IMPERIAL OIL LTD - Annual Report: 2004 (Form 10-K)

SECURITIES AND EXCHANGE COMMISSION

FORM 10-K

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

IMPERIAL OIL LIMITED

Registrant’s telephone number, including area code:

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

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.

Yesþ Noo

     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.

Yesþ Noo

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

Yesþ Noo

     As of the last business day of the 2004 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $ 6,768,415,742 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 18, 2005, was 342,365,873.

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, 2005, 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 $0.8133 U.S. = $1.00 Canadian.

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     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, 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.

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

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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, 2004, was as follows:

     From 2000 through 2003, 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 2004, conventional production increased primarily due to increased natural gas liquids production from the Wizard Lake gas cap. 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. In 2004, Cold Lake production declined due to the timing of steaming cycles and higher royalty, and Syncrude production increased due to fewer disruptions in upgrading operations than in 2003.

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The Company’s average daily production and sales of natural gas during the five years ended December 31, 2004 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 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. In 2004 natural gas production increased primarily due to increased production from the Wizard Lake gas cap.
     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, 2004, 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 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. In 2004, average production (lifting) costs decreased mainly due to higher production from the Wizard Lake gas cap.
     The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 27 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, 2004, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

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      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 2004, net production of crude oil and natural gas liquids was about 2,400 cubic metres (14,800 barrels) per day and gross production was about 3,500 cubic metres (22,000 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 2004, 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 2004 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 12 million cubic metres (420 million cubic feet) per day of natural gas and 3,200 cubic metres (20,000 barrels) per day of natural gas liquids through the end of the decade.

     Cold Lake
     The Company holds about 78,000 leased hectares (192,000 acres) of oil sands near Cold Lake, Alberta. This oil sands deposit contains a very heavy crude oil (crude bitumen). To develop the technology necessary to produce this oil commercially, the Company has conducted experimental pilot operations since 1964 to recover the crude bitumen from wells by means of new drilling and production techniques including steam injection. Research at, and operation of, the Cold Lake pilots is continuing.
     In late 1983, the Company commenced the development, in stages, of its oil sands resources at Cold Lake. During 2004, average net production at Cold Lake was about 17,700 cubic metres (111,500 barrels) per day and gross production was about 20,000 cubic metres (125,800 barrels) per day.
     To maintain production at Cold Lake, capital expenditures for additional production wells and associated facilities will be required periodically. In 2004, the Company spent $127 million on a development drilling program of 218 wells on existing stages. In 2005, a development drilling program of more than 150 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.
     In 2004, the Company received regulatory approval for further expansion of its operations at Cold Lake. Production is expected to begin in 2006 from part of the approved expansion, the development of which is expected to cost about $300 million and is expected to have gross production of about 4,770 cubic metres (30,000 barrels) per day by the end of the decade. Development plans for the remainder of the approved expansion are being examined to reduce development costs through increased integration with existing infrastructure. Most of the production from Cold Lake is sold to refineries in the northern United States. The remainder of the Cold Lake production is shipped to certain of the Company’s refineries and to a heavy oil upgrader in Lloydminster, Saskatchewan.

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      The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is entitled to a royalty on production from the Cold Lake production project. In late 2000, the Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the Company’s current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for royalties that apply to all other oil sands development in the Province will take effect. This transition is expected to be royalty neutral. The effective royalty on gross production was 11 percent in 2004, 10 percent in 2003, five percent in 2002 and 2001, and 14 percent in 2000. 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 68,000 leased net hectares (168,000 net acres) in the Athabasca area where the oil sands are buried too deeply to permit recovery by surface mining methods. The Company, as part of an industry consortium and several joint ventures, has been involved in recovery research and pilot studies and in evaluating the quality and extent of the oil sands.

