IMPERIAL OIL LTD - 10-K Annual Report

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

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

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.

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.

The registrant is an accelerated filer (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).

As of the last business day of the 2003 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $5,327,412,752 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 27, 2004, was 361,316,496.

All dollar amounts set forth in this report are in Canadian dollars, except where otherwise indicated. 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 cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York.

On February 27, 2004, the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.7460 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.

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 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3; 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 Canada’s largest integrated oil company. 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.

	(1)		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.

	(2)		Includes primarily interest charges on the debt obligations of the Company, interest income on investments and intersegment consolidating adjustments.

	(3)		The identifiable assets in each operating segment represent the net book value of the tangible and intangible assets attributed to such segment.

The Company’s average daily production of crude oil and natural gas liquids during the five years ended December 31, 2003, was as follows:

From 1999, conventional production has declined due to the sale of oil and gas producing properties and the natural decline in the productivity of the Company’s conventional oil fields. In 2000, Cold Lake production declined due to the timing of steaming cycles and Syncrude production decreased because of operating difficulties and extended maintenance to heavy crude oil upgrading equipment. In 2001, Cold Lake net production increased mainly due to the timing of steaming cycles and lower royalties and Syncrude production increased mainly due to the start up of the Aurora mine during the second half of 2000 and fewer disruptions in upgrading operations than the previous year. 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.

The Company’s average daily production and sales of natural gas during the five years ended December 31, 2003 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.

In 2000 and 2001, natural gas production increased primarily due to gas production from the Sable Offshore Energy Project, which went into production at the end of 1999, and increased production from gas caps overlaying two former oil fields, both in Alberta. In 2002 and 2003, natural gas production decreased primarily due to the depletion of gas caps in Alberta and in 2003 also due to increased maintenance activity at gas processing facilities.

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, 2003, were as follows:

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. Prices for Canadian natural gas increased significantly in 2000 and again in early 2001 and 2003, in line with tighter North American market conditions. Canadian natural gas prices decreased in 2002 primarily due to a weaker U.S. economy and warmer weather.

In 2000, average production (lifting) costs increased mainly due to higher costs for purchased natural gas at Cold Lake. In 2001, average production (lifting) costs decreased mainly due to higher net production at Cold Lake. 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.

The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 28 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 11 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, 2003, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

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 60 percent of the Company’s net production of conventional crude oil (approximately 65 percent of gross production).

Norman Wells is the Company’s largest producing conventional oil field. In 2003, net production of crude oil and natural gas liquids was about 2,500 cubic metres (15,900 barrels) per day and gross production was about 3,700 cubic metres (23,200 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 2003, those costs were about $35 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.

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 $4 billion has been spent by the participants to the end of 2003 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 13 million cubic metres (450 million cubic feet) per day of natural gas and 2,900 cubic metres (18,000 barrels) per day of natural gas liquids through the end of the decade.

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. During 2003, net production from the pilots averaged about 1,700 cubic metres (10,800 barrels) per day and gross production was about 1,900 cubic metres (12,000 barrels) per day. 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. The initial six stages of this production project were completed by 1986. In 1987, the Company received approval from the Alberta Energy Resources Conservation Board (“AERCB”) to increase the production of the existing six stages from 9,000 cubic metres (57,000 barrels) to 12,000 cubic metres (76,000 barrels) of crude bitumen per day. Also in 1987, the Company received an amended approval from the AERCB for four additional stages (stages seven to ten) of development at Cold Lake. During 2003, average net production from those ten stages was about 13,000 cubic metres (81,800 barrels) per day and gross production was about 14,500 cubic metres (91,000 barrels) per day.

To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2003, the Company spent $93 million on a development drilling program of 118 wells on existing stages. In 2004, a significant development drilling program of more than 300 wells is planned within the currently approved development area to enhance productivity from existing Cold Lake stages. In addition, opportunities are also being evaluated to improve utilization of the existing infrastructure.

Construction began in 2000 on stages 11 to 13 of development. Total capital investment for the development was about $650 million with the project being completed in late 2002. The new stages are expected to provide, on average, an additional 4,800 cubic metres (30,000 barrels) per day of crude bitumen production. To improve overall energy efficiency, the project includes a 170 megawatt cogeneration facility that will provide steam for the new stages and generate enough electricity to supply all of the Company’s other Cold Lake operations. Any surplus electricity is sold into the Province of Alberta power pool.

In 2002, the Company applied for regulatory approval for further expansion of its operations at Cold Lake. The expansion would include three more production stages (stages 14 to 16), which is expected to add about 4,800 cubic metres (30,000 barrels) per day, and the extension of existing stages 9 and 10. Assuming timely regulatory approval and favourable market conditions, production is expected to begin as early as 2007, from extended stages 9 and 10 and from stages 14 to 16 by the end of the decade. The total cost of the new developments is expected to be about $1 billion. The expansion, along with stages 11 to 13, is expected to bring total production to about 28,600 cubic metres (180,000 barrels) per day by the end of the decade.

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, as defined in an agreement with the Province. Near the beginning of 1996, the royalty increased from five percent of production to the greater of five percent of production or 30 percent of an amount based on revenue net of operating and capital costs for the project. The effective royalty on gross production was ten percent in 2003, five percent in 2002 and 2001, 14 percent in 2000 and 18 percent in 1999. 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 is expected to be royalty neutral. 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.

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 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.

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. The pipeline is currently being expanded to accommodate increased Syncrude production. Since startup in 1978, Syncrude has produced about 1.5 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. There were no known previous commercial operations on these leases prior to the start-up of operations in 1978.

The Syncrude participants agreed with the Province of Alberta, in its capacity as lessor of Syncrude tar sands leases, on an amendment to their revenue sharing agreement, which amendment applies from January 1, 1997. Among other things, this amendment provided for lower royalties on certain new production and for immediate royalty credit on capital expenditures. The royalty was reduced to 25 percent of deemed net profits from Syncrude, as defined in the agreement, on production in excess of 1996 levels for the period 1997 through 2001. 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), a truck, shovel and hydrotransport system is 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 2003, the upgrading process yielded 0.860 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.860 barrels of synthetic crude oil per barrel of crude bitumen). In 2003, about 55 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 45 percent was pipelined to refineries in eastern Canada and the mid-western 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 $2.2 billion.

In 2003, Syncrude’s net production of synthetic crude oil was about 33,300 cubic metres (209,400 barrels) per day and gross production was about 33,600 cubic metres (211,500 barrels) per day. The Company’s share of net production in 2003 was about 8,300 cubic metres (52,300 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 km 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. This project is expected to lead to a total production capacity of about 55,600 cubic metres (350,000 barrels) of synthetic crude oil a day with expected completion in mid-2006. The Company’s share of project costs is expected to be about $2 billion.

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

The Company holds a 100 percent interest in approximately 16,500 hectares (40,700 acres) of surface mineable tar sands in the Kearl area in the Athabasca area of northern Alberta. The Company is assessing a potential project with another company to jointly develop mineable bitumen. A 200 well delineation drilling program was begun in 2003 to better define the available resource. A phased project is being assessed which may have the potential to produce up to a total of 31,800 cubic metres (200,000 barrels) per day.

At December 31, 2003 and 2002, the Company held the following oil and gas rights, and tar sands leases:

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, 2003.

The 118 oil sands development wells in 2003 were related to productivity maintenance in existing stages at Cold Lake.

At December 31, 2003, the Company was participating in the drilling of 144 gross (90 net) exploratory and development wells.

Western Provinces

In 2003, the Company had a working interest in eight gross (three net) exploratory wells and 361 gross (214 net) development wells, while retaining an overriding royalty in an additional nine 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. The four companies are participating in development planning for onshore natural gas resources totalling approximately 170 billion cubic metres (six trillion cubic feet). The Company’s share of these resources is about 50 percent. 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 between the four companies, the APG and TransCanada PipeLines Limited were reached for the proposed Mackenzie Valley pipeline. In late 2003, the application for Commercial Discovery Declaration for the Taglu field was filed with the National Energy Board. This filing was the next regulatory step towards bringing natural gas from the Taglu field into production. Filing of the main regulatory applications for the project, the next major step in the process, is expected to take place in 2004.

In 2003, the Company relinquished its 86 percent interest in a petroleum and natural gas lease with the Inuvialuit Land Corporation. 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 four production licences, managed by others.

The Company has a nine percent working interest in an exploration licence for about 74,000 gross hectares (183,000 gross acres) in the Sable Island area off the coast of the Province of Nova Scotia. An exploratory well was completed in 2001 in this area, without commercial success.

In 1998, the Company acquired a 20 percent interest in an exploration licence for about 23,500 gross hectares (58,100 gross acres) in the Sable Island area. In 1999, the Company acquired a 20 percent interest in six exploration licences for about 217,000 gross hectares (536,000 gross acres) in the Sable Island area. One exploratory well was completed in 2000 in that area, without commercial success. Also in 1999, the Company acquired a 100 percent interest in two exploration licences for about 225,000 gross hectares (556,000 gross acres) farther offshore in deeper water. A 3-D seismic evaluation program was begun in 2000 in that area, which was completed in 2001, and in 2002 there were 3-D seismic and geological evaluations. In 2002, the Company signed a farmout agreement with another company whereby that company will earn a 30 percent interest in these licences by participating in the first exploration well. In 2003, one exploratory well was drilled on these licences, without commercial success. In early 2001, the Company acquired about a 17 percent interest in three additional deep water exploration licences for about 475,000 gross hectares (1,174,000 gross acres). The Company’s share of proposed exploration spending in these areas is about $125 million.

In early 2004, the Company and two other companies 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). The Company’s share of proposed exploration spending is about $170 million with a minimum commitment of about $40 million.

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 30-day contracts. There are no domestic purchases of crude oil under contracts longer than 60 days.

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 2003, capital expenditures of about $336 million were made at the Company’s refineries. About 75 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor gasoline with the remaining expenditures being on safety and efficiency improvements, and environmental control projects.

The approximate average daily volumes of refinery throughput during the five years ended December 31, 2003, and the daily rated capacities of the refineries at December 31, 1998 and 2003, were as follows:


	Average Daily Volumes of										Daily Rated
	Refinery Throughput (1)										Capacities at
	Year Ended December 31										December 31 (2)
	2003		2002		2001		2000		1999		2003		1998
	(thousands of cubic metres)
Strathcona, Alberta		27.6		26.0		25.4		27.0		26.2		29.8		28.0
Sarnia, Ontario		14.7		16.5		16.5		16.2		17.0		19.2		18.9
Dartmouth, Nova Scotia		13.0		12.5		12.3		11.2		11.9		13.1		13.1
Nanticoke, Ontario		16.3		16.2		17.2		17.2		15.0		17.8		17.8

Total		71.6		71.2		71.4		71.6		70.1		79.9		77.8


	Average Daily Volumes of										Daily Rated
	Refinery Throughput (1)										Capacities at
	Year Ended December 31										December 31 (2)
	2003		2002		2001		2000		1999		2003		1998
	(thousands of barrels)
Strathcona, Alberta		174		163		160		170		165		187		176
Sarnia, Ontario		92		104		104		102		107		121		119
Dartmouth, Nova Scotia		82		78		77		70		75		82		82
Nanticoke, Ontario		102		102		108		108		94		112		112

Total		450		447		449		450		441		502		489

(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 90 percent of capacity in 2003, the same as for the previous year.

Distribution

The Company maintains a nation-wide distribution system, including 29 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, 2003, the Company owned and operated two barges. These vessels are 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 2,100 Esso retail outlets, of which about 820 are Company owned or leased, but none of which are Company operated. The Company continues to improve its Esso retail outlet 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, of which about 40 also sell fertilizers to the western Canadian farm markets. A major program to improve the productivity of the Company’s rural agency marketing network was largely completed in 2002. The three year $50 million project transformed the rural network from more than 300 bulk fuel locations to less than 100 sites supplied by a more efficient transportation system. The final component of the new network, a centralized order management process to better meet customer needs was completed in 2003.

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.

The approximate daily volumes of petroleum products sold during the five years ended December 31, 2003 are set out in the following table:


	2003		2002		2001		2000		1999
	(thousands per day)
Gasolines:
Cubic metres		33.0		32.9		32.3		32.0		31.9
Barrels		208		207		203		201		201
Heating, Diesel and Jet Fuels:
Cubic metres		26.2		25.0		26.5		27.5		26.9
Barrels		165		157		166		173		169
Heavy Fuel Oils:
Cubic metres		5.4		4.9		5.4		5.1		4.6
Barrels		34		31		34		32		29
Lube Oils and Other Products (1):
Cubic metres		5.8		6.4		5.4		5.0		5.8
Barrels		36		41		34		31		36
Net petroleum product sales:
Cubic metres		70.4		69.2		69.6		69.6		69.2
Barrels		443		436		437		437		435
Sales under purchase and sale agreements:
Cubic metres		14.6		13.9		11.6		10.7		10.8
Barrels		92		87		73		67		68
Total:
Cubic metres		85.0		83.1		81.2		80.3		80.0
Barrels		535		523		510		504		503

(1) Includes 1.0 thousand cubic metres (6 thousand barrels) per day of butane commencing in 2002. Butane is not included in prior years.

The total domestic sales of petroleum products as a percentage of total sales of petroleum products during the five years ended December 31, 2003, were as follows:


2003			2002			2001			2000			1999
	93.3	%		91.5	%		93.4	%		94.0	%		95.6	%

The Company continues to evaluate and adjust its Esso retail outlet and distribution system to increase productivity and efficiency.

During 2003, the Company closed or debranded about 130 Esso retail sites, about 70 of which were Company owned, and added about 80 sites. The Company’s average annual throughput per Esso retail outlet was 3.4 million litres, an increase of 0.1 million litres from 2002. Average throughput per Company owned Esso retail outlet was 5.2 million litres in 2003, an increase of about 0.3 million litres from 2002.

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, 2003, were as follows:


	2003		2002		2001		2000		1999
	(thousands per day)
Petrochemicals:
Tonnes		3.3		3.5		3.3		3.1		3.0
Tons		3.6		3.9		3.6		3.4		3.3

Research

In 2003, the Company’s research expenditures in Canada, before deduction of investment tax credits, were $36 million, as compared with $50 million in 2002 and $37 million in 2001. 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 2003. 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. About 130 people were employed in this type of research at the end of 2003. 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 spent about $775 million on environmental protection and facilities. In 2003, the Company’s capital expenditures relating to environmental protection totalled approximately $290 million, and are expected to be about $195 million in 2004. Increased environmental expenditures over the past two years primarily reflect spending on a project to reduce sulphur in motor gasolines, a requirement of the Government of Canada. The total cost of that project is expected to be about $600 million. In 2002, the Government of Canada adopted a new regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006 and which is to be fully implemented in 2007. Capital expenditures on safety related projects in 2003 were approximately $20 million.

Human Resources

At December 31, 2003, the Company employed full-time approximately 6,300 persons compared with about 6,500 at the end of 2002 and 6,700 at the end of 2001. About seven percent of those 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 and refined products pipelines 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 are 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 2. Properties.

Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations, 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% and 5% 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


	2003								2002
	three months ended								three months ended
	Mar. 31		June 30		Sept. 30		Dec. 31		Mar. 31		June 30		Sept. 30		Dec. 31
Per-share information (dollars)
Dividends (declared quarterly)		0.21		0.22		0.22		0.22		0.21		0.21		0.21		0.21
Share prices (dollars)
Toronto Stock Exchange
High		47.80		47.40		53.49		58.22		47.85		49.38		47.10		46.10
Low		43.48		43.20		45.62		50.16		41.13		43.76		38.51		41.55
Close		47.35		47.10		50.80		57.53		47.45		47.29		45.90		44.86
American Stock Exchange ($U.S.)
High		32.20		34.99		38.79		44.75		30.33		31.85		31.09		29.31
Low		28.25		29.94		33.04		37.24		25.83		28.15		24.00		26.61
Close		32.14		34.92		37.21		44.42		29.84		31.19		29.00		28.70

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 27, 2004, there were 15,422 holders of record of common shares of the Company.

Issuer purchases of equity securities (1)


					(c) Total number of shares		(d) Maximum number (or appropriate
	(a) Total number				purchased as part		dollar value) or shares that
	of shares		(b) Average price		of publicly announced		may yet be purchased under
Period	purchased		paid per share		plans or programs		the plans or programs
October 2003 (October 1 - October 31)		1,088,546	$	51.94		1,088,546		12,971,885
November 2003 (November 1 -November 30)		2,343,788	$	52.08		2,343,788		10,628,097
December 2003 (December 1 - December 31)		1,864,647	$	54.49		1,864,647		8,763,450

(1) The purchases were pursuant to a 12 month normal course share purchase program that was renewed on June 23, 2003 under which the Company may purchase up to 18,632,218 of its outstanding common share less any shares purchased by the employee savings plan and Company pension fund. If not previously terminated, the program will terminate on June 22, 2004.

Item 6. Selected Financial Data.


	2003		2002		2001		2000		1999
	(millions)
Total revenues	$	19,208	$	17,042	$	17,253	$	18,051	$	12,853
Net earnings		1,682		1,224		1,255		1,410		628
Total assets		12,361		11,894		10,781		11,244		10,828
Long term debt		859		1,466		1,029		1,037		1,352
Other long term obligations		972		1,207		1,098		1,104		1,172


	(dollars)
Net earnings/share – basic		4.52	3.23	3.19	3.38	1.46
Net earnings/share – diluted		4.52	3.23	3.19	3.38	1.46
Cash dividends/share		0.87	0.84	0.83	0.78	0.75

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.

