SECURITIES AND EXCHANGE COMMISSION
FORM 10-K
ANNUAL REPORT PURSUANT TO SECTION 13 OR 15 (d) OF THESECURITIES 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.
YesþNoo
Disclosure of delinquent filers pursuant to Item 405 of Regulation S-K is not contained herein, and will not be contained, to the best of registrant’s knowledge, in definitive proxy or information statements incorporated by reference in Part III of this Form 10-K or any amendment to this Form 10-K.
The registrant is an accelerated filer (as defined in Rule 12 b-2 of the Securities Exchange Act of 1934).
As of the last business day of the 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)
Natural gas – production and sales (a)
Operating costs increased by seven percent in 2004. The main factor was higher depreciation and depletion expenses in line with higher production volumes.
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Sales of petroleum products
Refinery utilization
Margins were stronger in the refining segment of the industry in 2004 compared with those in 2003, as international wholesale product prices increased more than raw material costs. However, the effects of higher international margins were reduced partially by a higher Canadian dollar. Retail margins in the fuels marketing area were lower in 2004, reflecting the impact of highly competitive markets. Throughput at the refineries has increased with refinery capacity utilization averaging a record 93 percent during 2004, compared with 90 percent in 2003 (2002 – 90 percent). The Company’s total sales volumes, including those resulting from reciprocal supply agreements with other companies, were 87.6 million litres a day, compared with 85 million litres in 2003 (2002 – 83.1 million). Excluding sales resulting from reciprocal agreements, sales were 73.4 million litres a day, compared with 70.4 million litres in 2003 (2002 – 69.2 million). Operating costs increased by about two percent in 2004 from the previous year, mainly because of higher energy, environmental and depreciation costs.
Chemicals Net income from chemical operations was $100 million in 2004, compared with $37 million in 2003 (2002 – $52 million). Strong industry polyethylene and benzene margins were the main factors contributing to the improvement.
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Sales volumes
Total revenues from chemical operations were $1,509 million, compared with $1,232 million in 2003 (2002 – $1,164 million). Higher prices for polyethylene, intermediate chemicals and aromatics were the contributing factors. The average industry price of polyethylene was $1,584 a tonne in 2004, up 12 percent from $1,415 a tonne in 2003 (2002 – $1,229). Margins were higher as demand for polyethylene products grew. Sales of chemicals were 3,300 tonnes a day, unchanged from 2003 (2002 – 3,500 tonnes), while polyethylene and benzene sales were up three percent and 32 percent respectively over 2003. Operating costs in the chemicals segment for 2004 were about the same as 2003. Higher energy costs were offset by lower depreciation expense. A significant portion of the property, plant and equipment currently used in production and manufacturing, has been fully depreciated.
Corporate and other Net income from corporate and other accounts was negative $35 million in 2004, compared with positive $118 million in 2003 (2002 – negative $7 million). Lower net income in 2004 was mainly due to the absence of the favourable foreign exchange effects on the Company’s U.S. dollar denominated debt, which was replaced with Canadian dollar denominated debt in June and July of 2003. Net income for 2004 also included a nonrecurring after-tax write-down of $42 million on a north Toronto property, which was acquired in 1991 to be the Company’s future Toronto headquarters site. The remeasurement at fair value of this property reflected a change in its intended use and management’s commitment to sell following the announcement of the relocation of the Company’s headquarters to Calgary.
Liquidity and capital resourcesSources and uses of cash
Although the Company issues long term debt from time to time, internally generated funds cover the majority of its financial requirements. The management of cash that may be temporarily available as surplus to the Company’s immediate needs is carefully controlled, both to ensure that it is secure and readily available to meet the Company’s cash requirements as they arise and to optimize returns on cash balances. Cash flows from operating activities are highly dependent on crude oil and natural gas prices and product margins. In addition, the Company will need to continually find and develop new resources, and continue to develop and apply new technologies and recovery processes to existing fields, in order to maintain or increase production and resulting cash flows in future periods. Projects are in place, or underway, to increase production capacity. However, these volume increases are subject to a variety of risks including project execution, operational outages, reservoir performance and regulatory changes. The Company’s financial strength enables it to make large, long term capital expenditures. The Company’s large and diverse portfolio of development opportunities and the complementary nature of its business segments help mitigate the overall risks of the Company and associated cash flow. Further, due to its financial strength, debt capacity and diverse portfolio of opportunities, the risk associated with failure or delay of any single project would not have a significant impact on the Company’s liquidity or ability to generate sufficient cash flows for operations and its fixed commitments.
Cash flow from operating activities Cash provided by operating activities was $3,312 million, up from $2,227 million in 2003 (2002 – $1,688 million). The increased cash inflow was mainly due to higher net income, timing of scheduled income tax payments and the additional funding contributions to the employee pension plan in 2003.
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Capital and exploration expenditures Total capital and exploration expenditures were $1,445 million in 2004, down slightly from $1,559 million in 2003 (2002 – $1,612 million). The funds were used mainly to invest in growth opportunities in the oil sands and the Mackenzie gas project, to upgrade refineries to meet low sulphur diesel requirements and to enhance the Company’s retail network. About $150 million was spent on projects related to reducing the environmental impact of its operations and improving safety including about $90 million on the $500 million capital project to produce low sulphur diesel. The following table shows the Company’s capital and exploration expenditures for natural resources during the five years ending December 31, 2004:
For the natural resources segment, about 90 percent of the capital and exploration expenditures in 2004 was focused on growth opportunities. The single largest investment during the year was the Company’s share of the Syncrude expansion. Construction on the upgrader expansion made good progress since the first quarter of 2004 when cost estimates were substantially increased and the construction schedule was extended. At year end, the project was tracking to the revised cost and construction schedule. The remainder of 2004 investment was directed to advancing the Mackenzie gas project and drilling at Cold Lake and in conventional fields in Eastern and Western Canada. For the Mackenzie gas project, in October 2004, the main regulatory applications and environmental impact statement 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. A decision to proceed with the project will be made by the co-venturers of the project after approvals are received and any conditions attached to the approvals are assessed. Planned capital and exploration expenditures in natural resources are expected to be about $1 billion in 2005, with nearly 90 percent of the total focused on growth opportunities. Much of the expenditure will be directed to the expansion now underway at Syncrude. Investments are also planned for the ongoing development drilling at Cold Lake, the Mackenzie gas project and further development drilling in Western Canada. Planned expenditures for exploration and development drilling, as well as capacity additions in conventional oil and gas operations, are expected to be about $355 million. The following table shows the Company’s capital expenditures in the petroleum products segment during the five years ending December 31, 2004:
For the petroleum products segment, capital expenditures decreased to $283 million in 2004, compared with $478 million in 2003 (2002 – $589 million), primarily because of the completion of the project to significantly reduce sulphur content in gasoline, which began in 2001. New investments in 2004 included about $90 million spent on the initial phases of a three year project to reduce sulphur content in diesel. In addition, $24 million was spent on other refinery projects to improve energy efficiency and increase yield. Major investments were also made to upgrade the network of Esso service stations during the year. Capital expenditures for the petroleum products segment in 2005 are expected to be about $550 million. Major items include additional investment in refining facilities to reduce the sulphur content in diesel to meet regulatory requirements and continued enhancements to the Company’s retail network. The following table shows the Company’s capital expenditures for the chemicals operations during the five years ending December 31, 2004.
