e)		36			9			11			1,096			1,043			1,070		81			88			113
Federal excise tax		—			—			—			1,278			1,264			1,254		—			—			—
Depreciation and depletion		651			633			517			230			257			211		12			13			22
Financing costs (note 14)		—			1			1			2			2			2		—			—			—

Total expenses		5,498			4,393			4,008			23,021			18,399			15,388		1,479			1,341			1,165

Income before income taxes		3,022			2,232			1,640			1,056			812			670		186			168			67
Income taxes (note 4)
Current		955			771			540			409			314			75		69			61			14
Deferred		59			(56	)		(70	)		(47	)		(58	)		133		(4	)		(2	)		9

Total income tax expense		1,014			715			470			362			256			208		65			59			23

Income before cumulative effect of accounting change		2,008			1,517			1,170			694			556			462		121			109			44
Cumulative effect of accounting change, after income tax		—			—			4			—			—			—		—			—			—

Net income		2,008			1,517			1,174			694			556			462		121			109			44

Cash flow from (used in) operating activities		2,440			2,331			1,720			799			908			659		94			126			36

Capital and exploration expenditures (f)		937			1,113			1,007			478			283			478		19			15			41

Property, plant and equipment
Cost		14,229			13,538			12,610			6,350			6,078			6,069		701			682			609
Accumulated depreciation and depletion		(7,780	)		7,337			6,813			(3,037	)		2,959			2,856		(474	)		459			401

Net property, plant and equipment (g)(h)		6,449			6,201			5,797			3,313			3,119			3,213		227			223			208

Total assets		7,347			6,866			6,417			6,287			5,555			5,287		504			497			440


	Corporate and other									Eliminations									Consolidated
millions of dollars	2005			2004			2003			2005			2004			2003			2005			2004			2003

Revenues and other income
External sales (b)		—			—			—												27,797			22,408			19,094
Intersegment sales (c)		—			—			—			(6,074	)		(4,850	)		(3,756	)		—			—			—
Investment and other income		26			(35	)		26												417			52			114

		26			(35	)		26			(6,074	)		(4,850	)		(3,756	)		28,214			22,460			19,208

Expenses
Exploration		—			—			—												43			59			55
Purchases of crude oil and products		—			—			—			(6,072	)		(4,849	)		(3,754	)		17,168			13,094			10,823
Production and manufacturing (d)		—			—			—			(2	)		(1	)		(2	)		3,327			2,820			2,726
Selling and general (d)(e)		364			141			131												1,577			1,281			1,325
Federal excise tax		—			—			—												1,278			1,264			1,254
Depreciation and depletion		2			5			5												895			908			755
Financing costs (note 14)		6			4			(123	)											8			7			(120	)

Total expenses		372			150			13			(6,074	)		(4,850	)		(3,756	)		24,296			19,433			16,818

Income before income taxes		(346	)		(185	)		13			—			—			—			3,918			3,027			2,390
Income taxes (note 4)
Current		(72	)		(43	)		(19	)											1,361			1,103			610
Deferred		(51	)		(12	)		7												(43	)		(128	)		79

Total income tax expense		(123	)		(55	)		(12	)		—			—			—			1,318			975			689

Income before cumulative effect of accounting change		(223	)		(130	)		25												2,600			2,052			1,701
Cumulative effect of accounting change, after income tax		—			—			—												—			—			4

Net income		(223	)		(130	)		25			—			—			—			2,600			2,052			1,705

Cash flow from (used in) operating activities		118			(53	)		(188	)											3,451			3,312			2,227

Capital and exploration expenditures (f)		41			34			33												1,475			1,445			1,559

Property, plant and equipment
Cost		246			205			145												21,526			20,503			19,433
Accumulated depreciation and depletion		(103	)		101			96												(11,394	)		10,856			10,166

Net property, plant and equipment (g)(h)		143			104			49												10,132			9,647			9,267

Total assets		1,867			1,407			501			(423	)		(298	)		(308	)		15,582			14,027			12,337

F-11


(a)		A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the Company’s share of undivided interest in such activities as follows:


millions of dollars	2005			2004			2003

Total external and intersegment sales		3,687			2,744			2,494
Total expenses		1,805			1,598			1,577
Net income, after income tax		1,249			780			664