     Syncrude Mining Operations
      The Company holds a 25 percent participating interest in Syncrude, a joint venture established to recover shallow deposits of tar sands using open-pit mining methods, to extract the crude bitumen, and to produce a high-quality, light (32 degree API), sweet, synthetic crude oil. The Syncrude operation, located near Fort McMurray, Alberta, exploits a portion of the Athabasca Oil Sands Deposit. The location is readily accessible by public road. The produced synthetic crude oil is shipped from the Syncrude site to Edmonton, Alberta by Alberta Oil Sands Pipeline Ltd. 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.
     As of January 1, 2002, a greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all Syncrude production after the deduction of new capital expenditures.
     The Government of Canada had issued an order that expired at the end of 2003 which provided for the remission of any federal income tax otherwise payable by the participants as the result of the non-deductibility from the income of the participants of amounts receivable by the Province of Alberta as a royalty or otherwise with respect to Syncrude. That remission order excluded royalty payable on production for the Aurora project.
     Operations at Syncrude involve three main processes: open pit mining, extraction of crude bitumen and upgrading of crude bitumen into synthetic crude oil. In the Base mine (lease 17), the mining and transportation system uses draglines, bucketwheel reclaimers and belt conveyors. In the North mine (leases 17 and 22) and in the Aurora mine (leases 10, 12 and 34), truck, shovel and hydrotransport systems are used. The extraction facilities, which separate crude bitumen from sand, are capable of processing approximately 495,000 tonnes (545,000 tons) of tar sands a day, producing about 18 million cubic metres (110 million barrels) of crude bitumen a year. This represents recovery capability of about 92 percent of the crude bitumen contained in the mined tar sands.

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     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 2004, the upgrading process yielded 0.855 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.855 barrels of synthetic crude oil per barrel of crude bitumen). In 2004, about 45 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 55 percent was pipelined to refineries in eastern Canada or exported to the United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. The Company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $2.8 billion.
     In 2004, Syncrude’s net production of synthetic crude oil was about 37,500 cubic metres (235,600 barrels) per day and gross production was about 37,800 cubic metres (238,000 barrels) per day. The Company’s share of net production in 2004 was about 9,400 cubic metres (58,900 barrels) per day.
     In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 35 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. The second Aurora mining and extraction development became fully operational in 2004. The increased upgrading capacity is expected to be available in 2006. These projects are expected to lead to a total production capacity of about 56,500 cubic metres (355,000 barrels) of synthetic crude oil a day when completed. The Company’s share of project costs is expected to be about $2 billion of which about $1.6 billion has been incurred to the end of 2004.
     The following table sets forth certain operating statistics for the Syncrude operations:

     Other Tar Sands Activity
     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. A 400 well delineation drilling program to better define the available resource was begun in 2003 and is expected to be completed in 2005. The Company is assessing a potential phased project with another company to jointly develop mineable bitumen, which may have the potential to produce up to approximately 47,700 cubic metres (300,000 barrels) per day. The Company plans on filing a regulatory application with the Alberta Energy and Utilities Board for the Kearl oil sands project in 2005.

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     Land Holdings
     At December 31, 2004 and 2003, the Company held the following oil and gas rights, and tar sands leases:

     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 218 oil sands development wells in 2004 were related to productivity maintenance in existing stages at Cold Lake. In 2004, there was an increase in gas development wells related to an increase in drilling in shallow gas fields.
     At December 31, 2004, the Company was participating in the drilling of 17 gross (11 net) exploratory and development wells.

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     Western Provinces
     In 2004, the Company had a working interest in seven gross (three net) exploratory wells and 483 gross (211 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 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 2004, the four companies and the APG signed agreements covering the development and operations of the Mackenzie Valley pipeline. In October 2004, the main regulatory applications and environmental impact statement for the project were filed with the National Energy Board and other boards, panels and agencies responsible for assessing and regulating energy developments in the Northwest Territories. The regulatory review process is expected to take up to 24 months. The initial cost for the project is estimated to be about $7 billion with the Company’s share of the cost estimated to be about $3 billion.
     Other land holdings include majority interests in 20 and minority interests in six “significant discovery” licences granted by the Government of Canada as the result of previous oil and gas discoveries, all of which are managed by the Company and majority interests in two and minority interests in 16 other “significant discovery” licences and one production licence, managed by others.

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

     Atlantic Offshore
     The Company manages five “significant discovery” licences granted by the Government of Canada in the Atlantic offshore. The Company also has minority interests in 27 “significant discovery” licences, and five production licences, managed by others.
     In 2004 the Company’s 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 expired.
     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. One exploratory well was completed in 2004 in that area, without commercial success.
     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. In 2004, five of these exploration licences totalling about 196,000 gross hectares (484,000 gross acres) were allowed to expire. 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, and 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 earned 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 2004, the Company allowed the undrilled licence to expire while retaining its 70 percent interest in the other exploration licence for about 113,000 gross hectares (279,000 gross acres). 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). In 2004, these licences were allowed to expire. The Company is not planning further exploration in these areas.