Of the capital expenditures for chemicals in 2004, the major investment focused on improving energy efficiency, yields and process control technology.
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Planned capital expenditures for chemicals in 2005 will be about $20 million. Total capital and exploration expenditures for the Company in 2005, which will focus mainly on growth and productivity improvements, are expected to total about $1.6 billion and will be financed from internally generated funds.
Cash flow from financing activities In June, the Company renewed the normal course issuer bid (share repurchase program) for another 12 months. During 2004, the Company purchased about 14 million shares for $872 million (2003 – 16 million shares for $799 million). Since the Company initiated its first share repurchase program in 1995, the Company has purchased 233 million shares – representing about 40 percent of the total outstanding at the start of the program – with resulting distributions to shareholders of $6.8 billion. The Company declared dividends totalling 88 cents a share in 2004, up from 87 cents in 2003 (2002 – 84 cents). Regular per share dividends paid have increased in each of the past 10 years and, since 1986, payments per share have grown by more than 65 percent. Total debt outstanding at the end of 2004, excluding the Company’s share of equity Company debt, was $1,443 million, compared with $1,432 million at the end of 2003 (2002 – $1,538 million). Debt represented 19 percent of the Company’s capital structure at the end of 2004, compared with 21 percent at the end of 2003 (2002 – 24 percent). Debt related interest incurred in 2004, before capitalization of interest, was $37 million, down from $38 million in 2003 (2002 – $40 million). The average effective interest rate on the Company’s debt was 2.8 percent in 2004, compared with 2.9 percent in 2003 (2002 – 2.1 percent). On May 6, 2004, the Company filed a final short form shelf prospectus in Canada in connection with the issuance of medium term notes over the 25 month period that the shelf prospectus remains valid. The unsecured notes will be issued from time to time at the discretion of the Company in an aggregate amount not to exceed $1 billion. The Company has not issued any notes under this shelf prospectus.
Financial percentages and ratios
Contractual obligations To more fully explain the Company’s financial position, the following table shows the Company’s contractual obligations outstanding at December 31, 2004. It brings together, for easier reference, data from the consolidated balance sheet and from individual notes to the consolidated financial statements.
(Table continued on following page)
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The Company was contingently liable at December 31, 2004, for a maximum of $175 million relating to guarantees for purchasing operating equipment and other assets from its rural marketing associates upon expiry of the associate agreement or the death or resignation of the associate. The Company expects that the fair value of the operating equipment and other assets so purchased would cover the maximum potential amount of future payment under the guarantees. Various lawsuits are pending against Imperial Oil Limited and its subsidiaries. Based on a consideration of all relevant facts and circumstances, the Company does not believe the ultimate outcome of any currently pending lawsuits against the Company will have a material adverse effect upon the Company’s operations or financial condition. There are no events or uncertainties known to management beyond those already included in reported financial information that would indicate a material change in future operating results or financial condition.
Recently issued Statement of Financial Accounting Standards In December 2004, the Financial Accounting Standards Board (FASB) issued a revised Statement of Financial Accounting Standards No. 123 (SFAS 123R), Share Based Payments. SFAS 123R requires compensation costs related to share based payment arrangements to employees to be recognized in the income statement over the period that an employee provides service in exchange for the award. The amount of the compensation cost will be measured based on the grant date fair value of the instruments issued. In addition, liability awards will be remeasured each reporting period through settlement. SFAS 123R is effective as of July 1, 2005 for all awards granted or modified after that date and for those awards granted prior to that date for which the requisite employee service has not yet been rendered. SFAS 123R will have no impact on the Company because in 2003 the Company adopted a policy of expensing all share based payments that is consistent with the provisions of SFAS 123R and the requisite employee service for all prior year outstanding stock options has been rendered.
Emerging accounting and reporting issues
Accounting for purchases and sales of inventory with the same counterparty At its November 2004 meeting, the Emerging Issues Task Force (EITF) of FASB began discussion of Issue 04-13, “Accounting for Purchases and Sales of Inventory with the Same Counterparty”. This Issue addresses the question of when it is appropriate to measure purchases and sales of inventory at fair value and record them in cost of sales and revenues and when they should be recorded as an exchange measured at the book value of the item sold. The EITF did not reach a consensus on this issue, but requested the FASB staff to further explore the alternative views. The Company records certain purchases and sales entered into contemporaneously with the same counterparty as cost of sales and revenues, measured at fair value as agreed upon by a willing buyer and a willing seller. These transactions occur under contractual arrangements that establish the agreement terms either jointly, in a single contract, or separately, in individual contracts. Should the EITF reach a consensus on this issue, requiring these transactions to be recorded as exchanges measured at book value, the reported amounts in “operating revenues” and “purchases of crude oil and products” on the consolidated statement of income would be lower by equal amounts with no impact on net income. The Company has not yet determined the amount by which “operating revenues” and “purchases of crude oil and products” would be lower under this interpretation. A special effort is needed to identify purchase/sale transactions from other monetary purchases and monetary sales. A best effort estimate based on this undertaking is expected to be available in the second quarter of 2005. The Company will disclose this information, if material, once it is available.
Critical accounting policies The Company’s financial statements have been prepared in accordance with United States generally accepted accounting principles (GAAP) and include estimates that reflect management’s best judgments. The Company’s accounting and financial reporting fairly reflect its straightforward business model. The Company does not use financing structures for the purpose of altering accounting outcomes or removing debt from the balance sheet. The following summary provides further information about the critical accounting policies and the estimates that are made by the Company to apply those policies. It should be read in conjunction with pages F-7 to F-9.