Total current assets		305			367			302
Long-term assets		4,742			4,140			3,553
Total current liabilities		1,212			948			913
Other long-term obligations		524			330			302

Cash flow from operating activities		1,424			1,188			883
Cash (used in) investing activities		(403	)		(858	)		(754	)


(b)		Includes export sales to the United States, as follows:


millions of dollars	2005		2004		2003

Natural resources		1,633		1,360		1,304
Petroleum products		856		1,074		792
Chemicals		750		678		567

Total export sales		3,239		3,112		2,663


(c)		Intersegment sales are made essentially at prevailing market rates.
(d)		During 2005, incentive compensation expenses previously included in the operating segments have been reclassified to the corporate and other segment. This change has the effect of isolating in one segment all incentive compensation expenses and improving the transparency of operating events in the operating segments. This change has no impact on consolidated total expenses, net income or the cash-flow profile of the Company. Segmented results for 2004 and 2003 have been reclassified for comparative purposes.
(e)		Consolidated selling and general expenses include delivery costs from final storage areas to customers of $310 million in 2005 (2004 — $307 million, 2003 — $285 million).
(f)		There were no capital lease additions in 2005. Capital and exploration expenditures of the petroleum products segment included non-cash capital leases of $11 million in 2004.
(g)		Includes property, plant and equipment under construction of $954 million (2004 — $1,983 million).
(h)		Goodwill was not amortized in the past three years. All goodwill has been assigned to the petroleum products segment. There have been no goodwill acquisitions, impairment losses or write-offs due to sales in the past three years.

F-12

Notes to consolidated financial statements (continued)

Long-term debt

2005

2004

Issued

Maturity date

Interest rate

Millions of dollars

2003

$250 million due May 26, 2007 and

$250 million due August 26, 2007 (a)

Variable

500

—

2003

January 19, 2008 (a)

Variable

318

318

Long-term debt (b)

818

318

Capital leases (c)

Total long-term debt (d) (e)

863

367


(a)		These are long-term variable-rate loans from Exxon Overseas Corporation, an affiliated company of Exxon Mobil Corporation at interest equivalent to Canadian market rates. These loans were extended during 2005 for an additional two-year period to the maturity dates noted above.
(b)		The average effective rate for the loans was 2.8 percent for 2005 (2004 — 2.5 percent).
(c)		These obligations primarily relate to the capital lease for marine services, which are provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The average imputed rate was 10.5 percent in 2005 (2004-10.3 percent).
(d)		Principal payments on long-term loans of $500 million are due in 2007 and $318 million are due in 2008. Principal payments on capital leases of approximately $4 million a year are due in each of the next five years.
(e)		These amounts exclude that portion of long-term debt, totalling $477 million (2004 — $995 million), which matures within one year and is included in current liabilities.

Income taxes


millions of dollars	2005			2004			2003

Current income tax expense		1,361			1,103			610
Deferred income tax expense (a)		(43	)		(128	)		79

Total income tax expense (b)		1,318			975			689

Statutory corporate tax rate (percent)		35.6			37.0			38.5
Increase/(decrease) resulting from:
Non-deductible royalty payments to governments		3.8			3.9			5.0
Resource allowance in lieu of royalty deduction		(5.2	)		(7.0	)		(7.5	)
Manufacturing and processing credit		—			—			0.2
Enacted tax rate change		—			(1.8	)		(3.1	)
Other		(0.6	)		0.1			(4.3	)

Effective income tax rate		33.6			32.2			28.8


(a)		The deferred income tax expense for the year is the difference in net deferred income tax liabilities at the beginning and end of the year. The provisions for deferred income taxes in 2005 did not have any net (charges)/credits for the effect of changes in tax laws and rates (2004 — $25 million; 2003 — $72 million).
(b)		Cash outflow from income taxes, plus investment credits earned, was $1,024 million in 2005 (2004 — $641 million; 2003 — $573 million).

Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are remeasured at each year-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were:


millions of dollars	2005			2004

Depreciation and amortization		1,470			1,287
Successful drilling and land acquisitions		319			403
Pension and benefits (a)		(354	)		(343	)
Site restoration		(171	)		(158	)
Net tax loss carryforwards (b)		(49	)		(57	)
Capitalized interest		26			26
Other		(28	)		(3	)

Deferred income tax liabilities		1,213			1,155


LIFO inventory valuation		(487	)		(343	)
Other		(167	)		(105	)

Deferred income tax assets		(654	)		(448	)
Valuation allowance		—			—

Net deferred income tax liabilities		559			707


(a)		Income taxes charged directly to shareholders’ equity related to minimum pension liability adjustment were $105 million benefit in 2005 (2004 — $41 million benefit; 2003 — $57 million expense).
(b)		Tax losses can be carried forward indefinitely.