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      In early 2004, the Company acquired a 25 percent interest in eight deep water exploration licences offshore Newfoundland in the Orphan Basin for about 2,125,000 gross hectares (5,251,000 gross acres). In February of 2005, the Company reduced its interest to 15% through an agreement with another company. The Company’s share of proposed exploration spending is about $100 million with a minimum commitment of about $25 million. In 2004, the Company participated in a 3-D seismic survey in this area.
      In 2004, the Company converted nine exploration permits in the Laurentian basin area offshore Newfoundland and Labrador to a single exploration licence for about 192,000 gross hectares (474,000 gross acres). The Company holds a 100 percent interest in this licence.

     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 2004, capital expenditures of about $159 million were made at the Company’s refineries. About 60 percent of those expenditures were on new facilities required to meet Government of Canada regulations on the sulphur level in motor fuels with the remaining expenditures being on safety and efficiency improvements, and environmental control projects.
      The approximate average daily volumes of refinery throughput during the five years ended December 31, 2004, and the daily rated capacities of the refineries at December 31, 1999 and 2004, were as follows:

     Refinery throughput was 93 percent of capacity in 2004, three percent higher than the previous year.

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      Distribution
      The Company maintains a nation-wide distribution system, including 30 primary terminals, to handle bulk and packaged petroleum products moving from refineries to market by pipeline, tanker, rail and road transport. The Company owns and operates crude oil, natural gas liquids and products pipelines in Alberta, Manitoba and Ontario and has interests in the capital stock of two products and three crude oil pipeline companies.
      At December 31, 2004, the Company owned and operated two barges. These vessels are used primarily for domestic transportation of refined petroleum products.

      The total domestic sales of petroleum products as a percentage of total sales of petroleum products during the five years ended December 31, 2004, were as follows:

      The Company continues to evaluate and adjust its Esso service station and distribution system to increase productivity and efficiency.
      During 2004, the Company closed or debranded about 140 Esso service stations, about 60 of which were Company owned, and added about 50 sites. The Company’s average annual throughput in 2004 per Esso service station was 3.4 million litres, the same as for 2003. Average throughput per Company owned Esso service station was 5.5 million litres in 2004, an increase of about 0.3 million litres from 2003.

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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, 2004, were as follows:

Research
      In 2004, the Company’s research expenditures in Canada, before deduction of investment tax credits, were $40 million, as compared with $36 million in 2003 and $50 million in 2002. 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 2004. The Company also participated in bitumen recovery and processing research for tar sands development through its interest in Syncrude, which maintains research facilities in Edmonton, Alberta and through research arrangements with others.
      In Company laboratories in Sarnia, Ontario, research is mainly conducted on the development and improvement of lubricants and fuels. About 120 people were employed in this type of research at the end of 2004. 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 $825 million on environmental protection and facilities. In 2004, the Company’s capital expenditures relating to environmental protection totaled approximately $130 million, and are expected to be about $350 million in 2005. The increased environmental expenditures over the past three years primarily reflect spending on two major projects. One project completed in 2004, costing $600 million, reduced sulphur in motor gasolines, meeting a requirement of the Government of Canada a year in advance. The second project underway in 2004 is to meet a new Government of Canada regulation requiring ultra-low sulphur on-road diesel fuel commencing in 2006 and which is to be fully implemented in 2007. In 2004, there were capital expenditures of about $90 million on this second project, which is expected to cost about $500 million when completed. Capital expenditures on safety related projects in 2004 were approximately $20 million.

Human Resources
      At December 31, 2004, the Company employed full-time approximately 6,100 persons compared with about 6,300 at the end of 2003 and 6,500 at the end of 2002. About eight 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 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.

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Item 2. Properties.
      Reference is made to Item 1 above, and for the reserves of the Syncrude mining operations and oil and gas producing activities, reference is made to Item 8 of this report.

Item 3. Legal Proceedings.
      Not applicable.

Item 4. Submission of Matters to a Vote of Security Holders.
      Not applicable.

PART II

Information for Security Holders Outside Canada
      Cash dividends paid to shareholders resident in countries with which Canada has an income tax convention are usually subject to a Canadian nonresident withholding tax of 15 percent.
      The withholding tax is reduced to five percent on dividends paid to a corporation resident in the United States that owns at least 10 percent of the voting shares of the Company.
      The Company is a qualified foreign corporation for purposes of the new reduced U.S. capital gains tax rates (15 percent and 5 percent for certain individuals) which are applicable to dividends paid by U.S. domestic corporations and qualified foreign corporations.
      There is no Canadian tax on gains from selling shares or debt instruments owned by nonresidents not carrying on business in Canada.