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Hydrocarbon reserves Proved oil, gas and synthetic crude oil reserve quantities are used as the basis of calculating unit of production rates for depreciation and evaluating for impairment. Proved oil and gas reserves are the estimated quantities of crude oil, natural gas and natural gas liquids that geological and engineering data demonstrate with reasonable certainty to be recoverable in future years from known reservoirs and deposits under existing economic and operating conditions. Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The estimation of proved reserves is controlled by the Company through long standing approval guidelines. Reserve changes are made with a well established, disciplined process driven by senior level geoscience and engineering professionals (assisted by a central reserves group with significant independent technical experience) culminating in reviews with and approval by senior management and the Company’s board of directors. Key features of the estimation include rigorous peer reviewed technical evaluations and analysis of well and field performance information, and a requirement that management make a commitment toward the development of the reserves prior to booking. Notably, technical and other professionals involved in the process are not compensated based on the levels of proved reserves bookings. Although the Company is reasonably certain that proved reserves will be produced, the timing and ultimate recovery can be affected by a number of factors including completion of development projects, reservoir performance and significant changes in long term oil and gas price levels. In compliance with the United States Securities and Exchange Commission regulatory guidance, the Company has reported 2004 reserves on the basis of the day of December 31, 2004, prices and costs (“year end prices”). Resultant changes in Cold Lake bitumen and the associated natural gas reserves from the year end 2003 estimates, which were based on long term projections of oil and gas prices consistent with those used in the Company’s investment decision-making process, are shown in the line titled “Year end price/cost revisions” on page 29. The requirement to use year end prices for reserves estimation introduces single day price focus and volatility in the valuation of reserves to be produced over the next 20 to 30 years. The Company believes that this approach is inconsistent with the long term nature of the natural resources business. The use of prices from a single date is not relevant to the investment decisions made by the Company and annual variations in reserves based on such year end prices are not of consequence in how the business is managed. The impact of year end prices on reserve estimation is most clearly shown at Cold Lake where proved bitumen and associated natural gas reserves were reduced by about 485 million oil equivalent barrels as a result of using December 31, 2004 prices, which were unusually low. Prices of Cold Lake bitumen were strong for most of 2004, however, they began to deteriorate in the middle of the fourth quarter and ended on December 31, 2004, 70 percent below the year’s average. Prices quickly rebounded from December 31, and through January 2005 returned to levels that have restored the reserves to the proved category. Performance related revisions can include upward or downward changes in previously estimated volumes of proved reserves for existing fields due to the evaluation or revaluation of (1) already available geologic, reservoir or production data, or (2) new geologic or reservoir data. Performance related revisions can also include changes associated with the performance of improved recovery projects and significant changes in either development strategy or production equipment/facility capacity. The Company uses the successful efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field by field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The Company continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. Capitalized exploratory drilling costs pending the determination of proved reserves or the amount of suspended exploratory well costs were negligible, $2 million and $13 million at December 31, 2004, 2003 and 2002 respectively. Costs of productive wells and development dry holes are capitalized and amortized on the unit of production method for each field. The Company uses this accounting policy instead of the full cost method because it provides a more timely accounting of the success or failure of the Company’s exploration and production activities.
Impact of reserves on depreciation The calculation of unit of production depreciation is a critical accounting estimate that measures the depreciation of natural resources assets. It is the ratio of (1) actual volumes produced to (2) total proved developed reserves (those reserves recoverable through existing wells with existing equipment and operating methods) applied to (3) the asset cost. The volumes produced and asset cost are known and while proved developed reserves have a high probability of recoverability, they are based on estimates that are subject to some variability. This variability has generally resulted in net upward revisions of proved reserves in existing fields, as more information becomes available through research and production. Revisions have averaged 16 million oil equivalent barrels per year over the last five years and have resulted from effective reservoir
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management and the application of new technology. While the upward revisions the Company has made over the last five years are an indicator of variability, they have had little impact on the unit of production rates of depreciation because they have been small compared to the large proved reserves base.
Impact of reserves and prices on testing for impairment Proved oil and gas properties held and used by the Company are reviewed for impairment whenever events or circumstances indicate that the carrying amounts may not be recoverable. Assets are grouped at the lowest level for which there are identifiable cash flows that are largely independent of the cash flows of other groups of assets. The Company estimates the future undiscounted cash flows of the affected properties to judge the recoverability of carrying amounts. In general, impairment analyses are based on proved reserves. Where probable reserves exist, an appropriately risk adjusted amount of these reserves may be included in the impairment evaluation. An asset would be impaired if the undiscounted cash flows were less than its carrying value. Impairments are measured by the amount by which the carrying value exceeds its fair value. The impairment evaluation triggers include a significant decrease in current and projected prices or reserve volumes, an accumulation of project costs significantly in excess of the amount originally expected, and historical and current negative operating losses. In general, the Company does not view temporarily low oil prices as a triggering event for conducting the impairment tests. The markets for crude oil and natural gas have a history of significant price volatility. Although prices will occasionally drop precipitously, the relative growth/decline in supply versus demand will determine industry prices over the long term and these cannot be accurately predicted. Accordingly, any impairment tests that the Company performs make use of the Company’s long term price assumptions for the crude oil and natural gas markets, petroleum products and chemicals. These are the same price assumptions that are used in the Company’s annual planning and budgeting processes and are also used for capital investment decisions. The standardized measure of discounted future cash flows on page 30 is based on the year end 2004 price applied for all future years, as required under Statement of Financial Accounting Standards No. 69 (SFAS 69). Future prices used for any impairment tests will vary from the one used in the SFAS 69 disclosure, and could be lower or higher for any given year.
Retirement benefits The Company’s pension plan is managed in compliance with the requirements of governmental authorities and meets funding levels as determined by independent third party actuaries. Pension accounting requires explicit assumptions regarding, among others, the discount rate for the benefit obligations, the expected rate of return on plan assets and the long term rate of future compensation increases. All pension assumptions are reviewed annually by senior management. These assumptions are adjusted only as appropriate to reflect long term changes in market rates and outlook. The long term expected rate of return on plan assets of 8.25 percent used in 2004 compares to actual returns of 10.7 percent and 10.1 percent achieved over the last 10 and 20 year periods ending December 31, 2004. If different assumptions are used, the expense and obligations could increase or decrease as a result. The Company’s potential exposure to changes in assumptions is summarized in note 7 to the consolidated financial statements on page F-13. At the Company, differences between actual returns on plan assets versus long term expected returns are not recorded in the year the differences occur, but rather are amortized in pension expense as permitted by GAAP, along with other actuarial gains and losses over the expected remaining service life of employees. The Company uses the fair value of the plan assets at year end to determine the amount of the actual gain or loss that will be amortized and does not use a moving average value of plan assets. Pension expense represented about one percent of total expenses in 2004.