The operations of the Company are complex, and related tax interpretations, regulations and legislation are continually changing. As a result, there are usually some tax matters in question. The Company believes the provision made for income taxes is adequate.

F-13

5.		Headquarters relocation
		The relocation of the Company’s head office from Toronto, Ontario to Calgary, Alberta announced in September 2004 was completed as planned in August 2005.

		Expenses in connection with the headquarters relocation activity are expected to total approximately $77 million ($52 million, after tax), about 85 percent of which has been recognized in 2005 in conjunction with employee relocations and compensation payments for employees who chose not to move. All such expenses are included in selling and general on the consolidated statement of income. The change in liabilities associated with headquarters relocation is as follows:


millions of dollars	2005			2004

Beginning as of January 1		—			—
Additions		65			—
Settlement		(48	)		—

Ending as of December 31		17			—

		All operating segments are impacted by this activity, but the largest effects are in the petroleum products segment.

6.		Employee retirement benefits
		Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health-care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the Company makes contributions to the plans based upon an independent actuarial valuation.

		Pension-income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The Company shares in the cost of health-care and life-insurance benefits. The Company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels as well as a projection of salaries and service to retirement.

		The expense and obligations for both funded and unfunded benefits are determined in accordance with United States generally accepted accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases.

		The total obligation for retirement benefits exceeded the fair value of plan assets at December 31, 2005 by $1,823 million (2004 — $1,712 million), of which $1,365 million (2004 — $1,276 million) was related to pension benefits and $458 million (2004 — $436 million) was related to other post-retirement benefits. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets.

		Details of the employee retirement benefits plans are as follows:


			Pension benefits									Other post-retirement benefits
millions of dollars	2005			2004			2003			2005			2004			2003

Components of net benefit cost
Current service cost		86			76			71			7			6			5
Interest cost		239			237			219			24			24			22
Expected return on plan assets		(257	)		(223	)		(179	)		—			—			—
Amortization of prior service cost		25			27			25			—			—			—
Recognized actuarial loss/(gain)		83			68			69			7			4			3

Net benefit cost (a)		176			185			205			38			34			30


Change in benefit obligation
Benefit obligation at January 1		4,260			3,761						436			382
Current service cost		86			76						7			6
Interest cost		239			237						24			24
Amendments		20			37						—			—
Actuarial loss/(gain)		549			405						26			47
Other (b)		(88	)		—						(13	)		—
Benefits paid		(282	)		(256	)					(22	)		(23	)

Benefit obligation at December 31		4,784			4,260						458			436


Accumulated benefit obligation at December 31		4,261			3,743

F-14

Notes to consolidated financial statements (continued)


		Pension benefits								Other post-retirement benefits
millions of dollars	2005			2004			2003		2005			2004			2003

Change in plan assets
Fair value of plan assets at January 1		2,984			2,786
Actual return on plan assets		370			315
Company contributions		350			114
Payments directly to participants		56			25
Other (b)		(59	)		—
Benefits paid		(282	)		(256	)

Fair value of plan assets at December 31		3,419			2,984


Excess/(deficiency) of plan assets over benefit obligations		(1,365	)		(1,276	)				(458	)		(436	)
Unrecognized net actuarial loss/(gain) (c)		1,397			1,073					101			95
Unrecognized prior service cost (c)		94			99					—			—

Net amount recognized		126			(104	)				(357	)		(341	)


Amount recognized in the consolidated balance sheet consists of:
Accrued benefit cost (note 7)		(842	)		(759	)				(357	)		(341	)
Intangible assets		93			97					—			—
Accumulated other nonowner changes in equity, minimum pension liability adjustment		875			558					—			—

Net amount recognized		126			(104	)				(357	)		(341	)


Assumptions
Assumptions used to determine benefit obligations at December 31 (percent)

Discount rate (d)		5.00			5.75					5.00			5.75
Long-term rate of compensation increase		3.50			3.50					3.50			3.50


