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

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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)

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

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)

(Title of Class)

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

    Yes     þ     No     o

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

    Yes     þ     No     o

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

    Yes     þ     No     o

     As of the last business day of the 2003 second fiscal quarter, the aggregate market value of the voting stock held by non-affiliates of the registrant was Canadian $5,327,412,752 based upon the reported last sale price of such stock on the Toronto Stock Exchange on that date.

     The number of common shares outstanding, as of February 27, 2004, was 361,316,496.

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

     On February 27, 2004, the noon buying rate in New York City for cable transfers in Canadian dollars as certified for customs purposes by the Federal Reserve Bank of New York was $0.7460 U.S. = $1.00 Canadian.

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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

(continued on following page)

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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, 2003, was as follows:

     From 1999, conventional production has declined due to the sale of oil and gas producing properties and the natural decline in the productivity of the Company’s conventional oil fields. In 2000, Cold Lake production declined due to the timing of steaming cycles and Syncrude production decreased because of operating difficulties and extended maintenance to heavy crude oil upgrading equipment. In 2001, Cold Lake net production increased mainly due to the timing of steaming cycles and lower royalties and Syncrude production increased mainly due to the start up of the Aurora mine during the second half of 2000 and fewer disruptions in upgrading operations than the previous year. In 2002, Cold Lake production decreased mainly due to the timing of steaming cycles and Syncrude net production increased mainly due to lower royalties. In 2003, Cold Lake net production increased as a result of a full year of production of stages 11 to 13, which was offset in part by the timing of steaming cycles and higher royalties. Syncrude production decreased in 2003 due to extended maintenance of upgrading facilities.

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     The Company’s average daily production and sales of natural gas during the five years ended December 31, 2003 are set forth below. All gas volumes in this report are calculated at a pressure base of, in the case of cubic metres, 101.325 kilopascals absolute at 15 degrees Celsius and, in the case of cubic feet, 14.73 pounds per square inch at 60 degrees Fahrenheit.

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

     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, 2003, were as follows:

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

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

     In 2000, average production (lifting) costs increased mainly due to higher costs for purchased natural gas at Cold Lake. In 2001, average production (lifting) costs decreased mainly due to higher net production at Cold Lake. In 2002, average production (lifting) costs increased mainly due to lower net production at Cold Lake. In 2003, average production (lifting) costs increased mainly due to higher costs of purchased natural gas at Cold Lake.

     The Company has interests in a large number of facilities related to the production of crude oil and natural gas. Among these facilities are 28 plants that process natural gas to produce marketable gas and recover natural gas liquids or sulphur. The Company is the principal owner and operator of 11 of the plants.

     The Company’s production of conventional and Cold Lake crude oil and natural gas is derived from wells located exclusively in Canada. The total number of producing wells in which the Company had interests at December 31, 2003, is set forth in the following table. The statistics in the table are determined in part from information received from other operators.

     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 2003, net production of crude oil and natural gas liquids was about 2,500 cubic metres (15,900 barrels) per day and gross production was about 3,700 cubic metres (23,200 barrels) per day. The Government of Canada has a one-third carried interest and receives a production royalty of five percent in the Norman Wells oil field. The Government of Canada’s carried interest entitles it to receive payment of a one-third share of an amount based on revenues from the sale of Norman Wells production, net of operating and capital costs. Under a shipping agreement, the Company pays for the construction, operating and other costs of the 870 kilometre (540 mile) pipeline which transports the crude oil and natural gas liquids from the project. In 2003, those costs were about $35 million.

     Most of the larger oil fields in the Western Provinces have been in production for several decades, and the amount of oil that is produced from conventional fields is declining. In some cases, however, additional oil can be recovered by using various methods of enhanced recovery. The Company’s largest enhanced recovery projects are located at the West Pembina oil field.

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

     The Company has a nine percent interest in a project to develop natural gas reserves in the Sable Island area off the coast of the Province of Nova Scotia. About $4 billion has been spent by the participants to the end of 2003 on the project. Production from the Sable Offshore Energy Project began at the end of 1999 and is expected to average about 13 million cubic metres (450 million cubic feet) per day of natural gas and 2,900 cubic metres (18,000 barrels) per day of natural gas liquids through the end of the decade.

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     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 2003, net production from the pilots averaged about 1,700 cubic metres (10,800 barrels) per day and gross production was about 1,900 cubic metres (12,000 barrels) per day. Research at, and operation of, the Cold Lake pilots is continuing.