Reconciliation of Canadian and United States generally accepted accounting principles

The financial statements of the Company have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. These principles conform in all material respects to those in the United States except for the following:


	2003		2002			2001			2000			1999
						(millions)
Net earnings as shown in financial statements (a)	$	1,682	$	1,224		$	1,255		$	1,410		$	628
Impact of U.S. accounting principles:
Capitalized interest (1)		19		4			(3	)		(3	)		(3	)
Enacted tax rate difference (2)		—		—			(13	)		13			—
Restatement to reflect accounting changes (3)		—		(14	)		(16	)		(12	)		(7	)

Net earnings under U.S. GAAP before cumulative effect of accounting change	$	1,701	$	1,214		$	1,223		$	1,408		$	618
Cumulative effect of accounting change		4		—			—			—			—

Net earnings under U.S. GAAP (a)	$	1,705	$	1,214		$	1,223		$	1,408		$	618
Other comprehensive income (expense), net of tax (7):
Minimum pension liability adjustment (net of tax expense of $57 million in 2003; 2002 – $155 million benefit; 2001 – $34 million benefit;		49		(238	)		(52	)		(16	)		22

Comprehensive income under U.S. GAAP	$	1,754	$	976		$	1,171		$	1,392		$	640


(a) Net earnings/share	(dollars)
Under accounting principles of:
Canada – basic		4.52	3.23	3.19	3.38	1.46
– diluted		4.52	3.23	3.19	3.38	1.46
United States – basic		4.58	3.20	3.11	3.37	1.43
– diluted		4.58	3.20	3.11	3.37	1.43

Notes (1) through (9) found on pages 18 to 20 apply to the above and following tables.

The adjustments under United States GAAP result in changes to the consolidated balance sheet of the Company as follows:


	As at						As at
	December 31, 2003						December 31, 2002
	(millions)						(millions)
	As			U.S.			As			U.S.
	Reported			GAAP			Reported			GAAP
Current assets (6)	$	2,275		$	2,275		$	2,657		$	2,657
Future income tax assets (5)		353			502			323			530
Investments and other long term assets (4) (6)		259			97			134			134
Property, plant and equipment – cost (1)		19,288			19,433			18,078			18,130
Property, plant and equipment – accumulated depreciation and depletion (1)		(10,070	)		(10,166	)		(9,553	)		(9,610	)
Goodwill		204			204			204			204
Other intangible assets – cost (4)		87			176			81			195
– accumulated depreciation and depletion		(35	)		(35	)		(30	)		(30	)

	$	12,361		$	12,486		$	11,894		$	12,210

		(continued on the following page)


	As at						As at
	December 31, 2003						December 31, 2002
	(millions)						(millions)
	As			U.S.			As			U.S.
	Reported			GAAP			Reported			GAAP
Current liabilities (6)	$	2,889		$	2,889		$	2,743		$	2,743
Current portion of long term debt		501			501			—			—
Long term debt (6)		859			859			1,466			1,466
Other long term obligations (4)		972			1,314			1,207			1,823
Future income tax liabilities (5)		1,362			1,378			1,262			1,267
Shareholders’ equity		5,778			5,545			5,216			4,911

Total liabilities, deferred income taxes and shareholders’ equity	$	12,361		$	12,486		$	11,894		$	12,210

Shareholders’ Equity:
Common shares at stated value
At beginning of year	$	1,939		$	1,939		$	1,941		$	1,941
Share purchases at stated value (net)		(80	)		(80	)		(2	)		(2	)

At end of year	$	1,859		$	1,859		$	1,939		$	1,939

Retained earnings
At beginning of year	$	3,277		$	3,287		$	2,382		$	2,402
Net earnings for the year		1,682			1,705			1,224			1,214
Share purchases in excess of stated value		(717	)		(717	)		(11	)		(11	)
Dividends		(323	)		(323	)		(318	)		(318	)

At end of year	$	3,919		$	3,952		$	3,277		$	3,287

Accumulated other comprehensive income/(loss)
At beginning of year		—			(315	)		—			(77	)
Other comprehensive income for the period		—			49			—			(238	)

At end		—			(266	)		—			(315	)

Total shareholders’ equity	$	5,778		$	5,545		$	5,216		$	4,911

(1)		Interest expense related to major construction projects is not required to be capitalized in Canada, as it is in the United States. Total debt related interest expense in 2003 was $38 million of which $34 million was capitalized under U.S. GAAP. The Company’s financing costs including debt related expense are reported in note 12 to the financial statements on page F-17. At December 31, 2003, the unamortized balance of capitalized interest under U.S. GAAP was $49 million (2002 – $21 million). This was offset in future (deferred) income taxes and shareholders’ equity.

(2)		Under Canadian GAAP enacted income tax rates are recognized by the introduction of the enacting legislation in the Canadian federal parliament or provincial legislatures. Under U.S. GAAP income tax rates are “enacted” when proclaimed into law. There was no enacted tax rate difference for 2003.

(3)		When a change in accounting policy is applied retroactively, Canadian GAAP require the restatement of all prior periods presented to give effect to the new accounting policy for comparative purposes. Under U.S. GAAP, the cumulative effect, based on a retroactive computation, is recognized in net earnings for the period of the change.

		Net earnings as shown in the financial statements have been restated to reflect the adoption of the new standard of accounting for asset retirement obligations (ARO). The adjustment is to remove the restatement effect on earnings for all prior periods presented. Under Canadian GAAP, the following balance sheet accounts (as reported) have also been restated: property, plant and equipment, other long term obligations, future income tax liabilities and retained earnings.

(4)		Disclosures required under revised Statement of Financial Accounting Standards (SFAS) No. 132 “Employers Disclosures about Pensions and Other Postretirement Benefits” that are not in note 5 to the financial statements on pages F-12 and F-13 are as follows:


	Pension Benefits
	2003			2002
	(millions)
Liability recognized under Canadian GAAP	$	(219	)	$	(388	)
Prepaid benefit cost recognized under Canadian GAAP		162			—
Intangible asset		(89	)		(114	)
Accumulated other comprehensive income (before tax)		(415	)		(521	)

Net liability recognized under U.S. GAAP	$	(561	)	$	(1,023	)

Under Canadian GAAP, a prepaid benefit cost was recognized as funding exceeded the book liability for the registered pension plan. Under U.S. GAAP, a minimum pension liability adjustment was required resulting in book liability exceeding funding and no prepaid benefit cost existed. As a result, a reclassification of the prepaid benefit cost from investments and other long term assets to other long term obligation was required under U.S. GAAP.

An adjustment required by SFAS No. 130 remains a Canadian–U.S. GAAP difference (see note 7).

(Continued on following page)

The accumulated benefit obligation for all the defined pension plans was $3,347 million and $3,127 million at December 31, 2003 and 2002 respectively.

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


	Pension Benefits
	2003		2002
	(millions)
For funded pension plans with accumulated benefit obligations in excess of plan assets:
Projected benefit obligations	$	3,464	$	3,230
Accumulated benefit obligation		3,126		2,895
Fair value of plan assets		2,786		2,104
Accumulated benefit obligation less fair value of plan assets		340		791
For unfunded plans covered by book reserves:
Projected benefit obligation		297		300
Accumulated benefit obligation		221		232

In 2004, the Company expects to make cash contributions of about $110 million to the pension plans.

(5) Differences from the adjustments described in notes (1) and (7) result in future (deferred) income tax liabilities (net of future income tax assets) that are $133 million lower at December 31, 2003 than reported under Canadian GAAP (2002 – $202 million lower).

(6) SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” and SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” requires a summary table of the fair value and related carrying amounts of financial instruments. The estimated fair values of the Company’s financial instruments are as follows:


	2003						2002
	Carrying			Fair			Carrying			Fair
	Amount			Value			Amount			Value
	(millions)
Assets
Cash	$	448		$	448		$	766		$	766
Accounts receivable		1,315			1,315			1,348			1,348
Other long term assets (receivable)		20			18			60			59
Liabilities:
Current		(2,889	)		(2.889	)		(2,743	)		(2,743	)
Current portion of long term debt		(501	)		(501	)		–			–
Long term debt		(859	)		(859	)		(1,466	)		(1,466	)

The fair values of cash, marketable securities, promissory notes, 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 other financial instruments held by the Company are estimated primarily by discounting future cash flows using current rates for similar financial instruments under similar credit risk and maturity conditions.

No significant energy derivatives, foreign exchange forward contracts or currency and interest rate swaps were transacted by the Company in the past three years.

Letters of credit and guarantees that are outstanding have not been included in the above table because the fair value of these commitments, determined either by the fees charged to enter into similar agreements or the expected amount required to settle these instruments, is not material.

(7) SFAS No. 130, “Reporting Comprehensive Income”, adopted for U.S. GAAP reporting, requires that changes in the balances of items in equity from non-shareholder sources be reported in a financial statement as other comprehensive income (loss). The item of comprehensive income (loss) that applies to the Company is the equity adjustment for minimum pension liability as required by SFAS No. 87. The $49 million gain recognized in 2003 (2002 – $238 million loss; 2001 – $52 million loss) represents a reduction of the additional pension liability under U.S. GAAP in the current period.

(8) SFAS No. 148 “Accounting for Stock-Based Compensation Transition and Disclosure” provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock based employee compensation. In addition, the disclosure requirements under SFAS No. 148 require more prominent disclosures in the financial statements about the method of accounting for stock based employee compensation and the effect of the method used on reported results.

(Continued on following page)

Effective January 1, 2003, the Company adopted for all stock-based compensation granted after that date the fair value based recognition provisions as prescribed by SFAS No. 123 “Accounting for Stock Based Compensation”. The following information on stock based compensation meets the new disclosure requirements under SFAS No. 148.

Stock based compensation

The Company accounts for its stock based compensation programs, except for the stock option plan, under the fair value based recognition provisions of SFAS No. 123. Under the fair value based method, compensation expense related to the units of these programs is recorded in the consolidated statement of earnings over the vesting period. The Company accounts for its stock option plan by using the intrinsic value method as permitted by SFAS No. 123, and does not recognize compensation expense on the issuance of stock options as long as the exercise price is equal to the market value at date of grant. The Company’s incentive compensation programs are described in note 8 to the financial statements on page F-15.

If the provisions of SFAS No. 123 had been adopted for all prior years, the impact on compensation expense, net earnings and earnings per share would have been as follows:


	2003			2002			2001
	(millions)
Net earnings as shown in financial statements	$	1,682		$	1,224		$	1,255
Stock-based compensation expense as reported, net of tax		78			24			30
Stock-based compensation expense, net of tax, determined under fair value based method		(83	)		(40	)		(30	)

Pro forma net earnings	$	1,677		$	1,208		$	1,255

Net earnings/share:				(dollars)
As reported – basic and diluted		4.52			3.23			3.19
Pro forma – basic and diluted		4.51			3.19			3.19

(9) In December 2003, the Financial Accounting Standards Board issued a revised interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities”, replacing the original interpretation issued in January 2003. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities should be disclosed by enterprises that do not control them through majority voting interest. Under FIN 46, entities are required to be consolidated by enterprises that lack majority voting interest when equity investors of those entities have insignificant capital at risk or they lack voting rights, the obligation to absorb expected losses, or the right to receive expected returns. Entities identified with these characteristics are called variable interest entities and the interests that enterprises have in these entities are called variable interests. These interests can derive from certain guarantees, leases, loans, or other arrangements that result in risks and rewards that are disproportionate to the voting interests in the entities.

The provisions of FIN 46 must be immediately applied for variable interest entities created after January 31, 2003 and for variable interests in entities commonly referred to as “special purpose entities”. For all other variable interest entities, implementation is required by March 31, 2004.

This interpretation does not have an impact on the Company as the Company does not have a variable interest in any variable interest entities created before or after January 31, 2003.

Frequently used financial terms

Listed below are definitions of three of the Company’s frequently used financial performance measures. The definitions are provided to facilitate understanding of the terms and how they are calculated. These terms do not have any standardized meaning prescribed by Canadian generally accepted accounting principles (GAAP) and may not be calculated in the same way as similar measures are by other companies.

Capital employed

Capital employed is a measure of net investment. When viewed from the perspective of how capital is used by the business, it includes the Company’s property, plant and equipment and other assets, less liabilities, excluding both short term and long term debt. When viewed from the perspective of the sources of capital employed for the total company, it includes total debt and shareholders’ equity. Both of these views include the Company’s share of amounts applicable to equity companies.


	2003			2002			2001
	(millions)
Business uses: asset and liability perspective Total assets	$	12,361		$	11,894		$	10,781
Less: total current liabilities excluding short-term debt and current portion of long-term debt		(2,817	)		(2,671	)		(2,565	)
Less: total long-term liabilities excluding long-term debt		(2,334	)		(2,469	)		(2,404	)
Add: Imperial’s share of debt-financed equity company net assets		52			49			29

Total capital employed	$	7,262		$	6,803		$	5,841

(Continued on following page)


	2003		2002		2001
	(millions)
Total company sources: debt and equity perspective
Short-term debt	$	72	$	72	$	460
Current portion of long-term debt		501		—		—
Long-term debt		859		1,466		1,029
Shareholders’ equity		5,778		5,216		4,323
Add: Imperial’s share of equity company debt		52		49		29

Total capital employed	$	7,262	$	6,803	$	5,841

Operating costs

Operating costs are the combined total of operating, selling, general, exploration, depreciation and depletion expenses from the consolidated statement of earnings and the Company’s share of similar costs for equity companies. Operating costs are the costs incurred during the period to produce, manufacture and otherwise prepare the Company’s products for sale – including staffing, maintenance, and other costs to explore for and produce oil and gas and operate refining and chemical plants. Delivery costs to customers and marketing expenses are also included. Operating costs exclude the cost of raw materials and those costs incurred in bringing inventory to its existing condition and final storage prior to delivery to a customer. These expenses are on a before tax basis. While the Company’s management is responsible for all revenue and expense elements of net earnings, particular focus is placed on managing the controllable aspects of this group of expenses.


	2003		2002		2001
	(millions)
Expenses (from page F-3)
Exploration	$	55	$	30	$	45
Operating		2,025		1,865		1,830
Selling and general		1,269		1,222		1,280
Depreciation and depletion		750		705		718

Subtotal	$	4,099	$	3,822	$	3,873
Imperial’s share of equity company expenses		56		49		42

Total operating costs	$	4,155	$	3,871	$	3,915

Cash flow from earnings

Cash flow from earnings is determined by adjusting net earnings for the effects of non cash items. It measures the extent of cash generated from the business before the effects of changes in non cash working capital and before any investing and financing activities by the Company. Cash flow from earnings is a measure used by the Company’s management for analysis and evaluation of operating performance and liquidity of each business segment and for future investment decisions. A reconciliation of net earnings to cash flow from earnings is provided in the consolidated statement of cash flows on page F-4.

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

Financial Summary


	2003		2002			2001			2000			1999
	(millions)
Revenues	$	19,208	$	17,042		$	17,253		$	18,051		$	12,853
Net earnings by segment
Natural resources		1,139		1,056			957			1,177			567
Petroleum products		407		127			353			313			15
Chemicals		37		52			23			59			43
Corporate and other		99		(11	)		(78	)		(139	)		3

Net earnings	$	1,682	$	1,224		$	1,255		$	1,410		$	628

Total assets	$	12,361	$	11,894		$	10,781		$	11,244		$	10,828
Long term debt		859		1,466			1,029			1,037			1,352
Other long term obligations		972		1,207			1,098			1,104			1,172
Per share information (dollars)
Earnings per share – basic and diluted		4.52		3.23			3.19			3.38			1.46
Dividends		0.87		0.84			0.83			0.78			0.75

Results of operations

Net earnings in 2003 were $1,682 million or $4.52 a share – the best year on record – compared with $1,224 million or $3.23 a share in 2002 (2001 – $1,255 million or $3.19 a share). Higher realizations for natural gas and crude oil and higher industry margins for petroleum products, partly offset by the negative impact of a higher Canadian dollar, were the main reasons for the increased earnings.

Total revenues were $19.2 billion, up about 13 percent from 2002.

Natural Resources

Earnings from natural resources were $1,139 million, up from $1,056 million in 2002 (2001 – $957 million). Higher realizations for natural gas and crude oil and higher production of Cold Lake bitumen were largely offset by the negative impact of a higher Canadian dollar.

Resource revenues were $5.6 billion, up from $4.9 billion in 2002 (2001 – $5.3 billion). The main reasons for the increase were higher prices for natural gas and crude oil and increased production from Cold Lake.

Financial statistics


	2003		2002		2001		2000		1999
	(millions)
Net earnings	$	1,139	$	1,056	$	957	$	1,177	$	567
Revenues		5,648		4,894		5,321		5,900		3,904

World oil prices strengthened considerably in early 2003 and remained relatively strong due to a combination of world supply concerns and increased world demand. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was $29 (U.S.) a barrel in 2003, compared with $25 in 2002 (2001 – $24.50).

The increase in the Company’s realizations on sales of conventional Canadian crude oil was diminished by the strengthening of the Canadian dollar. Average realizations during the year were $40.10 (Cdn) a barrel versus $36.81 in 2002 (2001 – $35.56).

Average prices for Canadian heavy crude oil were higher in 2003, but not as high as those for lighter crude oil, as increased supply of Canadian heavy crude oil widened the average spread between light and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil, increased by four percent in 2003, compared with a nine percent increase in prices for Canadian light crude oil. Average realizations for Cold Lake bitumen were about two percent lower than the previous year, as the stronger Canadian dollar offset any price increases.

Prices for Canadian natural gas in 2003 were higher on average than in the previous year. The average of 30 day spot prices for natural gas at the AECO hub in Alberta was about $6.70 a thousand cubic feet in 2003, up from $4.10 in 2002 (2001 – $6.30).

The Company’s average realizations on natural gas sales increased to $6.60 a thousand cubic feet from $4.02 in 2002 (2001 – $5.72).

Average realizations and prices


	2003		2002		2001		2000		1999
Conventional crude oil realizations (a barrel)	$	40.10	$	36.81	$	35.56	$	41.52	$	24.75
Natural gas realizations (a thousand cubic feet)		6.60		4.02		5.72		4.99		2.66
Par crude oil price at Edmonton (a barrel)		43.93		40.44		39.64		45.02		27.80
Heavy crude oil price at Hardisty (Bow River, a barrel)		33.00		31.85		25.11		34.49		23.51

Gross production of crude oil and natural gas liquids (NGLs) increased to 256,000 barrels a day from 247,000 barrels in 2002 (2001 – 267,000). Net production increased slightly to 225,000 barrels a day from 223,000 barrels in 2002 (2001 – 237,000).

