IMPERIAL OIL LTD - Annual Report: 2003 (Form 10-K)

SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

FORM 10-K

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

IMPERIAL OIL LIMITED
(Exact name of registrant as specified in its charter)

        The registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.

        Yes ý No o

        Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant's knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.

        Yes ý No o

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

        Yes ý No o

        As of the last business day of the 2002 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $5,446,609,246 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 28, 2003, was 377,338,757.

        The Index to Exhibits is located on page E-1

TABLE OF CONTENTS

PART I

        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 28, 2003, 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 $0.6720 U.S. = $1.00 Canadian.

2

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

PART I

Item 1.    Business.

        Imperial Oil Limited was incorporated under the laws of Canada in 1880 and was continued under the Canada Business Corporations Act (the "CBCA") by certificate of continuance dated April 24, 1978. The head and principal office of the Company is located at 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, the majority by shareholders with 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 a major producer of natural gas, and the largest refiner and marketer of petroleum products. It is also a major supplier of petrochemicals.

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

Financial Information by Operating Segments

(continued on following page)

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(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.

Natural Resources

Petroleum and Natural Gas Production

        The Company's average daily production of crude oil and natural gas liquids during the five years ended December 31, 2002, was as follows:

(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.

        From 1998, 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. The increase in conventional production in 1999 was due to a reduction in the injection of natural gas liquids to enhance crude oil production which allowed more natural gas liquids to be available for sale. The reduction in net production at Cold Lake in 1999 resulted mainly from the increase in the effective royalty rate on gross production at Cold Lake, which depends in part on profitability. 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.

4

        The Company's average daily production and sales of natural gas during the five years ended December 31, 2002 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.

(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.

        In 1999, production of natural gas increased mainly due to new natural gas field developments and increased compressor capacity at two gas fields. 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, natural gas production decreased primarily due to the depletion of one of the gas caps in Alberta.

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

        The Company's average sales price and production (lifting) costs for conventional and Cold Lake crude oil and natural gas liquids and natural gas for the five years ended December 31, 2002, were as follows:

(1)

Average production (lifting) costs do not include depreciation and depletion of capitalized acquisition, exploration and development costs. Administrative expenses are included. Average production (lifting) costs per unit of net production were computed after converting gas production into equivalent units of oil on the basis of relative energy content.

5

        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. Improved access to U.S. markets for natural gas, resulting from expanded export pipeline capacity from the Province of Alberta in late 1998, allowed Canadian natural gas prices to increase in 1999 and to attain parity with U.S. natural gas markets. Prices for Canadian natural gas increased significantly in 2000 and again in early 2001, 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 1999, increased steam injections at Cold Lake were the main cause for the increase in average production (lifting) costs. 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.

        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, 2002, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

(1)

Gross wells are wells in which the Company owns a working interest.

(2)

Net wells are the sum of the fractional working interests owned by the Company in gross wells, rounded to the nearest whole number.

Conventional Oil and Gas

        The Company has major interests in the Norman Wells oil field in the Northwest Territories and the West Pembina oil field in Alberta. Together they currently account for approximately 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 2002, net production of crude oil and natural gas liquids was about 2,700 cubic metres (17,100 barrels) per day and gross production was about 4,000 cubic metres (25,200 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 2002, those costs were about $40 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 $3 billion has been spent by the participants to the end of 2002 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 14 million cubic metres (500 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids over a 20 year period.

6

Cold Lake

        The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the technology necessary to produce this oil commercially, the Company has conducted experimental pilot operations since 1964 to recover the crude bitumen from wells by means of new drilling and production techniques including steam injection. During 2002, net production from the pilots averaged about 2,100 cubic metres (13,400 barrels) per day and gross production was about 2,240 cubic metres (14,100 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 2002, average net production from those ten stages was about 14,100 cubic metres (88,700 barrels) per day and gross production was about 14,900 cubic metres (93,400 barrels) per day.

        In 2002, the Company spent $81 million to drill 332 development wells. To maintain production at Cold Lake, capital expenditures for additional production wells and associated equipment will be required periodically. The Company plans to spend about $92 million in 2003 on such facilities.

        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 by the second half of 2003. 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. 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 five percent in 2002 and 2001, 14 percent in 2000, 18 percent in 1999 and eight percent in 1998. 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.

Other Oil Sands Activity

        The Company has interests in other oil sands leases in the Athabasca and Peace River areas of northern Alberta. Evaluation wells completed on these leased areas established the presence of very heavy crude oil 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 78,000 leased net hectares (192,000 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.

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Syncrude Mining Operations

        The Company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. The pipeline is currently being expanded to accommodate increased Syncrude production. Since startup in 1978, Syncrude has produced about 1.4 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's Department of Resource Development. 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 has issued an order that expires at the end of 2003 which provides 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. This remission order excludes 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 2002, the upgrading process yielded 0.863 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.863 barrels of synthetic crude oil per barrel of crude bitumen). In 2002, about 60 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 40 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 $1.6 billion.