Quarterly Financial and Stock Trading Data

      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 28, 2005, there were 14,868 holders of record of common shares of the Company.
      During the period October 1, 2004 to December 31, 2004, the Company issued 85,925 common shares for $46.50 per share as a result of the exercise of stock options by the holders of the stock options, who are all employees or former employees of the Company, in sales of those common shares outside the U.S.A. which were not registered under the Securities Act in reliance on Regulation S thereunder.

Issuer purchases of equity securities (1)

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Item 6. Selected Financial Data.

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

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

Overview
      While commodity prices remain volatile on a short term basis depending upon supply and demand, the Company’s investment decisions are based on long term outlooks. The corporate plan is a fundamental annual management process that is the basis for setting near term operating and capital objectives in addition to providing the longer term economic assumptions used for investment evaluation purposes. Annual plan volumes are based on individual field production profiles updated annually. Prices for natural gas and other products used for investment evaluation purposes are based on corporate plan assumptions that are developed annually. Potential investment opportunities are tested over a wide range of economic scenarios to establish the resiliency of each opportunity. Once investments are made, a reappraisal process is completed.

Business environment and outlook
 
Natural resources
      The Company produces crude oil and natural gas for sale into large North American markets. Economic and population growth are expected to remain the primary drivers of energy demand. The Company expects the global economy to grow at an average rate of about three percent per year through 2030. World energy demand should grow by about two percent per year, and oil and gas are expected to account for about 60 percent of world energy supply by 2030. Over the same period, the Canadian economy is expected to grow at an average rate of two percent per year, and Canadian demand for energy at a rate of about one percent per year. Oil and gas are expected to continue to supply two-thirds of Canadian energy demand.
It is expected that Canada will also be a growing supplier of energy to U.S. markets through this period.
      Oil products are the transportation fuel of choice for the world’s fleet of cars, trucks, trains, ships and airplanes. Primarily because of increased demand in developing countries, oil production is expected to increase by 50 percent or nearly 30 million barrels per day over the next three decades. Canada’s oil sands represent an important additional source of supply.
      Natural gas is expected to be the fastest growing primary energy source globally, capturing about one-third of all incremental energy growth and approaching one quarter of global energy supplies. Natural gas production from mature established regions in the United States and Canada is not expected to meet increasing demand, strengthening the market opportunities for new gas supply from Canada’s frontier areas.
      Crude oil and natural gas prices are determined by global and North America markets and are subject to changing supply and demand conditions. These can be influenced by a wide range of factors including economic conditions, international political developments and weather. In the past, crude oil and natural gas prices have been volatile and the Company expects that volatility to continue.
      The Company has a large and diverse portfolio of oil and gas resources, both developed and undeveloped, in Canada, which helps reduce the risks of dependence on potentially limited supply sources in the upstream. With the relative maturity of conventional production in the established producing areas of Western Canada, the Company’s production is expected to come increasingly from frontier and unconventional sources, particularly oil sands and natural gas from the Far North, where the Company has large undeveloped resource opportunities.

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Petroleum products
      The downstream continues to experience ongoing volatility in industry margins. Refining margins are the difference between what a refinery pays for its raw materials (primarily crude oil) and the wholesale market prices for the range of products produced (primarily gasoline, diesel fuel, heating oil, jet fuel and fuel oil). Crude oil and many products are widely traded with published international prices. Prices for those commodities are determined by the marketplace, often an international marketplace, and are impacted by many factors, including global and regional supply/demand balances, inventory levels, refinery operations, import/export balances, seasonality and weather. Canadian wholesale prices in particular are largely determined by wholesale prices in adjacent U.S. regions. These prices and factors are continually monitored and provide input to operating decisions about which raw materials to buy, facilities to operate and products to make. However, there are no reliable indicators of future market factors that accurately predict changes in margins from period to period.
      The Company’s downstream strategies are to provide customers with quality service at the lowest total cost offer, have the lowest unit costs amongst the Company’s competitors, ensure efficient and effective use of capital and capitalize on integration with the Company’s other businesses. The Company owns and operates four refineries in Canada with distillation capacity of 502,000 barrels a day and lubricant manufacturing capacity of 9,000 barrels a day. The Company’s fuels marketing business includes retail operations across Canada serving customers through about 2,000 Esso-branded service stations, of which about 720 are Company owned or leased, and wholesale and industrial operations through a network of 30 distribution terminals.