Asset retirement obligations and other environmental liabilities Legal obligations associated with site restoration on the retirement of assets with determinable useful lives are recognized when they are incurred, which is typically at the time the assets are installed. The obligations are initially measured at fair value and discounted to present value. Over time, the discounted asset retirement obligation amount will be accreted for the change in its present value, with this effect included in operating expense. As payments to settle the obligations occur on an ongoing basis and will continue over the lives of the operating assets, which can exceed 25 years, the discount rate will be adjusted only as appropriate to reflect long term changes in market rates and outlook. For 2004, the obligations were discounted at six percent and the accretion expense was $22 million, which was significantly less than one percent of total expenses in the year. There would be no material impact on the Company’s reported financial results if a different discount rate had been used. Asset retirement obligations are not recognized for assets with an indeterminate useful life. For these and non-operating assets, the Company accrues provisions for environmental liabilities when it is probable that obligations have been incurred and the amount can be reasonably estimated.
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Asset retirement obligations and other environmental liabilities are based on engineering estimated costs, taking into account the anticipated method and extent of remediation consistent with legal requirements, current technology and the possible use of the location. Since these estimates are specific to the locations involved, there are many individual assumptions underlying the Company’s total asset retirement obligations and provision for other environmental liabilities. While these individual assumptions can be subject to change, none of them is individually significant to the Company’s reported financial results.
Item 7A. Quantitative and Qualitative Disclosures About Market Risk. The Company is exposed to a variety of financial, operating and market risks in the course of its business. Some of these risks are within the Company’s control, while others are not. For those risks that can be controlled, specific risk management strategies are employed to reduce the likelihood of loss. Other risks, such as changes in international commodity prices and currency exchange rates, are beyond the Company’s control. Although the Government of Canada in ratifying the Kyoto Protocol agreed to restrictions of greenhouse gas emissions by the period 2008-2012, it has not determined what measures it will impose on companies. Consequently, attempts to assess any impact on the Company can only be speculative. The Company will continue to monitor the development of legal requirements in this area. The Company’s size, strong financial position and the complementary nature of its natural resources, petroleum products and chemicals segments help mitigate the Company’s exposure to changes in these other risks. The Company’s potential exposure to these types of risk is summarized in the table below. The Company does not use derivative markets to speculate on the future direction of currency or commodity prices and does not sell forward any part of production from any business segment. The following table shows the estimated annual effect, under current conditions, of certain sensitivities of the Company’s after tax net income.
The amount quoted to illustrate the impact of each sensitivity represents a change of about 10 percent in the value of the commodity or rate in question at the end of 2004. Each sensitivity calculation shows the impact on net income that results from a change in one factor, after tax and royalties and holding all other factors constant. While these sensitivities are applicable under current conditions, they may not apply proportionately to larger fluctuations. The sensitivity of net income to changes in the Canadian dollar versus the U.S. dollar decreased from year end 2003 by about $10 million (after tax) a year for each one cent change. This is primarily due to the unusually low year end prices for Cold Lake bitumen, which is sold in U.S. dollars.
Item 8. Financial Statements and Supplementary Data. Reference is made to the Index to Financial Statements on page F-1 of this report.
Syncrude Mining Operations Syncrude’s crude bitumen is contained within the unconsolidated sands of the McMurray Formation. Ore bodies are buried beneath 15 to 45 metres (50 to 150 feet) of overburden, have bitumen grades ranging from 4 to 14 weight percent and ore thickness of 35 to 50 metres (115 to 160 feet). Estimates of synthetic crude oil reserves are based on detailed geological and engineering assessments of in-place crude bitumen volume, the mining plan, historical extraction recovery and upgrading yield factors, installed plant operating capacity and operating approval limits. The in-place volume, depth and grade are established through extensive and closely spaced core drilling. Proven reserves include the operating Base and North mines and the Aurora mine. In accordance with the approved mining plan, there are an estimated 1,865 million tonnes (2,055 million tons) of extractable tar sands, in the Base and North mines, with an average bitumen grade of 10.6 weight percent. In addition, at the Aurora mine, there are an estimated 4,060 million tonnes (4,470 million tons) of extractable tar sands at an average bitumen grade of 11.1 weight percent. After deducting royalties payable to the Province of Alberta, the Company estimates its 25 percent net share of proven reserves is equivalent to 120 million cubic metres (757 million barrels) of synthetic crude oil.
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The following table sets forth the Company’s share of net proven reserves of Syncrude after deducting royalties payable to the Province of Alberta:
Oil and Gas Producing Activities The following information is provided in accordance with the United States’ Statement of Financial Accounting Standards No. 69, “Disclosures about Oil and Gas Producing Activities”.
Results of operations
Capital and exploration expenditures
27
Property, plant and equipment
Net proved developed and undeveloped reserves (1)
28
29
Reserves data do not include certain resources of crude oil and natural gas such as those discovered in the Beaufort Sea-Mackenzie Delta and the Arctic islands, or the resources contained in oil sands other than those attributable to the Cold Lake Leming plant and stages 1 through 13 of Cold Lake production operations. Oil equivalent barrels (OEB) may be misleading, particularly if used in isolation. An OEB conversion ratio of 6,000 cubic feet to one barrel is based on an energy-equivalency conversion method primarily applicable at the burner tip and does not represent a value equivalency at the well head. No independent qualified reserves evaluator or auditor was involved in the preparation of the reserves data.
Net Proved Developed and Undeveloped Reserves of Crude Oil and Natural Gas (1)
Net Proved Developed Reserves of Crude Oil and Natural Gas (1)
Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves As required by the Financial Accounting Standards Board, the standardized measure of discounted future net cash flows is computed by applying year end prices, costs and legislated tax rates and a discount factor of 10 percent to net proved reserves. The standardized measure includes costs for future dismantlement, abandonment and rehabilitation obligations. The Company believes the standardized measure does not provide a reliable estimate of the Company’s expected future cash flows to be obtained from the development and production of its oil and gas properties or of the value of its proved oil and gas reserves. The standardized measure is prepared on the basis of certain prescribed assumptions including year end prices, which represent a single point in time and therefore may cause significant variability in cash flows from year to year as prices change. The table below excludes the Company’s interest in Syncrude.