Assumptions used to determine net benefit cost for years ended December 31 (percent)

Discount rate		5.75			6.25			6.25		5.75			6.25			6.25
Long-term rate of compensation increase		3.50			3.50			3.50		3.50			3.50			3.50
Long-term rate of return on funded assets		8.25			8.25			8.25		—			—			—


(a)		A summary of net benefit cost with elements of employee future benefit costs before and after adjustments to recognize the long-term nature of employee benefit cost is shown in the table below:


		Pension benefits									Other post-retirement benefits
millions of dollars	2005			2004			2003			2005			2004			2003

Components of net benefit cost
Current service cost		86			76			71			7			6			5
Interest cost		239			237			219			24			24			22
Actual return on plan assets		(370	)		(315	)		(377	)		—			—			—
Plan amendments for prior service		20			37			—			—			—			—
Actuarial loss/(gain)		549			405			171			26			47			19

Elements of employee future benefit costs before adjustments to recognize the long-term nature of employee future benefit costs		524			440			84			57			77			46


Adjustments to recognize the long-term nature of employee future benefit costs:

Difference between expected return and actual return on plan assets for the year		113			92			198			—			—			—

Difference between amortization or prior service costs for the year and actual plan amendments for the year		5			(10	)		25			—			—			—

Difference between actuarial (gain)/loss recognized for the year and actuarial (gain)/loss on accrued benefit obligation for the year		(466	)		(337	)		(102	)		(19	)		(43	)		(16	)

Net benefit cost		176			185			205			38			34			30


(b)		These assets and liabilities relate to employees who provide computer and customer support services to the Company. These employees were transferred to an affiliate of Exxon Mobil Corporation on January 1, 2005.
(c)		Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2006 and subsequent years is 12.3 years (2005 — 12.6 years; 2004 — 13 years).
(d)		The discount rate is determined using the yield for high quality, long-term Canadian corporate bonds at year end with an average maturity (or duration) approximating that of the liabilities of the pension plan.

F-15

		Plan assets
		The Company’s pension plan asset allocation at December 31, 2004 and 2005, and target allocation for 2006 are as follows:


	Target		Percentage of plan assets at
	allocation		December 31
Asset category (percent)	2006		2005		2004

Equities		50 — 75		62		62
Fixed income		25 — 50		38		38
Other		0 — 10		—		—

Total				100		100

The Company establishes the long-term expected rate of return by developing a forward-looking long-term return assumption for each asset class, taking into account factors such as the expected real return for the specific asset class and inflation. A single, long-term rate of return is then calculated as the weighted average of the target asset allocation and the long-term return assumption for each asset class. The 2005 long-term expected return of 8.25 percent used in the calculations of pension expense compares to an actual rate of return over the past decade of 10 percent.

The Company’s investment strategy for benefit plan assets reflects a long-term view, a careful assessment of the risks inherent in various asset classes and broad diversification to reduce the risk of the total portfolio. The Company primarily invests in funds that follow an index-based strategy to achieve its objectives of diversifying risk while minimizing costs. The fund holds Imperial Oil Limited common shares primarily only to the extent necessary to replicate the relevant equity index. Asset-liability studies, or simulations of the interaction of cash flows associated with both assets and liabilities, are periodically used to establish the preferred target asset allocation. The target asset allocation for equity securities reflects the long-term nature of the liability. The balance of the fund is targeted to debt securities.

Cash flows

Benefit payments expected in:


			Other post-retirement
millions of dollars	Pension benefits		benefits

2006		238		23
2007		242		25
2008		246		26
2009		253		28
2010		260		29
Years 2011 — 2015		1,449		169

In 2006, the Company expects to make cash contributions of about $395 million to its pension plan.