Net bitumen production at the Company’s wholly owned facilities at Cold Lake increased to 116,000 barrels a day from 106,000 barrels in 2002 (2001 – 121,000). The higher volume was a result of the initial production cycles from phases 11 – 13, which began operation in December 2002. This was offset in part by lower production from existing operations, due to the cyclic nature of production at Cold Lake.

The effective royalty rate on Cold Lake production increased in 2003, as capital expenditures were lower upon the completion of phases 11 – 13. The rate increased to 10 percent of production from five percent in 2002 (2001 – five percent).

Production from the Syncrude operation, in which the Company has a 25 percent interest, decreased during 2003 as increased unplanned maintenance affected production through much of the year. Gross production of upgraded crude oil dropped to 211,000 barrels a day from 229,000 barrels in 2002 (2001 – 223,000). The Company’s share of average net production decreased to 52,000 barrels a day from 57,000 barrels in 2002 (2001 – 52,000).

Net production of conventional oil decreased to 35,000 barrels a day from 39,000 barrels in 2002 (2001 – 42,000) as a result of the natural decline in western Canadian reservoirs.

Gross production of natural gas decreased to 513 million cubic feet a day from 530 million in 2002 (2001 – 572 million). Net production was 457 million cubic feet a day in 2003, down from 463 million in 2002 (2001 – 466 million). Net production available for sale decreased to 390 million cubic feet a day from 396 million in 2002 (2001 – 376 million). Lower production as a result of reservoir decline was mostly offset by production from the new facilities at Wizard Lake in Alberta, which were completed in the third quarter of 2003.

Crude oil and NGLs – production and sales (a)


	2003				2002				2001				2000				1999
	gross		net		gross		net		gross		net		gross		net		gross		net
	(thousands of barrels a day)
Conventional crude oil		46		35		51		39		55		42		60		46		65		51
Cold Lake		129		116		112		106		128		121		119		102		132		107
Syncrude		53		52		57		57		56		52		51		42		56		55

Total crude oil production		228		203		220		202		239		215		230		190		253		213
NGLs available for sale (b)		28		22		27		21		28		22		30		23		31		24

Total crude oil and NGL production		256		225		247		223		267		237		260		213		284		237
Cold Lake sales,including diluent (c)		170				145				167				156				173
NGL sales		39				40				43				42				43

Natural gas – production and sales (a)


	2003				2002				2001				2000				1999
	gross		net		gross		net		gross		net		gross		net		gross		net
	(millions of cubic feet a day)
Production (d)		513		457		530		463		572		466		526		459		469		413
Production available for sale (b)		446		390		463		396		482		376		345		277		300		244
Sales		460				499				502				419				393

(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 shares of mineral owners or governments or both. Net production excludes those shares.

(b)		Production available for sale excludes amounts used for internal consumption and amounts reinjected. Starting in 2001, production available for sale reflects a change in the supply of natural gas to Company operations from Company produced gas to third party purchased gas.

(c)		Includes natural gas condensate added to the Cold Lake bitumen to facilitate transportation to market by pipeline.

(d)		Production of natural gas includes amounts used for internal consumption with the exception of amounts reinjected.

Operating costs increased by 11 percent in 2003. The main factors were increased costs associated with the newly completed phases 11 – 13 and cogeneration facilities at Cold Lake, unplanned maintenance at Syncrude and increased exploration costs.

Petroleum Products

Net earnings from petroleum products were a record $407 million or 1.3 cents a litre in 2003, up from $127 million or 0.4 cents a litre in 2002 (2001 – $353 million or 1.2 cents a litre). Earnings improved mainly as a result of the strengthening of industry petroleum product margins and increased sales volumes, partly offset by the negative impact of a higher Canadian dollar.

Revenues were $16.1 billion, up from $14.4 billion in 2002 (2001 – $14.4 billion).

Financial statistics


	2003		2002		2001		2000		1999
	(millions)
Net earnings	$	407	$	127	$	353	$	313	$	15
Revenues		16,058		14,434		14,405		15,120		10,665

Sales of petroleum products


	2003		2002		2001		2000		1999
	(millions of litres a day (a))
Gasolines		33.0		32.9		32.3		32.0		31.9
Heating,diesel and jet fuels		26.2		25.0		26.5		27.5		26.9
Heavy fuel oils		5.4		4.9		5.4		5.1		4.6
Lube oils and other products		5.8		6.4		5.4		5.0		5.8

Net petroleum products sales		70.4		69.2		69.6		69.6		69.2
Sales under purchase and sale agreements		14.6		13.9		11.6		10.7		10.8

Total sales of petroleum products		85.0		83.1		81.2		80.3		80.0

Total domestic sales of petroleum products (percent)		93.3		91.5		93.4		94.0		95.6

Refinery utilization


	2003		2002		2001		2000		1999
	(millions of litres a day (a))
Total refinery throughput (b)		71.6		71.2		71.4		71.6		70.1
Refinery capacity at December 31		79.9		79.4		79.1		78.7		78.7
Utilization of total refinery capacity (percent)		90		90		90		91		89

(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 higher in the refining segment of the industry in 2003 compared with those in 2002, as international wholesale product prices increased more than raw material costs. However, the effects of higher international margins were reduced partially by a higher Canadian dollar.

The Company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 85 million litres a day, compared with 83.1 million litres in 2002 (2001 – 81.2 million). Excluding sales resulting from reciprocal agreements, sales were 70.4 million litres a day, compared with 69.2 million litres in 2002 (2001 – 69.6 million).

Operating costs increased by about five percent in 2003 from the previous year, mainly because of higher energy costs and expenses related to increased sales volumes.

Chemicals

Earnings from chemical operations were $37 million in 2003, down from $52 million in 2002 (2001 –$23 million). Reduced industry margins on sales of polyethylene as a result of higher feedstock costs and weaker industry demand were the main reasons for the decrease in earnings.

Total revenues from chemical operations were $1,232 million, compared with $1,164 million in 2002 (2001 – $1,175 million). Gains from higher prices for polyethylene, intermediate chemicals and aromatics during 2003 more than offset lower sales volumes.

Financial statistics


	2003		2002		2001		2000		1999
	(millions)
Net earnings	$	37	$	52	$	23	$	59	$	43
Revenues		1,232		1,164		1,175		1,173		872

The average industry price of polyethylene was $1,415 a tonne in 2003, up 15 percent from $1,229 a tonne in 2002 (2001 – $1,284). However, margins were reduced because of higher feedstock costs, reflecting increased prices for natural gas.

Sales of chemicals decreased to 3,300 tonnes a day from 3,500 tonnes in 2002 (2001 – 3,300 tonnes) as a result of reduced demand.

Sales volumes


	2003		2002		2001		2000		1999
	(thousands of tonnes a day (a)
Polymers & basic chemicals		2.4		2.5		2.4		2.2		2.0
Intermediates and other		0.9		1.0		0.9		0.9		1.0

Total chemicals		3.3		3.5		3.3		3.1		3.0

(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.

Operating costs in the chemicals segment increased by about four percent in 2003 mainly because of higher planned capital project related expenses.

Corporate and other

Earnings from corporate and other accounts were positive $99 million in 2003, compared with negative $11 million in 2002 (2001 – negative $78 million). The improvement was mainly attributable to favourable foreign exchange effects on the Company’s U.S. dollar denominated debt. The Company retired the remaining balance of its U.S. dollar denominated debt in 2003.

Liquidity and capital resources

Cash flow from earnings was $2,354 million, up from $1,781 million in 2002 (2001 – $2,016 million), mainly because of increased earnings. Cash provided from operating activities was $2,194 million, compared with $1,676 million in 2002 (2001 – $2,004 million). The increased cash inflow was mainly due to higher earnings, timing of scheduled income tax payments and the effects of commodity prices on receivable and payable balances, partly offset by additional funding contributions to the Company’s registered pension plan.

In June, the Company renewed the normal course issuer bid (share buyback program) for another 12 months. During 2003, the Company purchased more than 16 million shares for $799 million. Since the Company initiated its first buyback program in 1995, the Company has purchased 219 million shares – representing about 38 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $5,968 million.

The Company declared dividends totalling 87 cents a share in 2003, up from 84 cents in 2002 (2001 –83 cents). Regular per share dividends paid have increased in each of the past nine years and, since 1986, payments a share have grown by more than 55 percent.

Following one of the largest capital investment programs in the Company’s history as well as funding contributions to the Company’s registered pension plan, the cash balance was $448 million at year end, compared with $766 million at the end of 2002 (2001 – $872 million).

In 2003, the Company retired its $600 million U.S. variable rate debt, due in 2004, for $818 million (Cdn) and replaced it with $818 million of Canadian dollar denominated variable rate loans from Exxon Overseas Corporation at interest equivalent to Canadian market rates.

Total debt outstanding, excluding the Company’s share of equity company debt, at the end of 2003 was $1,432 million, compared with $1,538 million at the end of 2002 (2001 – $1,489 million). Debt represented 20 percent of the Company’s capital structure at the end of 2003, compared with 23 percent at the end of 2002 (2001 – 26 percent).

Debt related interest expense paid in 2003 was $38 million, down from $40 million in 2002 (2001 – $77 million). The retirement of the Company’s long term fixed rate debt during the past few years was the main reason for the reduction. The average effective interest rate on the Company’s debt was 2.9 percent in 2003, compared with 2.1 percent in 2002 (2001 – 5.1 percent).

Financial percentages, ratios and credit rating


	2003		2002		2001		2000		1999
Total debt as a percentage of capital (a)		20		23		26		25		24
Interest coverage ratios Earnings basis (b)		63		46		26		23		9
Cash flow basis (c)		79		63		36		29		14

(a)		Current and long term portions of debt (page F-5) divided by debt and shareholders’ equity (page F-5).

(b)		Net earnings (page F-3), debt related interest expense (page F-17, note 12) and income taxes (page F-3) divided by debt related interest expense.

(c)		Cash flow from earnings (page F-4), current income tax expense (page F-12, note 4) and debt related interest expense divided by debt related interest expense.

Capital and exploration expenditures

Total capital and exploration expenditures were $1,526 million in 2003, down slightly from $1,600 million in 2002 (2001 – $1,115 million).

The funds were used mainly to maintain and expand crude oil and natural gas production capacity, to upgrade refineries to meet low sulphur gasoline requirements and to enhance the Company’s retail network.

The following table shows the Company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2003:


	2003		2002		2001		2000		1999
	(millions)
Exploration	$	57	$	39	$	49	$	56	$	29
Production		181		143		109		110		138
Heavy oil		769		804		588		268		263

Total	$	1,007	$	986	$	746	$	434	$	430

For the natural resources segment, about 90 percent of the capital and exploration expenditures in 2003 was focused on growth opportunities. The single largest investment during the year was the Company’s share of the Syncrude expansion. The remainder of 2003 investment was directed to advancing the Mackenzie gas project, drilling for conventional oil and gas in Western Canada, and East Coast development and deepwater exploration.

Planned capital and exploration expenditures in natural resources are expected to total about $1 billion in 2004, with nearly 90 percent of the total focused on growth opportunities. Much of the expenditure will be directed to the expansion now underway at Syncrude. Investments are also planned for the ongoing development drilling at Cold Lake, the Mackenzie gas project, development of the Sable South Venture field and the Sable compression platform, as well as further development drilling in Western Canada. Planned expenditures for exploration and development drilling, as well as capacity additions in conventional oil and gas operations, are expected to be about $320 million.

The following table shows the Company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2003:


	2003		2002		2001		2000		1999
	(millions)
Marketing	$	91	$	133	$	171	$	121	$	80
Refining and supply		368		399		118		100		114
Other (a)		19		57		50		11		9

Total	$	478	$	589	$	339	$	232	$	203

(a)

Consists primarily of purchases of real estate.

For the petroleum product segment, capital expenditures decreased to $478 million in 2003, compared with $589 million in 2002 (2001 – $339 million), primarily because of the completion of the project to significantly reduce sulphur content in gasoline, which began in 2001. New investments in 2003 included the products segment’s $32 million share of capital expenditures on a 95 megawatt cogeneration facility to improve energy efficiency and reduce emissions at the petroleum products and chemicals operations in Sarnia. In addition, almost $60 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 retail outlets during the year.

Capital expenditures for the petroleum products segment in 2004 are expected to be about $450 million. Major items include investment in refining facilities to reduce the sulphur content in diesel to meet regulatory requirement and continued enhancements to the Company’s retail network.

The following table shows the Company’s capital expenditures for the chemicals operations during the five years ending December 31, 2003.


	2003		2002		2001		2000		1999
	(millions)
Chemicals	$	41	$	25	$	30	$	13	$	20

Of the capital expenditures for chemicals in 2003, the major investment was the Sarnia cogeneration project, a joint development between the petroleum products and chemicals operations at the site.

Planned capital expenditures for chemicals in 2004 will be about $20 million. Funds will be used largely to improve energy efficiency and yields.

Total capital and exploration expenditures for the Company in 2004, which will focus mainly on growth and productivity improvements, are expected to total about $1.5 billion and will be financed primarily from internally generated funds.

During 2003, the Company spent more than $310 million on projects related to reducing the environmental impact of its operations and improving safety. This included investments of more than $260 million in the Company’s four refineries as part of the capital project to produce low sulphur gasoline and diesel fuels.

Reporting investments in mineral interests in oil and gas properties

The accounting standards for business combinations and goodwill and other intangible assets issued by the Canadian Institute of Chartered Accountants (CICA) became effective for the Company of July 1, 2001, and January 1, 2002, respectively. These Canadian standards are harmonized with specific U.S. standards in these areas. Currently, the Emerging Issues Task Force (EITF) of the Financial Accounting Standards Board (FASB) is considering the issue of whether the U.S. standards require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. If such interests were deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both undeveloped and developed leaseholds would be classified separately from oil and gas properties as intangible assets on the Company’s balance sheet. The EITF interpretation could potentially have an impact on the Canadian standards and the Company’s financial reporting. Historically, in accordance with Canadian generally accepted accounting principles (GAAP), the Company has capitalized the cost of oil and gas leasehold interests and reported these assets as part of tangible oil and gas property, plant and equipment.

This interpretation of the current U.S. standards would only affect the classification of oil and gas leaseholds on the Company’s balance sheet and would not affect total assets, net worth or cash flows. The Company’s results of operations would not be affected, since these leasehold costs would continue to be amortized in accordance with GAAP. The amount that is subject to reclassification as of December 31, 2003, was $935 million and $1,109 million as of December 31, 2002.

Pension

An independent actuarial valuation of the Company’s registered pension plan was completed in 2003. As a result of the valuation, the Company contributed $500 million to the registered pension plan. While equity markets improved in 2003 and the Company’s contribution levels increased, the Company plans to take a measured approach to the pace of funding, within the requirements of pension regulations. However, pension liabilities need to be assessed in light of the Company’s strong credit position and prudent financial management. The Company has in the past and expects to continue to use its strong balance sheet to effectively manage pension liabilities. Future funding requirements are not expected to affect the Company’s existing capital investment plans or its ability to pursue new investment opportunities.

Contractual obligations

To more fully explain the Company’s financial position, the following table shows the Company’s contractual obligations outstanding at December 31, 2003. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to consolidated financial statements.


	Financial	Payment due by period
	statement note			2005 to		2009 and		Total
millions of dollars	reference	2004		2008		beyond		amount
Long term debt & capital leases	note 3	$	501	$	834	$	25	$	1,360
Company’s share of equity company debt			52		—		—		52
Operating leases	note 9		72		185		114		371
Unconditional purchase obligations (a)	note 9		90		161		98		349
Firm capital commitments (b)	note 9		176		13		—		189
Pension obligations (c)	note 5		138		100		318		556
Asset retirement obligations (d)	note 6		34		112		181		327
Other long term agreements (e)	note 9		260		500		277		1,037

Total		$	1,323	$	1,905	$	1,013	$	4,241

(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 $189 million at the end of 2003, compared with $284 million at year end 2002. The largest commitment outstanding at year end 2003 was associated with the Company’s share of capital projects at Syncrude ($56 million).

(c)		Pension obligations represent the amount by which accumulated benefit obligations (ABO) exceeded the fair value of plan assets. The ABO is less than the (projected) benefit obligation shown in note 5 to the consolidated financial statements because it does not take into account future compensation levels. It is used instead of the projected benefit obligation because it more truly reflects the actual benefit obligation at the end of the year. The payments by period include expected contributions to the Company’s registered pension plan in 2004 and estimated benefit payments for unfunded plans in all years. The term ABO used here is consistent with the definition under Statement of Financial Accounting Standards No. 87 issued by the Financial Accounting Standards Board.

(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.

Critical accounting policies

The Company’s financial statements have been prepared in accordance with Canadian generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgments. 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 pages F-6 to F-8.

Oil and gas and synthetic crude oil reserves

Proved oil and gas and synthetic crude oil reserves quantities are used as the basis of calculating unit of production rates for depreciation and evaluating for impairment. These 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. The estimation of reserves is an ongoing process based on rigorous technical evaluations and extrapolations of appropriate information.

While proved reserves have a reasonable certainty of recovery, they are based on estimates that are subject to some variability. The variability can result in upward or downward revisions in the previously estimated volumes of proved reserves for existing fields due to initial study or restudy of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data obtained from wells. Revisions can also include changes associated with improved recovery projects, fiscal terms and significant changes in development strategy, oil and gas prices or production equipment/facility capacity. Over time, revisions of proved reserves for the Company have generally resulted in net upward experience based changes through effective reservoir management and the application of new technology. While revisions are an indicator of variability, they have had little impact on the unit of production rates of depreciation and on impairment testing because the revisions have been small compared to the large proved reserves base.