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Changes in Standardized Measure of Discounted Future Net Cash Flows Related to Proved Oil and Gas Reserves
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.
Item 9A. Controls and Procedures.
As indicated in the certifications in Exhibit 31.1 and 31.2 of this report, the Company’s principal executive officer and principal financial officer have evaluated the Company’s disclosure controls and procedures as of December 31, 2004. Based on that evaluation, these officers have concluded that the Company’s disclosure controls and procedures are appropriate and effective for the purpose of ensuring that material information relating to the Company, including its consolidated subsidiaries, is made known to them by others within those entities, particularly during the period in which this annual report is being prepared.
31
PART III
Item 10. Directors and Executive Officers of the Registrant.
32
Pierre Des Marais II is currently a director and has been a director of the Company since April 22, 1977. He holds 1,560 common shares of the Company, 5,031 deferred share units and 2,750 restricted stock units.
33
Jack Mintz is a director of Brascan Corporation and CHC Helicopter Corporation, Roger Phillips is a director of Canadian Pacific Railway Limited, Cleveland – Cliffs Inc., and The Toronto Dominion Bank, and Victor L. Young is a director of Royal Bank of Canada and BCE Inc., which companies are subject to reporting requirements under the U.S. Securities Exchange Act of 1934.
The following table provides information on the senior executives of the Company.
All of the above senior executives have been engaged for more than five years at their current occupations or in other executive capacities with the Company or its affiliates. All senior executives hold office until their appointment is rescinded by the directors, or by the chief executive officer.
Audit committee
Audit committee financial expert
Code of ethics
34
Item 11. Executive Compensation.
Directors’ compensation
Senior executive compensationSummary compensation table
35
36
Long term incentive compensation
Consistent with the Company’s compensation philosophy of being performance driven, long term incentive compensation is granted to retain selected employees and reward them for high performance. The compensation has generally been in the form of units.
37
In 1998, an additional form of long term incentive compensation (“deferred share units”) was made available to selected executives whereby they could elect to receive all or part of their performance bonus compensation in the form of such units. The number of units granted to an executive is determined by dividing the amount of the executive’s bonus elected to be received as deferred share units by the average of the closing prices of the Company’s shares on the Toronto Stock Exchange for the five consecutive trading days (“average closing price”) immediately prior to the date that the bonus would have been paid to the executive. Additional units will be granted to recipients of these units based on the cash dividend payable on the Company shares divided by the average closing price immediately prior to the payment date for that dividend and multiplying the resulting number by the number of deferred share units held by the recipient. An executive may not exercise these units until after termination of employment with the Company and must exercise the units no later than December 31 of the year following termination of employment with the Company. The units held must all be exercised on the same date. On the date of exercise, the cash value to be received for the units will be determined by multiplying the number of units exercised by the average closing price immediately prior to the date of exercise.
38
There are 927,908 common shares issuable upon future exercise of restricted stock units, which represent about 0.27 percent of the Company’s currently outstanding common shares. The Company’s directors, officers and vice-presidents have available as a group 22 percent of the common shares issuable under outstanding restricted stock units.
Earnings bonus unit plan – awards in most recently completed financial year
39
Aggregated option/SAR exercises during the most recently completed financial year and financial year end option/SAR values The following table provides information on the exercise in 2004 and the aggregate holdings at the end of 2004 of incentive share units (referred to in the table as “SARs”) by the named senior executives.
The following table provides information on the exercise in 2004 and the aggregate holdings at the end of 2004 of stock options by the named senior executives.
40
Payments to employees who retirePension plan table
The Company’s pension plan applies to almost all employees. The plan provides an annual pension of a specific percentage of an employee’s “final three year average earnings”, multiplied by the employee’s years of service, subject to certain requirements concerning age and length of service. An employee may elect to forego three of the six percent of the Company’s contributions to the savings plan under one of the options of that plan (except for K.C. Williams and J.M. Yeager), to receive an enhanced pension equal to 0.4 percent of the employee’s “final three year average earnings”, multiplied by the employee’s years of service while foregoing such Company contributions. In addition to the pension payable under the plan, the Company has paid and may continue to pay a supplemental retirement income to employees who have earned a pension in excess of the maximum pension under the Income Tax Act. The pension plan table on this page shows estimated undiscounted annual payments, consisting of pension and supplemental retirement income, payable on retirement to employees including the senior executives in specified classifications of remuneration and years of service currently applicable to that group. The remuneration used to determine the payments on retirement to the individuals named in the summary compensation table on pages 36 and 37, corresponds generally to the salary, bonus compensation, and bonus compensation amount elected to be received as deferred share units in that table, and the aggregate maximum settlement value that could be paid for earnings bonus units granted shown in the table on page 39 is included in the employee’s “final three year average earnings” for the year of grant of such units. As of February 18, 2005, the number of completed years of service with Imperial Oil Limited used to determine payments on retirement were 38 for T.J. Hearn, 36 for B.J. Fischer, 25 for P.A. Smith and 28 for J.F. Kyle. K.C. Williams and J.M. Yeager are not members of the Company’s pension plan but are members of Exxon Mobil Corporation’s pension plan. Under that plan, J.M. Yeager has 23 years of service and he will receive a pension payable in U.S. dollars. The remuneration used to determine the payment on retirement to him also corresponds generally to his salary and bonus compensation in the summary compensation table on pages 36 and 37, which remuneration may be applied to the pension plan table above but with the dollars in that table representing U.S. rather than Canadian dollars.
Composition of the Company’s compensation committee The executive resources committee of the board of directors, composed of the nonemployee directors, is responsible for decisions on the compensation of senior management above the level of vice-president including all officers of the Company, and for reviewing the executive development system, including specific succession plans for senior management positions. It also reviews corporate policy on compensation. During 2004, the membership of the executive resources committee was as follows:
P. Des Marais II – ChairR. Phillips – Vice-chairJ.F. ShepardS.D. WhittakerV.L. YoungT.J. Hearn periodically attends meetings at the request of the committee.