A summary of the change in other nonowner changes in equity related to the minimum pension liability adjustment is shown in the table below:


		Pension benefits
millions of dollars	2005			2004			2003

Increase/(decrease) in accumulated other nonowner changes in equity, before tax		(317	)		(143	)		106
Deferred income tax (charge)/credit (note 4)		105			41			(57	)

Increase/(decrease) in accumulated other nonowner changes in equity, after tax		(212	)		(102	)		49

A summary of pension plans with accumulated benefit obligations in excess of plan assets is shown in the table below:


		Pension benefits
millions of dollars	2005		2004

For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligation		4,403		3,876
Accumulated benefit obligation		3,908		3,430
Fair value of plan assets		3,419		2,984
Accumulated benefit obligation less fair value of plan assets		489		446

For unfunded plans covered by book reserves:
Projected benefit obligation		381		384
Accumulated benefit obligation		353		313

F-16

Notes to consolidated financial statements (continued)

Additional expenses include contributions to the defined contribution plans, primarily the employee savings plan of $30 million in 2005 (2004 — $32 million; 2003 — $31 million).

The most recent independent actuarial valuation was as at December 31, 2004 and the next required valuation will be as of December 31, 2005. The measurement date used to determine the plan assets and the benefit obligations was December 31, 2005.

A one percent change in the assumptions at which retirement liabilities could be effectively settled is as follows:


Increase/(decrease)	One percent			One percent
millions of dollars	increase			decrease

Rate of return on plan assets:
Effect on net benefit costs		(35	)		35

Discount rate:
Effect on net benefit costs		(50	)		60
Effect on benefit obligations		(605	)		750

Rate of pay increases:
Effect on net benefit costs		30			(35	)
Effect on benefit obligations		180			(165	)

For measurement purposes, a five percent health-care cost trend rate was assumed for 2005 and thereafter. A one percent change in the assumed health-care cost trend rate would have the following effects:


Increase/(decrease)	One percent		One percent
millions of dollars	increase		decrease

Effect on service and interest cost components		4		(3	)
Effect on other post-retirement benefits obligations		45		(40	)

F-17

Other long-term obligations


millions of dollars	2005		2004

Employee retirement benefits (note 6)(a)		1,152		1,052
Asset retirement obligations and other environmental liabilities (b)		423		380
Other obligations		153		93

Total other long-term obligations		1,728		1,525


(a)		Total recorded employee retirement benefits obligations also include $47 million in current liabilities (2004 — $48 million).
(b)		Total asset retirement obligations and other environmental liabilities also include $76 million in current liabilities (2004 — $76 million). The estimated cash flows of asset retirement obligations have been discounted at six percent. The total undiscounted amount of the estimated cash flow required to settle the obligation is $1,717 million. Payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years. The change in asset retirement obligations liability is as follows:


millions of dollars	2005			2004

Asset retirement obligations liability at January 1		328			327
Additions		53			16
Accretion		20			22
Settlement		(34	)		(37	)

Asset retirement obligations liability at December 31		367			328

8.		Derivatives and financial instruments
		No significant energy derivatives, foreign-exchange forward contracts or currency and interest-rate swaps were transacted in the past three years. The Company maintains a system of controls that includes a policy covering the authorization, reporting and monitoring of derivative activity.

		The fair value of the Company’s financial instruments is determined by reference to various market data and other appropriate valuation techniques. There are no material differences between the fair values of the Company’s financial instruments from the recorded book value.

9.		Stock-based incentive compensation programs
		Stock-based incentive compensation programs are designed to retain selected employees, reward them for high performance and promote individual contribution to sustained improvement in the Company’s future business performance and shareholder value.

		Incentive share units, deferred share units and restricted stock units
		Incentive share units have value if the market price of the Company’s common shares when the unit is exercised exceeds the market value when the unit was issued. The issue price of incentive share units is the closing price of the Company’s shares on the Toronto Stock Exchange on the grant date. Up to 50 percent of the units may be exercised after one year from issuance; an additional 25 percent may be exercised after two years; and the remaining 25 percent may be exercised after three years. Incentive share units are eligible for exercise up to 10 years from issuance. The units may expire earlier if employment is terminated other than by retirement, death or disability.

		The deferred share unit plan is made available to selected executives and nonemployee directors. The selected executives can elect to receive all or part of their performance bonus compensation in units and the nonemployee directors can elect to receive all or part of their directors’ fees in units. The number of units granted to executives is determined by dividing the amount of the bonus elected to be received as deferred share units by the average of the closing prices of the Company’s shares on the Toronto Stock Exchange for the five consecutive trading days immediately prior to the date that the bonus would have been paid. The number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of director’s fees for the calendar quarter that the nonemployee director elected to receive as deferred share units by the average closing price of the Company’s shares for the five consecutive trading days immediately prior to the last day of the calendar quarter. Additional units are granted based on the cash dividend payable on the Company’s shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient.