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 financial 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 2003 compares to actual returns of 9.5 percent and 10 percent achieved over the last 10 and 20 year periods ending December 31, 2003. If different assumptions are used, the expense and obligations could increase or decrease as a result. The Company’s potential exposure to change in assumptions is summarized in footnote (e)

of note 5 to the consolidated financial statements. 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 about one percent of total expenses in 2003.

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. In 2003, the obligations have been discounted at six percent and the accretion expense was $20 million, 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. 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 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 earnings.


	millions of dollars after tax
Three dollars (U.S.) a barrel change in crude oil prices		+(-	)	140
Sixty cents a thousand cubic feet change in natural gas prices		+(-	)	40
One cent a litre change in sales margins for total petroleum products		+(-	)	180
One cents (U.S.) a pound change in sales margins for polyethylene		+(-	)	8
One quarter percent decrease (increase) in short term interest rates		+(-	)	2
Eight cents decrease (increase) in the value of the Canadian dollar versus the U.S. dollar		+(-	)	340

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 2003. Each sensitivity calculation shows the impact on annual earnings 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 to changes in the Canadian dollar versus the U.S.dollar increased from 2002 by about $12 million (after tax) a year for each one cent change. This is primarily a result of the retirement of the U.S. dollar denominated debt which had previously moderated the impact of foreign exchange rate changes on commodity prices and product margins.

The sensitivity to changes in crude oil prices decreased from 2002 by about $13 million (after tax) for each one U.S. dollar difference. An increase in the value of the Canadian dollar has lessened the impact of U.S. dollar denominated crude oil prices on the Company’ s revenues and earnings.

Item 8. Financial Statements and Supplementary Data.

Reference is made to the Index to Financial Statements on page F-1 of this report. The reconciliation to U.S. GAAP is in Item 6 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 4 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 approved mining plan, there are an estimated 2,990 million tonnes (3,295 million tons) of extractable tar sands, in the Base and North mines, with an average bitumen grade of 10.4 weight percent. In addition, at the Aurora mine, there are an estimated 3,665 million tonnes (4,050 million tons) of extractable tar sands at an average bitumen grade of 11.3 weight percent. After deducting royalties payable to the Province of Alberta, the Company estimates its 25 percent net share of proven reserves is equivalent to 124 million cubic metres (781 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 2001		60			37			97
Revision of previous estimate		—			37			37
Production		(2	)		(1	)		(3	)

End of year 2001		58			73			131
Revision of previous estimate		—			—			—
Production		(3	)		(1	)		(4	)

End of year 2002		55			72			127
Revision of previous estimate		—			—			—
Production		(2	)		(1	)		(3	)

End of year 2003		53			71			124


	Synthetic Crude Oil
	Base Mine and
	North Mine			Aurora Mine			Total
	(millions of barrels)
Beginning of year 2001		373			237			610
Revision of previous estimate		—			230			230
Production		(15	)		(4	)		(19	)

End of year 2001		358			463			821
Revision of previous estimate		—			—			—
Production		(14	)		(7	)		(21	)

End of year 2002		344			456			800
Revision of previous estimate		—			—			—
Production		(13	)		(6	)		(19	)

End of year 2003		331			450			781

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


	2003		2002		2001
	(millions of dollars)
Sales to customers	$	1,816	$	1,381	$	1,306
Intersegment sales		584		741		767

Total sales (1)	$	2,400	$	2,122	$	2,073
Production expenses		594		576		526
Exploration expenses		55		30		45
Depreciation and depletion		463		426		411
Income taxes		364		350		340

Results of operations	$	924	$	740	$	751

Capital and exploration expenditures


	2003		2002		2001
	(millions of dollars)
Property costs (2)
Proved	$	—	$	13	$	—
Unproved		2		5		5
Exploration costs		55		34		44
Development costs		339		469		489

Total capital and exploration expenditures	$	396	$	521	$	538

Property, plant and equipment


	2003		2002
	(millions of dollars)
Property costs (2)
Proved	$	3,332	$	3,338
Unproved		163		155
Producing assets		5,775		5,371
Support facilities		125		126
Incomplete construction		200		227

Total cost	$	9,595	$	9,217
Accumulated depreciation and depletion		6,012		5,528

Net property, plant and equipment	$	3,583	$	3,689

(1)		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. Total sales exclude the sale of natural gas and natural gas liquids purchased for resale.

(2)		“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 meters)
Beginning of year 2001		31			135			166			45
Revisions of previous estimates and improved recovery		(1	)		—			(1	)		—
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			—
Production		(4	)		(7	)		(11	)		(5	)

End of year 2001		26			128			154			40
Revisions of previous estimates and improved recovery		—			5			5			—
(Sale)/purchase of reserves in place		—			—			—			—
Discoveries and extensions		—			—			—			—
Production		(3	)		(6	)		(9	)		(5	)

End of year 2002		23			127			151			35
Revisions of previous estimates 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

(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 2001		196			851			1,047			1,572
Revisions of previous estimates and improved recovery		(8	)		—			(8	)		9
(Sale)/purchase of reserves in place		—			—			—			1
Discoveries and extensions		—			—			—			2
Production		(23	)		(44	)		(67	)		(170	)

End of year 2001		165			807			972			1,414
Revisions of previous estimates and improved recovery		3			33			36			(26	)
(Sale)/purchase of reserves in place		—			—			—			2
Discoveries and extensions		—			—			—			3
Production		(22	)		(39	)		(61	)		(169	)

End of year 2002		146			801			947			1,224
Revisions of previous estimates 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

(1)

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 existing experimental pilot plants and commercial stages 1 through 13.

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 those attributable to the Cold Lake pilot area and stages 1 through 13 of Cold Lake production operations.

In 2003, the Company’s net proved reserves of crude oil and natural gas liquids decreased by about nine million cubic metres (58 million barrels), while the proved reserves of natural gas decreased by about six billion cubic metres (201 billion cubic feet). Production in 2003 totalled about 10 million cubic metres (64 million barrels) of crude oil and natural gas liquids and about five billion cubic metres (167 billion cubic feet) of natural gas. Revisions of previous estimates and improved recovery increased reserves of crude oil and natural gas liquids by about one million cubic metres (six million barrels) and decreased reserves of natural gas by about one billion cubic metres (40 billion cubic feet). Discoveries and extensions in 2003 totalled less than one billion cubic metres (six billion cubic feet) of natural gas.

Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1)


	2003		2002		2001		2000		1999
	(millions)
Crude Oil:
Conventional:
Cubic metres		20		23		26		31		36
Barrels		126		146		165		196		225
Oil Sands (Cold Lake crude bitumen):
Cubic metres		121		127		128		135		139
Barrels		763		801		807		851		878
Total:
Cubic metres		141		151		154		166		175
Barrels		889		947		972		1,047		1,103
Natural Gas:	(billions)
Cubic metres		29		35		40		45		48
Cubic feet		1,023		1,224		1,414		1,572		1,692

Net Proved Developed Reserves of Crude Oil and Natural Gas (1)


	2003		2002		2001		2000		1999
	(millions)
Crude Oil:
Conventional:
Cubic metres		19		22		25		28		32
Barrels		121		139		157		175		200
Oil Sands (Cold Lake crude bitumen):
Cubic metres		63		49		34		40		36
Barrels		398		308		216		250		229
Total:
Cubic metres		82		71		59		68		68
Barrels		519		447		373		425		429
Natural Gas:	(billions)
Cubic metres		24		27		30		35		36
Cubic feet		859		959		1,060		1,233		1,264

(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 (1)


	2003			2002			2001
	(millions)
Future cash flows	$	27,611		$	35,811		$	17,936
Future production costs		(10,871	)		(8,940	)		(7,107	)
Future development costs		(3,084	)		(3,117	)		(2,641	)
Future income taxes		(5,543	)		(9,107	)		(3,285	)

Future net cash flows	$	8,113		$	14,647		$	4,903
Annual discount of 10 percent for estimated timing of cash flows		(3,375	)		(6,446	)		(2,114	)

Discounted future net cash flows	$	4,738		$	8,201		$	2,789

Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves (1)


	2003			2002			2001
	(millions)
Balance at beginning of year	$	8,201		$	2,789		$	5,987
Changes resulting from:
Sales and transfers of oil and gas produced, net of production costs		(2,075	)		(1,645	)		(1,698	)
Net changes in prices, development costs and production costs		(4,395	)		9,276			(6,477	)
Extensions, discoveries, additions and improved recovery, less related costs		22			34			31
Purchase/(sales) of minerals in place		—			4			5
Development costs incurred during the year		281			432			504
Revisions of previous quantity estimates		(368	)		111			88
Accretion of discount		1,108			423			1,030
Net change in income taxes		1,964			(3,223	)		3,319

Net Change	$	(3,463	)	$	5,412		$	(3,198	)

Balance at end of year	$	4,738		$	8,201		$	2,789

(1)

The schedules above are calculated using year-end prices, costs, statutory tax rates and existing proved oil and gas reserves excluding the Company’s interest in Syncrude. 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.

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.

PART III

Item 10. Directors and Executive Officers of the Registrant.

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

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(1)(2)
P. (Pierre) Des Marais II President, Gestion PDM Inc. (management company)	—	April 22, 1977	Common shares of Imperial Oil Limited Deferred share units of	1,560
			Imperial Oil Limited	4,234

			Restricted stock units of Imperial Oil Limited	1,750

			Shares of Exxon Mobil Corporation	0

B.J. (Brian) Fischer Senior vice-president, products and chemicals division, Imperial Oil Limited	Senior vice-president, chemicals division, Imperial Oil Limited	September 1, 1992	Common shares of Imperial Oil Limited	33,698

			Deferred share units of Imperial Oil Limited	19,773

			Restricted stock units of Imperial Oil Limited	48,400

			Shares of Exxon Mobil Corporation	0

T.J. (Tim) Hearn Chairman, president and chief executive officer, Imperial Oil Limited	President, Imperial Oil Limited	January 1, 2002	Common shares of Imperial Oil Limited	23,095

			Deferred share units of Imperial Oil Limited	0

			Restricted stock units of Imperial Oil Limited	110,000

			Shares of Exxon Mobil Corporation	9,274

R. (Roger) Phillips Retired president and chief executive officer, IPSCO Inc. (steel manufacturing)	—	April 23, 2002	Common shares of Imperial Oil Limited	3,000

			Deferred share units of Imperial Oil Limited	2,316

			Restricted stock units of Imperial Oil Limited	1,750

			Shares of Exxon Mobil Corporation	2,000

J.F. (Jim) Shepard Retired chairman and chief executive officer, Finning International Inc. (sale, lease, repair and financing of heavy equipment)	—	October 21, 1997	Common shares of Imperial Oil Limited	3,000

			Deferred share units of Imperial Oil Limited	4,878

			Restricted stock units of Imperial Oil Limited	1,750

			Shares of Exxon Mobil Corporation	0


	Last major
	position or office with the
Name and current principal	Company or Exxon Mobil
occupation or employment	Corporation	Director since	Holdings(1)(2)
P.A. (Paul) Smith Controller and senior vice-president, finance and administration, Imperial Oil Limited	Corporate finance manager, Exxon Mobil Corporation	February 1, 2002	Common shares of Imperial Oil Limited	4,120

			Deferred share units of Imperial Oil Limited	0

			Restricted stock units of Imperial Oil Limited	29,200

			Shares of Exxon Mobil Corporation	1,190

S.D. (Sheelagh) Whittaker Managing Director, public sector business Electronic Data Systems Limited (business and information technology services)	—	April 19, 1996	Common shares of Imperial Oil Limited	3,000

			Deferred share units of Imperial Oil Limited	7,313

			Restricted stock units of Imperial Oil Limited	1,750

			Shares of Exxon Mobil Corporation	0

K.C. (K.C.) Williams Senior vice-president, resources division, Imperial Oil Limited	Vice-president, production, Exxon Company, International	January 1, 1999	Common shares of Imperial Oil Limited	12,000

			Deferred share units of Imperial Oil Limited	—

			Restricted stock units of Imperial Oil Limited	—

			Shares of Exxon Mobil Corporation	73,045

V.L. (Victor) Young Corporate director of several corporations	—	April 23, 2002	Common shares of Imperial Oil Limited	3,000

			Deferred share units of Imperial Oil Limited	579

			Restricted stock units of Imperial Oil Limited	1,750

			Shares of Exxon Mobil Corporation	0

(1) 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.

(2) The Company’s plans for deferred share units and restricted stock units for selected employees and nonemployee directors are described on pages 40 and 41.

The ages of the directors, nominees for election as directors, and the five senior executives of the Company are: Pierre Des Marais II 69, Brian J. Fischer 57, Timothy J. Hearn 60, Roger Phillips 64, James F. Shepard 65, Paul A. Smith 51, Sheelagh D. Whittaker 56, K.C. Williams 54, Victor L. Young 58, and John F. Kyle 61.

Roger Phillips is a director of Canadian Pacific Railway Limited, Cleveland – Cliffs Inc., Inco Limited, and The Toronto Dominion Bank, and Victor L. Young is a director of Royal Bank of Canada and BCE Inc., which companies are subject to reporting requirements under the U.S. Securities Exchange Act of 1934.

All of the directors and nominees for election as directors, except for Roger Phillips, Victor L. Young and James F. Shepard, 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 on January 1, 2002. During the five preceding years, Victor L. Young was chairman and chief executive officer of Fishery Products International Limited (seafood products), until May 1, 2001 and is currently a director of Royal Bank of Canada, BCE Inc., McCain Foods Limited, Aliant Inc., and Telesat Canada. For more than five years before 2000, James F. Shepard’s principal occupation was successively president and chief executive officer, and from April 1996, chairman and chief executive officer of Finning International Inc. (sale, lease, repair and financing of heavy equipment) following which, in 2000, he retired.

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


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

Brian J. Fischer		February 1, 1994
senior vice-president,
products and chemicals division

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

K.C. Williams		January 1, 1999
senior vice-president,
resources division

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

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 members of the audit committee: P. Des Marais II, R. Phillips, J.F. Shepard, S.D. Whittaker and V.L. Young.

Audit committee financial expert

The Company’s board of directors has determined that P. Des Marais II, R. Phillips, S.D. Whittaker and V. L. Young meet the definition of “audit committee financial expert” and are independent, as that term is defined by both 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 and conflict-of-interest guidelines that apply to all employees, including its principal executive officer, principal financial officer and principal accounting officer. The code of ethics and conflict-of-interest guidelines are available at the Company’s website www.imperialoil.ca.

Item 11. Executive Compensation.

Directors’ compensation

Directors’ fees are paid only to nonemployee directors. For 2003, nonemployee directors were paid an annual retainer of $35,000 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. Effective December 31, 2003, the annual board retainer was increased by the issuance of 1,000 restricted stock units to each nonemployee director. The restricted stock units issued to nonemployee directors have the same features as the restricted stock units for selected employees described on page 41.

Starting in 1999, the nonemployee directors have been able to receive all or part of their directors’ fees in the form of deferred share units for nonemployee directors. The purpose of the deferred share unit plan for nonemployee 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 pages 40 and 41.

While serving as directors in 2003, the aggregate cash remuneration paid to nonemployee directors, as a group, was $346,500, and they received an additional 5,006 deferred share units for nonemployee directors, as a group, based on an aggregate of $250,000 of cash remuneration elected to be received as deferred share units. The nonemployee directors, as a group, received an additional 279 deferred share units granted as the equivalent to the cash dividend paid on Company shares during 2003 for previously granted deferred share units.

Senior executive compensation

Summary compensation table

The following table shows the compensation for the chief executive officer and the four other senior executives of the Company who were serving as senior executives at the end of 2003. 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		Restricted
										Under		Shares or
Name and							Other Annual			Options/SARs		Restricted		LTIP		All Other
Principal			Salary		Bonus (2)		Compensation (3)			Granted (4)		Share Units (5) (6) (7)		Payouts		Compensation (9)
Position	Year		($)		($)		($)			(#)		(#)		(8) ($)		($)
T.J. Hearn		2003		825,000		750,000		182,072			–		60,000		738,000		24,750
Chairman, president and chief executive officer								U.S. 293,450				restricted
												stock units
													0
												deferred share units

		2002		668,333		442,000		71,777			65,000		50,000		–		20,050
								U.S. 328,796		stock		restricted
										options		stock units
													0
												deferred share units

		2001		475,000		300,000		19,888			50,000		0		–		9,500
								U.S. (163,873	)	incentive		deferred
										share units		share units
B.J. Fischer		2003		530,833		357,000		24,815			–		26,700		486,000		31,850
Senior												restricted
vice-president,												stock units
products and													341
chemicals division												deferred share units

		2002		505,000		216,000		0			50,000		21,700		–		30,300
										stock		restricted
										options		share units
													358
												deferred share units

		2001		475,000		67,500		2,935			50,000		5,039		–		23,750
										incentive		deferred
										share units		share units
P.A. Smith		2003		357,917		183,000		11,083			–		16,700		204,510		21,475
Controller and								U.S. 72,891				restricted
senior vice-president,												stock units
finance and													0
administration												deferred share units

		2002		331,667		94,500		U.S. 100,390			25,000		12,500		–		19,900
										stock		restricted
										options		stock units
													0
												deferred share units

		2001		291,666		110,000		U.S. 30,908			25,000		0		–		14,583
										incentive		deferred
										share units		share units
K.C. Williams (1)		2003		U.S. 431,667		U.S. 260,900		U.S. 530,391			–		–		U.S. 197,490		U.S. 27,900
Senior vice-president, resources division		2002		U.S. 412,500		U.S. 158,000		U.S. 363,932			–		–		U.S.		U.S.
															197,450		26,750

		2001		U.S. 382,750		U.S. 197,500		U.S. 144,175			–		–		U.S.		U.S.
															97,515		24,665
J.F. Kyle		2003		355,000		171,000		41,391			–		11,400		261,000		21,300
Vice-president												restricted
and treasurer												stock units
													0
												deferred share units

		2002		345,000		110,000		13,077			29,000		10,600		–		20,700
										stock		restricted
										options		stock units
													0
												deferred share units

		2001		325,000		150,000		15,107			29,000		0		–		16,250
										incentive		deferred
										share units		share units

(1) K.C. Williams is on a loan assignment from Exxon Mobil Corporation to the Company. 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 K.C. Williams, 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 pages 40 and 41, dividend equivalent payments on restricted stock units, interest paid in respect of deferred payments of bonuses and reimbursement for any income tax paid as a result of use of Company aircraft. For T.J. Hearn the amounts also include a leased automobile which in 2003 was $44,010 and financial counselling. For T.J. Hearn and P.A. Smith, the U.S. dollar amounts are payments by the Company on account of U.S. income taxes incurred while on assignment in the U.S.A. For K.C. Williams, 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 K.C. Williams 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 T.J. Hearn for 2001, the negative amount was a net payment to the Company as a result of differences in timing of the amounts paid by the Company on account of U.S. income taxes and the amounts he paid to the Company to approximate the income taxes that would have been imposed if he was resident in Canada.