41
Executive resources committee report on executive compensation The Company’s executive compensation policy is designed to reinforce the Company’s orientation toward career employment and its emphasis on performance as the primary determinant of advancement. This acknowledges the long term nature of the Company’s business and its philosophy that the experience, skill and motivation of its senior executives are significant determinants of future business success. The compensation program emphasizes competitive salaries and performance based incentives as the primary instruments to develop and retain key personnel. In establishing levels of compensation for its senior executives, the executive resources committee relies on market comparisons to other leading Canadian employers, typically in the group of major companies with revenues in excess of $1 billion a year. These market comparisons are prepared by independent external compensation consultants. On a case by case basis, depending on the scope of market coverage represented by a particular comparison, compensation is targeted to a range between the mid-point and the upper quartile of comparable employers, reflecting the Company’s emphasis on quality of management. The Company’s senior executive compensation policy has three main elements: base salary, short term and long term incentive compensation. While these elements are related to the extent that compensation policy is compared in total to the competitive practices of other major Canadian employers, individual decisions on base salary, short term and long term incentive compensation are made independently of each other.
Base salary The Company’s salary ranges for executives were increased by three percent in 2003, two and one half percent in 2004 and one and one half percent in 2005. High performing executives, and those recently promoted, whose salaries were low relative to their level of responsibility, were given limited additional salary increases. This included senior executives. T.J. Hearn’s salary is currently assessed to be within the range of the competitive target for the Company’s chief executive officer which is between the median and upper quartile. The target is consistent with the executive resources committee’s view that the chief executive officer’s salary should be above the average of salaries for chief executive officers of major Canadian companies, reflecting the Company’s executive development philosophy and the significance placed on experience and judgment in leading a large, complex operation.
Cash bonus Cash bonuses are typically granted to about 80 executives at the end of each year, based on individual performance. The bonuses are drawn from an aggregate bonus amount established annually by the executive resources committee based on the Company’s financial performance, and are granted in tandem with the Company’s earnings bonus units, which are described on page 38. In 2004, the executive resources committee increased the bonus awards including the grant of earnings bonus units to reflect the Company’s record financial results and in response to comparisons to other leading Canadian employers. In the case of T.J. Hearn, the committee’s approach to cash bonuses is based on the Company’s financial and operating performance and on the committee’s assessment of T.J. Hearn’s effectiveness in leading the organization. The continuing progress being made in focussing the organization on advancing key strategic interests, safety, environmental performance, productivity, cost effectiveness and asset management were primary considerations in determining a cash bonus for the chief executive officer. T.J. Hearn’s bonus including the grant of earnings bonus units was increased in 2004 to reflect his effectiveness in the position, the Company’s record financial results, and comparisons to other leading Canadian employers.
Long term incentive compensation Each year, the executive resources committee has approved long term incentive awards for selected key employees. These awards were an added incentive to promote individual contribution to sustained improvement in business performance and shareholder value, and to encourage key employees to remain with the Company. Individual awards reflected both level of responsibility and performance, with an emphasis on ability to influence longer term results. In each case, including senior executives and the chief executive officer, award amounts took into account the competitive practices of other major Canadian employers and were not influenced by prior years’ results or by an individual’s holdings of unexercised long term incentive compensation units. Incentive awards also have been awarded selectively to the general managerial, professional and technical (non-executive) workforce as a way of delivering added financial incentive to selected high performing employees.
42
For selected executives, the executive resources committee allows cash bonus awards to be elected to be received in the form of deferred share units and also awards earnings bonus units as a means of providing additional incentive to promote the Company’s long term financial performance. Eligibility to participate in the deferred share unit and earnings bonus plans is restricted to those executives whose decisions are considered to have a direct effect on the long term financial performance of the Company. In 2004, one executive elected to receive deferred share units and 77 executives were awarded earnings bonus units. For many years, the Company’s long term incentive compensation programs have been cash based programs tied to earnings and share performance, and incentive awards have been reported as expenses in the consolidated statement of earnings. In 2002, to meet competitive practices, the Company introduced a stock option program. However, recognizing current concerns over stock option incentive programs and their proper accounting treatment, the Company decided to return to straightforward, cash based incentive compensation programs that will again be reported as expenses against earnings. There are no plans to issue stock options in the future. A total of 575 employees, including executives, were granted restricted stock units in 2004.
Submitted on behalf of the executive resources committee:P. Des Marais II – ChairR. Phillips – Vice-chairJ.F. ShepardS.D. WhittakerV.L. Young
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters. To the knowledge of the management of the Company, the only shareholder who, as of February 18, 2005, owned beneficially, or exercised control or direction over, more than five percent of the outstanding common shares of the Company is Exxon Mobil Corporation, 5959 Las Colinas Boulevard, Irving, Texas 75039-2298, which owns beneficially 242,453,672 common shares, representing 69.6 percent of the outstanding voting shares of the Company. Reference is made to the security ownership information under the preceding Items 10 and 11. As of February 18, 2005, John F. Kyle was the owner of 3,774 common shares of the Company and held options to acquire 29,000 common shares of the Company and restricted share units to acquire 12,300 common shares of the Company. The directors and the senior executives of the Company consist of 10 persons, who, as a group, own beneficially 85,896 common shares of the Company, being approximately 0.02 percent of the total number of outstanding shares of the Company, and 118,452 shares of Exxon Mobil Corporation. This information not being within the knowledge of the Company has been provided by the directors and the senior executives individually. As a group, the directors and senior executives of the Company held options to acquire 163,000 common shares of the Company and held restricted stock units to acquire 127,950 common shares of the Company, as of February 18, 2005.
Equity Compensation Plan Information as of December 31, 2004
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Item 13. Certain Relationships and Related Transactions. On June 23, 2003, the Company implemented another 12-month “normal course” share-purchase program under which it purchased 15,511,833 of its outstanding shares between June 23, 2003, and June 22, 2004. On June 23, 2004, another 12-month “normal course” program was implemented under which the Company may purchase up to 17,864,398 of its outstanding shares, less any shares purchased by the employee savings plan and Company pension fund. Exxon Mobil Corporation participated by selling shares to maintain its ownership at 69.6 percent. In 2004, such purchases cost $872 million, of which $594 million was received by ExxonMobil. During 2003, the Company borrowed $818 million from Exxon Overseas Corporation under two long term loan agreements at interest equivalent to Canadian market rates. Interest paid on the loans in 2004 was $20 million. The average effective interest rates for the loans was 2.45 percent for 2004. The amounts of purchases and sales by the Company and its subsidiaries for other transactions in 2004 with Exxon Mobil Corporation and affiliates of Exxon Mobil Corporation were $3,176 million and $1,580 million, respectively. These transactions were conducted on terms as favorable as they would have been with unrelated parties, and primarily consisted of the purchase and sale of crude oil, petroleum and chemical products, as well as transportation, technical and engineering services. Transactions with Exxon Mobil Corporation also include amounts paid and received in connection with the Company’s participation in a number of natural resources activities conducted jointly in Canada. The Company has agreements with affiliates of Exxon Mobil Corporation to provide computer and customer support services to the Company and to share common business and operational support services to allow the companies to consolidate duplicate work and systems.