8

        In 2002, Syncrude's net production of synthetic crude oil was about 36,100 cubic metres (227,000 barrels) per day and gross production was about 36,500 cubic metres (229,000 barrels) per day. The Company's share of net production in 2002 was about 9,000 cubic metres (56,800 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. The first stage of the Aurora mine is expected to increase the Company's share of Syncrude's gross production to about 9,500 cubic metres (60,000 barrels) per day in 2003.

        In 2001, the Syncrude owners approved another major expansion of upgrading capacity to convert crude bitumen into synthetic crude oil. This project, when combined with further development of the Aurora deposits, is expected to increase the Company's share of Syncrude's gross production to more than about 14,200 cubic metres (89,000 barrels) per day. Startup of production is expected in early 2005, and the Company's share of the project costs is expected to be about $1.2 billion.

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

(1)

Includes pre-stripping of mine areas and reclamation volumes.

(2)

Crude bitumen production is equal to crude bitumen in mined tar sands multiplied by the average extraction recovery and the appropriate conversion factor.

(3)

Reflects the Company's 25 percent interest in production, less applicable royalties payable to the Province of Alberta.

Other Tar Sands Activity

        Prior to October, 2002, the Company held a 75 percent interest in approximately 13,600 leased hectares (33,800 acres) and a 20 percent interest in about 13,900 leased hectares (34,800 acres) in the Kearl Lake area in the Athabasca area of northern Alberta containing tar sands. In October 2002, the Company completed transactions that resulted in the Company obtaining a 100 percent interest in approximately 16,500 hectares (40,700 acres) of surface mineable tar sands. The Company continues to evaluate these leases to determine their potential for future development.

9

Land Holdings

        At December 31, 2002 and 2001, the Company held the following oil and gas rights, and tar sands leases:

(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).

Exploration and Development

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

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

        The following table sets forth the conventional and oil sands net exploratory and development wells that were drilled or participated in by the Company during the five years ended December 31, 2002.

        The oil sands development wells in 2002 include 267 wells related to the development of stages 11 to 13 at Cold Lake with the balance for productivity maintenance in existing stages and prior to 2001 also reflect drilling for stages 9 and 10 at Cold Lake, and the addition of productivity maintenance wells.

        At December 31, 2002, the Company was participating in the drilling of 44 gross (35 net) exploratory and development wells.

10

Western Provinces

        In 2002, the Company had a working interest in four gross (three net) exploratory wells and 491 gross (378 net) development wells, while retaining an overriding royalty in an additional 11 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 totaling 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 Mackenzie Valley Aboriginal Pipeline Corporation ("MVAPC"), 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 MVAPC their intention to begin preparing the regulatory applications needed to develop the gas resources, including construction of a Mackenzie Valley pipeline.

        The Company retains an 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 licenses by participating in the first exploration well. 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.

11

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 2002, capital expenditures of about $370 million were made at the Company's refineries. About 80 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, 2002, and the daily rated capacities of the refineries at December 31, 1997 and 2002, were as follows:

(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 2002, the same as for the previous year.

Distribution

        The Company maintains a nation-wide distribution system, including 29 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, 2002, the Company owned and operated two barges. These vessels are used primarily for domestic transportation of refined petroleum products.

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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 870 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 110 sales facilities, of which about 40 also sell fertilizers to the western Canadian farm markets under the brand name Engro. 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, is expected to be completed in 2003.

        Heating oil and related equipment services are 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, 2002 are set out in the following table:

(1)

Includes 1.0 thousand cubic metres (6.4 thousand barrels) per day of butane for 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, 2002, were as follows:

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

        During 2002, the Company closed or debranded about 140 Esso retail sites, about 60 of which were Company owned, and added about 70 sites. The Company's average annual throughput per Esso retail outlet was 3.3 million litres, an increase of 0.3 million litres from 2001. Average throughput per Company owned Esso retail outlet was 4.9 million litres in 2002, an increase of about 0.5 million litres from 2001.

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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, 2002, were as follows:

Research

        In 2002, the Company's research expenditures in Canada, before deduction of investment tax credits, were $50 million, as compared with $37 million in 2001 and $31 million in 2000. 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 2002. 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 2002. 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 $510 million on environmental protection and facilities. In 2002, the Company's capital expenditures relating to environmental protection totalled approximately $360 million, and are expected to be about $275 million in 2003. 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 $575 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 2002 were approximately $15 million.

Human Resources

        At December 31, 2002, the Company employed full-time approximately 6,500 persons compared with about 6,700 at the end of 2001 and 2000. 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.

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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 Web site www.imperialoil.ca contains a variety of corporate and investor information which are available free of charge, including the Company's Form 10-K and quarterly reports on Form 10-Q. The Company's current reports on Form 8-K will also be made available on the Web site for reports filed during and after 2003.

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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 and Related Stockholder Matters.

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.

        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