(4) For 2001, these are the number of units granted under the Company’s plan for incentive share units described on page 40. In 2002, the Company granted instead stock options which are described on page 41.

(5) These include the number of units granted under the Company’s plan for deferred share units for selected executives described on pages 40 and 41. The values and number of these units, as at the end of 2003, were nil for T.J. Hearn, $1,137,541 for 19,773 units for B.J. Fischer, and nil for P.A. Smith and J.F. Kyle. These amounts include no deferred share units elected to be received in lieu of bonus for 2003 and 2002, and 4,880 share units based on $202,500 of bonus elected to be received as deferred share units for 2001 for B.J. Fischer.

(6) These also include restricted stock units granted under the Company’s plan for restricted stock units for selected employees and nonemployee directors described on page 41. The values and number of these units, as at the end of 2003, were $6,328,300 for 110,000 units for T.J. Hearn, $2,784,452 for 48,400 units for B.J. Fischer, $1,679,876 for 29,200 units for P.A. Smith and $1,265,660 for 22,000 units for J.F. Kyle. The values of these units granted for 2003, as at the end of 2003, were $3,451,800 for T.J. Hearn, $1,536,051 for B.J. Fischer, $960,751 for P.A. Smith and $655,842 for J.F. Kyle. The values of these units granted for 2002, as at the end of 2002, were $2,243,000 for T.J. Hearn, $973,462 for B.J. Fischer, $560,750 for P.A. Smith and $475,516 for J.F. Kyle.

(7) K.C. Williams participates in Exxon Mobil Corporation’s restricted stock plan which is similar to the Company’s restricted stock unit plan. The value and number of these units for K.C. Williams, as at the end of the year, were U.S. $1,918,800 for 46,800 units. Under that plan, K.C. Williams was granted 23 400 units in 2003 whose value on the date of grant was U.S. $959,400 and 23 400 units in 2002 whose value on the date of grant was U.S. $810,576.

(8) Payouts were from 2001 and 2002 earnings bonus units that reached maximum value of $3.00 per unit in 2003. That plan is described on page 41.

(9) Amounts under “All Other Compensation”, except for K.C. Williams, 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 K.C. Williams, 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 K.C. Williams, the amounts are Exxon Mobil Corporation’s contributions to its employee savings plan.

Long term incentive compensation

Long term incentive compensation is granted to retain selected employees and reward them for high performance. The compensation has generally been in the form of units.

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, if exercised within the periods of eligibility. 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. The periods of eligibility for the exercise of the units are as follows: no units may be exercised before one year after the grant date; up to 50 percent of the units may be exercised on or after one year following the grant date; an additional 25 percent of the units may be exercised on or after two years following the grant date; and the remaining 25 percent of the units may be exercised on or after three years following 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 whereby they could elect to receive all or part of their performance 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 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.

Starting in 1999, a form of long term incentive compensation, similar to the deferred share units for executives, was made available to nonemployee directors in lieu of their receiving all or part of their directors’ fees. The main differences between the two plans are that all nonemployee directors are allowed to participate in the plan for nonemployee directors and that the number of units granted to a nonemployee director is determined at the end of each calendar quarter by dividing the amount of the directors’ fees for that calendar quarter that the nonemployee 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, the earnings bonus unit 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.

Under the stock option plan, adopted by the Company in April 2002, a total of 3,210,200 options were granted on April 30, 2002 for the purchase of the Company’s common shares at an exercise price of $46.50 per share. Up to 75 percent of the options were exercisable 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.

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 employees and nonemployee directors directly with the interests of shareholders. Each unit entitles the recipient the conditional 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 units 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 872,085 units were granted on December 31, 2003.

Earnings bonus unit plan – awards in most recently completed financial year

The following table provides information on earnings bonus units granted in 2003 to the named senior executives.


			Performance		Estimated Future Payouts Under
	Securities Units or		or Other Period Until		Non-Securities-Price Based Plans
	Other Rights		Maturation or		Threshold		Target		Maximum
Name	(#)		Payout (1)		($)		($) (2)		($)(2)
T.J. Hearn		250,000	Nov. 20, 2008			0		3.00		3.00
B.J. Fischer		119,000	Nov. 20, 2008			0		3.00		3.00
P.A. Smith		61,000	Nov. 20, 2008			0		3.00		3.00
K.C. Williams (3)		—		—		—		—		—
J.F. Kyle		57,000	Nov. 20, 2008			0		3.00		3.00

(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 2002.

(3) K.C. Williams participates in Exxon Mobil Corporation’s earnings bonus unit plan which is similar to the Company’s earnings bonus unit plan. In 2003, K.C. Williams was granted 86,960 units under that plan for which the maximum settlement value payable per earnings bonus unit is U.S. $3.00.

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 2003 and the aggregate holdings at the end of 2003 of incentive share units (referred to in the table as “SARs”) by the named senior executives.


									Value of
									Unexercised
					Unexercised				in-the-Money
					Options/SARs				Options/SARs
					at Financial				at Financial
	Securities		Aggregate		Year-End				Year-End
	Acquired on Exercise		Value Realized		(#)				($)
Name	(#)		($)		Exercisable		Unexercisable (1)		Exercisable		Unexercisable (1)
T.J. Hearn		—		181,350		50,000		12,500		1,027,750		231,625
B.J. Fischer		—		—		139,5000		25,000		3,583,535		564,500
P.A. Smith		—		503,100		66,750		6,250		2,176,438		115,813
K.C. Williams		—		—		—		—		—		—
J.F. Kyle		—		626,570		81,750		7,250		2,108,728		134,343

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

The following table provides information on the exercise in 2003 and the aggregate holdings at the end of 2003 of stock options by named senior executives.


									Value of
									Unexercised
					Unexercised				in-the-Money
					Options/SARs				Options/SARs
					at Financial				at Financial
	Securities		Aggregate		Year-End				Year-End
	Acquired on Exercise		Value Realized		(#)				($)
Name	(#)		($)		Exercisable		Unexercisable (2)		Exercisable		Unexercisable (2)
T.J. Hearn		—		—		32,500		32,500		358,475		358,475
B.J. Fischer		—		—		25,000		25,000		275,750		275,750
P.A. Smith		—		—		12,500		12,500		137,875		137,875
K.C. Williams (1)		—		—		—		—		—		—
J.F. Kyle		—		—		14,500		14,500		159,935		159,935

(1) At the end of 2003, K.C. Williams held options to acquire 475,000 Exxon Mobil Corporation shares of which all options were exercisable. The values of K.C. Williams’s exercisable options were U.S. $4,617,084 at the end of 2003. In 2003, K.C. Williams exercised 26,508 options and realized an aggregate value of U.S. $573,059.

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

Payments to employees who retire

Pension plan table


Remuneration for	Estimated undiscounted payments
determining payments on retirement	on retirement at the age of 65 after years of service indicated below ($)
($)	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
700,000		224,000		280,000		336,000		392,000		448,000
800,000		256,000		320,000		384,000		448,000		512,000
900,000		288,000		360,000		432,000		504,000		576,000
1,000,000		320,000		400,000		480,000		560,000		640,000
1,100,000		352,000		440,000		528,000		616,000		704,000
1,200,000		384,000		480,000		576,000		672,000		768,000
1,300,000		416,000		520,000		624,000		728,000		832,000
1,400,000		448,000		560,000		672,000		784,000		896,000
1,500,000		480,000		600,000		720,000		840,000		960,000
1,600,000		512,000		640,000		768,000		896,000		1,024,000
1,700,000		544,000		680,000		816,000		952,000		1,088,000
1,800,000		576,000		720,000		864,000		1,008,000		1,152,000
1,900,000		608,000		760,000		912,000		1,064,000		1,216,000
2,000,000		640,000		800,000		960,000		1,120,000		1,280,000
2,100,000		672,000		840,000		1,008,000		1,176,000		1,344,000
2,200,000		704,000		880,000		1,056,000		1,232,000		1,408,000
2,300,000		736,000		920,000		1,104,000		1,288,000		1,472,000
2,400,000		768,000		960,000		1,152,000		1,344,000		1,536,000
2,500,000		800,000		1,000,000		1,200,000		1,400,000		1,600,000

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 to which the senior executives subscribe, except for K.C. Williams, 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 employees including 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 pages 39 and 40, corresponds generally to the salary, bonus compensation, and bonus compensation amount elected to be received as deferred share units in that table, and the aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 41 is included in the employee’s “final three year average earnings” for the year of grant of such units. As of February 18, 2004, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement were 37 for T.J. Hearn, 35 for B.J. Fischer, 24 for P.A. Smith and 27 for J.F. Kyle.

K.C. Williams is not a member of the Company’s pension plan but is a member of Exxon Mobil Corporation’s pension plan. Under that plan, K.C. Williams has 31 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 and bonus compensation in the summary compensation table on pages 39, and 40, which remuneration may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.

Composition of the Company’s compensation committee

The executive resources committee of the board of directors, composed of the nonemployee directors, is responsible for decisions on the compensation of senior management above the level of vice-president and for reviewing the executive development system, including specific succession plans for senior management positions. It also reviews corporate policy on compensation. During 2003, the membership of the executive resources committee was as follows:

P. Des Marais II - Chair
R. Phillips - Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young
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. 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, short term 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, short term and long term incentive compensation are made independently of each other.

Base salary

The Company’s salary ranges for executives were increased by four and one half percent in 2002, and three percent in 2003 and two and one half percent in 2004. 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 below the competitive target for the Company’s chief executive officer which is between the median and upper quartile. The target is consistent with the executive resources committee’s view that the 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 90 executives at the end of each year, based on individual performance. The bonuses are drawn from an aggregate bonus amount established annually by the executive resources committee based on the Company’s financial performance, and are granted in tandem with the Company’s earnings bonus units, which are described on page 41.

In 2003, the executive resources committee increased the bonus awards including the grant of earnings bonus units to reflect the Company’s record financial results 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 focussing 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 chief executive officer. T.J. Hearn’s bonus including the grant of earnings bonus units was increased in 2003 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 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.

For selected executives, the executive resources committee allows cash bonus awards to be elected to be received in the form of deferred share units and also awards earnings bonus units as a means of providing additional incentive to promote the Company’s long term financial performance. Eligibility to participate in the deferred share unit and earnings bonus plans is restricted to those executives whose decisions are considered to have a direct effect on the long term financial performance of the Company. In 2003, no executives elected to receive deferred share units and 83 executives were awarded earnings bonus units.

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 and their proper accounting treatment, the Company decided to return to straightforward, 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.

A total of 618 employees, including executives, were granted restricted stock units in 2003.

Submitted on behalf of the executive resources committee:

P.Des Marais II - Chair
R. Phillips - Vice-chair
J.F. Shepard
S.D. Whittaker
V.L. Young

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 18, 2004, 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 251,464,070 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 18, 2004, John F. Kyle was the owner of 3,551 common shares of the Company and held options to acquire 29,000 common shares of the Company and restricted share units to acquire 5,700 common shares of the Company.

The directors and the senior executives of the Company consist of 10 persons, who, as a group, own beneficially 90,024 common shares of the Company, being approximately 0.02 percent of the total number of outstanding shares of the Company, and 85,509 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 314,000 common shares of the Company and held restricted stock units to acquire 109,175 common shares of the Company, as of February 18, 2004.

Equity Compensation Plan Information as of December 31, 2003

Number of securities

remaining available for future

Number of securities to

Weighted-average

issuance under equity

be issued upon exercise

excercise price of

compensation plans (excluding

of outstanding options,

outstanding options,

securities reflected in

warrants and rights

column (a))

Plan category

(a)

(b)

(c)

Equity compensation plans approved by security holders (1)

3,210,200

46.50

13,289,800

Equity compensation plans not approved by security holders (2)

321,162

not applicable

3,178,838

Total

3,531,362

16,468,638

(1) This is the stock option plan, which is described on page 41 of this report.

(2) This is the restricted stock unit plan, which is described on page 41 of this report.

Item 13. Certain Relationships and Related Transactions.

On June 21, 2002, the Company implemented another 12-month “normal course” share-purchase program under which it purchased 6,390,770 of its outstanding shares between June 21, 2002, and June 20, 2003. On June 23, 2003, another 12-month “normal course” program was implemented under which the Company may purchase up to 18,632,218 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 2003, such purchases cost $799 million, of which $555 million was received by ExxonMobil.

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 paid on the loans in 2003 was $14 million. The average effective interest rates for the loans was 3.1 percent for 2003.

The amounts of purchases and sales by the Company and its subsidiaries for other transactions in 2002 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $2,478 million and $950 million, respectively. These transactions were conducted on terms as favorable 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 include amounts paid and received in connection with the Company’s participation in a number of natural resources joint venture operations in Canada.The Company has an existing agreement with ExxonMobil Canada Ltd., to share common business and operational support services that allow the companies to consolidate duplicate work and systems.

Item 14. Principal Accountant Fees and Services.

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, 2003 and December 31, 2002 were as follows:


Dollars (thousands)	2003		2002
Audit Fees		767		747
Audit-Related Fees		62		111
Tax Fees		395		255
All Other Fees		Nil		Nil
Total Fees		1,224		1,113

Audit fees include the audit of the Company’s annual financial statements and a review of the first three quarterly financial statements in 2003.

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.

All other fees would include other services including financial systems consulting and implementation. The Company did not engage the auditors for these types of 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 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 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, Financial Statement Schedules, and Reports on Form 8-K.

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)).

(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); units granted in 1995 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, 1995 (File No. 0-12014); and units granted in 1994 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, 1994 (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) Earnings Bonus Units granted in 2003; Earnings Bonus Unit Plan and units granted in 2002 are (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)) and Earnings Bonus Unit Plan and units granted in 2001 are 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, 2000 (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.


(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, 2003.

(23)		(ii)	(A)	Consent of PricewaterhouseCoopers LLP.

			(B)	Consent of Chief Engineering Officer.

(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, 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3, and payment of processing and mailing costs.

Except for a report on Form 8-K dated October 28, 2003, the Company did not file any other reports on Form 8-K during the fourth quarter of 2003. By the report on Form 8-K dated October 28, 2003, the Company submitted to the Securities and Exchange Commission a press release of the Company on October 23, 2003 disclosing information relating to the Company’s financial condition and results of operations for the fiscal quarter ended September 30, 2003.

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 March 11, 2004 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 March 11, 2004 by the following persons on behalf of the registrant and in the capacities indicated.


Signature		Title

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

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

/s/ Pierre Des Marais II
(Pierre Des Marais II)		Director

/s/ Brian J. Fischer
(Brian J. Fischer)		Director

/s/ Roger Phillips
(Roger Phillips)		Director

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

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

/s/ K. C. Williams
(K.C. Williams)		Director

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

Auditors’ Report

To the Directors of
Imperial Oil Limited

We have audited the consolidated balance sheets of Imperial Oil Limited as at December 31, 2003 and 2002 and the consolidated statements of earnings and cash flows for each of the three years in the period ended December 31, 2003. 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 in accordance with auditing standards generally accepted in Canada and the United States. Those standards require that we plan and perform an audit to obtain reasonable assurance whether the financial statements are free of material misstatement. An audit includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements. An audit also includes assessing the accounting principles used and significant estimates made by management, as well as evaluating the overall financial statement presentation.

In our opinion, these consolidated financial statements present fairly, in all material respects, the financial position of the Company as at December 31, 2003 and 2002 and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2003 in accordance with Canadian generally accepted accounting principles.

We have also audited the “Reconciliation of Canadian and United States generally accepted accounting principles” in Item 6 of this 10-K as at December 31, 2003 and 2002 and for each of the three years in the period ended December 31, 2003. In our opinion, the “Reconciliation of Canadian and United States generally accepted accounting principles” is presented fairly, in all material respects, when read in conjunction with the related consolidated financial statements.

/s/ PricewaterhouseCoopers LLP

PricewaterhouseCoopers LLP
Chartered Accountants
Toronto, Ontario
February 18, 2004

F-2

Consolidated statement of earnings (a)


millions of dollars
For the years ended December 31	2003			2002		2001		2000		1999
Revenues
Operating revenues (b)		19,094			16,890		17,153		17,829		12,763
Investment and other income		114			152		100		222		90

Total revenues		19,208			17,042		17,253		18,051		12,853

Expenses
Exploration		55			30		45		35		28
Purchases of crude oil and products		11,580			10,155		10,134		10,772		7,091
Operating		2,025			1,865		1,830		1,554		1,511
Selling and general		1,269			1,222		1,280		1,271		1,251
Federal excise tax (b)		1,254			1,231		1,180		1,194		1,188
Depreciation and depletion		750			705		718		726		736
Financing costs (note 12)		(87	)		32		152		163		38

Total expenses		16,846			15,240		15,339		15,715		11,843

Earnings before income taxes		2,362			1,802		1,914		2,336		1,010
Income taxes (note 4)		680			578		659		926		382

Net earnings		1,682			1,224		1,255		1,410		628

Per-share information (dollars)
Net earnings – basic and diluted (note 10)		4.52			3.23		3.19		3.38		1.46
Dividends		0.87			0.84		0.83		0.78		0.75

(a) Business segments are reported in note 1.