Item 14. Principal Accountant Fees and Services.
Audit Fees The aggregate fees of the Company’s auditors for professional services rendered for the audit of the Company’s financial statements and other services for the fiscal years ended December 31, 2004 and December 31, 2003 were as follows:
Audit fees include the audit of the Company’s annual financial statements, audit of management’s report on internal control over financial reporting and a review of the first three quarterly financial statements in 2004. Audit-related fees include other assurance services including the audit of the Company’s retirement plan, the Imperial Oil Foundation, and royalty statement audits for oil and gas producing entities. Tax fees are mainly tax services for employees on foreign loan assignments. The Company did not engage the auditors for any other services. The audit committee recommends the external auditors to be appointed by the shareholders, fixes their remuneration and oversees their work. The audit committee also approves the proposed current year audit program of the auditors, assesses the results of the program after the end of the program period and approves in advance any non-audit services to be performed by the auditors after considering the effect of such services on their independence. All of the services rendered by the auditors to the Company were approved by the audit committee.
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PART IV
Item 15. Exhibits and Financial Statement Schedules. Reference is made to the Index to Financial Statements on page F-1 of this report. The following exhibits numbered in accordance with Item 601 of Regulation S-K are filed as part of this report:
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46
Copies of Exhibits may be acquired upon written request of any shareholder to the investor relations manager, Imperial Oil Limited, 111 St. Clair Avenue West, Toronto, Ontario, Canada M5W 1K3, and payment of processing and mailing costs.
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SIGNATURES
Pursuant to the requirements of Section 13 or 15(d) of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf on March 9, 2005 by the undersigned, thereunto duly authorized.
Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below on March 9, 2005 by the following persons on behalf of the registrant and in the capacities indicated.
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INDEX TO FINANCIAL STATEMENTS
F-1
MANAGEMENT’S REPORT ON INTERNAL CONTROL OVER FINANCIAL REPORTING
Management, including the Company’s chief executive officer and principal accounting officer and principal financial officer, is responsible for establishing and maintaining adequate internal control over the Company’s financial reporting. Management conducted an evaluation of the effectiveness of internal control over financial reporting based on the Internal Control – Integrated Framework issued by the Committee of Sponsoring Organizations of the Treadway Commission. Based on this evaluation, management concluded that Imperial Oil Limited’s internal control over financial reporting was effective as of December 31, 2004.
Management’s assessment of the effectiveness of internal control over financial reporting as of December 31, 2004, was audited by PricewaterhouseCoopers LLP, an independent registered public accounting firm, as stated in their report which is included herein.
REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM
To the Shareholders of Imperial Oil Limited:
We have completed an integrated audit of Imperial Oil Limited’s 2004 consolidated financial statements and of its internal control over financial reporting as of December 31, 2004, and audits of its 2003 and 2002 consolidated financial statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Our opinions, based on our audits, are presented below.
Consolidated financial statements In our opinion, the accompanying consolidated balance sheets and the related consolidated statements of income, shareholders’ equity and cash flows appearing on pages F-3 through F-20 of this Annual Report present fairly, in all material respects, the financial position of Imperial Oil Limited and its subsidiaries at December 31, 2004 and 2003, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2004 in conformity with accounting principles generally accepted in the United States of America. These financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these financial statements based on our audits. We conducted our audits of these statements in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the financial statements are free of material misstatement. An audit of financial statements includes examining, on a test basis, evidence supporting the amounts and disclosures in the financial statements, assessing the accounting principles used and significant estimates made by management, and evaluating the overall financial statement presentation. We believe that our audits provide a reasonable basis for our opinion.
Internal control over financial reporting Also, in our opinion, management ’s assessment, included in the accompanying Management’ s Report on Internal Control Over Financial Reporting, that the Company maintained effective internal control over financial reporting as of December 31, 2004 based on criteria established in Internal Control — Integrated Frame work issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO), is fairly stated, in all material respects, based on those criteria. Furthermore, in our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2004, based on criteria established in Internal Control — Integrated Framework issued by the COSO. The Company’ s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting. Our responsibility is to express opinions on management’s assessment and on the effectiveness of the Company’ s internal control over financial reporting based on our audit. We conducted our audit of internal control over financial reporting in accordance with the standards of the Public Company Accounting Oversight Board (United States). Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects . An audit of internal control over financial reporting includes obtaining an understanding of internal control over financial reporting, evaluating management’ s assessment, testing and evaluating the design and operating effectiveness of internal control, and performing such other procedures as we consider necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinions.
/s/ PricewaterhouseCoopers LLP
PricewaterhouseCoopers LLPChartered AccountantsToronto, Ontario, CanadaMarch 9, 2005
F-2
Consolidated statement of income
The information on pages F-7 through F-20 is part of these consolidated financial statements. Certain figures for prior years have been reclassified in the financial statements to conform with the current year’s presentation.