F-18

		Notes to consolidated financial statements (continued)

		Deferred share units cannot be exercised until after termination of employment with the Company or resignation as a director and must be exercised no later than December 31 of the year following termination or resignation. On the exercise date, the cash value to be received for the units is determined based on the average closing price of the Company’s shares for the five consecutive trading days immediately prior to the date of exercise.

		Under the restricted stock unit plan, each unit entitles the recipient to the conditional right to receive from the Company, upon exercise, an amount equal to the closing price of the Company’s common shares on the Toronto Stock Exchange on the exercise dates. Fifty percent of the units are exercised three years following the grant date, and the remainder are exercised seven years following the grant date.

		All units require settlement by cash payments with one exception. The restricted stock unit plan was amended for units granted in 2003 and future years by providing that the recipient may receive one common share of the Company per unit or elect to receive the cash payment for the units to be exercised on the seventh anniversary of the grant date.

		Incentive stock options
		In April 2002, incentive stock options were granted for the purchase of the Company’s common shares at an exercise price of $46.50 per share. Up to 50 percent of the options may be exercised on or after January 1, 2003, a further 25 percent may be exercised on or after January 1, 2004, and the remaining 25 percent may be exercised on or after January 1, 2005. Any unexercised options expire after April 29, 2012. The Company has not issued incentive stock options since 2002 and has no plans to issue incentive stock options in the future.

		The Company did not recognize compensation expense on the issuance of stock options because the exercise price was equal to the market value at the date of grant. If the fair-value-based method of accounting had been adopted, the impact on net income and earnings per share is shown in note 1 to the consolidated financial statements on page F-7. The average fair value of each option granted during 2002 was $12.70. The fair value was estimated at the grant date using an option-pricing model with the following weighted average assumptions: risk-free interest rate of 5.7 percent, expected life of five years, volatility of 25 percent and a dividend yield of 1.9 percent.

		The Company has purchased shares on the market to fully offset the dilutive effects from the exercise of stock options. The practice is expected to continue.

		A summary of the incentive compensation programs is as follows:


													Obligations
	Number of units										Expensed in		outstanding at
						Cancelled or			Outstanding at		period		December 31
	Granted		Exercised			adjusted			December 31		(millions of dollars)		(millions of dollars)

Incentive share units
2005		—		(1,987,454	)		(250	)		3,278,719		230		299
2004		—		(1,620,332	)		(2,575	)		5,266,423		94		245
2003		—		(1,142,145	)		19,225			6,889,330		109		216
Deferred share units
2005		2,604		(5,225	)		—			46,189		1		3
2004		4,899		—			—			48,810		1		4
2003		8,253		(49,486	)		(379	)		43,911		1		3
Incentive stock options
2005		—		(813,450	)		3,950			2,045,000		—		-
2004		—		(274,250	)		(7,400	)		2,854,500		—		—
2003		—		(49,050	)		(11,500	)		3,136,150		—		—
Restricted stock units
2005		886,050		—			(9,465	)		3,518,910		119		158
2004		987,480		—			(5,710	)		2,642,325		31		41
2003		872,085		(3,300	)		(120	)		1,660,555		11		11

F-19

10.		Investment and other income
		Investment and other income includes gains and losses on asset sales as follows:


millions of dollars	2005		2004		2003

Proceeds from asset sales		440		102		56
Book value of assets sold		96		59		44

Gain/(loss) on asset sales, before tax (a)		344		43		12

Gain/(loss) on asset sales, after tax (a)		233		32		10


(a)		2005 included a gain of $251 million ($163 million, after tax) from the sale of the wholly owned Redwater and interests in the North Pembina fields.