(b) Operating revenues include federal excise tax of $1,254 million (2002 – $1,231 million; 2001 – $1,180 million).

The information on pages F-6 through F-18 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. The effects of new accounting standards on the consolidated statement of earnings and balance sheet are described in note 2.

F-3

Consolidated statement of cash flows


millions of dollars
inflow (outflow)
For the years ended December 31	2003			2002			2001			2000			1999
Operating activities
Net earnings		1,682			1,224			1,255			1,410			628
Depreciation and depletion		750			705			718			726			736
(Gain)/loss on asset sales, after tax		(10	)		(4	)		(7	)		(96	)		(17	)
Future income taxes and other		(68	)		(144	)		50			(175	)		(324	)

Cash flow from earnings (note 11)		2,354			1,781			2,016			1,865			1,023
Accounts receivable		33			(356	)		504			(358	)		(124	)
Inventories and prepaids		31			51			(11	)		(6	)		(16	)
Income taxes payable		38			(225	)		(408	)		503			225
Accounts payable and other (a)		(262	)		425			(97	)		85			362

Change in operating assets and liabilities		(160	)		(105	)		(12	)		224			447

Cash from operating activities		2,194			1,676			2,004			2,089			1,470

Investing activities
Additions to property, plant and equipment and intangibles		(1,449	)		(1,552	)		(1,070	)		(644	)		(625	)
Proceeds from asset sales		56			61			46			274			88
Proceeds from marketable securities		—			—			—			116			59
Additions to marketable securities		—			—			—			(58	)		(88	)

Cash from (used in) investing activities		(1,393	)		(1,491	)		(1,024	)		(312	)		(566	)

Financing activities
Short-term debt – net		—			(388	)		385			75			—
Long-term debt issued		818			500			—			—			—
Repayment of long-term debt		(818	)		(71	)		(379	)		(68	)		(379	)
Issuance of common shares under stock option plan		2			—			—			—			—
Common shares purchased (note 10)		(799	)		(13	)		(812	)		(1,208	)		—
Dividends paid		(322	)		(319	)		(322	)		(331	)		(319	)

Cash from (used in) financing activities		(1,119	)		(291	)		(1,128	)		(1,532	)		(698	)

Increase (decrease) in cash		(318	)		(106	)		(148	)		245			206
Cash at beginning of year		766			872			1,020			775			569

Cash at end of year (b)		448			766			872			1,020			775

(a) Includes contribution to registered pension plans of $511 million (2002 – $19 million; 2001 – $6 million).

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

F-4

Consolidated balance sheet


millions of dollars
At December 31	2003			2002			2001			2000			1999
Assets
Current assets
Cash		448			766			872			1,020			775
Marketable securities		—			—			—			—			59
Accounts receivable (note 11)		1,315			1,348			992			1,496			1,138
Inventories of crude oil and products (note 11)		407			433			478			421			451
Materials, supplies and prepaid expenses		105			110			116			162			125
Future income tax assets (note 4)		353			323			227			377			285

Total current assets		2,628			2,980			2,685			3,476			2,833
Investments and other long-term assets (note 5)		259			134			139			127			172
Property, plant and equipment (note 1)		9,218			8,525			7,722			7,391			7,549
Goodwill (note 1)		204			204			204			232			260
Other intangible assets (note 1)		52			51			31			18			14

Total assets (note 1)		12,361			11,894			10,781			11,244			10,828

Liabilities
Current liabilities
Short-term debt		72			72			460			75			—
Accounts payable and accrued liabilities (note 13)		2,222			2,114			1,791			1,866			1,731
Income taxes payable		595			557			774			1,182			666
Current portion of long-term debt		501			—			—			300			—

Total current liabilities		3,390			2,743			3,025			3,423			2,397
Long-term debt (note 3)		859			1,466			1,029			1,037			1,352
Other long-term obligations (note 6)		972			1,207			1,098			1,104			1,172
Future income tax liabilities (note 4)		1,362			1,262			1,306			1,476			1,580
Commitments and contingent liabilities (note 9)

Total liabilities		6,583			6,678			6,458			7,040			6,501

Shareholders’ equity
Common shares at stated value (note 10)		1,859			1,939			1,941			2,039			2,209
Net earnings retained and used in the business
At beginning of year		3,277			2,382			2,165			2,118			1,814
Net earnings for the year		1,682			1,224			1,255			1,410			628
Share purchases (note 10)		(717	)		(11	)		(714	)		(1,038	)		—
Dividends		(323	)		(318	)		(324	)		(325	)		(324	)

At end of year		3,919			3,277			2,382			2,165			2,118

Total shareholders’ equity		5,778			5,216			4,323			4,204			4,327

Total liabilities and shareholders’ equity		12,361			11,894			10,781			11,244			10,828

Approved by the directors


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

F-5

Summary of significant accounting policies

Principles of consolidation

The consolidated financial statements include the accounts of the Company and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which the Company 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 proportionate 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.

Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash, marketable securities and long-term debt. Net earnings in this category primarily include debt-related charges and interest income.

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. Items included in capital employed that are not identifiable by segment are allocated according to their nature.

Accounts receivable

Accounts receivable arise mainly from customer purchases of the Company’s products. Interest is accrued on overdue accounts (generally those over 30 days) and is reported in “investment and other income” in the consolidated statement of earnings. Interest accrual will be suspended if collection becomes doubtful. An allowance for doubtful accounts is established based upon an assessment of the collectability of individual larger account balances and upon historical experience, economic and judgmental factors collectively for groups of smaller homogeneous accounts. Accounts are written off when judged to be uncollectable.

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 cost.

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. The Company’s share of the after-tax earnings of these companies is included in “investment and other income” in the consolidated statement of earnings. 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 the 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’s does not invest in these companies in order to remove liabilities from its balance sheet.

F-6

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 follows the successful-efforts method of accounting for its exploration and development activities. Under this method, costs of exploration acreage are capitalized and amortized over the period of exploration or until a discovery is made. Costs of exploration wells are capitalized until their success can be determined. If the well is successful, the costs remain capitalized; otherwise they are expensed. Capitalized exploration costs are re-evaluated annually. All other exploration costs are expensed as incurred. Development costs, including the cost of natural gas and natural gas liquids used as injectants in enhanced (tertiary) oil-recovery projects, are capitalized.

The Company selected the successful-efforts method over the alternative full-cost method of accounting because it provides a more timely accounting of the success or failure of 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.

Depreciation and depletion for assets associated with producing properties begins at the time when production commences on a regular basis. Depreciation for other assets begin 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, including capitalized exploratory drilling and development costs. 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.

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

Goodwill and other intangible assets

Goodwill and intangible assets with indefinite lives are not subject to amortization. These assets are tested for impairment annually or more frequently if events or circumstances indicate the assets 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 earnings.

Asset retirement obligations and other environmental liabilities

No asset retirement obligations are set up for assets with an indeterminate useful life. 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. The fair values of 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 earnings.

F-7

Financial instruments

Financial instruments are initially recorded at historical cost. If subsequent circumstances indicate that a decline in the fair value of a financial asset is other than temporary, the financial asset is written down to its fair value. Unless otherwise indicated, the fair values of financial instruments approximate their recorded amounts.

The fair values of cash, marketable securities, 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 other financial instruments held by the Company 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 makes limited use of derivatives. Derivative instruments are not held for trading purposes.

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 collectability 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 earnings. Delivery costs from final storage to customers are recorded as a marketing expense in selling and general expenses.

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 by the fair value of the unit and is recorded in the consolidated statement of earnings over the vesting period.

As permitted by the new Canadian Institute of Chartered Accountants (CICA) standard on accounting for stock-based compensation, 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 long as the exercise price is equal to the market value at the date of grant.

Consumer taxes

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

Interest costs

Interest costs are expensed as incurred and included in “financing costs” in the consolidated statement of earnings.

Accounting principles

The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in Canada. Form 10-K, filed with the United States Securities and Exchange Commission, includes a description of the differences between GAAP in Canada and in the United States as they apply to the Company.

Effective January 1, 2003, the Company has adopted the new CICA standards on accounting for asset retirement obligations. The impact of adopting this new standard is described in note 2 to the consolidated financial statements on page F-10. The Company has early adopted the additional disclosure requirements by the CICA on employee future benefits, as shown in note 5 on page F-12. The Company has also early adopted the new CICA standard on stock-based compensation with no impact on its accounting or reporting.

F-8

Notes to consolidated financial statements

1. Business segments


	Natural resources (a)									Petroleum products							Chemicals
millions of dollars	2003			2002			2001			2003		2002			2001		2003		2002			2001
Revenues
External sales (c)		3,390			2,573			3,144			14,710		13,362			13,079		994		955			930
Intersegment sales		2,224			2,217			2,166			1,294		1,038			1,300		238		209			245
Investment and other income		34			104			11			54		34			26		—		—			—

Total revenues		5,648			4,894			5,321			16,058		14,434			14,405		1,232		1,164			1,175

Expenses
Exploration		55			30			45			—		—			—		—		—			—
Purchases of crude oil and products		2,357			1,814			2,444			12,066		10,974			10,505		911		830			895
Operating		1,093			990			952			810		761			755		124		115			124
Selling and general (d)		28			21			30			1,123		1,076			1,134		118		115			97
Federal excise tax		—			—			—			1,254		1,231			1,180		—		—			—
Depreciation and depletion (e) (f)		517			479			457			211		203			238		22		23			23
Financing costs (note 12)		1			1			2			2		1			2		—		—			—

Total expenses		4,051			3,335			3,930			15,466		14,246			13,814		1,175		1,083			1,139

Earnings before income taxes		1,597			1,559			1,391			592		188			591		57		81			36
Income taxes (note 4)
Current		535			517			556			66		172			125		13		40			11
Future		(77	)		(14	)		(122	)		119		(111	)		113		7		(11	)		2

Total income tax expense		458			503			434			185		61			238		20		29			13

Net earnings		1,139			1,056			957			407		127			353		37		52			23

Cash flow from earnings		1,576			1,526			1,287			719		216			700		66		63			49

Capital and exploration expenditures (g)		1,007			986			746			478		589			339		41		25			30

Property, plant and equipment
Cost		12,610			11,672			10,785			6,069		5,827			5,462		609		579			554
Accumulated depreciation and depletion		6,813			6,303			5,871			2,856		2,867			2,842		401		383			366

Net property, plant and equipment (h)		5,797			5,369			4,914			3,213		2,960			2,620		208		196			188

Total assets (f)		6,434			6,014			5,385			5,341		5,048			4,348		446		418			373

Total capital employed		3,784			3,325			2,580			2,784		2,484			2,148		246		178			195


	Corporate and other									Consolidated (b)
millions of dollars	2003			2002			2001			2003			2002			2001
Revenues
External sales (c)		—			—			—			19,094			16,890			17,153
Intersegment sales		—			—			—			—			—			—
Investment and other income		26			14			63			114			152			100

Total revenues		26			14			63			19,208			17,042			17,253

Expenses
Exploration		—			—			—			55			30			45
Purchases of crude oil and products		—			—			—			11,580			10,155			10,134
Operating		—			—			—			2,025			1,865			1,830
Selling and general (d)		—			10			19			1,269			1,222			1,280
Federal excise tax		—			—			—			1,254			1,231			1,180
Depreciation and depletion (e) (f)		—			—			—			750			705			718
Financing costs (note 12)		(90	)		30			148			(87	)		32			152

Total expenses		(90	)		40			167			16,846			15,240			15,339

Earnings before income taxes		116			(26	)		(104	)		2,362			1,802			1,914
Income taxes (note 4)
Current		(4	)		(11	)		(13	)		610			718			679
Future		21			(4	)		(13	)		70			(140	)		(20	)

Total income tax expense		17			(15	)		(26	)		680			578			659

Net earnings		99			(11	)		(78	)		1,682			1,224			1,255

Cash flow from earnings		(7	)		(24	)		(20	)		2,354			1,781			2,016

Capital and exploration expenditures (g)		—			—			—			1,526			1,600			1,115

Property, plant and equipment
Cost		—			—			—			19,288			18,078			16,801
Accumulated depreciation and depletion		—			—			—			10,070			9,553			9,079

Net property, plant and equipment (h)		—			—			—			9,218			8,525			7,722

Total assets (f)		448			766			873			12,361			11,894			10,781

Total capital employed		448			816			918			7,262			6,803			5,841

(Continued on following page)

F-9

(a) A significant portion of activities in the natural resources segment is conducted jointly with other companies. The segment includes the Company’s proportionate share of joint-venture activities, as follows:


millions of dollars	2003			2002			2001
Total revenues		2,494			2,357			2,689
Total expenses		1,577			1,520			1,733
Net earnings, after income taxes		664			557			637
Total current assets		302			321			232
Long-term assets		3,553			3,038			2,750
Total current liabilities		913			669			919
Other long-term obligations		302			268			262
Cash flow from earnings		868			767			828
Cash flow from operating activities		883			615			850
Cash from (used in) investing activities		(754	)		(601	)		(301	)

(b) Information is presented as though each segment were a separate business activity. Intersegment sales are made essentially at prevailing market prices. Consolidated amounts exclude intersegment transactions, as follows:


millions of dollars	2003		2002		2001
Purchases of crude oil and products		3,754		3,463		3,710
Operating expense		2		1		1

Total intersegment sales		3,756		3,464		3,711

Intersegment receivables and payables		308		352		198


millions of dollars	2003		2002		2001
Natural resources		1,304		942		1,018
Petroleum products		792		723		770
Chemicals		567		520		503

Total export sales		2,663		2,185		2,291

(d) Consolidated selling and general expenses include delivery costs from final storage to customers of $285 million (2002 – $216 million; 2001 – $244 million).

(e) Goodwill was not amortized in 2003 and 2002 (amortization expense in 2001 – $28 million). 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) Total assets include amortized intangible assets, consisting primarily of acquired customer lists and capitalized computer-software development costs, as follows:


millions of dollars	2003		2002
Cost		87		81
Accumulated amortization		35		30

Net intangible assets		52		51

Customer lists acquired in 2003 were $1 million (2002 – $5 million), those disposed of or retired were $1 million (2002 – $1 million) and no gain or loss was recognized. Capitalized computer-software development costs in 2003 were $6 million (2002 – $20 million). The estimated annual amortization expense for intangible assets in each of the next five years is $8 million.

(g) Capital and exploration expenditures of the petroleum products segment include non-cash capital leases of $22 million in 2003 (2002 – $18 million).

(h) Includes property, plant and equipment under construction of $1,426 million (2002 – $1,275 million).

2. Reporting changes

Effective January 1, 2003, the Company implemented reporting changes to reflect the new accounting standard of the Canadian Institute of Chartered Accountants (CICA) dealing with accounting for asset retirement obligations. The new CICA standard changes the method of accruing for certain site-restoration costs. Under the new standard, the fair values of asset retirement obligations are recorded as liabilities on a discounted basis when they are incurred, which is typically at the time the related assets are installed. Amounts recorded for the related assets are increased by the amount of these obligations. Over time the liabilities will be accreted for the change in their present value, and the initial capitalized costs will be depreciated over the useful lives of the related assets. There are no asset retirement liabilities set up for those assets that have an indeterminate useful life.

Estimated cash flows have been discounted at six percent. Implementation of the new standard has reduced environmental liabilities by $28 million to $462 million as of December 31, 2003. The total undiscounted amount of the estimated cash flows required to settle the obligations is $895 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. This change in accounting standard has no impact on the cash flow profile of the Company. The new standard has been applied retroactively, and the financial statements of prior periods have been restated.

(Continued on following page)

F-10

The impact of adopting the new standard of accounting for asset retirement obligations on the consolidated balance sheet and statement of earnings is:

Changes in consolidated balance sheet


millions of dollars increase/(decrease)	2003			2002
Property, plant and equipment		24			26

Total assets		24			26

Other long-term obligations		(28	)		20
Future income tax liabilities		18			2
Retained earnings		34			4

Total liabilities and shareholders’ equity		24			26

Changes in consolidated statement of earnings


millions of dollars increase/(decrease)	2003			2002			2001
Operating expense		(48	)		(23	)		(25	)
Depreciation and depletion expense		2			2			2

Total expenses		(46	)		(21	)		(23	)
Income taxes		16			7			7

Net earnings		30			14			16

Earnings per share basic and diluted (dollars)		0.08			0.04			0.04

The change in asset retirement obligations liability is as follows:


millions of dollars	2003			2002
Asset retirement obligations liability at January 1		341			334
Additions		—			8
Accretion		20			20
Settlements		(34	)		(21

Asset retirement obligations liability at December 31		327			341

3. Long-term debt

2003

2002

issued

maturity date

interest rate

millions of dollars

1989

September 1, 2004 (2002 – $600 million (U.S.))(a)

Variable

—

946

2002

May 7, 2004 (b)

Variable

—

500

2003

$250 million due May 26, 2005 and

$250 million due August 26, 2005(a)

Variable

500

—

2003

January 19, 2006(a)

Variable

318

—

Long-term debt (at period-end exchange rates)(c)

818

1,446

Capital leases(d)

Total long-term debt(e)

859

1,466

(a) During the first half of 2003, the company redeemed the $600-million (U.S.) variable-rate debt for $818 million (Cdn) and replaced it with long-term variable-rate loans of $818 million (Cdn) from Exxon Overseas Corporation at interest equivalent to Canadian market rates. The average effective interest rate for the loans was 3.1 percent for 2003.

(b) Principal payments on medium-term notes of $500 million, which have been reclassified to current portion of long-term debt in the balance sheet, are due in 2004.

These notes are extendable up to May 7, 2007, at note holders’ discretion.

(c) The estimated fair value of the long-term debt at December 31, 2003, was $818 million (2002 – $1,446 million).

(d) These obligations primarily relate to the capital lease for marine services, which are to be provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The obligations recorded to date represent the costs incurred by the lessor for the construction of the related marine assets.