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

Results of operations
      Net income in 2004 was $2,052 million or $5.74 a share – the best year on record – compared with $1,705 million or $4.58 a share in 2003 (2002 – $1,214 million or $3.20 a share). Higher realizations for crude oil, stronger industry refining and petrochemical margins, and higher volumes of Syncrude production, natural gas and petroleum products contributed positively to net income, partly offset by lower marketing margins. Compared with 2003, these favourable operating results were partly offset by the combined negative effects of a higher Canadian dollar on resource and product prices of about $260 million, the absence of favourable foreign exchange effects on the Company’s U.S. dollar denominated debt of about $110 million, and lower benefits from tax matters of about $100 million.
      Total revenues were $22.5 billion, up about 17 percent from 2003.

Natural Resources
      Net income from natural resources was a record $1,487 million, up from $1,143 million in 2003 (2002 –$1,042 million). The positive earnings effects of improved realizations for crude oil and natural gas, combined with higher Syncrude, natural gas and natural gas liquids (NGLs) volumes were partly offset by lower Cold Lake bitumen production, lower benefits from tax matters and the negative effects of a higher Canadian dollar.
      Resource revenues were $6.6 billion, up from $5.6 billion in 2003 (2002 – $4.9 billion). The main reasons for the increase were higher prices for crude oil and increased natural gas and Syncrude volumes.

Financial statistics

      U.S. dollar world oil prices were considerably higher in 2004 than in the previous year. The annual average price of Brent crude oil, the most actively traded North Sea crude and a common benchmark of world oil markets, was $38 (U.S.) a barrel in 2004, a more than 30 percent increase over the average price of $29 in 2003 (2002 – $25).
      However, increases in the Company’s Canadian dollar realizations for conventional crude oil and Cold Lake bitumen were dampened by the effects of a higher Canadian dollar. Average realizations for conventional crude oil during the year were $48.96 (Cdn) a barrel, an increase of 22 percent from that of $40.10 in 2003 (2002 – $36.81).

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      Average prices for Canadian heavy crude oil were higher in 2004, but by less than the relative increase in light crude oil prices, as increased supply of heavy crude oil widened the average spread between light and heavy crude. The price of Bow River, a benchmark Canadian heavy crude oil, increased by 15 percent in 2004, much less than the increase in prices for Canadian light crude oil. Cold Lake bitumen realizations in U.S. dollars averaged 19 percent higher in 2004 than in 2003. Average realizations for Cold Lake bitumen were only about 10 percent higher than the previous year, reflecting the effect of the higher Canadian dollar.
      Prices for Canadian natural gas in 2004 were essentially unchanged from the previous year. The average of 30 day spot prices for natural gas at the AECO hub in Alberta was about $6.80 a thousand cubic feet in 2004, compared with $6.70 in 2003 (2002 – $4.10).
      The Company’s average realizations on natural gas sales were $6.78 a thousand cubic feet, compared with $6.60 in 2003 (2002 – $4.02).

Average realizations and prices

      Gross production of crude oil and NGL increased to 262,000 barrels a day from 256,000 barrels in 2003 (2002 – 247,000).
      Gross bitumen production at the Company’s wholly owned facilities at Cold Lake decreased to 126,000 barrels a day from 129,000 barrels in 2003 (2002 – 112,000), due to the cyclic nature of production at Cold Lake.
      Production from the Syncrude operation, in which the Company has a 25 percent interest, increased during 2004 as a result of reduced turnaround activities. Gross production of upgraded crude oil increased to a record 238,000 barrels a day from 211,000 barrels in 2003 (2002 – 229,000). The Company’s share of average gross production increased to 60,000 barrels a day from 53,000 barrels in 2003 (2002 – 57,000).
      Gross production of conventional oil decreased to 43,000 barrels a day from 46,000 barrels in 2003 (2002 – 51,000) as a result of the natural decline in Western Canadian reservoirs.
      Gross production of NGLs available for sale averaged 33,000 barrels a day in 2004, up from 28,000 barrels in 2003 (2002 – 27,000).
      Gross production of natural gas increased to 569 million cubic feet a day from 513 million in 2003 (2002 – 530 million). Higher natural gas and NGL volumes were mainly a result of the full year production of natural gas from the Wizard Lake gas cap in Alberta, which began in the third quarter of 2003.

Crude oil and NGLs – production and sales (a)