F-3
Consolidated statement of cash flows
F-4
Consolidated balance sheet
F-5
Consolidated statement of shareholders’ equity
F-6
Notes to consolidated financial statements
1. Summary of significant accounting policies
The company’s principal business is energy, involving the exploration, production, transportation and sale of crude oil and natural gas and the manufacture, transportation and sale of petroleum products. Imperial is also a major manufacturer and marketer of petrochemicals.The consolidated financial statements have been prepared in accordance with generally accepted accounting principles (GAAP) in the United States of America. The financial statements include certain estimates that reflect management’s best judgment. All amounts are in Canadian dollars unless otherwise indicated.Principles of consolidationThe consolidated financial statements include the accounts of Imperial Oil Limited and its subsidiaries. Intercompany accounts and transactions are eliminated. Subsidiaries include those companies in which Imperial has both an equity interest and the continuing ability to unilaterally determine strategic operating, investing and financing policies. Significant subsidiaries included in the consolidated financial statements include Imperial Oil Resources Limited, Imperial Oil Resources N.W.T. Limited, Imperial Oil Resources Ventures Limited and McColl-Frontenac Petroleum Inc. All of the above companies are wholly owned. A significant portion of the company’s activities in natural resources is conducted jointly with other companies. The accounts reflect the company’s share of undivided interest in such activities, including its 25-percent interest in the Syncrude joint venture and its nine-percent interest in the Sable offshore energy project.Segment reportingThe company operates its business in Canada in the following segments:Natural resources includes the exploration for and production of crude oil and natural gas.Petroleum products comprises the refining of crude oil into petroleum products and the distribution and marketing of these products.Chemicals includes the manufacturing and marketing of various hydrocarbon-based chemicals and chemical products.The above functions have been defined as the operating segments of the company because they are the segments (a) that engage in business activities from which revenues are earned and expenses are incurred; (b) whose operating results are regularly reviewed by the company’s chief operating decision-maker to make decisions about resources to be allocated to the segment and assess its performance; and (c) for which discrete financial information is available.Corporate and other includes assets and liabilities that do not specifically relate to business segments – primarily cash and long-term debt. Net income in this segment primarily includes financing costs and interest income.Segment accounting policies are the same as those described in this summary of significant accounting policies. Natural resources, petroleum products and chemicals expenses include amounts allocated from the “corporate and other” segment. The allocation is based on a combination of fee for service, proportional segment expenses and a three-year average of capital expenditures. Transfers of assets between segments are recorded at book amounts. Items included in capital employed that are not identifiable by segment are allocated according to their nature.InventoriesInventories are recorded at the lower of cost or net realizable value. The cost of crude oil and products is determined primarily using the last-in, first-out (LIFO) method. LIFO was selected over the alternative first-in, first-out and average cost methods because it provides a better matching of current costs with the revenues generated in the period.Inventory costs include expenditures and other charges, including depreciation, directly or indirectly incurred in bringing the inventory to its existing condition and final storage prior to delivery to a customer. Selling and general expenses are reported as period costs and excluded from inventory costs.InvestmentsThe principal investments in companies other than subsidiaries are accounted for using the equity method. They are recorded at the original cost of the investment plus Imperial’s share of earnings since the investment was made, less dividends received. Imperial’s share of the after-tax earnings of these companies is included in “investment and other income” in the consolidated statement of income. Other investments are recorded at cost. Dividends from these other investments are included in “investment and other income.”These investments represent interests in non-publicly traded pipeline companies that facilitate the sale and purchase of crude oil and natural gas in the conduct of company operations. Other parties who also have an equity interest in these companies share in the risks and rewards according to their percentage of ownership. Imperial does not invest in these companies in order to remove liabilities from its balance sheet.Property, plant and equipmentProperty, plant and equipment is recorded at cost. Investment tax credits and other similar grants are treated as a reduction of the capitalized cost of the asset to which they apply.The company uses the successful-efforts method to account for its exploration and production activities. Under this method, costs are accumulated on a field-by-field basis with certain exploratory expenditures and exploratory dry holes being expensed as incurred. The company continues to carry as an asset the cost of drilling exploratory wells that find sufficient quantities of reserves to justify their completion as producing wells if the required capital expenditure is made and drilling of additional exploratory wells is underway or firmly planned for the near future. Once exploration activities demonstrate that sufficient quantities of commercially producible reserves have been discovered, continued capitalization is dependent on project reviews, which take place at least annually, to ensure that satisfactory progress toward ultimate development of the reserves is being achieved. Exploratory well costs not meeting these criteria are charged to expense. Costs of productive wells and development dry holes are capitalized and amortized on the unit-of-production method for each field. The company uses this accounting policy instead of the full-cost method because it provides a more timely accounting of the success or failure of the company’s exploration and production activities.
F-7
F-8
Consumer taxesTaxes levied on the consumer and collected by the company are excluded from the consolidated statement of income. These are primarily provincial taxes on motor fuels and the federal goods and services tax.
F-9
2. Business segments
F-10
Notes to consolidated financial statements (continued)
3. Long-term debt
On May 6, 2004, the company filed a final short-form shelf prospectus in Canada in connection with the issuance of medium-term notes over the 25-month period that the shelf prospectus remains valid. The unsecured notes will be issued from time to time at the discretion of the company in an aggregate amount not to exceed $1 billion. The company has not issued any notes under this shelf prospectus.
F-11
4. Income taxes
Deferred income taxes are based on differences between the accounting and tax values of assets and liabilities. These differences in value are remeasured at each period-end using the tax rates and tax laws expected to apply when those differences are realized or settled in the future. Components of deferred income tax liabilities and assets as at December 31 were:
The operations of the company are complex, and related tax interpretations, regulations and legislation are continually changing. As a result, there are usually some tax matters in question. The company believes the provision made for income taxes is adequate.
5. Reporting of fuel consumed in operations
6. Headquarters relocation
F-12
7. Employee retirement benefits
Retirement benefits, which cover almost all retired employees and their surviving spouses, include pension-income and certain health-care and life-insurance benefits. They are met through funded registered retirement plans and through unfunded supplementary benefits that are paid directly to recipients. Funding of registered retirement plans complies with federal and provincial pension regulations, and the company makes contributions to the plans based upon an independent actuarial valuation.
Pension-income benefits consist mainly of company-paid defined benefit plans that are based on years of service and final average earnings. The company shares in the cost of health-care and life-insurance benefits. The company’s benefit obligations are based on the projected benefit method of valuation that includes employee service to date and present compensation levels as well as a projection of salaries and service to retirement.
The expense and obligations for both funded and unfunded benefits are determined in accordance with United States generally accepted accounting principles and actuarial procedures. The process for determining retirement-income expense and related obligations includes making certain long-term assumptions regarding the discount rate, rate of return on plan assets and rate of compensation increases.
The total obligation for retirement benefits exceeded the fair value of plan assets at December 31, 2004, by $1,712 million (2003 — $1,357 million), $1,276 million (2003 — $975 million) of which was related to pension benefits and $436 million (2003 — $382 million) to other post-retirement benefits. The obligation and pension expense can vary significantly with changes in the assumptions used to estimate the obligation and the expected return on plan assets.
Details of the employee retirement benefits plans are as follows:
F-13
Plan assets
The company’s pension plan asset allocation at December 31, 2003 and 2004, and target allocation for 2005 are as follows:
F-14
F-15
8. Other long-term obligations
9. Derivatives and financial instruments
10. Incentive compensation programs
F-16
F-17
11. Investment and other income
12. Commitments and contingent liabilities
13. Common shares
F-18
14. Miscellaneous financial information
F-19
15. Financing costs
16. Transactions with related parties
17. Net payments/payables to governments
F-20