(e) Principal payments on long-term loans of $500 million are due in 2005 and $318 million are due in 2006. Principal payments on capital leases of approximately $4 million a year are due in each of the next five years.

F-11

4. Income taxes


millions of dollars	2003			2002			2001
Current income tax expense		610			718			679
Future income tax expense (a)		70			(140	)		(20	)

Total income tax expense (b)		680			578			659

Statutory corporate tax rate (percent)		38.5			42.0			42.7
Increase/(decrease) resulting from:
Non-deductible royalty payments to governments		5.0			5.4			7.9
Resource allowance in lieu of royalty deduction		(7.5	)		(11.8	)		(11.4	)
Manufacturing and processing credit		0.2			(0.3	)		(1.3	)
Non-deductible depreciation and amortization		—			—			0.6
Enacted tax rate change		(3.1	)		(0.9	)		(2.1	)
Other		(4.3	)		(2.3	)		(2.0	)

Effective income tax rate		28.8			32.1			34.4

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


millions of dollars	2003			2002
Depreciation and amortization		1,233			1,098
Successful drilling and land acquisitions		495			660
Pension and benefits		(137	)		(229	)
Site restoration		(167	)		(186	)
Net tax loss carryforwards (c)		(57	)		(37	)
Other		(5	)		(44	)

Total future income tax liabilities		1,362			1,262

LIFO inventory valuation		(268	)		(271	)
Other		(85	)		(52	)

Total future income tax assets		(353	)		(323	)

Net future income tax liabilities		1,009			939

(a) The future income tax expense for the year is the difference in net future income tax liabilities at the beginning and end of the year.

(b) Net cash outflow from income taxes, plus investment credits earned, were $573 million in 2003 (2002 – $935 million; 2001 – $1,086 million).

(c) 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.

5. 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 which 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 generally accepted Canadian 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 employee retirement benefits exceeded the fair value of plan assets at December 31, 2003, by $1,357 million (2002 – $1,780 million), 975 million (2002 – $1,426 million) of which was related to pension benefits and $382 million (2002 – 354 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.

(Continued on following page)

F-12

Details of the employee retirement benefits plans are as follows:


	Pension benefits									Other post-retirement benefits
millions of dollars	2003			2002			2001			2003			2002			2001
Components of net benefit expense
Current service cost		71			64			57			5			4			4
Interest cost		219			222			215			22			21			21
Expected return on plan assets		(179	)		(191	)		(257	)		—			—			—
Amortization of prior service cost		25			25			23			—			—			—
Recognized actuarial loss/(gain)		69			34			—			3			1			—

Net benefit expense(a)(e)		205			154			38			30			26			25

Change in benefit obligation
Benefit obligation at January 1		3,530			3,248						354			323
Current service cost		71			64						5			4
Interest cost		219			222						22			21
Amendments		—			27						—			—
Actuarial loss/(gain)		171			196						19			25
Benefits paid		(230	)		(227	)					(18	)		(19	)

Benefit obligation at December 31(b)(e)		3,761			3,530						382			354

Change in plan assets
Fair value of plan assets at January 1		2,104			2,390
Actual return on plan assets		377			(107	)
Company contributions (b)		511			19
Payments directly to participants		24			29
Benefits paid		(230	)		(227	)

Fair value of plan assets at December 31(b)		2,786			2,104

Excess/(deficiency) of plan assets over benefit obligation		(975	)		(1,426	)					(382	)		(354	)
Unrecognized net actuarial (gain)/loss (c)		829			924						52			36
Unrecognized prior service cost (c)		89			114						—			—

Total net liability		(57	)		(388	)					(330	)		(318	)
Less: Prepaid benefit cost (d)		162			—						—			—

Liability recognized (note 6)		(219	)		(388	)					(330	)		(318	)

The benefit obligation at year-end includes funded and unfunded plans, as follows:
Funded plans		3,464			3,230						—			—
Unfunded plans		297			300						382			354

Benefit obligation at December 31		3,761			3,530						382			354

Assumptions

The discount rate used for year-end employee retirement liabilities reflects the rate at which employee retirement liabilities could be effectively settled and is based on the year-end rate of interest on a portfolio of high-quality bonds.


Assumptions used to determine benefit obligations at December 31 (percent)
Discount rate	6.25	6.25		6.25	6.25
Long-term rate of compensation increase	3.50	3.50		3.50	3.50

Assumptions used to determine net benefit expense for years ended December 31 (percent)
Discount rate	6.25	6.75	7.00	6.25	6.75	7.00
Long-term rate of compensation increase	3.50	3.50	3.50	3.50	3.50	3.50
Long-term rate of return on plan assets	8.25	8.25	10.00	—	—	—

(Continued on following page)

F-13

Plan assets

The Company’s pension plan asset allocation at December 31, 2002 and 2003, and target allocation for 2004 are as follows:


			Percentage of
	Target		plan assets
	allocation		at December 31
Asset category (percent)	2004		2003		2002
Equities		50 - 75		62		60
Fixed income		25 - 50		38		40
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 2003 long-term expected rate of return of 8.25 percent used in the calculations of pension expense compares to an actual rate of return over the past decade of 9.5 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 the Company’s common shares 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.

(a) Additional expenses include contributions to defined contribution plans, primarily the employee savings plan, of $31 million in 2003 (2002 – $30 million; 2001 – $23 million).

(b) The most recent independent actuarial valuation was as at June 30, 2003. The measurement date used to determine the plan assets and the benefit obligations was December 31, 2003.

(c) Unrecorded assets/(liabilities) are amortized over the average remaining service life of employees, which for 2004 and subsequent years is 13 years (2003 – 13.5 years; 2002 – 13.5 years).

(d) Prepaid benefit costs are included in investments and other long-term assets on the consolidated balance sheet.

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


	One-percent			One-percent
millions of dollars	increase			decrease
Rate of return on plan assets:
Effect on net benefits expenses		(20	)		20
Discount rate:
Effect on net benefits expenses		(35	)		40
Effect on benefits obligations		(440	)		540
Rate of compensation increases:
Effect on net benefits expenses		25			(25	)
Effect on benefits obligations		130			(115	)

For measurement purposes, a five-percent health-care cost trend rate was assumed for 2003 and thereafter. A one-percent change in the assumed health-care cost trend rate would have the following effects:


	One-percent		One-percent
millions of dollars	increase		decrease
Effect on service and interest cost components		3		(2	)
Effect on other post-retirement benefit obligation		35		(30	)

6. Other long-term obligations


millions of dollars	2003		2002
Employee retirement benefits (note 5)(a)		505		671
Asset retirement obligations and other environmental liabilities (b)		393		454
Other obligations		74		82

Total other long-term obligations		972		1,207

(a) Total recorded employee retirement benefits obligations also include $44 million in current liabilities (2002 – $35 million).

(b) Total asset retirement obligations and other environmental liabilities also include $69 million in current liabilities (2002 – $71 million).

7. Derivative 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.

F-14

8. Incentive compensation programs

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, earnings bonus 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 directors’ 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.

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.

The earnings bonus unit plan is available to selected executives. 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. Earnings bonus units may expire if employment is terminated other than by death or disability.

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.

For deferred share units, a charge is made to expense in the year of grant equal to the cash performance bonus payment and directors’ fees foregone. The Company records expense for incentive share, deferred share and restricted stock units based on changes in the price of common shares in the year. Expense for earnings bonus units is recorded based on the cumulative net earnings per outstanding common share from issue date, up to the maximum settlement value for the units.

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 did not issue incentive stock options in 2003 and has no plans to issue incentive stock options in the future.

The Company does not recognize compensation expense on the issuance of stock options because the exercise price is equal to the market value at the date of grant. If the fair-value-based method of accounting had been adopted, net income and earnings per share (on both a basic and diluted basis) for 2003 would have been reduced by $5 million or $0.01 per share (2002 – $16 million or $0.04 per share). 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.

(Continued on following page)

F-15

A summary of the incentive compensation is as follows:


	Granted in period						Number				Obligations
							of units		Expensed		outstanding at
	Number		To number		To number of		outstanding at		in period		December 31
	of units		of employees		nonemployees		December 31		(millions of dollars)		(millions of dollars)
Incentive share units
2003		—		—		—		6,889,330		109		216
2002		7,000		3		—		8,012,250		39		142
2001		2,752,700		744		—		8,823,125		51		129
Deferred share units
2003		8,253		5		6		43,911		1		3
2002		7,479		6		7		85,523		—		4
2001		15,222		2		5		87,897		1		4
Earnings bonus units
2003		2,221,580		84		—		3,234,250		3		3
2002		1,036,500		75		—		2,169,040		3		3
2001		1,132,540		21		—		1,132,540		—		—
Incentive stock options
2003		—		—		—		3,136,150		—		—
2002		3,210,200		765		—		3,196,700		—		—
Restricted stock units
2003		872,085		613		5		1,660,555		11		11
2002		791,890		690		5		791,890		—		—

9. Commitments and contingent liabilities

At December 31, 2003, the Company had commitments for noncancellable operating leases and other long-term agreements that require the following minimum future payments:


millions of dollars	2004		2005		2006		2007		2008		After 2008
Operating leases (a)		72		59		49		43		34		114
Unconditional purchase obligations (b)		90		47		38		38		38		98
Firm capital commitments (c)		176		8		5		–		–		–
Other long-term agreements (d)		260		235		151		57		57		277

(a) Total rental expense incurred for operating leases in 2003 was $124 million (2002 – $124 million; 2001 – $122 million). Operating lease commitments related to joint-venture activities are 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 $114 million in 2003 (2002 – $115 million; 2001 – $179 million).

(c) Firm capital commitments related to capital projects, shown on an undiscounted basis, totalled approximately $189 million at the end of 2003 (2002 – $284 million). The largest commitments outstanding at year-end 2003 were associated with the Company’s share of capital projects at Syncrude of $56 million and offshore East Coast of $50 million.

(d) Other long-term agreements include primarily raw material supply and transportation services agreements. Total payments under other long-term agreements were $332 million in 2003 (2002 – $288 million; 2001 – $264 million). Payments under other long-term agreements related to joint-venture activities are approximately $44 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 was contingently liable at December 31, 2003, for a maximum of $163 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing agents upon expiry of the agency agreement or the death or resignation of the agent. The Company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees.

     The Company provides in its financial statements for asset retirement obligations and other environmental liabilities (see accounting policies on page F-6). Provision is not made with respect to those manufacturing, distribution and marketing facilities with indeterminate useful lives for which estimates of these future costs cannot be reasonably determined. 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. The actual liability with respect to these lawsuits is not determinable, but management believes, based on the opinion of counsel, that any liability will not materially affect the Company’s consolidated financial position.

F-16

10. Common shares

The number of authorized common shares of the Company as at December 31, 2003 was 450,000,000, unchanged from December 31, 2002 and December 31, 2001.

From 1995 to 2002, the Company purchased shares under eight 12-month normal course share purchase programs, as well as an auction tender. On June 23, 2003, another 12-month normal course share purchase program was implemented with an allowable purchase of 18.6 million shares (five percent of the total at June 19, 2003), 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 2001		202,365,149		5,156
2002		296,052		13
2003		16,259,538		799

Cumulative purchases to date		218,920,739		5,968

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

     The excess of the purchase cost over the stated value of shares purchased has been recorded as a distribution of retained earnings.

     The Company’s common share activity is summarized below:


	Thousands of			At stated value,
	shares			millions of dollars
Balance as at December 31, 2001		379,159			1,941
Issued for cash under stock option plan		–			–
Purchases		(296	)		(2	)

Balance as at December 31, 2002		378,863			1,939
Issued for cash under stock option plan		49			2
Purchases		(16,260	)		(82	)

Balance as at December 31, 2003		362,652			1,859

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


	2003		2002		2001
Net earnings (millions of dollars)		1,682		1,224		1,255
Average number of common shares outstanding, weighted monthly (thousands)		372,011		378,875		393,121
Plus: average number of shares issued on assumed exercise of stock options (thousands)		143		1		–

Weighted average number of diluted common shares (thousands)		372,154		378,876		393,121

Earnings per share — basic (dollars)		4.52		3.23		3.19
Earnings per share — diluted (dollars)		4.52		3.23		3.19

11. Miscellaneous financial information

In 2003, net earnings included an after-tax gain of $9 million (2002 – $2 million loss; 2001 – $18 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, 2003, by $797 million (2002 – $941 million). Inventories of crude oil and products at year-end consisted of the following:


millions of dollars	2003		2002
Crude oil		161		148
Petroleum products		175		198
Chemical products		57		70
Natural gas and other		14		17

Total inventories of crude oil and products		407		433

     Research and development costs in 2003 were $63 million (2002 – $64 million; 2001 – $71 million) before investment tax credits earned on these expenditures of $10 million (2002 – $10 million; 2001 – $6 million). The net costs are included in expenses due to the uncertainty of future benefits.

     Cash flow from earnings included dividends of $15 million received from equity investments in 2003 (2002 – $18 million; 2001 – $10 million).

     Accounts receivable included allowance for doubtful accounts of $13 million in 2003 (2002 – $13 million).

12. Financing costs


millions of dollars	2003			2002			2001
Debt-related interest		38			40			77
Other interest		4			2			4

Total interest expense (a)		42			42			81
Foreign-exchange expense (gain) on long-term debt		(129	)		(10	)		71

Total financing costs		(87	)		32			152

(a) Cash interest payments in 2003 were $38 million (2002 – $41 million; 2001 – $99 million). The weighted-average interest rate on short-term debt in 2003 was 3.1 percent (2002 – 2.4 percent). The average effective interest rate on the Company’s debt was 2.9 percent in 2003 (2002 – 2.1 percent).

F-17

13. Transactions with Exxon Mobil Corporation and affiliated companies (ExxonMobil)

Revenues and expenses of the Company also include the results of transactions with 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, 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 joint-venture operations in Canada. The Company has an existing agreement with ExxonMobil Canada to share common business and operational support services that allow the companies to consolidate duplicate work and systems. The amounts paid or received have been reflected in the statement of earnings as shown in the table below.


millions of dollars	2003		2002		2001
Operating revenues		950		1036		664
Purchases of crude oil and products		2,464		2,134		1,873
Operating expense		14		57		47

Accounts payable due to Exxon Mobil Corporation at December 31, 2003, with respect to the above transactions were $167 million (2002 – $146 million).

During 2003, the Company borrowed $818 million (Cdn) from Exxon Overseas Corporation under two long-term loan agreements as described in note 3. Interest paid on the loans in 2003 was $14 million.

14. Net payments to governments


millions of dollars	2003			2002			2001
Current income tax expense (note 4)		610			718			679
Federal excise tax		1,254			1,231			1,180
Property taxes included in expenses		80			85			86
Payroll and other taxes included in expenses		52			51			47
GST/QST/HST collected (a)		2,015			1,717			1,749
GST/QST/HST input tax credits (a)		(1,705	)		(1,368	)		(1,384	)
Other consumer taxes collected		1,662			1,589			1,585
Crown royalties		418			314			460

Total paid or payable to governments		4,386			4,337			4,402
Less investment tax credits and other receipts		30			12			7

Net payments to governments		4,356			4,325			4,395

Net payments to:
Federal government		2,061			2,171			2,160
Provincial governments		2,215			2,069			2,149
Local governments		80			85			86

Net payments to governments		4,356			4,325			4,395

(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.

15. Reporting investments in mineral interests in oil and gas properties

Statements of Financial Accounting Standards No. 141 (FAS 141), “Business Combinations” and No. 142 (FAS 142), “Goodwill and Other intangible Assets” were issued by the Financial Accounting Standards Board (FASB) in June 2001 and became effective for the Company on July 1, 2001 and January 1, 2002, respectively. Currently, the Emerging Issues Task Force (EITF) is considering the issue of whether FAS 141 and 142 require interests held under oil, gas and mineral leases to be separately classified as intangible assets on the balance sheets of companies in the extractive industries. If such interests were deemed to be intangible assets by the EITF, mineral rights to extract oil and gas for both undeveloped and developed leaseholds would be classified separately from oil and gas properties as intangible assets on the Company’s balance sheet. Historically, the Company has capitalized the cost of oil and gas leasehold interests in accordance with statement of Financial Accounting Standard No. 19 (FAS 19), “Financial Accounting and Reporting by Oil and Gas Producing Companies”. Also, consistent with industry practice, the Company has reported these assets as part of tangible oil and gas property, plant and equipment.

This interpretation of FAS 141 and 142 would only affect the classification of oil and gas leaseholds on the Company’s balance sheet and would not affect total assets, net worth or cash flows. The Company’s results of operations would not be affected, since these leasehold costs would continue to be amortized in accordance with FAS 19. The amount that is subject to reclassification as of December 31, 2003 was $935 million and $1,109 million as of December 31, 2002.

F-18

INDEX TO EXHIBITS

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)).

(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, 2003.

(23) (ii) (A) Consent of PricewaterhouseCoopers LLP.

(B) Consent of Chief Engineering Officer.

(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.