11. Commitments and contingent liabilities

At December 31, 2005, the Company had commitments for noncancellable operating leases and other long-term agreements that require the following minimum future payments:


											After
millions of dollars	2006		2007		2008		2009		2010		2010

Operating leases (a)		48		46		44		41		37		57
Unconditional purchase obligations (b)		94		41		42		42		20		20
Firm capital commitments (c)		196		15		6		10		5		—
Other long-term agreements (d)		403		398		241		227		156		356


(a)		Total rental expense incurred for operating leases in 2005 was $83 million (2004 — $104 million; 2003 — $124 million) which included minimum rental expenditures of $63 million (2004 — $77 million; 2003 — $93 million). Related rental income was not material.
(b)		Unconditional purchase obligations are those long-term commitments that are noncancellable or cancellable only under certain conditions. These mainly pertain to pipeline throughput agreements. Total payments under unconditional purchase obligations were $104 million in 2005 (2004 — $117 million; 2003 — $114 million).
(c)		Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $232 million at the end of 2005 (2004 — $171 million). The largest commitment outstanding at year-end 2005 was associated with the Company’s share of upstream capital projects of $72 million offshore Canada’s East Coast.
(d)		Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $448 million in 2005 (2004 — $355 million; 2003 — $332 million). Payments under other long-term agreements related to the Company’s share of undivided interest in activities conducted jointly with other companies are approximately $95 million per year.

Other commitments arising in the normal course of business for operating and capital needs do not materially affect the Company’s consolidated financial position.

The Company provides in its financial statements for asset retirement obligations and other environmental liabilities (see note 7 to the consolidated financial statements on page F-18). Provision is not made with respect to those manufacturing, distribution and marketing facilities with indeterminate useful lives, because such potential obligations cannot be measured since it is not possible to estimate the settlement dates. These are primarily currently operated sites. These costs are not expected to have a material effect on the Company’s current consolidated financial position.

Various lawsuits are pending against the Company and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the Company does not believe the ultimate outcome of any currently pending lawsuits against the Company will have a material adverse effect upon the Company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.

F-20

Notes to consolidated financial statements (continued)

12.		Common shares
		The number of authorized common shares of the Company as at December 31, 2005 was 450,000,000, unchanged from January 1, 2004.

		On February 2, 2006, the Company proposed to subdivide the common shares of the Company on a three-for-one basis. The proposed stock split is subject to shareholder and regulatory approvals.

		From 1995 to 2004, the Company purchased shares under ten 12-month normal course share purchase programs, as well as an auction tender. On June 23, 2005, another 12-month normal course share purchase program was implemented with an allowable purchase of 17.1 million shares (five percent of the total at June 21, 2005), less any shares purchased by the employee savings plan and company pension fund. The results of these activities are shown below.


	Purchased		Millions of
Year	shares		dollars

1995 to 2003		218,920,739		5,968
2004		13,606,712		872
2005		17,508,935		1,795

Cumulative purchases to date		250,036,386		8,635

		Exxon Mobil Corporation’s participation in the above maintained its ownership interest in Imperial at 69.6 percent.

		The Company’s common share activities are summarized below:


	Thousands of shares			Millions of dollars

Balance as at January 1, 2003		378,863			1,939
Issued for cash under the stock option plan		49			2
Purchases		(16,259	)		(82	)

Balance as at December 31, 2003		362,653			1,859
Issued for cash under the stock option plan		274			13
Purchases		(13,607	)		(71	)

Balance as at December 31, 2004		349,320			1,801
Issued for cash under the stock option plan		814			38
Purchases		(17,509	)		(92	)

Balance as at December 31, 2005		332,625			1,747

The following table provides the calculation of basic and diluted earnings per share:


	2005		2004		2003

Net income per common share — basic

Income before cumulative effect of accounting change (millions of dollars)		2,600		2,052		1,701
Net income (millions of dollars)		2,600		2,052		1,705

Weighted average number of common shares outstanding (thousands of shares)		341,373		356,834		372,011

Net income per common share (dollars)
Income before cumulative effect of accounting change		7.62		5.75		4.57
Cumulative effect of accounting change, after income tax		—		—		0.01

Net income		7.62		5.75		4.58


Net income per common share — diluted

Income before cumulative effect of accounting change (millions of dollars)		2,600		2,052		1,701
Net income (millions of dollars)		2,600		2,052		1,705

Weighted average number of common shares outstanding (thousands of shares)		341,373		356,834		372,011
Effect of employee stock-based awards (thousands of shares)		1,393		818		143

Weighted average number of common shares outstanding, assuming dilution (thousands of shares)		342,766		357,652		372,154

Net income per common share (dollars)
Income before cumulative effect of accounting change		7.59		5.74		4.57
Cumulative effect of accounting change		—		—		0.01