     In late 1983, the Company commenced the development, in stages, of its oil sands resources at Cold Lake. The initial six stages of this production project were completed by 1986. In 1987, the Company received approval from the Alberta Energy Resources Conservation Board (“AERCB”) to increase the production of the existing six stages from 9,000 cubic metres (57,000 barrels) to 12,000 cubic metres (76,000 barrels) of crude bitumen per day. Also in 1987, the Company received an amended approval from the AERCB for four additional stages (stages seven to ten) of development at Cold Lake. During 2003, average net production from those ten stages was about 13,000 cubic metres (81,800 barrels) per day and gross production was about 14,500 cubic metres (91,000 barrels) per day.

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

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

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

     Most of the production from Cold Lake is sold to refineries in the northern United States. The remainder of the Cold Lake production is shipped to certain of the Company’s refineries and to a heavy oil upgrader in Lloydminster, Saskatchewan.

     The Province of Alberta, in its capacity as lessor of the Cold Lake oil sands leases, is entitled to a royalty on production from the Cold Lake production project, as defined in an agreement with the Province. Near the beginning of 1996, the royalty increased from five percent of production to the greater of five percent of production or 30 percent of an amount based on revenue net of operating and capital costs for the project. The effective royalty on gross production was ten percent in 2003, five percent in 2002 and 2001, 14 percent in 2000 and 18 percent in 1999. In late 2000, the Company entered into an agreement with the Province of Alberta, effective January 1, 2000, on a transitional royalty arrangement that will apply to all of the Company’s current and proposed operations at Cold Lake until the end of 2007, at which time the generic Alberta regulations for royalties that apply to all other oil sands development in the Province will take effect. This transition is expected to be royalty neutral. The Company expects that after 2007 the royalty will be the greater of one percent of gross revenue or 25 percent of an amount based on revenue net of operating and capital costs for the Cold Lake production project and the pilot operations.

     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.

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     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.

     The Syncrude participants agreed with the Province of Alberta, in its capacity as lessor of Syncrude tar sands leases, on an amendment to their revenue sharing agreement, which amendment applies from January 1, 1997. Among other things, this amendment provided for lower royalties on certain new production and for immediate royalty credit on capital expenditures. The royalty was reduced to 25 percent of deemed net profits from Syncrude, as defined in the agreement, on production in excess of 1996 levels for the period 1997 through 2001. As of January 1, 2002, a greater of 25 percent deemed net profit royalty or one percent gross royalty applies to all Syncrude production after the deduction of new capital expenditures.

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

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

     Crude bitumen extracted from tar sands is refined to a marketable hydrocarbon product through a combination of carbon removal in two large, high temperature, fluid coking vessels and by hydrogen addition in high temperature, high pressure, hydrocracking vessels. These processes remove carbon and sulphur and reformulate the crude into a low viscosity, low sulphur, high quality synthetic crude oil product. In 2003, the upgrading process yielded 0.860 cubic metres of synthetic crude oil per cubic metre of crude bitumen (0.860 barrels of synthetic crude oil per barrel of crude bitumen). In 2003, about 55 percent of the synthetic crude oil was processed by Edmonton area refineries and the remaining 45 percent was pipelined to refineries in eastern Canada and the mid-western United States. Electricity is provided to Syncrude by a 270 megawatt electricity generating plant and a 80 megawatt electricity generating plant, both located at Syncrude. The generating plants are owned by the Syncrude participants. The Company’s 25 percent share of net investment in plant, property and equipment, including surface mining facilities, transportation equipment and upgrading facilities is about $2.2 billion.

     In 2003, Syncrude’s net production of synthetic crude oil was about 33,300 cubic metres (209,400 barrels) per day and gross production was about 33,600 cubic metres (211,500 barrels) per day. The Company’s share of net production in 2003 was about 8,300 cubic metres (52,300 barrels) per day.

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     In 2000, Syncrude completed development of the first stage of the Aurora mine. The Aurora investment involved extending mining operations to a new location about 35 km from the main Syncrude site and expanding upgrading capacity. In 2001, the Syncrude owners approved another major expansion of upgrading capacity and further development of the Aurora mine. This project is expected to lead to a total production capacity of about 55,600 cubic metres (350,000 barrels) of synthetic crude oil a day with expected completion in mid-2006. The Company’s share of project costs is expected to be about $2 billion.

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

     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. The Company is assessing a potential project with another company to jointly develop mineable bitumen. A 200 well delineation drilling program was begun in 2003 to better define the available resource. A phased project is being assessed which may have the potential to produce up to a total of 31,800 cubic metres (200,000 barrels) per day.

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     Land Holdings

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