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

111 ST. CLAIR AVENUE WEST, TORONTO, ONT., CANADA		M5W 1K3
(Address of principal executive officers)		(Zip Code)


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


	2003		2002		2001		2000		1999

					(Dollars)
Rate at end of period		0.7738		0.6329		0.6279		0.6669		0.6925
Average rate during period		0.7186		0.6368		0.6444		0.6725		0.6744
High		0.7738		0.6619		0.6697		0.6969		0.6925
Low		0.6349		0.6200		0.6241		0.6410		0.6535


			2003		2002		2001		2000		1999

Average Sales Price:
	Crude oil and natural gas liquids:
		Per cubic metre	$	181.92	$	174.72	$	134.16	$	190.02	$	120.82
		Per barrel		28.92		27.78		21.33		30.21		19.21
	Natural gas:
		Per thousand cubic metres	$	232.99	$	141.91	$	201.92	$	176.15	$	93.90
		Per thousand cubic feet		6.60		4.02		5.72		4.99		2.66
Average Production (Lifting) Costs Per Unit of Net Production (1):
		Per cubic metre	$	63.85	$	48.81	$	46.17	$	47.36	$	37.54
		Per barrel		10.15		7.76		7.34		7.53		5.97


	Crude Oil				Natural Gas				Total

	Gross (1)		Net (2)		Gross (1)		Net (2)		Gross (1)		Net (2)

Conventional wells		2,334		1,321		4,033		2,187		6,367		3,508
Oil Sands (Cold Lake) wells		3,524		3,524		—		—		3,524		3,524


For the fiscal year ended December 31, 2003		Commission file number: 0-12014


PART I
	Item 1. Business
		Financial Information by Operating Segments
		Natural Resources
			Petroleum and Natural Gas Production
			Land Holdings
			Exploration and Development
		Petroleum Products
			Supply
			Refining
			Distribution
			Marketing
		Chemicals
		Research
		Environmental Protection
		Human Resources
		Competition
		Government Regulation
		The Company Online
	Item 2. Properties
	Item 3. Legal Proceedings
	Item 4. Submission of Matters to a Vote of Security Holders
PART II
	Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities
	Item 6. Selected Financial Data
	Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation
	Item 7A. Quantitative and Qualitative Disclosures About Market Risk
	Item 8. Financial Statements and Supplementary Data
	Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure
	Item 9A. Controls and Procedures
PART III
	Item 10. Directors and Executive Officers of the Registrant
	Item 11. Executive Compensation
	Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters
	Item 13. Certain Relationships and Related Transactions
	Item 14. Principal Accountant Fees and Services
PART IV
	Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K
SIGNATURES
INDEX TO FINANCIAL STATEMENTS
Auditors’ Report
	Consolidated statement of earnings
	Consolidated statement of cash flows
	Consolidated balance sheet
	Summary of significant accounting policies
	Notes to consolidated financial statements
INDEX TO EXHIBITS
EX-10(iii)(A)(5)
EX-10(iii)(A)(8)
EX-23(ii)(A)
EX-23(ii)(B)
EX-31.1
EX-31.2
EX-32.1
EX-32.2


			Page
PART I
Item 1. Business				3
	Financial Information by Operating Segments			3
	Natural Resources			4
		Petroleum and Natural Gas Production		4
		Land Holdings		10
		Exploration and Development		10
	Petroleum Products			12
		Supply		12
		Refining		12
		Distribution		13
		Marketing		13
	Chemicals			14
	Research			14
	Environmental Protection			14
	Human Resources			14
	Competition			14
	Government Regulation			15
	The Company Online			15
Item 2. Properties				16
Item 3. Legal Proceedings				16
Item 4. Submission of Matters to a Vote of Security Holders				16
PART II
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities				16
Item 6. Selected Financial Data				17
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operation				21
Item 7A. Quantitative and Qualitative Disclosures About Market Risk				29
Item 8. Financial Statements and Supplementary Data				30
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure				33
Item 9A. Controls and Procedures				34
PART III
Item 10. Directors and Executive Officers of the Registrant				35
Item 11. Executive Compensation				38
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters				45
Item 13. Certain Relationships and Related Transactions				46
Item 14. Principal Accountant Fees and Services				46
PART IV
Item 15. Exhibits, Financial Statement Schedules, and Reports on Form 8-K				47
Index to Financial Statements				F-1
Auditors’ Report				F-2

(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.

(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.

(3)		Gross production available for sale is the Company’s share of production available for sale (excluding purchases) before deducting the shares of mineral owners or governments or both. Net production available for sale excludes those shares. Production available for sale data exclude amounts used for internal consumption and amounts reinjected. Production available for sale in 2001 reflects a change in the supply of natural gas to Company operations from Company produced natural gas to purchased natural gas.

	(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.

(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.


		Hectares												Acres

		Developed				Undeveloped				Total				Developed				Undeveloped				Total

		2003		2002		2003		2002		2003		2002		2003		2002		2003		2002		2003		2002

						(thousands)
Western Provinces Conventional –
	Gross (1)		1,101		1,109		187		205		1,288		1,314		2,721		2,740		462		507		3,183		3,247
	Net (2)		450		454		127		139		577		593		1,112		1,122		314		343		1,426		1,465
Oil Sands (Cold Lake and other) –
	Gross (1)		42		41		175		200		217		241		104		101		432		494		536		595
	Net (2)		41		41		104		114		145		155		101		101		257		282		358		383
Tar Sands (Syncrude and other) –
	Gross (1)		41		20		77		98		118		118		101		49		190		242		291		291
	Net (2)		10		10		32		32		42		42		25		25		79		79		104		104
Canada Lands (3): Conventional –
	Gross (1)		31		31		321		396		352		427		77		77		793		979		870		1,056
	Net (2)		4		4		98		150		102		154		10		10		242		371		252		381
Atlantic Offshore: Conventional –
	Gross (1)		17		17		1,329		1,329		1,346		1,346		42		42		3,284		3,284		3,326		3,326
	Net (2)		2		2		565		565		567		567		5		5		1,396		1,396		1,401		1,401
Total (4):
	Gross (1)		1,232		1,218		2,089		2,228		3,321		3,446		3,045		3,009		5,161		5,506		8,206		8,515
	Net (2)		507		511		926		1,000		1,433		1,511		1,253		1,263		2,288		2,471		3,541		3,734

(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 (farmout) and whereby the Company may earn interests in others’ holdings by performing certain exploratory work (farmin).

	(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.


		2003		2002		2001		2000		1999

Total mined volume (1)
	millions of cubic metres		83.5		77.9		90.3		65.0		76.5
	millions of cubic yards		109.2		102.0		118.3		85.1		100.1
Mined volume to tar sands ratio (1)			1.15		1.05		1.15		0.96		0.99
Tar sands mined
	millions of tonnes		152.4		156.5		164.8		142.2		162.1
	millions of tons		168.0		172.1		181.2		156.4		178.7
Average bitumen grade (weight percent)			11.0		11.2		11.0		11.0		10.8
Crude bitumen in mined tar sands
	millions of tonnes		16.8		17.5		18.1		15.6		17.5
	millions of tons		18.5		19.2		19.9		17.2		19.3
Average extraction recovery (percent)			88.6		89.9		87.0		89.7		91.4
Crude bitumen production (2)
	millions of cubic metres		14.7		15.5		15.5		13.8		15.8
	millions of barrels		92.3		97.8		97.6		86.8		99.6
Average upgrading yield (percent)			86.0		86.3		84.5		84.3		83.9
Gross synthetic crude oil produced
	millions of cubic metres		12.5		13.5		13.1		11.6		13.3
	millions of barrels		78.4		84.8		82.4		73.2		83.6
Company’s net share (3)
	millions of cubic metres		3		3		3		2		3
	millions of barrels		19		21		19		15		20

		Under Canadian GAAP, a prepaid benefit cost was recognized as funding exceeded the book liability for the registered pension plan. Under U.S. GAAP, a minimum pension liability adjustment was required resulting in book liability exceeding funding and no prepaid benefit cost existed. As a result, a reclassification of the prepaid benefit cost from investments and other long term assets to other long term obligation was required under U.S. GAAP.

		An adjustment required by SFAS No. 130 remains a Canadian–U.S. GAAP difference (see note 7).

		The accumulated benefit obligation for all the defined pension plans was $3,347 million and $3,127 million at December 31, 2003 and 2002 respectively.

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

		In 2004, the Company expects to make cash contributions of about $110 million to the pension plans.

(5)		Differences from the adjustments described in notes (1) and (7) result in future (deferred) income tax liabilities (net of future income tax assets) that are $133 million lower at December 31, 2003 than reported under Canadian GAAP (2002 – $202 million lower).

(6)		SFAS No. 107 “Disclosures about Fair Value of Financial Instruments” and SFAS No. 133 “Accounting for Derivative Instruments and Hedging Activities” requires a summary table of the fair value and related carrying amounts of financial instruments. The estimated fair values of the Company’s financial instruments are as follows:

		The fair values of cash, marketable securities, promissory notes, 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 other financial instruments held by the Company are estimated primarily by discounting future cash flows using current rates for similar financial instruments under similar credit risk and maturity conditions.

		No significant energy derivatives, foreign exchange forward contracts or currency and interest rate swaps were transacted by the Company in the past three years.

		Letters of credit and guarantees that are outstanding have not been included in the above table because the fair value of these commitments, determined either by the fees charged to enter into similar agreements or the expected amount required to settle these instruments, is not material.

(7)		SFAS No. 130, “Reporting Comprehensive Income”, adopted for U.S. GAAP reporting, requires that changes in the balances of items in equity from non-shareholder sources be reported in a financial statement as other comprehensive income (loss). The item of comprehensive income (loss) that applies to the Company is the equity adjustment for minimum pension liability as required by SFAS No. 87. The $49 million gain recognized in 2003 (2002 – $238 million loss; 2001 – $52 million loss) represents a reduction of the additional pension liability under U.S. GAAP in the current period.

(8)		SFAS No. 148 “Accounting for Stock-Based Compensation Transition and Disclosure” provides alternative methods of transition for a voluntary change to the fair value based method of accounting for stock based employee compensation. In addition, the disclosure requirements under SFAS No. 148 require more prominent disclosures in the financial statements about the method of accounting for stock based employee compensation and the effect of the method used on reported results.

		Effective January 1, 2003, the Company adopted for all stock-based compensation granted after that date the fair value based recognition provisions as prescribed by SFAS No. 123 “Accounting for Stock Based Compensation”. The following information on stock based compensation meets the new disclosure requirements under SFAS No. 148.

		Stock based compensation

		The Company accounts for its stock based compensation programs, except for the stock option plan, under the fair value based recognition provisions of SFAS No. 123. Under the fair value based method, compensation expense related to the units of these programs is recorded in the consolidated statement of earnings over the vesting period. The Company accounts for its stock option plan by using the intrinsic value method as permitted by SFAS No. 123, and does not recognize compensation expense on the issuance of stock options as long as the exercise price is equal to the market value at date of grant. The Company’s incentive compensation programs are described in note 8 to the financial statements on page F-15.

		If the provisions of SFAS No. 123 had been adopted for all prior years, the impact on compensation expense, net earnings and earnings per share would have been as follows:

(9)		In December 2003, the Financial Accounting Standards Board issued a revised interpretation No. 46 (FIN 46), “Consolidation of Variable Interest Entities”, replacing the original interpretation issued in January 2003. FIN 46 provides guidance on when certain entities should be consolidated or the interests in those entities should be disclosed by enterprises that do not control them through majority voting interest. Under FIN 46, entities are required to be consolidated by enterprises that lack majority voting interest when equity investors of those entities have insignificant capital at risk or they lack voting rights, the obligation to absorb expected losses, or the right to receive expected returns. Entities identified with these characteristics are called variable interest entities and the interests that enterprises have in these entities are called variable interests. These interests can derive from certain guarantees, leases, loans, or other arrangements that result in risks and rewards that are disproportionate to the voting interests in the entities.

		The provisions of FIN 46 must be immediately applied for variable interest entities created after January 31, 2003 and for variable interests in entities commonly referred to as “special purpose entities”. For all other variable interest entities, implementation is required by March 31, 2004.

		This interpretation does not have an impact on the Company as the Company does not have a variable interest in any variable interest entities created before or after January 31, 2003.

		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, 2003. 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.

		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 2003 that has materially affected, or is reasonably likely to materially affect, the Company’s internal control over financial reporting.

(1)		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.

(2)		The Company’s plans for deferred share units and restricted stock units for selected employees and nonemployee directors are described on pages 40 and 41.

(1)		K.C. Williams is on a loan assignment from Exxon Mobil Corporation to the Company. 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 K.C. Williams, 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 pages 40 and 41, dividend equivalent payments on restricted stock units, interest paid in respect of deferred payments of bonuses and reimbursement for any income tax paid as a result of use of Company aircraft. For T.J. Hearn the amounts also include a leased automobile which in 2003 was $44,010 and financial counselling. For T.J. Hearn and P.A. Smith, the U.S. dollar amounts are payments by the Company on account of U.S. income taxes incurred while on assignment in the U.S.A. For K.C. Williams, 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 K.C. Williams 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 T.J. Hearn for 2001, the negative amount was a net payment to the Company as a result of differences in timing of the amounts paid by the Company on account of U.S. income taxes and the amounts he paid to the Company to approximate the income taxes that would have been imposed if he was resident in Canada.

(4)		For 2001, these are the number of units granted under the Company’s plan for incentive share units described on page 40. In 2002, the Company granted instead stock options which are described on page 41.

(5)		These include the number of units granted under the Company’s plan for deferred share units for selected executives described on pages 40 and 41. The values and number of these units, as at the end of 2003, were nil for T.J. Hearn, $1,137,541 for 19,773 units for B.J. Fischer, and nil for P.A. Smith and J.F. Kyle. These amounts include no deferred share units elected to be received in lieu of bonus for 2003 and 2002, and 4,880 share units based on $202,500 of bonus elected to be received as deferred share units for 2001 for B.J. Fischer.

(6)		These also include restricted stock units granted under the Company’s plan for restricted stock units for selected employees and nonemployee directors described on page 41. The values and number of these units, as at the end of 2003, were $6,328,300 for 110,000 units for T.J. Hearn, $2,784,452 for 48,400 units for B.J. Fischer, $1,679,876 for 29,200 units for P.A. Smith and $1,265,660 for 22,000 units for J.F. Kyle. The values of these units granted for 2003, as at the end of 2003, were $3,451,800 for T.J. Hearn, $1,536,051 for B.J. Fischer, $960,751 for P.A. Smith and $655,842 for J.F. Kyle. The values of these units granted for 2002, as at the end of 2002, were $2,243,000 for T.J. Hearn, $973,462 for B.J. Fischer, $560,750 for P.A. Smith and $475,516 for J.F. Kyle.

(7)		K.C. Williams participates in Exxon Mobil Corporation’s restricted stock plan which is similar to the Company’s restricted stock unit plan. The value and number of these units for K.C. Williams, as at the end of the year, were U.S. $1,918,800 for 46,800 units. Under that plan, K.C. Williams was granted 23 400 units in 2003 whose value on the date of grant was U.S. $959,400 and 23 400 units in 2002 whose value on the date of grant was U.S. $810,576.

(8)		Payouts were from 2001 and 2002 earnings bonus units that reached maximum value of $3.00 per unit in 2003. That plan is described on page 41.

(9)		Amounts under “All Other Compensation”, except for K.C. Williams, 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 K.C. Williams, 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 K.C. Williams, the amounts are Exxon Mobil Corporation’s contributions to its employee savings plan.

(1)		At the end of 2003, K.C. Williams held options to acquire 475,000 Exxon Mobil Corporation shares of which all options were exercisable. The values of K.C. Williams’s exercisable options were U.S. $4,617,084 at the end of 2003. In 2003, K.C. Williams exercised 26,508 options and realized an aggregate value of U.S. $573,059.

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

(1)		This is the stock option plan, which is described on page 41 of this report.

(2)		This is the restricted stock unit plan, which is described on page 41 of this report.

(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)).

(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); units granted in 1995 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, 1995 (File No. 0-12014); and units granted in 1994 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, 1994 (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)		Earnings Bonus Units granted in 2003; Earnings Bonus Unit Plan and units granted in 2002 are (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)) and Earnings Bonus Unit Plan and units granted in 2001 are 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, 2000 (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.

(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.


		Pages in this
		Report
Auditors’ report		F-2
Financial statements:
Consolidated statement of earnings for the years 1999, 2000, 2001, 2002 and 2003		F-3
Consolidated statement of cash flows for the years 1999, 2000, 2001, 2002 and 2003		F-4
Consolidated balance sheet as at December 31, 1999, 2000, 2001, 2002 and 2003		F-5
Summary of significant accounting policies		F-6 – F-8
Notes to the consolidated financial statements		F-9 – F18

(a)		Business segments are reported in note 1.

(b)		Operating revenues include federal excise tax of $1,254 million (2002 – $1,231 million; 2001 – $1,180 million).

(d)		Consolidated selling and general expenses include delivery costs from final storage to customers of $285 million (2002 – $216 million; 2001 – $244 million).

(e)		Goodwill was not amortized in 2003 and 2002 (amortization expense in 2001 – $28 million). 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)		Total assets include amortized intangible assets, consisting primarily of acquired customer lists and capitalized computer-software development costs, as follows:

		Customer lists acquired in 2003 were $1 million (2002 – $5 million), those disposed of or retired were $1 million (2002 – $1 million) and no gain or loss was recognized. Capitalized computer-software development costs in 2003 were $6 million (2002 – $20 million). The estimated annual amortization expense for intangible assets in each of the next five years is $8 million.

(g)		Capital and exploration expenditures of the petroleum products segment include non-cash capital leases of $22 million in 2003 (2002 – $18 million).

(h)		Includes property, plant and equipment under construction of $1,426 million (2002 – $1,275 million).

(a)		During the first half of 2003, the company redeemed the $600-million (U.S.) variable-rate debt for $818 million (Cdn) and replaced it with long-term variable-rate loans of $818 million (Cdn) from Exxon Overseas Corporation at interest equivalent to Canadian market rates. The average effective interest rate for the loans was 3.1 percent for 2003.

(b)		Principal payments on medium-term notes of $500 million, which have been reclassified to current portion of long-term debt in the balance sheet, are due in 2004.

		These notes are extendable up to May 7, 2007, at note holders’ discretion.

(c)		The estimated fair value of the long-term debt at December 31, 2003, was $818 million (2002 – $1,446 million).

(d)		These obligations primarily relate to the capital lease for marine services, which are to be provided by the lessor commencing in 2004 for a period of 10 years, extendable for an additional five years. The obligations recorded to date represent the costs incurred by the lessor for the construction of the related marine assets.

(e)		Principal payments on long-term loans of $500 million are due in 2005 and $318 million are due in 2006. Principal payments on capital leases of approximately $4 million a year are due in each of the next five years.