Net income		7.59		5.74		4.58

F-21

13.		Miscellaneous financial information
		In 2005, net earnings included an after-tax gain of $5 million (2004 — $23 million gain; 2003 - $9 million gain) attributable to the effect of changes in last-in, first-out (LIFO) inventories. The replacement cost of inventories was estimated to exceed their LIFO carrying values at December 31, 2005, by $1,429 million (2004 — $1,013 million). Inventories of crude oil and products at year-end consisted of the following:


million of dollars	2005		2004

Crude oil		174		165
Petroleum products		234		190
Chemical products		63		59
Natural gas and other		10		18

Total inventories of crude oil and products		481		432

		Research and development costs in 2005 were $68 million (2004 — $70 million; 2003 — $63 million) before investment tax credits earned on these expenditures of $10 million (2004 — $7 million; 2003 — $10 million). The net costs are included in expenses due to the uncertainty of future benefits.

		Cash flow from operating activities included dividends of $21 million received from equity investments in 2005 (2004 — $18 million; 2003 — $15 million).

14.		Financing costs


millions of dollars	2005			2004			2003

Debt-related interest		45			37			38
Capitalized interest		(41	)		(34	)		(33	)

Net interest expense		4			3			5
Other interest		4			4			4

Total interest expense (a)		8			7			9
Foreign-exchange expense/(gain) on long-term debt		—			—			(129	)

Total financing costs		8			7			(120	)


(a)		Cash interest payments in 2005 were $45 million (2004 — $41 million; 2003 — $38 million). The weighted-average interest rate on short-term borrowings in 2005 was 2.7 percent (2004 — 2.3 percent).

15.		Transactions with related parties
		Revenues and expenses of the Company also include the results of transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil) in the normal course of operations. These were conducted on terms as favourable as they would have been with unrelated parties and primarily consisted of the purchase and sale of crude oil and petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with ExxonMobil also included amounts paid and received in connection with the Company’s participation in a number of natural resources activities conducted jointly in Canada. The Company has existing agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the Company and to share common business and operational support services that allow the companies to consolidate duplicate work and systems. During 2005, the Company and an affiliate of Exxon Mobil Corporation in Canada agreed to operate their respective Western Canada production organizations as one single organization. Under the consolidation, the Company will operate all Western Canada properties. There are no asset ownership changes. The amounts paid or received have been reflected in the consolidated statement of income as shown below.

millions of dollars

2005

2004

2003

Total revenues and other income

1,357

1,176

950

Purchases of crude oil and products

3,599

3,133

2,464

Total expenses

175

		Accounts payable due to Exxon Mobil Corporation at December 31, 2005, with respect to the above transactions, were $224 million (2004 — $67 million).

		Certain charges from ExxonMobil have been capitalized; they are not material in the aggregate.

		The Company borrowed $818 million (Cdn) from Exxon Overseas Corporation under two long-term loan agreements as presented in note 3. Interest on the loans in 2005 was $23 million (2004 — $20 million).

		During 2004, the Company extended loans of $32 million to Montreal Pipe Line Limited, in which the Company has an equity interest, for financing of the equity Company’s capital expenditure programs and working capital requirements.

F-22

Notes to consolidated financial statements (continued)

16.

Net payments/payables to governments


millions of dollars	2005			2004			2003

Current income tax expense (note 4)		1,361			1,103			610
Federal excise tax		1,278			1,264			1,254
Property taxes included in expenses		99			85			80
Payroll and other taxes included in expenses		52			50			52
GST/QST/HST collected (a)		2,703			2,297			2,015
GST/QST/HST input tax credits (a)		(2,344	)		(1,948	)		(1,705	)
Other consumer taxes collected for governments		1,613			1,670			1,662
Crown royalties		620			472			418

Total paid or payable to governments		5,382			4,993			4,386
Less investment tax credits and other receipts		9			14			30

Net paid or payable to governments		5,373			4,979			4,356

Net paid or payable to:
Federal government		2,736			2,472			2,061
Provincial governments		2,538			2,422			2,215
Local governments		99			85			80

Net paid or payable to governments		5,373			4,979			4,356


(a)		The abbreviations refer to the federal goods and services tax, the Quebec sales tax and the federal/provincial harmonized sales tax, respectively.

		The HST is applicable in the provinces of Nova Scotia, New Brunswick and Newfoundland and Labrador.

F-23